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,
2009
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OR
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o
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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
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75240
(Zip code)
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(Address of principal executive
offices)
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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 whether the registrant has submitted
electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and
posted pursuant to Rule 405 of Regulation S-T during the
preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files).* Yes o No o
* The registrant has not been phased into the interactive
data requirements.
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, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
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 common 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, 2009, was $2,072,764,690.
As of November 8, 2009, the registrant had
92,599,896 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 3, 2010 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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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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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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Fitch
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Fitch Ratings, Ltd.
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GRIP
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Gas Reliability Infrastructure Program
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GSRS
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Gas System Reliability Surcharge
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ISRS
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Infrastructure System Replacement Surcharge
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KPSC
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Kentucky Public Service Commission
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LTIP
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1998 Long-Term Incentive Plan
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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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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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RRM
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Rate Review Mechanism
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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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Settled Cities
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Represents 438 of the 439 incorporated cities, or approximately
80 percent of the Mid-Tex Divisions customers, with
whom a settlement agreement was reached during the fiscal 2008
second quarter.
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SRF
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Stable Rate Filing
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TXU Gas
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TXU Gas Company, which was acquired on October 1, 2004
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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 Energy and the Company refer to
Atmos Energy Corporation and its subsidiaries, unless the
context suggests otherwise.
Overview
and Strategy
Atmos Energy Corporation, headquartered in Dallas, Texas, is
engaged primarily in the regulated natural gas distribution and
transmission and storage businesses as well as other
nonregulated natural gas businesses. Since our incorporation in
Texas in 1983, we have grown primarily through a series of
acquisitions, the most recent of which was the acquisition in
October 2004 of the natural gas distribution and pipeline
operations of TXU Gas Company. We are also incorporated in the
state of Virginia.
Today, we distribute natural gas through regulated sales and
transportation arrangements to over 3 million residential,
commercial, public authority and industrial customers in
12 states located primarily in the South, which makes us
one of the countrys largest natural-gas-only distributors
based on number of customers. We also operate one of the largest
intrastate pipelines in Texas based on miles of pipe.
Through our nonregulated businesses, we primarily provide
natural gas management and marketing services to municipalities,
other local gas distribution companies and industrial customers
primarily in the Midwest and Southeast and natural gas
transportation along with storage services to certain of our
natural gas distribution divisions and third parties.
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 regulated and nonregulated businesses
exceptionally well and
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enhance and strengthen a culture built on our core values.
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We have experienced more than 25 consecutive years of increasing
dividends and earnings growth after giving effect to our
acquisitions. Historically, we achieved this record of growth
through acquisitions while efficiently managing our operating
and maintenance expenses and leveraging our technology to
achieve more efficient operations. In recent years, we have also
achieved growth by implementing rate designs that reduce or
eliminate regulatory lag and separate the recovery of our
approved margins from customer usage patterns. In addition, we
have developed various commercial opportunities within our
regulated transmission and storage operations. Finally, we have
strengthened our nonregulated businesses by increasing sales
volumes and improving
per-unit
margins.
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.
Operating
Segments
We operate the Company through the following four segments:
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The natural gas distribution segment, which includes our
regulated natural gas distribution and related sales operations.
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The regulated transmission and storage segment, which
includes the regulated pipeline and storage operations of our
Atmos Pipeline Texas Division.
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The natural gas marketing segment, which includes a
variety of nonregulated natural gas management services.
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4
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The pipeline, storage and other segment, which is
comprised of our nonregulated natural gas gathering,
transmission and storage services.
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These operating segments are described in greater detail below.
Natural
Gas Distribution Segment Overview
Our natural gas distribution segment consists of the following
six regulated divisions, presented in order of total customers
served, covering service areas in 12 states:
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Atmos Energy Mid-Tex Division,
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Atmos Energy Kentucky/Mid-States Division,
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Atmos Energy Louisiana Division,
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Atmos Energy West Texas Division,
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Atmos Energy Mississippi Division and
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Atmos Energy Colorado-Kansas Division
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Our natural gas distribution business is a seasonal business.
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.
Revenues in this operating segment are established by regulatory
authorities in the states in which we operate. These rates are
intended to be sufficient to cover the costs of conducting
business and to provide a reasonable return on invested capital.
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.
Rates established by regulatory authorities often include cost
adjustment mechanisms for costs that (i) are subject to
significant price fluctuations compared to our other costs,
(ii) represent a large component of our cost of service and
(iii) are generally outside our control.
Purchased gas cost mechanisms represent a common form of cost
adjustment mechanism. Purchased gas cost adjustment mechanisms
provide natural gas utility companies a method of recovering
purchased gas costs on an ongoing basis without filing a rate
case because they provide a
dollar-for-dollar
offset to increases or decreases in natural gas distribution gas
costs. Therefore, although substantially all of our natural gas
distribution operating revenues fluctuate with the cost of gas
that we purchase, natural gas distribution gross profit (which
is defined as operating revenues less purchased gas cost) is
generally not affected by fluctuations in the cost of gas.
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 instruments to
lock in gas costs. Under the performance-based ratemaking
adjustment, purchased gas costs savings are shared between the
utility and its customers.
Finally, regulatory authorities have approved weather
normalization adjustments (WNA) for over 90 percent of
residential and commercial meters in our service areas as a part
of our rates. WNA minimizes the effect of weather that is above
or below normal by allowing 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.
5
As of September 30, 2009 we had WNA for our residential and
commercial 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
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December March
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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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Texas: Mid-Tex
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November April
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Texas: West Texas
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October May
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Virginia
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January December
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Financial results for this segment are affected by the cost of
natural gas and economic conditions in the areas that we serve.
As discussed above, we are generally able to pass the cost of
gas through to our customers under purchased gas adjustment
clauses; therefore, the cost of gas typically does not have a
direct impact on our gross profit. 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 expense and may require us to
increase borrowings under our credit facilities resulting in
higher interest expense.
Our supply of natural gas is provided by a variety of suppliers,
including independent producers, marketers and pipeline
companies and withdrawals of gas from proprietary and contracted
storage assets. Additionally, the natural gas supply for our
Mid-Tex Division includes peaking and spot purchase agreements.
Supply arrangements consist of both base load and swing supply
(peaking) quantities and are contracted from our suppliers on a
firm basis with various terms at market prices. 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.
Currently, all of our natural gas distribution divisions, except
for our Mid-Tex Division, utilize 39 pipeline transportation
companies, both interstate and intrastate, to transport our
natural gas. 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.
Except for local production purchases, we select our natural gas
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 2009 were Anadarko Energy Services, Chesapeake
Energy Marketing, Inc., ConocoPhillips Company, Devon Gas
Services, L.P., Enbridge Marketing (US) L.P., Iberdrola
Renewables, Inc., National Fuel Marketing Company, LLC, ONEOK
Energy Services Company L.P., 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. We
estimate our
peak-day
availability of natural gas supply to be approximately
4.2 Bcf. The
peak-day
demand for our natural gas distribution operations in fiscal
2009 was on January 15, 2009, when sales to customers
reached approximately 3.1 Bcf.
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 regulations or statutes. Our customers
demand on our system is not necessarily indicative of our
ability to 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
6
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.
The following briefly describes our six natural gas distribution
divisions. We operate in our service areas under terms of
non-exclusive franchise agreements granted by the various cities
and towns that we serve. At September 30, 2009, we held
1,111 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. Additional information concerning our natural
gas distribution divisions is presented under the caption
Operating Statistics.
Atmos Energy Mid-Tex Division. Our Mid-Tex
Division serves approximately 550 incorporated and
unincorporated communities in the north-central, eastern and
western parts of Texas, including the Dallas/Fort Worth
Metroplex. The governing body of each municipality we serve has
original jurisdiction over all gas distribution rates,
operations and services within its city limits, except with
respect to sales of natural gas for vehicle fuel and
agricultural use. The Railroad Commission of Texas (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.
Prior to fiscal 2008, this division operated under one
system-wide rate structure. However, in 2008, we reached a
settlement with cities representing approximately
80 percent of this divisions customers (Settled
Cities) that has allowed us, beginning in 2008, to update rates
for customers in these cities through an annual rate review
mechanism. Rates for the remaining 20 percent of this
divisions customers, primarily the City of Dallas,
continue to be updated through periodic formal rate proceedings
and filings made under Texas Gas Reliability
Infrastructure Program (GRIP). GRIP allows us to include in our
rate base annually approved capital costs incurred in the prior
calendar year provided that we file a complete rate case at
least once every five years.
Atmos Energy Kentucky/Mid-States Division. Our
Kentucky/Mid-States Division operates in more than 420
communities across Georgia, Illinois, Iowa, Kentucky, Missouri,
Tennessee and Virginia. The service areas in these states are
primarily rural; however, this division serves Franklin,
Tennessee, and other suburban areas of Nashville. We update our
rates in this division through periodic formal rate filings made
with each states public service commission.
Atmos Energy Louisiana Division. In Louisiana,
we serve nearly 300 communities, including the suburban areas of
New Orleans, the metropolitan area of Monroe and western
Louisiana. 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. Our rates in this division are updated annually through
a rate stabilization clause filing without filing a formal rate
case.
Atmos Energy West Texas Division. Our West
Texas Division serves approximately 80 communities in West
Texas, including the Amarillo, Lubbock and Midland areas. Like
our Mid-Tex Division, each municipality we serve has original
jurisdiction over all gas distribution rates, operations and
services within its city limits, with the RRC having exclusive
appellate jurisdiction over the municipalities and exclusive
original jurisdiction over rates and services provided to
customers not located within the limits of a municipality. Prior
to fiscal 2008, rates were updated in this division through
formal rate proceedings. However, the West Texas Division
entered into agreements with its West Texas service areas during
2008 and its Amarillo and Lubbock service area during 2009 to
update rates for customers in these service areas through an
annual rate review mechanism.
Atmos Energy Mississippi Division. In
Mississippi, we serve about 110 communities throughout the
northern half of the state, including the Jackson metropolitan
area. Our rates in the Mississippi Division are updated annually
through a stable rate filing without filing a formal rate case.
7
Atmos Energy Colorado-Kansas Division. Our
Colorado-Kansas Division serves approximately 170 communities
throughout Colorado and Kansas and parts of Missouri, including
the cities of Olathe, Kansas, a suburb of Kansas City and
Greeley, Colorado, located near Denver. We update our rates in
this division through periodic formal rate filings made with
each states public service commission.
The following table provides a jurisdictional rate summary for
our regulated operations. This information is for regulatory
purposes only and may not be representative of our actual
financial position.
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Effective
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Authorized
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Authorized
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Date of Last
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Rate Base
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Rate of
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Return on
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Division
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Jurisdiction
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Rate/GRIP Action
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(thousands)(1)
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Return(1)
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Equity(1)
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Atmos Pipeline Texas
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Texas
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5/24/04
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$417,111
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8.258%
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10.00%
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Atmos Pipeline
Texas GRIP
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Texas
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4/28/09
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755,038
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8.258%
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10.00%
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Colorado-Kansas
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Colorado
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10/1/07
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81,208
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8.45%
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11.25%
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Kansas
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5/12/08
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(2)
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(2)
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(2)
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Kentucky/Mid-States
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Georgia
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9/22/08
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66,893
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7.75%
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10.70%
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Illinois
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11/1/00
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24,564
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9.18%
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11.56%
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Iowa
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3/1/01
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5,000
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(2)
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11.00%
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Kentucky
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8/1/07
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(2)
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(2)
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(2)
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Missouri
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3/4/07
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(2)
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(2)
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(2)
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Tennessee
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4/1/09
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190,100
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8.24%
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10.30%
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Virginia
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9/30/08
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33,194
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8.46% - 8.96%
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9.50% - 10.50%
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Louisiana
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Trans LA
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4/1/09
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96,570
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(2)
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10.00% - 10.80%
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LGS
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7/1/09
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236,600
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(2)
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10.40%
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Mid-Tex Settled Cities
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Texas
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8/1/09
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1,262,969(3)
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7.78%
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9.60%
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Mid-Tex Dallas & Environs
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Texas
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6/24/08
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1,127,924(3)
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7.98%
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10.00%
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Mississippi
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Mississippi
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1/1/05
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196,801
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8.23%
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9.80%
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West Texas
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Amarillo
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9/1/03
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36,844
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9.88%
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12.00%
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Lubbock
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3/1/04
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43,300
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9.15%
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11.25%
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West Texas
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8/1/09
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124,401
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(2)
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9.60%
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8
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Bad
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Performance-
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Authorized Debt/
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Debt
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Based Rate
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Customer
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Division
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Jurisdiction
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Equity Ratio
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Rider(4)
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WNA
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Program(5)
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Meters
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Atmos Pipeline Texas
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Texas
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50/50
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No
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N/A
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N/A
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N/A
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Colorado-Kansas
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Colorado
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54/46
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No
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(7)
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No
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No
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111,382
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Kansas
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(2)
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Yes
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Yes
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No
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129,983
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Kentucky/Mid-States
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Georgia
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55/45
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No
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Yes
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Yes
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65,080
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Illinois
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67/33
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No
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No
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No
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22,623
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Iowa
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57/43
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No
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No
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No
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4,344
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|
|
Kentucky
|
|
(2)
|
|
|
No
|
(7)
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
175,789
|
|
|
|
Missouri
|
|
(2)
|
|
|
No
|
|
|
|
No
|
(6)
|
|
|
No
|
|
|
|
57,332
|
|
|
|
Tennessee
|
|
52/48
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
132,764
|
|
|
|
Virginia
|
|
55/45
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
23,182
|
|
Louisiana
|
|
Trans LA
|
|
52/48
|
|
|
No
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
78,345
|
|
|
|
LGS
|
|
52/48
|
|
|
No
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
277,648
|
|
Mid-Tex Settled Cities
|
|
Texas
|
|
52/48
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
1,227,598
|
|
Mid-Tex Dallas & Environs
|
|
Texas
|
|
52/48
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
306,899
|
|
Mississippi
|
|
Mississippi
|
|
47/53
|
|
|
No
|
(7)
|
|
|
Yes
|
|
|
|
No
|
|
|
|
266,785
|
|
West Texas
|
|
Amarillo
|
|
50/50
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
69,836
|
|
|
|
Lubbock
|
|
50/50
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
73,642
|
|
|
|
West Texas
|
|
52/48
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
155,612
|
|
|
|
|
(1) |
|
The rate base, authorized rate of return and authorized return
on equity presented in this table are those from the last rate
case or GRIP filing for each jurisdiction. These rate bases,
rates of return and returns on equity are not necessarily
indicative of current or future rate bases, rates of return or
returns on equity. |
|
(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 Mid-Tex Rate Base amounts for the Settled Cities and Dallas
and Environs both represent system-wide, or
100 percent, of the Mid-Tex Divisions rate base. The
difference in rate base amounts is due to two separate test
filing periods covered. |
|
(4) |
|
The bad debt rider allows us to recover from ratepayers the gas
cost portion of uncollectible accounts. |
|
(5) |
|
The performance-based rate program provides incentives to
natural gas utility companies to minimize purchased gas costs by
allowing the utility company and its customers to share the
purchased gas costs savings. |
|
(6) |
|
The Missouri jurisdiction has a straight-fixed variable rate
design which decouples gross profit margin from customer usage
patterns. |
|
(7) |
|
The Company has pending requests in Colorado, Kentucky and
Mississippi to move bad debt cost to the gas cost recovery
mechanism. A hearing regarding the Mississippi request was held
on September 1, 2009. |
9
Natural
Gas Distribution Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
METERS IN SERVICE, end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,901,577
|
|
|
|
2,911,475
|
|
|
|
2,893,543
|
|
|
|
2,886,042
|
|
|
|
2,862,822
|
|
Commercial
|
|
|
265,843
|
|
|
|
268,845
|
|
|
|
272,081
|
|
|
|
275,577
|
|
|
|
274,536
|
|
Industrial
|
|
|
2,193
|
|
|
|
2,241
|
|
|
|
2,339
|
|
|
|
2,661
|
|
|
|
2,715
|
|
Public authority and other
|
|
|
9,231
|
|
|
|
9,218
|
|
|
|
19,164
|
|
|
|
16,919
|
|
|
|
17,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total meters
|
|
|
3,178,844
|
|
|
|
3,191,779
|
|
|
|
3,187,127
|
|
|
|
3,181,199
|
|
|
|
3,157,840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
57.0
|
|
|
|
58.3
|
|
|
|
58.0
|
|
|
|
59.9
|
|
|
|
54.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEATING DEGREE
DAYS(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual (weighted average)
|
|
|
2,713
|
|
|
|
2,820
|
|
|
|
2,879
|
|
|
|
2,527
|
|
|
|
2,587
|
|
Percent of normal
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
87
|
%
|
|
|
89
|
%
|
SALES VOLUMES
MMcf(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
159,762
|
|
|
|
163,229
|
|
|
|
166,612
|
|
|
|
144,780
|
|
|
|
162,016
|
|
Commercial
|
|
|
91,379
|
|
|
|
93,953
|
|
|
|
95,514
|
|
|
|
87,006
|
|
|
|
92,401
|
|
Industrial
|
|
|
18,563
|
|
|
|
21,734
|
|
|
|
22,914
|
|
|
|
26,161
|
|
|
|
29,434
|
|
Public authority and other
|
|
|
12,413
|
|
|
|
13,760
|
|
|
|
12,287
|
|
|
|
14,086
|
|
|
|
12,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales volumes
|
|
|
282,117
|
|
|
|
292,676
|
|
|
|
297,327
|
|
|
|
272,033
|
|
|
|
296,283
|
|
Transportation volumes
|
|
|
130,691
|
|
|
|
141,083
|
|
|
|
135,109
|
|
|
|
126,960
|
|
|
|
122,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
412,808
|
|
|
|
433,759
|
|
|
|
432,436
|
|
|
|
398,993
|
|
|
|
418,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING REVENUES
(000s)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
1,830,140
|
|
|
$
|
2,131,447
|
|
|
$
|
1,982,801
|
|
|
$
|
2,068,736
|
|
|
$
|
1,791,172
|
|
Commercial
|
|
|
838,184
|
|
|
|
1,077,056
|
|
|
|
970,949
|
|
|
|
1,061,783
|
|
|
|
869,722
|
|
Industrial
|
|
|
135,633
|
|
|
|
212,531
|
|
|
|
195,060
|
|
|
|
276,186
|
|
|
|
229,649
|
|
Public authority and other
|
|
|
89,183
|
|
|
|
137,821
|
|
|
|
114,298
|
|
|
|
144,600
|
|
|
|
114,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales revenues
|
|
|
2,893,140
|
|
|
|
3,558,855
|
|
|
|
3,263,108
|
|
|
|
3,551,305
|
|
|
|
3,005,285
|
|
Transportation revenues
|
|
|
59,914
|
|
|
|
60,504
|
|
|
|
59,813
|
|
|
|
62,215
|
|
|
|
59,996
|
|
Other gas revenues
|
|
|
31,711
|
|
|
|
35,771
|
|
|
|
35,844
|
|
|
|
37,071
|
|
|
|
37,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
2,984,765
|
|
|
$
|
3,655,130
|
|
|
$
|
3,358,765
|
|
|
$
|
3,650,591
|
|
|
$
|
3,103,140
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average transportation revenue per Mcf
|
|
$
|
0.46
|
|
|
$
|
0.43
|
|
|
$
|
0.44
|
|
|
$
|
0.49
|
|
|
$
|
0.49
|
|
Average cost of gas per Mcf sold
|
|
$
|
6.95
|
|
|
$
|
9.05
|
|
|
$
|
8.09
|
|
|
$
|
10.02
|
|
|
$
|
7.41
|
|
Employees
|
|
|
4,691
|
|
|
|
4,558
|
|
|
|
4,472
|
|
|
|
4,402
|
|
|
|
4,327
|
|
See footnotes following these tables.
10
Natural
Gas Distribution Sales and Statistical Data By
Division
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30, 2009
|
|
|
|
|
|
|
Kentucky/
|
|
|
|
|
|
West
|
|
|
|
|
|
Colorado-
|
|
|
|
|
|
|
|
|
|
Mid-Tex
|
|
|
Mid-States
|
|
|
Louisiana
|
|
|
Texas
|
|
|
Mississippi
|
|
|
Kansas
|
|
|
Other(3)
|
|
|
Total
|
|
|
METERS IN SERVICE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
1,417,869
|
|
|
|
423,829
|
|
|
|
333,224
|
|
|
|
270,757
|
|
|
|
237,289
|
|
|
|
218,609
|
|
|
|
|
|
|
|
2,901,577
|
|
Commercial
|
|
|
116,480
|
|
|
|
53,386
|
|
|
|
22,769
|
|
|
|
24,986
|
|
|
|
26,142
|
|
|
|
22,080
|
|
|
|
|
|
|
|
265,843
|
|
Industrial
|
|
|
148
|
|
|
|
909
|
|
|
|
|
|
|
|
508
|
|
|
|
532
|
|
|
|
96
|
|
|
|
|
|
|
|
2,193
|
|
Public authority and other
|
|
|
|
|
|
|
2,555
|
|
|
|
|
|
|
|
2,839
|
|
|
|
2,822
|
|
|
|
1,015
|
|
|
|
|
|
|
|
9,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,534,497
|
|
|
|
480,679
|
|
|
|
355,993
|
|
|
|
299,090
|
|
|
|
266,785
|
|
|
|
241,800
|
|
|
|
|
|
|
|
3,178,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEATING DEGREE
DAYS(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
2,036
|
|
|
|
3,853
|
|
|
|
1,574
|
|
|
|
3,553
|
|
|
|
2,746
|
|
|
|
5,520
|
|
|
|
|
|
|
|
2,713
|
|
Percent of normal
|
|
|
100
|
%
|
|
|
98
|
%
|
|
|
101
|
%
|
|
|
99
|
%
|
|
|
103
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
100
|
%
|
SALES VOLUMES
MMcf(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
73,678
|
|
|
|
26,589
|
|
|
|
12,371
|
|
|
|
16,341
|
|
|
|
13,503
|
|
|
|
17,280
|
|
|
|
|
|
|
|
159,762
|
|
Commercial
|
|
|
48,363
|
|
|
|
16,049
|
|
|
|
6,771
|
|
|
|
6,780
|
|
|
|
6,568
|
|
|
|
6,848
|
|
|
|
|
|
|
|
91,379
|
|
Industrial
|
|
|
2,918
|
|
|
|
6,217
|
|
|
|
|
|
|
|
3,528
|
|
|
|
5,704
|
|
|
|
196
|
|
|
|
|
|
|
|
18,563
|
|
Public authority and other
|
|
|
|
|
|
|
1,434
|
|
|
|
|
|
|
|
6,014
|
|
|
|
2,901
|
|
|
|
2,064
|
|
|
|
|
|
|
|
12,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
124,959
|
|
|
|
50,289
|
|
|
|
19,142
|
|
|
|
32,663
|
|
|
|
28,676
|
|
|
|
26,388
|
|
|
|
|
|
|
|
282,117
|
|
Transportation volumes
|
|
|
44,991
|
|
|
|
41,693
|
|
|
|
5,151
|
|
|
|
23,417
|
|
|
|
4,968
|
|
|
|
10,471
|
|
|
|
|
|
|
|
130,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
169,950
|
|
|
|
91,982
|
|
|
|
24,293
|
|
|
|
56,080
|
|
|
|
33,644
|
|
|
|
36,859
|
|
|
|
|
|
|
|
412,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING MARGIN
(000s)(2)
|
|
$
|
483,155
|
|
|
$
|
163,602
|
|
|
$
|
118,021
|
|
|
$
|
89,982
|
|
|
$
|
91,680
|
|
|
$
|
78,188
|
|
|
$
|
|
|
|
$
|
1,024,628
|
|
OPERATING EXPENSES
(000s)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
$
|
150,978
|
|
|
$
|
68,823
|
|
|
$
|
41,956
|
|
|
$
|
35,126
|
|
|
$
|
43,642
|
|
|
$
|
32,935
|
|
|
$
|
(4,031
|
)
|
|
$
|
369,429
|
|
Depreciation and amortization
|
|
$
|
94,040
|
|
|
$
|
32,755
|
|
|
$
|
22,492
|
|
|
$
|
15,242
|
|
|
$
|
12,411
|
|
|
$
|
15,334
|
|
|
$
|
|
|
|
$
|
192,274
|
|
Taxes, other than income
|
|
$
|
108,412
|
|
|
$
|
13,261
|
|
|
$
|
9,629
|
|
|
$
|
15,863
|
|
|
$
|
13,925
|
|
|
$
|
8,222
|
|
|
$
|
|
|
|
$
|
169,312
|
|
Asset impairments
|
|
$
|
2,100
|
|
|
$
|
785
|
|
|
$
|
510
|
|
|
$
|
413
|
|
|
$
|
415
|
|
|
$
|
376
|
|
|
$
|
|
|
|
$
|
4,599
|
|
OPERATING INCOME
(000s)(2)
|
|
$
|
127,625
|
|
|
$
|
47,978
|
|
|
$
|
43,434
|
|
|
$
|
23,338
|
|
|
$
|
21,287
|
|
|
$
|
21,321
|
|
|
$
|
4,031
|
|
|
$
|
289,014
|
|
CAPITAL EXPENDITURES (000s)
|
|
$
|
173,201
|
|
|
$
|
57,943
|
|
|
$
|
42,626
|
|
|
$
|
33,960
|
|
|
$
|
22,173
|
|
|
$
|
24,726
|
|
|
$
|
24,871
|
|
|
$
|
379,500
|
|
PROPERTY, PLANT AND EQUIPMENT, NET (000s)
|
|
$
|
1,615,900
|
|
|
$
|
722,530
|
|
|
$
|
390,957
|
|
|
$
|
299,242
|
|
|
$
|
266,053
|
|
|
$
|
284,398
|
|
|
$
|
124,391
|
|
|
$
|
3,703,471
|
|
OTHER STATISTICS, at year end
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miles of pipe
|
|
|
28,996
|
|
|
|
12,158
|
|
|
|
8,321
|
|
|
|
7,702
|
|
|
|
6,540
|
|
|
|
7,162
|
|
|
|
|
|
|
|
70,879
|
|
Employees
|
|
|
1,585
|
|
|
|
605
|
|
|
|
446
|
|
|
|
352
|
|
|
|
389
|
|
|
|
290
|
|
|
|
1,024
|
|
|
|
4,691
|
|
See footnotes following these tables.
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30, 2008
|
|
|
|
|
|
|
Kentucky/
|
|
|
|
|
|
West
|
|
|
|
|
|
Colorado-
|
|
|
|
|
|
|
|
|
|
Mid-Tex
|
|
|
Mid-States
|
|
|
Louisiana
|
|
|
Texas
|
|
|
Mississippi
|
|
|
Kansas
|
|
|
Other(3)
|
|
|
Total
|
|
|
METERS IN SERVICE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
1,414,543
|
|
|
|
431,880
|
|
|
|
336,211
|
|
|
|
270,990
|
|
|
|
240,113
|
|
|
|
217,738
|
|
|
|
|
|
|
|
2,911,475
|
|
Commercial
|
|
|
117,022
|
|
|
|
54,538
|
|
|
|
23,059
|
|
|
|
25,226
|
|
|
|
27,219
|
|
|
|
21,781
|
|
|
|
|
|
|
|
268,845
|
|
Industrial
|
|
|
163
|
|
|
|
930
|
|
|
|
|
|
|
|
497
|
|
|
|
562
|
|
|
|
89
|
|
|
|
|
|
|
|
2,241
|
|
Public authority and other
|
|
|
|
|
|
|
2,563
|
|
|
|
|
|
|
|
2,888
|
|
|
|
2,822
|
|
|
|
945
|
|
|
|
|
|
|
|
9,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,531,728
|
|
|
|
489,911
|
|
|
|
359,270
|
|
|
|
299,601
|
|
|
|
270,716
|
|
|
|
240,553
|
|
|
|
|
|
|
|
3,191,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEATING DEGREE
DAYS(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
2,213
|
|
|
|
3,799
|
|
|
|
1,531
|
|
|
|
3,546
|
|
|
|
2,741
|
|
|
|
5,861
|
|
|
|
|
|
|
|
2,820
|
|
Percent of normal
|
|
|
99
|
%
|
|
|
96
|
%
|
|
|
99
|
%
|
|
|
99
|
%
|
|
|
101
|
%
|
|
|
105
|
%
|
|
|
|
|
|
|
100
|
%
|
SALES VOLUMES
MMcf(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
76,296
|
|
|
|
26,009
|
|
|
|
12,475
|
|
|
|
17,190
|
|
|
|
12,882
|
|
|
|
18,377
|
|
|
|
|
|
|
|
163,229
|
|
Commercial
|
|
|
50,348
|
|
|
|
15,731
|
|
|
|
6,858
|
|
|
|
7,162
|
|
|
|
6,590
|
|
|
|
7,264
|
|
|
|
|
|
|
|
93,953
|
|
Industrial
|
|
|
3,293
|
|
|
|
7,740
|
|
|
|
|
|
|
|
3,876
|
|
|
|
6,580
|
|
|
|
245
|
|
|
|
|
|
|
|
21,734
|
|
Public authority and other
|
|
|
|
|
|
|
1,419
|
|
|
|
|
|
|
|
6,933
|
|
|
|
3,013
|
|
|
|
2,395
|
|
|
|
|
|
|
|
13,760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
129,937
|
|
|
|
50,899
|
|
|
|
19,333
|
|
|
|
35,161
|
|
|
|
29,065
|
|
|
|
28,281
|
|
|
|
|
|
|
|
292,676
|
|
Transportation volumes
|
|
|
49,606
|
|
|
|
44,796
|
|
|
|
6,136
|
|
|
|
26,411
|
|
|
|
4,219
|
|
|
|
9,915
|
|
|
|
|
|
|
|
141,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
179,543
|
|
|
|
95,695
|
|
|
|
25,469
|
|
|
|
61,572
|
|
|
|
33,284
|
|
|
|
38,196
|
|
|
|
|
|
|
|
433,759
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING MARGIN
(000s)(2)
|
|
$
|
478,622
|
|
|
$
|
159,265
|
|
|
$
|
110,754
|
|
|
$
|
87,344
|
|
|
$
|
91,749
|
|
|
$
|
78,332
|
|
|
$
|
|
|
|
$
|
1,006,066
|
|
OPERATING EXPENSES
(000s)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
$
|
167,497
|
|
|
$
|
65,161
|
|
|
$
|
42,367
|
|
|
$
|
36,688
|
|
|
$
|
46,024
|
|
|
$
|
35,414
|
|
|
$
|
(3,907
|
)
|
|
$
|
389,244
|
|
Depreciation and amortization
|
|
$
|
84,202
|
|
|
$
|
30,574
|
|
|
$
|
21,193
|
|
|
$
|
14,781
|
|
|
$
|
11,752
|
|
|
$
|
14,703
|
|
|
$
|
|
|
|
$
|
177,205
|
|
Taxes, other than income
|
|
$
|
111,914
|
|
|
$
|
14,799
|
|
|
$
|
8,104
|
|
|
$
|
22,032
|
|
|
$
|
14,003
|
|
|
$
|
7,600
|
|
|
$
|
|
|
|
$
|
178,452
|
|
OPERATING INCOME
(000s)(2)
|
|
$
|
115,009
|
|
|
$
|
48,731
|
|
|
$
|
39,090
|
|
|
$
|
13,843
|
|
|
$
|
19,970
|
|
|
$
|
20,615
|
|
|
$
|
3,907
|
|
|
$
|
261,165
|
|
CAPITAL EXPENDITURES (000s)
|
|
$
|
178,409
|
|
|
$
|
59,274
|
|
|
$
|
46,674
|
|
|
$
|
34,354
|
|
|
$
|
22,590
|
|
|
$
|
20,331
|
|
|
$
|
24,910
|
|
|
$
|
386,542
|
|
PROPERTY, PLANT AND EQUIPMENT, NET (000s)
|
|
$
|
1,491,188
|
|
|
$
|
689,109
|
|
|
$
|
370,751
|
|
|
$
|
278,326
|
|
|
$
|
254,452
|
|
|
$
|
272,121
|
|
|
$
|
127,609
|
|
|
$
|
3,483,556
|
|
OTHER STATISTICS, at year end
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miles of pipe
|
|
|
28,697
|
|
|
|
12,104
|
|
|
|
8,277
|
|
|
|
14,697
|
|
|
|
6,537
|
|
|
|
7,150
|
|
|
|
|
|
|
|
77,462
|
|
Employees
|
|
|
1,506
|
|
|
|
635
|
|
|
|
427
|
|
|
|
342
|
|
|
|
393
|
|
|
|
281
|
|
|
|
974
|
|
|
|
4,558
|
|
Notes to preceding tables:
|
|
|
(1) |
|
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 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. |
|
(2) |
|
Sales volumes, revenues, operating margins, operating expense
and operating income reflect segment operations, including
intercompany sales and transportation amounts. |
|
(3) |
|
The Other column represents our shared services function, which
provides administrative and other support to the Company.
Certain costs incurred by this function are not allocated. |
Regulated
Transmission and Storage Segment Overview
Our regulated transmission and storage segment consists of the
regulated pipeline and storage operations of our Atmos
Pipeline Texas Division. This 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.
12
Lending services provide short-term interruptible loans of
natural gas from our pipeline to meet market demands. Gross
profit earned from our Mid-Tex Division and through certain
other transportation and storage services is subject to
traditional ratemaking governed by the RRC. However, Atmos
Pipeline Texas existing regulatory mechanisms
allow certain transportation and storage services to be provided
under market-based rates with minimal regulation.
These operations include 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.
Regulated
Transmission and Storage Sales and Statistical
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
CUSTOMERS, end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Industrial
|
|
|
68
|
|
|
|
62
|
|
|
|
65
|
|
|
|
67
|
|
|
|
66
|
|
Other
|
|
|
168
|
|
|
|
189
|
|
|
|
196
|
|
|
|
178
|
|
|
|
191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
236
|
|
|
|
251
|
|
|
|
261
|
|
|
|
245
|
|
|
|
257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PIPELINE TRANSPORTATION VOLUMES
MMcf(1)
|
|
|
706,132
|
|
|
|
782,876
|
|
|
|
699,006
|
|
|
|
581,272
|
|
|
|
554,452
|
|
OPERATING REVENUES
(000s)(1)
|
|
$
|
209,658
|
|
|
$
|
195,917
|
|
|
$
|
163,229
|
|
|
$
|
141,133
|
|
|
$
|
142,952
|
|
Employees, at year end
|
|
|
62
|
|
|
|
60
|
|
|
|
54
|
|
|
|
85
|
|
|
|
78
|
|
|
|
|
(1) |
|
Transportation volumes and operating revenues reflect segment
operations, including intercompany sales and transportation
amounts. |
Natural
Gas Marketing Segment Overview
Our natural gas marketing activities are conducted through Atmos
Energy Marketing (AEM), which is wholly-owned by Atmos Energy
Holdings, Inc. (AEH). AEH is a wholly-owned subsidiary of AEC
and operates primarily in the Midwest and Southeast areas of the
United States.
AEMs primary business is to aggregate and purchase gas
supply, arrange transportation and storage logistics and
ultimately deliver gas to customers at competitive prices. In
addition, AEM utilizes proprietary and customer-owned
transportation and storage assets to provide 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 financial instruments. AEM
serves most of its customers under contracts generally having
one to two year terms and sells natural gas to some of its
industrial customers on a delivered burner tip basis under
contract terms ranging from 30 days to two years. As a
result, AEMs margins arise from the types of commercial
transactions we have structured with our customers and our
ability to identify the lowest cost alternative among the
natural gas supplies, transportation and markets to which it has
access to serve those customers.
AEM also seeks to maximize, through asset optimization
activities, the economic value associated with the storage and
transportation capacity we own or control in our natural gas
distribution and natural gas marketing segments. We attempt to
meet this objective by engaging in natural gas storage
transactions in which we seek to find and profit through the
arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time. This
process involves purchasing physical natural gas, storing it in
the storage and transportation assets to which AEM has access
and selling financial instruments at advantageous prices to lock
in a gross profit margin.
13
Natural
Gas Marketing Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
CUSTOMERS, end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Industrial
|
|
|
631
|
|
|
|
624
|
|
|
|
677
|
|
|
|
679
|
|
|
|
559
|
|
Municipal
|
|
|
63
|
|
|
|
55
|
|
|
|
68
|
|
|
|
73
|
|
|
|
69
|
|
Other
|
|
|
321
|
|
|
|
312
|
|
|
|
281
|
|
|
|
289
|
|
|
|
211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,015
|
|
|
|
991
|
|
|
|
1,026
|
|
|
|
1,041
|
|
|
|
839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
17.0
|
|
|
|
11.0
|
|
|
|
19.3
|
|
|
|
15.3
|
|
|
|
8.2
|
|
NATURAL GAS MARKETING SALES VOLUMES
MMcf(1)
|
|
|
441,081
|
|
|
|
457,952
|
|
|
|
423,895
|
|
|
|
336,516
|
|
|
|
273,201
|
|
OPERATING REVENUES
(000s)(1)
|
|
$
|
2,336,847
|
|
|
$
|
4,287,862
|
|
|
$
|
3,151,330
|
|
|
$
|
3,156,524
|
|
|
$
|
2,106,278
|
|
|
|
|
(1) |
|
Sales volumes and operating revenues reflect segment operations,
including intercompany sales and transportation amounts. |
Pipeline,
Storage and Other Segment Overview
Our pipeline, storage and other segment primarily consists of
the operations of Atmos Pipeline and Storage, LLC (APS), which
is wholly-owned by AEH. APS is engaged in nonregulated
transmission, storage and natural gas gathering services. Its
primary asset is a proprietary 21 mile pipeline located in
New Orleans, Louisiana. It also owns or controls additional
pipeline and storage capacity including interests in underground
storage fields in Kentucky and Louisiana that are used to reduce
the need of our natural gas distribution divisions to contract
for pipeline capacity to meet customer demand during peak
periods.
APS primary business is to provide storage and
transportation services to our Louisiana and Kentucky/MidStates
regulated natural gas distribution divisions, to our natural gas
marketing segment and, on a more limited basis, to third
parties. APS earns transportation fees and storage demand
charges to aggregate and provide gas supply, provide access to
storage capacity and transport gas for these customers.
APS also engages in various asset optimization activities.
APS primary asset optimization activity involves the
administration of two asset management plans with regulated
affiliates of the Company. These arrangements provide APS the
opportunity to maximize the economic value associated with the
transportation and storage capacity assigned to these plans. APS
attempts to meet this objective through a variety of activities
including engaging in natural gas storage transactions and
utilizing excess asset capacity to find and profit through the
arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time. These
plans require APS to share a portion of the economic value
created by these activities with the regulated customers served
by these affiliates. These arrangements have been approved by
applicable state regulatory commissions and are subject to
annual regulatory review intended to ensure proper allocation of
economic value between our regulated customers and APS.
APS also seeks to maximize the economic value associated with
the storage and transportation capacity it owns or controls. We
attempt to meet this objective by engaging in natural gas
storage transactions in which we seek to find and profit through
the arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time. This
process involves purchasing physical natural gas, storing it in
the storage and transportation assets to which APS has access
and, in transactions involving storage capacity, selling
financial instruments at advantageous prices to lock in a gross
profit margin.
14
Pipeline,
Storage and Other Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
2009
|
|
2008
|
|
2007
|
|
2006
|
|
2005
|
|
OPERATING REVENUES
(000s)(1)
|
|
$
|
41,924
|
|
|
$
|
31,709
|
|
|
$
|
33,400
|
|
|
$
|
25,574
|
|
|
$
|
15,639
|
|
PIPELINE TRANSPORTATION VOLUMES
MMcf(1)
|
|
|
6,395
|
|
|
|
5,492
|
|
|
|
7,710
|
|
|
|
9,712
|
|
|
|
7,593
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
2.9
|
|
|
|
1.4
|
|
|
|
2.0
|
|
|
|
2.6
|
|
|
|
1.8
|
|
|
|
|
(1) |
|
Transportation volumes and operating revenues reflect segment
operations, including intercompany sales and transportation
amounts. |
Ratemaking
Activity
Overview
The method of determining regulated rates varies among the
states in which our natural gas distribution divisions operate.
The regulatory authorities have the responsibility of ensuring
that utilities in their jurisdictions operate in the best
interests of customers while providing utility companies the
opportunity to earn a reasonable return on their investment.
Generally, each regulatory authority reviews rate requests and
establishes a rate structure intended to generate revenue
sufficient to cover the costs of conducting business and to
provide a reasonable return on invested capital.
Our current rate strategy is to focus on reducing or eliminating
regulatory lag, obtaining adequate returns and providing stable,
predictable margins. Atmos Energy has annual ratemaking
mechanisms in place in three states that provide for an annual
rate review and adjustment to rates for approximately
68 percent of our customers. Additionally, we have WNA
mechanisms in eight states. These mechanisms work in tandem to
provide insulation from volatile margins, both for the Company
and our customers.
We will also continue to address various rate design changes,
including the recovery of bad debt gas costs, inclusion of other
taxes in gas costs and stratification of rates to benefit low
income households in future rate filings. These design changes
would address cost variations that are related to pass-through
energy costs beyond our control.
Although substantial progress has been made in recent years by
improving rate design across Atmos operating area,
potential changes in federal energy policy and adverse economic
conditions will necessitate continued vigilance by the Company
and our regulators in meeting the challenges presented by these
external factors.
15
Recent
Ratemaking Activity
Substantially all of our natural gas distribution revenues in
the fiscal years ended September 30, 2009, 2008 and 2007
were derived from sales at rates set by or subject to approval
by local or state authorities. Annual net operating income
increases resulting from ratemaking activity totaling
$54.4 million, $40.6 million, and $45.2 million
became effective in fiscal 2009, 2008 and 2007 as summarized
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual Increase (Decrease) to Operating
|
|
|
|
Income For the Fiscal Year Ended September 30
|
|
Rate Action
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Rate case filings
|
|
$
|
2,959
|
|
|
$
|
27,838
|
|
|
$
|
7,793
|
|
GRIP filings
|
|
|
11,443
|
|
|
|
8,101
|
|
|
|
25,624
|
|
Annual rate filing mechanisms
|
|
|
38,764
|
|
|
|
3,275
|
|
|
|
12,963
|
|
Other rate activity
|
|
|
1,237
|
|
|
|
1,424
|
|
|
|
(1,132
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
54,403
|
|
|
$
|
40,638
|
|
|
$
|
45,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additionally, the following ratemaking efforts were initiated
during fiscal 2009 but had not been completed as of
September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
Division
|
|
Rate Action
|
|
Jurisdiction
|
|
Requested
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
Rate
Case(1)
|
|
Dallas & Environs
|
|
$
|
7,743
|
|
Colorado/Kansas
|
|
Rate Case
|
|
Colorado
|
|
|
3,834
|
|
|
|
GSRS(2)
|
|
Kansas
|
|
|
766
|
|
Kentucky/Mid-States
|
|
Rate
Case(3)
|
|
Virginia
|
|
|
1,677
|
|
|
|
PRP
Surcharge(4)
|
|
Georgia
|
|
|
909
|
|
West Texas
|
|
Rate Review
Mechanism(5)
|
|
Lubbock
|
|
|
3,476
|
|
|
|
Rate Review
Mechanism(5)
|
|
Amarillo
|
|
|
2,285
|
|
Mississippi
|
|
Stable Rate Filing
|
|
Mississippi
|
|
|
10,195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
30,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Texas Railroad Commission Examiners issued a proposal for
decision (PFD) on October 9, 2009. The PFD recommended a
rate change of $3.5 million applicable to the Dallas and
Environs area of the Mid-Tex system. The Company has filed
exceptions to the Examiners proposal. A final Commission
decision is expected before the end of the year. |
|
(2) |
|
Gas System Reliability Surcharge (GSRS) relates to safety
related investments made since the previous rate case. |
|
(3) |
|
The Company filed a Rate Case with the state of Virginia
requesting a $1.7 million increase. The staff has
recommended an increase of $1.4 million. |
|
(4) |
|
The Pipeline Replacement Program (PRP) surcharge relates to a
long-term cast iron replacement program. |
|
(5) |
|
The Company filed Rate Review Mechanisms with the City of
Lubbock requesting an increase of $3.5 million and with the
City of Amarillo requesting an increase of $2.3 million.
Effective October 1, 2009, the respective cities have
approved increases of $2.7 million and $1.3 million. |
In October 2009, we filed rate cases in Georgia and Kentucky,
requesting an increase in operating income of $3.8 million
and $9.5 million.
16
Our recent ratemaking activity is discussed in greater detail
below.
Rate
Case Filings
A rate case is a formal request from Atmos Energy to a
regulatory authority to increase rates that are charged to
customers. Rate cases may also be initiated when the regulatory
authorities request us to justify our rates. This process is
referred to as a show cause action. Adequate rates
are intended to provide for recovery of the Companys costs
as well as a fair rate of return to our shareholders and ensure
that we continue to deliver reliable, reasonably priced natural
gas service to our customers. The following table summarizes our
recent rate cases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) in
|
|
|
Effective
|
|
Division
|
|
State
|
|
Annual Operating Income
|
|
|
Date
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
2009 Rate Case Filings:
|
|
|
|
|
|
|
|
|
|
|
Kentucky/Mid-States
|
|
Tennessee
|
|
$
|
2,513
|
|
|
|
4/1/09
|
|
West Texas
|
|
Texas
|
|
|
446
|
|
|
|
Various
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2009 Rate Case Filings
|
|
|
|
$
|
2,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Rate Case Filings:
|
|
|
|
|
|
|
|
|
|
|
Kentucky/Mid-States
|
|
Virginia
|
|
$
|
869
|
|
|
|
9/30/08
|
|
Kentucky/Mid-States
|
|
Georgia
|
|
|
3,351
|
|
|
|
9/22/08
|
|
Mid-Tex(1)
|
|
Texas
|
|
|
5,430
|
|
|
|
6/24/08
|
|
Colorado-Kansas
|
|
Kansas
|
|
|
2,100
|
|
|
|
5/12/08
|
|
Mid-Tex(2)
|
|
Texas
|
|
|
8,000
|
|
|
|
4/1/08
|
|
Kentucky/Mid-States
|
|
Tennessee
|
|
|
8,088
|
|
|
|
11/4/07
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2008 Rate Case Filings
|
|
|
|
$
|
27,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Rate Case Filings:
|
|
|
|
|
|
|
|
|
|
|
Kentucky/Mid-States
|
|
Kentucky(3)
|
|
$
|
6,200
|
|
|
|
8/1/07
|
|
Mid-Tex
|
|
Texas(4)
|
|
|
4,793
|
|
|
|
4/1/07
|
|
Kentucky/Mid-States
|
|
Missouri(5)
|
|
|
1,500
|
|
|
|
3/4/07
|
|
Kentucky/Mid-States
|
|
Tennessee
|
|
|
(4,700
|
)
|
|
|
12/15/06
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2007 Rate Case Filings
|
|
|
|
$
|
7,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Increase relates only to the City of Dallas and Environs areas
of the Mid-Tex Division. |
|
(2) |
|
Increase relates only to the Settled Cities area of the Mid-Tex
Division. |
|
(3) |
|
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. In June 2007, the KPSC issued an order
dismissing the case. In December 2006, the Company filed a rate
application for an increase in base rates. Additionally, we
proposed to implement a process to review our rates annually and
to collect the bad debt portion of gas costs directly rather
than through the base rate. In July 2007, the KPSC approved a
settlement we had reached with the Attorney General for an
increase in annual operating income of $6.2 million
effective August 1, 2007. |
|
(4) |
|
In March 2007, the RRC issued an order, which increased the
Mid-Tex Divisions annual operating income by approximately
$4.8 million beginning April 2007 and established a
permanent WNA based on
10-year
average weather effective for the months of November through
April of each year. The RRC also approved a cost allocation
method that eliminated a subsidy received from industrial and
transportation customers and increased the revenue
responsibility for residential and commercial customers.
However, the order also required an immediate refund of amounts
collected from our 2003 2005 GRIP filings of
approximately |
17
|
|
|
|
|
$2.9 million and reduced our total return to
7.903 percent from 8.258 percent, based on a capital
structure of 48.1 percent equity and 51.9 percent debt
with a return on equity of 10 percent. |
|
(5) |
|
The Missouri Commission issued an order in March 2007 approving
a settlement with rate design changes, including revenue
decoupling through the recovery of all non-gas cost revenues
through fixed monthly charges and an estimated increase in
operating income of $1.5 million. |
GRIP
Filings
As discussed above in Natural Gas Distribution Segment
Overview, GRIP allows natural gas utility companies the
opportunity to include in their rate base annually approved
capital costs incurred in the prior calendar year. The following
table summarizes our GRIP filings with effective dates during
the fiscal years ended September 30, 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
Incremental Net
|
|
|
Annual
|
|
|
|
|
|
|
|
Utility Plant
|
|
|
Operating
|
|
|
Effective
|
Division
|
|
Calendar Year
|
|
Investment
|
|
|
Income
|
|
|
Date
|
|
|
|
|
(In thousands)
|
|
|
(In thousands)
|
|
|
|
|
2009 GRIP:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Tex(1)
|
|
2007
|
|
$
|
57,385
|
|
|
$
|
1,837
|
|
|
1/26/09
|
West
Texas(2)
|
|
2007/08
|
|
|
27,425
|
|
|
|
532
|
|
|
Various
|
Atmos Pipeline Texas
|
|
2008
|
|
|
51,308
|
|
|
|
6,342
|
|
|
4/28/09
|
Mid-Tex(3)
|
|
2008
|
|
|
105,777
|
|
|
|
2,732
|
|
|
9/9/09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2009 GRIP
|
|
|
|
$
|
241,895
|
|
|
$
|
11,443
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 GRIP:
|
|
|
|
|
|
|
|
|
|
|
|
|
Atmos Pipeline Texas
|
|
2007
|
|
$
|
46,648
|
|
|
$
|
6,970
|
|
|
4/15/08
|
West Texas
|
|
2006
|
|
|
7,022
|
|
|
|
1,131
|
|
|
12/17/07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2008 GRIP
|
|
|
|
$
|
53,670
|
|
|
$
|
8,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 GRIP:
|
|
|
|
|
|
|
|
|
|
|
|
|
Atmos Pipeline Texas
|
|
2006
|
|
$
|
88,938
|
|
|
$
|
13,202
|
|
|
9/14/07
|
Mid-Tex
|
|
2006
|
|
|
62,375
|
|
|
|
12,422
|
|
|
9/14/07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2007 GRIP
|
|
|
|
$
|
151,313
|
|
|
$
|
25,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Increase relates to the City of Dallas and Environs areas of the
Mid-Tex Division. |
|
(2) |
|
The West Texas Division files GRIP applications related only to
the Lubbock Environs and the West Texas Cities Environs. GRIP
implemented for this division include investments that related
to both calendar years 2007 and 2008. The incremental investment
is based on system-wide plant and additional annual operating
income is applicable to Environs customers only. |
|
(3) |
|
Increase relates only to the City of Dallas area of the Mid-Tex
Division. |
Annual
Rate Filing Mechanisms
As an instrument to reduce regulatory lag, annual rate filing
mechanisms allow us to refresh our rates on a periodic basis
without filing a formal rate case. However, these filings still
involve discovery by the appropriate regulatory authorities
prior to the final determination of rates under these
mechanisms. As discussed above in Natural Gas Distribution
Segment Overview, we currently have annual rate filing
mechanisms in our Louisiana and Mississippi divisions and in
significant portions of our Mid-Tex and West Texas divisions.
These mechanisms are referred to as rate review mechanisms in
our Mid-Tex and West Texas
18
divisions, stable rate filings in the Mississippi Division and
rate stabilization clause in the Louisiana Division. The
following table summarizes filings made under our various annual
rate filing mechanisms:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Effective
|
|
Division
|
|
Jurisdiction
|
|
Test Year Ended
|
|
|
Income
|
|
|
Date
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
2009 Filings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana
|
|
LGS
|
|
|
12/31/08
|
|
|
$
|
3,307
|
|
|
|
7/1/09
|
|
Louisiana
|
|
Transla
|
|
|
9/30/08
|
|
|
|
611
|
|
|
|
4/1/09
|
|
Mississippi
|
|
Mississippi
|
|
|
6/30/08
|
|
|
|
|
|
|
|
N/A
|
|
Mid-Tex
|
|
Settled Cities
|
|
|
12/31/07
|
|
|
|
21,800
|
|
|
|
11/8/08
|
|
Mid-Tex
|
|
Settled Cities
|
|
|
12/31/08
|
|
|
|
1,979
|
|
|
|
8/1/09
|
|
West Texas
|
|
WT Cities
|
|
|
12/31/07
|
|
|
|
4,468
|
|
|
|
11/20/08
|
|
West Texas
|
|
WT Cities
|
|
|
12/31/08
|
|
|
|
6,599
|
|
|
|
8/1/09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2009 Filings
|
|
|
|
|
|
|
|
$
|
38,764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Filings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana
|
|
LGS
|
|
|
12/31/07
|
|
|
$
|
1,709
|
|
|
|
7/1/08
|
|
Louisiana
|
|
Transla
|
|
|
9/30/07
|
|
|
|
1,566
|
|
|
|
4/1/08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2008 Filings
|
|
|
|
|
|
|
|
$
|
3,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Filings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi
|
|
Mississippi
|
|
|
6/30/07
|
|
|
$
|
|
|
|
|
11/1/07
|
|
Louisiana
|
|
LGS
|
|
|
12/31/06
|
|
|
|
2,000
|
|
|
|
7/1/07
|
|
Louisiana
|
|
Transla
|
|
|
9/30/06
|
|
|
|
1,445
|
|
|
|
4/1/07
|
|
Louisiana
|
|
LGS
|
|
|
12/31/05
|
|
|
|
9,518
|
|
|
|
8/1/06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2007 Filings
|
|
|
|
|
|
|
|
$
|
12,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The rate review mechanism in the Mid-Tex Division was entered
into as a result of a settlement in the September 20, 2007
Statement of Intent case filed with all Mid-Tex Division cities.
Of the 439 incorporated cities served by the Mid-Tex Division,
438 of these cities are part of the rate review mechanism
process. The West Texas rate review mechanism was entered into
in August 2008 as a result of a settlement with the West Texas
Coalition of Cities. The Lubbock and Amarillo rate review
mechanisms were entered into in the spring of 2009. All
mechanisms have been implemented on a three year trial period,
of which three began in fiscal 2009, based upon calendar 2007
financial information and two of which began in fiscal 2009
based on 2008 financial information. The third rate review
mechanism in the Mid-Tex Division will be filed in March 2010
based upon calendar 2009 financial information. This filing will
be the last filing under the three year trial period.
19
Other
Ratemaking Activity
The following table summarizes other ratemaking activity during
the fiscal years ended September 30, 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
|
|
|
|
|
|
|
|
|
|
(Decrease) in
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Effective
|
Division
|
|
Jurisdiction
|
|
Rate Activity
|
|
Income
|
|
|
Date
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
2009 Other Rate Activity:
|
|
|
|
|
|
|
|
|
|
|
Kentucky/Mid-States
|
|
Georgia
|
|
PRP
Surcharge(1)
|
|
$
|
198
|
|
|
10/1/08
|
|
|
Missouri
|
|
ISRS(2)
|
|
|
408
|
|
|
11/4/08
|
Colorado-Kansas
|
|
Kansas
|
|
Tax
Surcharge(3)
|
|
|
631
|
|
|
2/1/09
|
|
|
|
|
|
|
|
|
|
|
|
Total 2009 Other Rate Activity
|
|
|
|
|
|
$
|
1,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Other Rate Activity:
|
|
|
|
|
|
|
|
|
|
|
West Texas
|
|
Triangle
|
|
Special Contract
|
|
$
|
748
|
|
|
6/1/08
|
Colorado-Kansas
|
|
Kansas
|
|
Tax
Surcharge(3)
|
|
|
1,434
|
|
|
1/1/08
|
|
|
Colorado
|
|
Agreement(4)
|
|
|
(1,100
|
)
|
|
11/20/07
|
Kentucky/Mid-States
|
|
Georgia
|
|
PRP
Surcharge(1)
|
|
|
342
|
|
|
10/1/07
|
|
|
|
|
|
|
|
|
|
|
|
Total 2008 Other Rate Activity
|
|
|
|
|
|
$
|
1,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Other Rate Activity:
|
|
|
|
|
|
|
|
|
|
|
West Texas
|
|
Triangle
|
|
Special Contract
|
|
$
|
227
|
|
|
7/1/07
|
Mid-Tex
|
|
Texas
|
|
GRIP Refund
|
|
|
(2,887
|
)
|
|
4/1/07
|
Colorado-Kansas
|
|
Kansas
|
|
Tax
Surcharge(3)
|
|
|
1,528
|
|
|
1/1/07
|
|
|
|
|
|
|
|
|
|
|
|
Total 2007 Other Rate Activity
|
|
|
|
|
|
$
|
(1,132
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Pipeline Replacement Program (PRP) surcharge relates to a
long-term cast iron replacement program. |
|
(2) |
|
Infrastructure System Replacement Surcharge (ISRS) relates to
maintenance capital investments made since the previous rate
case. |
|
(3) |
|
In the State of Kansas, the tax surcharge represents a
true-up of
ad valorem taxes paid versus what is designed to be recovered
through base rates. |
|
(4) |
|
In November 2007, the Colorado Public Utilities Commission
approved an earnings agreement entered into jointly between the
Colorado-Kansas Division, the Commission Staff and the Office of
Consumer Counsel. The agreement called for a one-time refund to
customers of $1.1 million made in January 2008. |
In May 2007, our Mid-Tex Division filed for a
36-month gas
contract review filing. This filing was mandated by prior RRC
orders and related to the prudency of gas purchases made from
November 2003 through October 2006, which total approximately
$2.7 billion. In February 2009, the RRC approved the
Hearing Examiners recommendation to disallow no gas costs.
In March 2009, the RRC established a procedural schedule in GUD
9696 to examine the
36-month gas
contract review process. In August 2009, the full Commission
approved an order to eliminate the 36 month gas contract
review at its August 2009 meeting.
Other
Regulation
Each of our natural gas distribution 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. In
addition, 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
20
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.
The Federal Energy Regulatory Commission (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.
Additionally, the FERC has regulatory authority over the sale of
natural gas in the wholesale gas market and the use and release
of interstate pipeline and storage capacity, as well as
authority to detect and prevent market manipulation and to
enforce compliance with FERCs other rules, policies and
orders by companies engaged in the sale, purchase,
transportation or storage of natural gas in interstate commerce.
We have taken what we believe are all necessary and appropriate
steps to comply with these regulations.
In September 2008, the RRC issued a final rule requiring the
replacement of known compression couplings at pre-bent gas meter
risers by November 2009. This rule primarily affected the
operations of the Mid-Tex Division. Compliance with this rule
has required us to expend significant amounts of capital in the
Mid-Tex Division, but these prudent and mandatory expenditures
have been recoverable through our rates. As of
September 30, 2009 we had substantially completed our
pre-bent riser replacement program in the Mid-Tex Division.
Competition
Although our natural gas distribution 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 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, and
natural gas historically has maintained its price advantage in
the residential, commercial and industrial markets. However,
periods of higher gas prices, coupled with the electric
utilities marketing efforts, increase competition for
residential and commercial customers. In addition, AEM competes
with other natural gas marketers to provide natural gas
management and other related services to customers.
Our regulated transmission 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.
Employees
At September 30, 2009, we had 4,891 employees,
consisting of 4,753 employees in our regulated operations
and 138 employees in our nonregulated operations.
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, and other
forms that we file with or furnish to the Securities and
Exchange Commission (SEC) are available free of charge at our
website, www.atmosenergy.com, under Publications
and Filings under the Investors tab, 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 and telephone number
appearing below:
Shareholder Relations
Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas
75265-0205
972-855-3729
21
Corporate
Governance
In accordance with and pursuant to relevant related rules and
regulations of the SEC as well as corporate governance-related
listing standards of the New York Stock Exchange (NYSE), the
Board of Directors of the Company has established and
periodically updated our Corporate Governance Guidelines and
Code of Conduct, which is applicable to all directors, officers
and employees of the Company. In addition, in accordance with
and pursuant to such NYSE listing standards, our Chief Executive
Officer, Robert W. Best, has certified to the New York Stock
Exchange that he was not aware of any violation by the Company
of NYSE corporate governance listing standards. The Board of
Directors also annually reviews and updates, if necessary, 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 our
website. We will also provide copies of all corporate governance
documents free of charge upon request to Shareholder Relations
at the address listed above.
Our financial and operating results are subject to a number of
risk factors, many of which are not within our control. Although
we have tried to discuss key risk factors below, please be aware
that other or new risks may prove to be important in the future.
Investors should carefully consider the following discussion of
risk factors as well as other information appearing in this
report. These factors include the following:
Further
disruptions in the credit markets could limit our ability to
access capital and increase our costs of capital.
We rely upon access to both short-term and long-term credit
markets to satisfy our liquidity requirements. The global credit
markets have experienced significant disruptions and volatility
during the last two years to a greater degree than has been seen
in decades. In some cases, the ability or willingness of
traditional sources of capital to provide financing has been
reduced.
Historically, we have accessed the commercial paper markets to
finance our short-term working capital needs. The disruptions in
the credit markets during the fall of 2008 temporarily limited
our access to the commercial paper markets and increased our
borrowing costs. Consequently, for a short period, we were
forced to borrow directly under our primary credit facility that
backstops our commercial paper program to provide much of our
working capital. This credit facility provides up to
$567 million in committed financing through its expiration
in December 2011. Our borrowings under this facility, along with
our commercial paper, have been used primarily to purchase
natural gas supplies for the upcoming winter heating season. The
amount of our working capital requirements in the near-term will
depend primarily on the market price of natural gas. Higher
natural gas prices may adversely impact our accounts receivable
collections and may require us to increase borrowings under our
credit facilities to fund our operations. The cost of both our
borrowings under the primary credit facility and our commercial
paper has increased significantly since September 2008. We have
historically supplemented our commercial paper program with a
short-term committed credit facility that must be renewed
annually. No borrowings are currently outstanding under our
current $200 million short-term facility, which matures in
October 2010.
Our long-term debt is currently rated as investment
grade by Standard & Poors Corporation,
Moodys Investors Services, Inc. and Fitch Ratings, Ltd. If
adverse credit conditions were to cause a significant limitation
on our access to the private and public credit markets, we could
see a reduction in our liquidity. A significant reduction in our
liquidity could in turn trigger a negative change in our ratings
outlook or even a reduction in our credit ratings by one or more
of the three credit rating agencies. Such a downgrade could
further limit our access to public
and/or
private credit markets and increase the costs of borrowing under
each source of credit.
Further, if our credit ratings were downgraded, we could be
required to provide additional liquidity to our natural gas
marketing segment because the commodity financial instruments
markets could become unavailable to us. Our natural gas
marketing segment depends primarily upon a committed
$450 million credit facility to finance its working capital
needs, which it uses primarily to issue standby letters of
credit to its natural gas
22
suppliers. A significant reduction in the availability of this
facility could require us to provide extra liquidity to support
its operations or reduce some of the activities of our natural
gas marketing segment. Our ability to provide extra liquidity is
limited by the terms of our existing lending arrangements with
AEH, which are subject to annual approval by one state
regulatory commission.
While we believe we can meet our capital requirements from our
operations and the sources of financing available to us, we can
provide no assurance that we will continue to be able to do so
in the future, especially if the market price of natural gas
increases significantly in the near-term. The future effects on
our business, liquidity and financial results of a further
deterioration of current conditions in the credit markets could
be material and adverse to us, both in the ways described above
or in other ways that we do not currently anticipate.
The
continuation of recent economic conditions could adversely
affect our customers and negatively impact our financial
results.
The slowdown in the U.S. economy, together with increased
mortgage defaults and significant decreases in the values of
homes and investment assets, has adversely affected the
financial resources of many domestic households. It is unclear
whether the administrative and legislative responses to these
conditions will be successful in ending the current recession,
including the lowering of current high unemployment rates across
the U.S. As a result, our customers may seek to use even
less gas and it may become more difficult for them to pay their
gas bills. This may slow collections and lead to higher than
normal levels of accounts receivable. This in turn could
increase our financing requirements and bad debt expense.
The
costs of providing pension and postretirement health care
benefits and related funding requirements are subject to changes
in pension fund values, changing demographics and fluctuating
actuarial assumptions and may have a material adverse effect on
our financial results.
We provide a cash-balance pension plan and postretirement
healthcare benefits to eligible full-time employees. Our costs
of providing such benefits and related funding requirements are
subject to changes in the market value of the assets funding our
pension and postretirement healthcare plans. The fluctuations
over the last two years in the values of investments that fund
our pension and postretirement healthcare plans may
significantly differ from or alter the values and actuarial
assumptions we use to calculate our future pension plan expense
and postretirement healthcare costs and funding requirements
under the Pension Protection Act. Any significant declines in
the value of these investments could increase the expenses of
our pension and postretirement healthcare plans and related
funding requirements in the future. Our costs of providing such
benefits and related funding requirements are also subject to
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, as well as
various actuarial calculations and assumptions, which may differ
materially from actual results due to changing market and
economic conditions, higher or lower withdrawal rates and
interest rates and other factors.
Our
operations are exposed to market risks that are beyond our
control which could adversely affect our financial results and
capital requirements.
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,
storage and other 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 the end of any
particular trading day requires us to make assumptions as to
future circumstances, including the use of gas by our customers
in relation to our anticipated
23
storage and market positions. Because the price risk associated
with any net open position at the end of such 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 usually do not 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, storage and other segments.
Our natural gas marketing and pipeline, storage and other
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 instruments. 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. Further
tightening of the credit markets could cause more of our
counterparties to fail to perform than expected. 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. These circumstances could also increase our capital
requirements.
We are also subject to interest rate risk on our borrowings. In
recent 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 historical interest
rates. However, increases in interest rates could adversely
affect our future financial results.
We are
subject to state and local regulations that affect our
operations and financial results.
Our natural gas distribution and regulated transmission and
storage segments are subject to various regulated returns on our
rate base in each jurisdiction 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
business in the regulatory environment, assets may be placed in
service and historical test periods established before rate
cases can be filed that could result in an adjustment of our
allowed returns. 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. Rate cases also
involve a risk of rate reduction, because once rates have been
approved, they are still subject to challenge for their
reasonableness by appropriate regulatory authorities. In
addition, regulators may review our purchases of natural gas and
can adjust the amount of our gas costs that we pass through to
our customers. Finally, our debt and equity financings are also
subject to approval by regulatory commissions in several states,
which could limit our ability to access or take advantage of
changes in the capital markets.
Some
of our operations are subject to increased federal regulatory
oversight that could affect our operations and financial
results.
FERC has regulatory authority that affects some of our
operations, including sales of natural gas in the wholesale gas
market and the use and release of interstate pipeline and
storage capacity. Under legislation passed by Congress in 2005,
FERC has adopted rules designed to prevent market power abuse
and market manipulation and to promote compliance with
FERCs other rules, policies and orders by companies
engaged in the sale, purchase, transportation or storage of
natural gas in interstate commerce. These rules carry increased
penalties for violations. We are currently under investigation
by FERC for possible violations of its posting and competitive
bidding regulations for pre-arranged released firm capacity on
interstate natural gas
24
pipelines. Should FERC conclude that we have committed such
violations of its regulations and levies substantial fines
and/or
penalties against us, our business, financial condition or
financial results could be adversely affected. In addition,
although we have taken steps to structure current and future
transactions to comply with applicable current FERC regulations,
changes in FERC regulations or their interpretation by FERC or
additional regulations issued by FERC in the future could also
adversely affect our business, financial condition or financial
results.
We are
subject to environmental regulations 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.
Our
business may be subject in the future to additional regulatory
and financial risks associated with global warming and climate
change.
There are a number of new federal and state legislative and
regulatory initiatives being proposed and adopted in an attempt
to control or limit the effects of global warming and overall
climate change, including greenhouse gas emissions, such as
carbon dioxide. For example, in June 2009, the U.S. House
of Representatives approved The American Clean Energy and
Security Act of 2009, also known as the Waxman-Markey bill
or cap and trade bill. The legislation, which
strives to promote energy efficiency in the United States and
reduce the amount of greenhouse gases produced, has implications
for the natural gas industry. The bill, if adopted, would
accelerate significantly the reduction in energy use per
customer through a number of measures, including a dramatic
tightening of building and appliance codes and other practices
designed to put an increased focus on building and appliance
efficiency. According to the bill, overall nationwide energy
savings would total 75 percent by the year 2030 as a result
of adopting its provisions. If adopted, the Waxman-Markey bill
would establish a phased-in greenhouse gas emission
cap-and-trade
program that would reduce overall greenhouse gas emissions from
capped sources by 17 percent by 2020 compared to emissions
from such sources in 2005. These caps would be postponed on
natural gas residential and commercial customers until 2016.
Subsequent to the adoption by the House of this bill, a similar
bill was introduced in the U.S. Senate, entitled the
Clean Energy Jobs and American Power Act, also known as
the Kerry-Boxer bill. At this time, the Kerry-Boxer bill is
awaiting Senate action. The adoption of this legislation by
Congress or similar legislation by states or the adoption of
related regulations by federal or state governments mandating a
substantial reduction in greenhouse gas emissions could have
far-reaching and significant impacts on the energy industry.
Such new legislation or regulations could result in increased
compliance costs for us or additional operating restrictions on
our business, affect the demand for natural gas or impact the
prices we charge to our customers. At this time, we cannot
predict the potential impact of such laws or regulations on our
future business, financial condition or financial results.
The
concentration of our distribution, pipeline and storage
operations in the State of Texas exposes our operations and
financial results to economic conditions and regulatory
decisions in Texas.
Over 50 percent of our natural gas distribution customers
and most of our pipeline and storage assets and operations are
located in the State of Texas. This concentration of our
business in Texas means that our operations and financial
results may be significantly affected by changes in the Texas
economy in general and regulatory decisions by state and local
regulatory authorities in Texas.
25
Adverse
weather conditions could affect our operations or financial
results.
Since the
2006-2007
winter heating season, we have had weather-normalized rates for
over 90 percent of our residential and commercial meters,
which has substantially mitigated the adverse effects of
warmer-than-normal
weather for meters in those service areas. However, there is no
assurance that we will continue to receive such regulatory
protection from adverse weather in our rates in the future. The
loss of such weather normalized rates could have an
adverse effect on our operations and financial results. In
addition, our natural gas distribution and regulated
transmission and storage operating results may continue to vary
somewhat with the actual temperatures during the winter heating
season. 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.
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
natural gas distribution 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 impact future financial results.
Rapid increases in the costs of purchased gas would cause us to
experience a significant increase in short-term debt. 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
natural gas distribution 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
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 enable us to adequately serve any
significant amount of additional 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 generally are sufficient to supply funding for
all our capital expenditures, including the financing of the
costs of new construction along with capital expenditures
necessary to maintain our existing natural gas system. Due to
the timing of these cash flows and capital expenditures, we
often must fund at least a portion of these costs through
borrowing funds from third party lenders, the cost and
availability of which is dependent on the liquidity of the
credit markets, interest rates and other market conditions. This
in turn may limit our ability to connect new customers to our
system due to constraints on the amount of funds we can invest
in our infrastructure.
Our
operations are subject to increased competition.
In residential and commercial customer markets, our natural gas
distribution 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, reducing
our 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, 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 regulated transmission and
26
storage segment currently faces 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.
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 operations or financial results could be
adversely affected.
Natural
disasters, terrorist activities or other significant events
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 our operations or
financial results.
|
|
ITEM 1B.
|
Unresolved
Staff Comments.
|
Not applicable.
Distribution,
transmission and related assets
At September 30, 2009, our natural gas distribution segment
owned an aggregate of 70,879 miles of underground
distribution and transmission mains throughout our gas
distribution systems. These mains are located on easements or
rights-of-way
which generally provide for perpetual use. We maintain our mains
through a program of continuous inspection and repair and
believe that our system of mains is in good condition. Our
regulated transmission and storage segment owned
5,950 miles of gas transmission and gathering lines and our
pipeline, storage and other segment owned 113 miles of gas
transmission and gathering lines.
27
Storage
Assets
We 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)
|
|
|
Natural Gas Distribution Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky
|
|
|
4,442,696
|
|
|
|
6,322,283
|
|
|
|
10,764,979
|
|
|
|
109,100
|
|
Kansas
|
|
|
3,239,000
|
|
|
|
2,300,000
|
|
|
|
5,539,000
|
|
|
|
45,000
|
|
Mississippi
|
|
|
2,211,894
|
|
|
|
2,442,917
|
|
|
|
4,654,811
|
|
|
|
48,000
|
|
Georgia
|
|
|
490,000
|
|
|
|
10,000
|
|
|
|
500,000
|
|
|
|
30,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
10,383,590
|
|
|
|
11,075,200
|
|
|
|
21,458,790
|
|
|
|
232,100
|
|
Regulated Transmission and Storage Segment
Texas
|
|
|
39,243,226
|
|
|
|
13,128,025
|
|
|
|
52,371,251
|
|
|
|
1,235,000
|
|
Pipeline, Storage and Other Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky
|
|
|
3,492,900
|
|
|
|
3,295,000
|
|
|
|
6,787,900
|
|
|
|
71,000
|
|
Louisiana
|
|
|
438,583
|
|
|
|
300,973
|
|
|
|
739,556
|
|
|
|
56,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3,931,483
|
|
|
|
3,595,973
|
|
|
|
7,527,456
|
|
|
|
127,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
53,558,299
|
|
|
|
27,799,198
|
|
|
|
81,357,497
|
|
|
|
1,594,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cushion gas represents the volume of gas that must be retained
in a facility to maintain reservoir pressure. |
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
|
|
Segment
|
|
Division/Company
|
|
(MMBtu)
|
|
|
(MMBtu)(1)
|
|
|
Natural Gas Distribution Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Colorado-Kansas Division
|
|
|
3,237,243
|
|
|
|
97,832
|
|
|
|
Kentucky/Mid-States Division
|
|
|
18,497,006
|
|
|
|
348,290
|
|
|
|
Louisiana Division
|
|
|
2,574,479
|
|
|
|
158,731
|
|
|
|
Mississippi Division
|
|
|
3,875,429
|
|
|
|
165,402
|
|
|
|
West Texas Division
|
|
|
1,225,000
|
|
|
|
56,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
29,409,157
|
|
|
|
826,255
|
|
Natural Gas Marketing Segment
|
|
Atmos Energy Marketing, LLC
|
|
|
9,539,053
|
|
|
|
278,417
|
|
Pipeline, Storage and Other Segment
|
|
Trans Louisiana Gas Pipeline, Inc.
|
|
|
1,674,000
|
|
|
|
67,507
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contracted Storage Capacity
|
|
|
40,622,210
|
|
|
|
1,172,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
28
Other
facilities
Our natural gas distribution 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 and corporate headquarters 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
nonregulated operations are headquartered in Houston, Texas,
with offices in Houston and other locations, primarily in leased
facilities.
|
|
ITEM 3.
|
Legal
Proceedings.
|
See Note 12 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 2009.
29
EXECUTIVE
OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of
September 30, 2009, 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
|
|
|
62
|
|
|
|
12
|
|
|
Chairman and Chief Executive Officer
|
Kim R. Cocklin
|
|
|
58
|
|
|
|
3
|
|
|
President and Chief Operating Officer
|
Louis P. Gregory
|
|
|
54
|
|
|
|
9
|
|
|
Senior Vice President and General Counsel
|
Michael E. Haefner
|
|
|
49
|
|
|
|
1
|
|
|
Senior Vice President, Human Resources
|
Mark H. Johnson
|
|
|
50
|
|
|
|
8
|
|
|
Senior Vice President, Nonregulated Operations and President,
Atmos Energy Marketing, LLC
|
Fred E. Meisenheimer
|
|
|
65
|
|
|
|
9
|
|
|
Senior Vice President and Chief Financial Officer
|
Robert W. Best was named Chairman of the Board, President and
Chief Executive Officer in March 1997. Since October 1,
2008, Mr. Best has continued to serve the Company as
Chairman of the Board and Chief Executive Officer.
Kim R. Cocklin joined the Company in June 2006 as Senior Vice
President, Regulated Operations. On October 1, 2008,
Mr. Cocklin was named President and Chief Operating
Officer. On November 10, 2009, Mr. Cocklin was elected
to the Board of Directors. 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.
Louis P. Gregory was named Senior Vice President and General
Counsel in September 2000.
Michael E. Haefner joined the Company in June 2008 as Senior
Vice President, Human Resources. Prior to joining the Company,
Mr. Haefner was a self-employed consultant and founder and
president of Perform for Life, LLC from May 2007 to May 2008.
Mr. Haefner previously served for 10 years as the
Senior Vice President, Human Resources, of Sabre Holding
Corporation, the parent company of Sabre Airline Solutions,
Sabre Travel Network and Travelocity.
Mark H. Johnson was named Senior Vice President, Nonregulated
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 left his position
with the Company to pursue other interests, effective
October 31, 2009.
Fred E. Meisenheimer was named Senior Vice President and Chief
Financial Officer in February 2009. Mr. Meisenheimer
previously served the Company as Vice President and Controller
from July 2000 through May 2009 and also served as interim Chief
Financial Officer beginning in January 2009.
30
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 2009 and
2008 are listed below. The high and low prices listed are the
closing NYSE quotes, as reported on the NYSE composite tape, for
shares of our common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
High
|
|
|
Low
|
|
|
paid
|
|
|
High
|
|
|
Low
|
|
|
Paid
|
|
|
Quarter ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
$
|
27.88
|
|
|
$
|
21.17
|
|
|
$
|
.330
|
|
|
$
|
29.46
|
|
|
$
|
26.11
|
|
|
$
|
.325
|
|
March 31
|
|
|
25.95
|
|
|
|
20.20
|
|
|
|
.330
|
|
|
|
28.96
|
|
|
|
25.09
|
|
|
|
.325
|
|
June 30
|
|
|
26.37
|
|
|
|
22.81
|
|
|
|
.330
|
|
|
|
28.54
|
|
|
|
25.81
|
|
|
|
.325
|
|
September 30
|
|
|
28.80
|
|
|
|
24.65
|
|
|
|
.330
|
|
|
|
28.25
|
|
|
|
25.49
|
|
|
|
.325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.32
|
|
|
|
|
|
|
|
|
|
|
$
|
1.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends are payable at the discretion of our Board of
Directors out of legally available funds. 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, 2009 was 20,824. 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 2009 that were not registered under the Securities Act of
1933, as amended.
31
Performance
Graph
The performance graph and table below compares the yearly
percentage change in our total return to shareholders for the
last five fiscal years with the total return of the Standard and
Poors 500 Stock Index and the cumulative total return of
two different customized peer company groups, the New Comparison
Company Index and the Old Comparison Company Index. The New
Comparison Company Index includes National Fuel Gas and excludes
Questar Corporation because the Board of Directors determined
that National Fuel Gas better fits the profile of the companies
in the peer group, which is comprised of natural gas
distribution companies with similar revenues, market
capitalizations and asset bases to that of the Company. The
graph and table below assume that $100.00 was invested on
September 30, 2004 in our common stock, the S&P 500
Index and in the common stock of the companies in the New and
Old Comparison Company Indexes, as well as a reinvestment of
dividends paid on such investments throughout the period.
Comparison
of Five-Year Cumulative Total Return
among Atmos Energy Corporation, S&P 500 Index
and Comparison Company Indices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative Total Return
|
|
|
9/30/04
|
|
9/30/05
|
|
9/30/06
|
|
9/30/07
|
|
9/30/08
|
|
9/30/09
|
|
Atmos Energy Corporation
|
|
|
100.00
|
|
|
|
117.33
|
|
|
|
124.23
|
|
|
|
128.40
|
|
|
|
126.62
|
|
|
|
141.40
|
|
S&P 500 Index
|
|
|
100.00
|
|
|
|
112.25
|
|
|
|
124.37
|
|
|
|
144.81
|
|
|
|
112.99
|
|
|
|
105.18
|
|
New Comparison Company Index
|
|
|
100.00
|
|
|
|
131.99
|
|
|
|
130.72
|
|
|
|
152.32
|
|
|
|
134.96
|
|
|
|
136.40
|
|
Old Comparison Company Index
|
|
|
100.00
|
|
|
|
140.50
|
|
|
|
136.86
|
|
|
|
160.95
|
|
|
|
139.13
|
|
|
|
137.43
|
|
The New Comparison Company Index contains a hybrid group of
utility companies, primarily natural gas distribution companies,
recommended by a global management consulting firm and approved
by the Board of Directors. The companies included in the index
are AGL Resources Inc., CenterPoint Energy Resources
Corporation, CMS Energy Corporation, EQT Corporation (formerly
known as Equitable Resources, Inc.), Integrys Energy Group,
Inc., National Fuel Gas, Nicor Inc., NiSource Inc., ONEOK Inc.,
Piedmont Natural Gas Company, Inc., Vectren Corporation and WGL
Holdings, Inc. The Old Comparison Company Index includes the
companies listed above in the New Comparison Company Index with
the exception of National Fuel Gas, which replaced Questar
Corporation in the Companys peer group in the current year
for the reasons discussed above.
32
The following table sets forth the number of securities
authorized for issuance under our equity compensation plans at
September 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
1998 Long-Term Incentive Plan
|
|
|
611,227
|
|
|
$
|
21.88
|
|
|
|
1,473,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity compensation plans approved by security
holders
|
|
|
611,227
|
|
|
|
21.88
|
|
|
|
1,473,531
|
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
611,227
|
|
|
$
|
21.88
|
|
|
|
1,473,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009(1)
|
|
|
2008
|
|
|
2007(1)
|
|
|
2006(1)
|
|
|
2005
|
|
|
|
(In thousands, except per share data and ratios)
|
|
|
Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
4,969,080
|
|
|
$
|
7,221,305
|
|
|
$
|
5,898,431
|
|
|
$
|
6,152,363
|
|
|
$
|
4,961,873
|
|
Gross profit
|
|
|
1,346,702
|
|
|
|
1,321,326
|
|
|
|
1,250,082
|
|
|
|
1,216,570
|
|
|
|
1,117,637
|
|
Operating
expenses(1)
|
|
|
899,300
|
|
|
|
893,431
|
|
|
|
851,446
|
|
|
|
833,954
|
|
|
|
768,982
|
|
Operating income
|
|
|
447,402
|
|
|
|
427,895
|
|
|
|
398,636
|
|
|
|
382,616
|
|
|
|
348,655
|
|
Miscellaneous income (expense)
|
|
|
(3,303
|
)
|
|
|
2,731
|
|
|
|
9,184
|
|
|
|
881
|
|
|
|
2,021
|
|
Interest charges
|
|
|
152,830
|
|
|
|
137,922
|
|
|
|
145,236
|
|
|
|
146,607
|
|
|
|
132,658
|
|
Income before income taxes
|
|
|
291,269
|
|
|
|
292,704
|
|
|
|
262,584
|
|
|
|
236,890
|
|
|
|
218,018
|
|
Income tax expense
|
|
|
100,291
|
|
|
|
112,373
|
|
|
|
94,092
|
|
|
|
89,153
|
|
|
|
82,233
|
|
Net income
|
|
$
|
190,978
|
|
|
$
|
180,331
|
|
|
$
|
168,492
|
|
|
$
|
147,737
|
|
|
$
|
135,785
|
|
Weighted average diluted shares outstanding
|
|
|
92,024
|
|
|
|
90,272
|
|
|
|
87,745
|
|
|
|
81,390
|
|
|
|
79,012
|
|
Diluted net income per share
|
|
$
|
2.08
|
|
|
$
|
2.00
|
|
|
$
|
1.92
|
|
|
$
|
1.82
|
|
|
$
|
1.72
|
|
Cash flows from operations
|
|
$
|
919,233
|
|
|
$
|
370,933
|
|
|
$
|
547,095
|
|
|
$
|
311,449
|
|
|
$
|
386,944
|
|
Cash dividends paid per share
|
|
$
|
1.32
|
|
|
$
|
1.30
|
|
|
$
|
1.28
|
|
|
$
|
1.26
|
|
|
$
|
1.24
|
|
Total natural gas distribution throughput
(MMcf)(2)
|
|
|
408,885
|
|
|
|
429,354
|
|
|
|
427,869
|
|
|
|
393,995
|
|
|
|
411,134
|
|
Total regulated transmission and storage transportation volumes
(MMcf)(2)
|
|
|
528,689
|
|
|
|
595,542
|
|
|
|
505,493
|
|
|
|
410,505
|
|
|
|
373,879
|
|
Total natural gas marketing sales volumes
(MMcf)(2)
|
|
|
370,569
|
|
|
|
389,392
|
|
|
|
370,668
|
|
|
|
283,962
|
|
|
|
238,097
|
|
Financial Condition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
4,439,103
|
|
|
$
|
4,136,859
|
|
|
$
|
3,836,836
|
|
|
$
|
3,629,156
|
|
|
$
|
3,374,367
|
|
Working capital
|
|
|
91,519
|
|
|
|
78,017
|
|
|
|
149,217
|
|
|
|
(1,616
|
)
|
|
|
151,675
|
|
Total assets
|
|
|
6,343,766
|
|
|
|
6,386,699
|
|
|
|
5,895,197
|
|
|
|
5,719,547
|
|
|
|
5,610,547
|
|
Short-term debt, inclusive of current maturities of long-term
debt
|
|
|
72,681
|
|
|
|
351,327
|
|
|
|
154,430
|
|
|
|
385,602
|
|
|
|
148,073
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
|
2,176,761
|
|
|
|
2,052,492
|
|
|
|
1,965,754
|
|
|
|
1,648,098
|
|
|
|
1,602,422
|
|
Long-term debt (excluding current maturities)
|
|
|
2,169,400
|
|
|
|
2,119,792
|
|
|
|
2,126,315
|
|
|
|
2,180,362
|
|
|
|
2,183,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,346,161
|
|
|
|
4,172,284
|
|
|
|
4,092,069
|
|
|
|
3,828,460
|
|
|
|
3,785,526
|
|
Capital expenditures
|
|
|
509,494
|
|
|
|
472,273
|
|
|
|
392,435
|
|
|
|
425,324
|
|
|
|
333,183
|
|
Financial Ratios
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
ratio(3)
|
|
|
49.3
|
%
|
|
|
45.4
|
%
|
|
|
46.3
|
%
|
|
|
39.1
|
%
|
|
|
40.7
|
%
|
Return on average shareholders
equity(4)
|
|
|
8.9
|
%
|
|
|
8.8
|
%
|
|
|
8.8
|
%
|
|
|
8.9
|
%
|
|
|
9.0
|
%
|
|
|
|
(1) |
|
Financial results for 2009, 2007 and 2006 include a
$5.4 million, $6.3 million and a $22.9 million
pre-tax loss for the impairment of certain assets. |
|
(2) |
|
Net of intersegment eliminations |
|
(3) |
|
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. |
|
(4) |
|
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. |
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.
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: our ability to continue to access the credit markets
to satisfy our liquidity requirements; the impact of recent
economic conditions on our customers; increased costs of
providing pension and postretirement health care benefits and
increased funding requirements; market risks beyond our control
affecting our risk management activities including market
liquidity, commodity price volatility, increasing interest rates
and counterparty creditworthiness; regulatory trends and
decisions, including the impact of rate proceedings before
various state regulatory commissions; increased federal
regulatory oversight and potential penalties; the impact of
environmental regulations on our business; the possible impact
of future additional regulatory and financial risks associated
with global warming and climate change; the concentration of our
distribution, pipeline and storage operations in Texas; adverse
weather conditions; the effects of inflation and changes in the
availability and price of natural gas; the capital-intensive
nature of our gas distribution business; increased competition
from energy suppliers and alternative forms of energy; the
inherent hazards and risks involved in operating our gas
distribution business, natural disasters, terrorist activities
or other events, and other risks and uncertainties discussed
herein, especially those discussed 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.
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
35
our estimates, including those related to risk management and
trading activities, fair value measurements, allowance for
doubtful accounts, legal and environmental accruals, insurance
accruals, pension and postretirement obligations, deferred
income taxes and 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.
Regulation Our natural gas distribution and
regulated transmission and storage 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. We
meet the criteria established within accounting principles
generally accepted in the United States of a cost-based,
rate-regulated entity, which requires us to reflect the
financial effects of the ratemaking and accounting practices and
policies of the various regulatory commissions in our financial
statements in accordance with applicable authoritative
accounting standards. We apply the provisions of this standard
to our regulated operations and record regulatory assets for
costs that have been deferred for which future recovery through
customer rates is considered probable and regulatory liabilities
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 or deferred on the
balance sheet because it is probable they can be recovered
through rates. Discontinuing the application of this method of
accounting for regulatory assets and liabilities could
significantly increase our operating expenses as fewer costs
would likely be capitalized or deferred on the balance sheet,
which could reduce our net income. 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 regulated operations may be
affected by decisions of the regulatory authorities or the
issuance of new regulations.
Revenue recognition Sales of natural gas to
our natural gas distribution customers are billed on a monthly
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 natural gas distribution
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 regulatory authorities, which
are subject to refund. 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 costs through
purchased gas cost adjustment mechanisms. Purchased gas cost
adjustment mechanisms provide gas utility companies a method of
recovering purchased gas costs on an ongoing basis without
filing a rate case to address all of the utility companys
non-gas costs. These mechanisms are commonly utilized when
regulatory authorities recognize a particular type of cost, such
as purchased gas costs, that (i) is subject to significant
price fluctuations compared to the utility companys other
costs, (ii) represents a large component of the utility
companys cost of service and (iii) is generally
outside the control of the gas utility company. There is no
gross profit generated through purchased gas cost adjustments,
but they provide a
dollar-for-dollar
offset to increases or decreases in utility gas costs. Although
substantially all natural gas distribution sales to our
customers fluctuate with the cost of gas that we purchase, our
gross profit is generally not affected by fluctuations in the
cost of gas as a result of the purchased gas cost adjustment
mechanism. The effects of these purchased gas cost adjustment
mechanisms are recorded as deferred gas costs on our balance
sheet.
Operating revenues for our regulated transmission and storage
and pipeline, storage and other segments are recognized in the
period in which actual volumes are transported and storage
services are provided.
Operating revenues for our natural gas marketing segment and the
associated carrying value of natural gas inventory (inclusive of
storage costs) are recognized when we sell the gas and
physically deliver it to our customers. Operating revenues
include realized gains and losses arising from the settlement of
financial
36
instruments used in our natural gas marketing activities and
unrealized gains and losses arising from changes in the fair
value of natural gas inventory designated as a hedged item in a
fair value hedge and the associated financial instruments.
Allowance for doubtful accounts Accounts
receivable arise from natural gas sales to residential,
commercial, industrial, municipal 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 affected.
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.
Financial instruments and hedging activities
We currently use financial instruments to
mitigate commodity price risk. Additionally, we periodically use
financial instruments to manage interest rate risk. The
objectives and strategies for using financial instruments have
been tailored to meet the needs of our regulated and
nonregulated businesses.
We record all of our financial instruments on the balance sheet
at fair value as required by accounting principles generally
accepted in the United States, with changes in fair value
ultimately recorded in the income statement. The timing of when
changes in fair value of our financial instruments are recorded
in the income statement depends on whether the financial
instrument has been designated and qualifies as a part of a
hedging relationship or if regulatory rulings require a
different accounting treatment. Changes in fair value for
financial instruments that do not meet one of these criteria are
recognized in the income statement as they occur.
Financial
Instruments Associated with Commodity Price Risk
In our natural gas distribution segment, our customers are
exposed to the effect of volatile natural gas prices. We manage
this exposure through a combination of physical storage,
fixed-price forward contracts and financial instruments,
primarily
over-the-counter
swap and option contracts, in an effort to minimize the impact
of natural gas price volatility on our customers during the
winter heating season. The costs associated with and the gains
and losses arising from the use of financial instruments to
mitigate commodity price risk in this segment are included in
our purchased gas adjustment mechanisms in accordance with
regulatory requirements. Therefore, changes in the fair value of
these financial instruments are initially recorded as a
component of deferred gas costs and recognized in the
consolidated statement of income as a component of purchased gas
cost when the related costs are recovered through our rates and
recognized in revenue in accordance with accounting principles
generally accepted in the United States. Accordingly, there is
no earnings impact to our natural gas distribution segment as a
result of the use of financial instruments.
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. We also perform asset optimization
activities in both our natural gas marketing segment and
pipeline, storage and other segment. As a result of these
activities, our nonregulated operations are exposed to risks
associated with changes in the market price of natural gas. We
manage our exposure to the risk of natural gas price changes
through a combination of physical storage and financial
instruments, including futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties.
In our natural gas marketing and pipeline, storage and other
segments, we have designated the natural gas inventory held by
these operating segments as the hedged item in a fair-value
hedge. This inventory is marked to market at the end of each
month based on the Gas Daily index, with changes in fair value
recognized as unrealized gains or losses in revenue in the
period of change. The financial instruments associated with this
natural gas inventory have been designated as fair-value hedges
and are marked to market each month based upon the NYMEX price
with changes in fair value recognized as unrealized gains or
losses in revenue in the period of change. Changes in the
spreads between the forward natural gas prices used to value the
financial instruments designated against our physical inventory
(NYMEX) and the market (spot) prices used to value
37
our physical storage (Gas Daily) result in unrealized margins
until the underlying physical gas is withdrawn and the related
financial instruments are settled. The difference in the spot
price used to value our physical inventory and the forward price
used to value the related financial instruments can result in
volatility in our reported income as a component of unrealized
margins. We have elected to exclude this spot/forward
differential for purposes of assessing the effectiveness of
these fair-value hedges. Once the gas is withdrawn and the
financial instruments are settled, the previously unrealized
margins associated with these net positions are realized. 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 have elected to treat fixed-price forward contracts used in
our natural gas marketing segment to deliver gas as normal
purchases and normal sales. As such, these deliveries are
recorded on an accrual basis in accordance with our revenue
recognition policy. Financial instruments used to mitigate the
commodity price risk associated with these contracts have been
designated as cash flow hedges of anticipated purchases and
sales at indexed prices. Accordingly, unrealized gains and
losses on open financial instruments are 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.
We also use storage swaps and futures to capture additional
storage arbitrage opportunities in our natural gas marketing
segment that arise after 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. These financial instruments have
not been designated as hedges.
Financial
Instruments Associated with Interest Rate Risk
We periodically manage interest rate risk, typically when we
issue new or refinance existing long-term debt. As of
September 30, 2009, we had no financial instruments in
place to manage interest rate risk. However, in prior years, we
entered into Treasury lock agreements to fix the Treasury yield
component of the interest cost associated with anticipated
financings. We designated these Treasury lock agreements as a
cash flow hedge of an anticipated transaction at the time the
agreements were executed. Accordingly, unrealized gains and
losses associated with the Treasury lock agreements were
recorded as a component of accumulated other comprehensive
income (loss). The realized gain or loss recognized upon
settlement of each Treasury lock agreement was initially
recorded as a component of accumulated other comprehensive
income (loss) and is recognized as a component of interest
expense over the life of the related financing arrangement.
Impairment assessments We perform impairment
assessments of our goodwill, intangible assets subject to
amortization and long-lived assets. As of September 30,
2009, we had 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 natural gas
distribution divisions and wholly-owned subsidiaries and
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 annually assess whether the cost of our intangible assets
subject to amortization or other long-lived assets is
recoverable or that the remaining useful lives may warrant
revision. We perform this assessment more frequently when
specific events or circumstances have occurred that suggest the
recoverability of the cost of the intangible and other
long-lived assets is at risk.
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 from the
38
operating division or subsidiary to which these assets relate.
These cash flow projections consider various factors such as the
timing of the future cash flows and the discount rate and are
based upon the best information available at the time the
estimate is made. Changes in these factors could materially
affect the cash flow projections and result in the recognition
of an impairment charge. An impairment charge is recognized as
the difference between the carrying amount and the fair value if
the sum of the undiscounted cash flows is less than the carrying
value of the related asset.
Pension and other postretirement plans
Pension and other postretirement plan 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. Prior to fiscal 2009, we reviewed the estimates
and assumptions underlying our pension and other postretirement
plan costs and liabilities annually based upon a June 30
measurement date. Effective October 1, 2008, we changed our
measurement date to September 30. 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
obligations and net pension and postretirement costs. When
establishing our discount rate, we consider high quality
corporate bond rates, 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 costs. 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 costs are
not affected. Rather, this gain or loss reduces or increases
future pension or postretirement plan costs 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 costs ultimately recognized. A
0.25 percent change in our discount rate would impact our
pension and postretirement costs by approximately
$0.8 million. A 0.25 percent change in our expected
rate of return would impact our pension and postretirement costs
by approximately $0.9 million.
Fair Value Measurements We report certain
assets and liabilities at fair value, which is defined as the
price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). We primarily
use quoted market prices and other observable market pricing
information in valuing our financial assets and liabilities and
minimize the use of unobservable pricing inputs in our
measurements.
Prices actively quoted on national exchanges are used to
determine the fair value of most of our assets and liabilities
recorded on our balance sheet at fair value. Within our
nonregulated operations, we utilize a mid-market pricing
convention (the mid-point between the bid and ask prices) as a
practical expedient for determining fair value measurement, as
permitted under current accounting standards. Values derived
from these sources reflect the market in which transactions
involving these financial instruments are executed. We
39
utilize models and other valuation methods to determine fair
value when external sources are not available. 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. We believe the market
prices and models used to value these assets and liabilities
represent the best information available with respect to closing
exchange and
over-the-counter
quotations, time value and volatility factors underlying the
assets and liabilities.
Fair-value estimates also consider our own creditworthiness and
the creditworthiness of the counterparties involved. Our
counterparties consist primarily of financial institutions and
major energy companies. This concentration of counterparties may
materially impact our exposure to credit risk resulting from
market, economic or regulatory conditions. Recent adverse
developments in the global financial and credit markets have
made it more difficult and more expensive for companies to
access the short-term capital markets, which may negatively
impact the creditworthiness of our counterparties. A continued
tightening of the credit markets could cause more of our
counterparties to fail to perform. We seek to minimize
counterparty credit risk through an evaluation of their
financial condition and credit ratings and the use of collateral
requirements under certain circumstances.
Amounts reported at fair value are subject to potentially
significant volatility based upon 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
financial instruments. We believe the market prices and models
used to value these financial instruments 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.
RESULTS
OF OPERATIONS
Overview
Atmos Energy Corporation is involved in the distribution,
marketing and transportation of natural gas. Accordingly, our
results of operations are impacted by the demand for natural
gas, particularly during the winter heating season, and the
volatility of the natural gas markets. This generally results in
higher operating revenues and net income during the period from
October through March of each fiscal year and lower operating
revenues and either lower net income or net losses during the
period from April through September of each fiscal year. As a
result of the seasonality of the natural gas industry, 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, the seasonality of our business impacts our
working capital differently at various times during the year.
Typically, our accounts receivable, accounts payable and
short-term debt balances peak by the end of January and then
start to decline, as customers begin to pay their winter heating
bills. Gas stored underground, particularly in our natural gas
distribution segment, typically peaks in November and declines
as we utilize storage gas to serve our customers.
During the current year, several external factors have impacted
Atmos Energy, including, but not limited to, adverse
developments in the global and financial credit markets and the
unfavorable impact of the economic recession.
The tightening of the credit markets has made it more difficult
and more expensive for us to access the capital markets.
However, during the fiscal year, we took several steps to
improve our financial position. In March 2009, we successfully
completed an offering of $450 million 8.5% senior
notes, and used most of the proceeds in April 2009 to redeem
$400 million of senior notes that were scheduled to mature
in October 2009. Additionally, we enhanced our liquidity sources
in various ways. In October 2008, we replaced our former
$300 million
364-day
committed credit facility with a new
364-day
$212.5 million committed credit facility. Then, in October
2009, we replaced the $212.5 million
364-day
committed credit facility with a new
364-day
$200 million committed credit facility. We also converted
AEMs former $580 million uncommitted credit
40
facility to a
364-day
$375 million committed credit facility in December 2008.
This facility was subsequently increased to $450 million in
April 2009. Finally, in April 2009 we replaced an expiring
$18 million unsecured committed credit facility with a
$25 million unsecured committed credit facility. After
entering into these new facilities, we currently have a total of
approximately $902.0 million available to us under four
committed credit facilities. As a result of these developments
and our continued successful financial performance,
Standard & Poors Corporation (S&P) upgraded
our credit rating from BBB to BBB+ in December 2008 and
Moodys Investors Service (Moodys) upgraded the
credit rating on our senior long-term debt from Baa3 to Baa2 and
our commercial paper from
P-3 to
P-2 in May
2009. These ratings upgrades have improved our ability to access
the short-term capital markets to satisfy our liquidity
requirements on more economical terms.
However, the turmoil in the financial markets did also have a
direct financial impact on our results of operations. We
determined that the decline in fair value for certain
available-for-sale
securities in our Supplemental Executive Benefit Plans
experienced during the year ended September 30, 2009 was
other than temporary and, accordingly, recorded a
$5.4 million noncash charge to impair the assets. As a
result of these impairments, we do not maintain any investments
that are in an unrealized loss position.
Finally, challenging economic times resulted in a general
decline in throughput across most of our business segments. The
impact of the economic downturn is most apparent in a general
decline in throughput. Our natural gas distribution segment has
experienced a
year-over-year
5 percent decrease in consolidated throughput, primarily
associated with lower residential, commercial and industrial
consumption. Declines in the demand for natural gas as a result
of idle production and plant closures have contributed to an
11 percent
year-over-year
decrease in consolidated throughput in our regulated
transmission and storage segment and a 5 percent
year-over-year
decrease in consolidated sales volumes in our natural gas
marketing segment. However, recent improvements in rate design
in our natural gas distribution segment and the ability to earn
higher
per-unit
margins in our regulated transmission and storage and natural
gas marketing segments has more than offset the decline in
throughput and sales volumes. Additionally, reduced demand for
natural gas has resulted in lower natural gas prices, which has
contributed significantly to the increase in our operating cash
flow.
Consolidated
Results
The following table presents our consolidated financial
highlights for the fiscal years ended September 30, 2009,
2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Operating revenues
|
|
$
|
4,969,080
|
|
|
$
|
7,221,305
|
|
|
$
|
5,898,431
|
|
Gross profit
|
|
|
1,346,702
|
|
|
|
1,321,326
|
|
|
|
1,250,082
|
|
Operating expenses
|
|
|
899,300
|
|
|
|
893,431
|
|
|
|
851,446
|
|
Operating income
|
|
|
447,402
|
|
|
|
427,895
|
|
|
|
398,636
|
|
Miscellaneous income (expense)
|
|
|
(3,303
|
)
|
|
|
2,731
|
|
|
|
9,184
|
|
Interest charges
|
|
|
152,830
|
|
|
|
137,922
|
|
|
|
145,236
|
|
Income before income taxes
|
|
|
291,269
|
|
|
|
292,704
|
|
|
|
262,584
|
|
Income tax expense
|
|
|
100,291
|
|
|
|
112,373
|
|
|
|
94,092
|
|
Net income
|
|
$
|
190,978
|
|
|
$
|
180,331
|
|
|
$
|
168,492
|
|
Earnings per diluted share
|
|
$
|
2.08
|
|
|
$
|
2.00
|
|
|
$
|
1.92
|
|
Historically, our regulated operations arising from our natural
gas distribution and regulated transmission and storage
operations contributed 65 to 85 percent of our consolidated
net income. Regulated operations contributed 83 percent,
74 percent and 64 percent to our consolidated net
income for fiscal years 2009, 2008,
41
and 2007. Our consolidated net income during the last three
fiscal years was earned across our business segments as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
116,807
|
|
|
$
|
92,648
|
|
|
$
|
73,283
|
|
Regulated transmission and storage segment
|
|
|
41,056
|
|
|
|
41,425
|
|
|
|
34,590
|
|
Natural gas marketing segment
|
|
|
20,194
|
|
|
|
29,989
|
|
|
|
45,769
|
|
Pipeline, storage and other segment
|
|
|
12,921
|
|
|
|
16,269
|
|
|
|
14,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
190,978
|
|
|
$
|
180,331
|
|
|
$
|
168,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table segregates our consolidated net income and
diluted earnings per share between our regulated and
nonregulated operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
157,863
|
|
|
$
|
134,073
|
|
|
$
|
107,873
|
|
Nonregulated operations
|
|
|
33,115
|
|
|
|
46,258
|
|
|
|
60,619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
190,978
|
|
|
$
|
180,331
|
|
|
$
|
168,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
1.72
|
|
|
$
|
1.49
|
|
|
$
|
1.23
|
|
Diluted EPS from nonregulated operations
|
|
|
0.36
|
|
|
|
0.51
|
|
|
|
0.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
2.08
|
|
|
$
|
2.00
|
|
|
$
|
1.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income during fiscal 2009 increased six percent over fiscal
2008. Net income from our regulated operations increased
18 percent during fiscal 2009. The increase primarily
reflects a $32.3 million increase in gross profit resulting
from the net favorable impact of various ratemaking activities
in our natural gas distribution segment, partially offset by
higher depreciation expense, pipeline maintenance costs and
interest expense. Net income in our nonregulated operations
decreased $13.1 million, primarily due to the impact of
unrealized margins. Unrealized margins totaled
$35.9 million which reduced earnings per share by $0.23 per
diluted share. The overall increase in consolidated net income
was also favorably affected by non-recurring items totaling
$17.1 million, or $0.19 per diluted share, related to the
following pre-tax amounts:
|
|
|
|
|
$11.3 million related to a favorable one-time tax benefit
|
|
|
|
$7.6 million related to the favorable impact of an update
to the estimate for unbilled accounts
|
|
|
|
$7.0 million favorable impact of the reversal of estimated
uncollectible gas costs
|
|
|
|
$5.4 million unfavorable impact of a non-cash impairment
charge of $5.4 million related to
available-for-sale
securities in our Supplemental Executive Retirement Plan
|
Net income during fiscal 2008 increased seven percent over
fiscal 2007. Net income from our regulated operations increased
24 percent during fiscal 2008. The increase primarily
reflects a $53.8 million increase in gross profit resulting
from our ratemaking efforts, coupled with higher
per-unit
transportation margins and an 18 percent increase in
consolidated throughput in our Atmos Pipeline Texas
Division. These increases were partially offset by a four
percent increase in operating expenses. Net income in our
nonregulated operations experienced a 24 percent decline as
less volatile natural gas market conditions significantly
reduced our asset optimization margins. However, higher
delivered gas margins in our natural gas marketing segment and
unrealized margins partially offset this decrease.
See the following discussion regarding the results of operations
for each of our business operating segments.
42
Natural
Gas Distribution Segment
The primary factors that impact the results of our natural gas
distribution operations are our ability to earn our authorized
rates of return, the cost of natural gas, competitive factors in
the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates is based primarily on
our ability to improve the rate design in our various ratemaking
jurisdictions by reducing or eliminating regulatory lag and,
ultimately, separating the recovery of our approved margins from
customer usage patterns. Improving rate design is a long-term
process and is further complicated by the fact that we operate
in multiple rate jurisdictions. The Ratemaking
Activity section of this
Form 10-K
describes our current rate strategy and recent ratemaking
initiatives in more detail.
Our natural gas distribution operations are also affected by the
cost of natural gas. The cost of gas is passed through to our
customers without markup. Therefore, increases in the cost of
gas are offset by a corresponding increase in revenues.
Accordingly, we believe gross profit is a better indicator of
our financial performance than revenues. However, gross profit
in our Texas and Mississippi service areas include franchise
fees and gross receipts taxes, which are calculated as a
percentage of revenue (inclusive of gas costs). Therefore, the
amount of these taxes included in revenues is influenced by the
cost of gas and the level of gas sales volumes. We record the
tax expense as a component of taxes, other than income. Although
changes in revenue-related taxes arising from changes in gas
costs affect gross profit, over time the impact is offset within
operating income. Prior to January 1, 2009, timing
differences existed between the recognition of revenue for
franchise fees collected from our customers and the recognition
of expense of franchise taxes. These timing differences had a
significant temporary effect on operating income in periods with
volatile gas prices, particularly in our Mid-Tex Division.
Beginning January 1, 2009, changes in our franchise fee
agreements in our Mid-Tex Division became effective which should
significantly reduce the impact of this timing difference on a
prospective basis. Although this timing difference will still be
present for gross receipts taxes, the timing differences
described above should be less significant.
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. Finally, higher
gas costs, as well as competitive factors in the industry and
general economic conditions may cause customers to conserve or
use alternative energy sources.
43
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the fiscal years ended
September 30, 2009, 2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009 vs. 2008
|
|
|
2008 vs. 2007
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
1,024,628
|
|
|
$
|
1,006,066
|
|
|
$
|
952,684
|
|
|
$
|
18,562
|
|
|
$
|
53,382
|
|
Operating expenses
|
|
|
735,614
|
|
|
|
744,901
|
|
|
|
731,497
|
|
|
|
(9,287
|
)
|
|
|
13,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
289,014
|
|
|
|
261,165
|
|
|
|
221,187
|
|
|
|
27,849
|
|
|
|
39,978
|
|
Miscellaneous income
|
|
|
5,766
|
|
|
|
9,689
|
|
|
|
8,945
|
|
|
|
(3,923
|
)
|
|
|
744
|
|
Interest charges
|
|
|
124,055
|
|
|
|
117,933
|
|
|
|
121,626
|
|
|
|
6,122
|
|
|
|
(3,693
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
170,725
|
|
|
|
152,921
|
|
|
|
108,506
|
|
|
|
17,804
|
|
|
|
44,415
|
|
Income tax expense
|
|
|
53,918
|
|
|
|
60,273
|
|
|
|
35,223
|
|
|
|
(6,355
|
)
|
|
|
25,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
116,807
|
|
|
$
|
92,648
|
|
|
$
|
73,283
|
|
|
$
|
24,159
|
|
|
$
|
19,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
282,117
|
|
|
|
292,676
|
|
|
|
297,327
|
|
|
|
(10,559
|
)
|
|
|
(4,651
|
)
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
126,768
|
|
|
|
136,678
|
|
|
|
130,542
|
|
|
|
(9,910
|
)
|
|
|
6,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
408,885
|
|
|
|
429,354
|
|
|
|
427,869
|
|
|
|
(20,469
|
)
|
|
|
1,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.47
|
|
|
$
|
0.44
|
|
|
$
|
0.45
|
|
|
$
|
0.03
|
|
|
$
|
(0.01
|
)
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
6.95
|
|
|
$
|
9.05
|
|
|
$
|
8.09
|
|
|
$
|
(2.10
|
)
|
|
$
|
0.96
|
|
The following table shows our operating income by natural gas
distribution division for the fiscal years ended
September 30, 2009, 2008 and 2007. The presentation of our
natural gas distribution operating income is included for
financial reporting purposes and may not be appropriate for
ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009 vs. 2008
|
|
|
2008 vs. 2007
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
127,625
|
|
|
$
|
115,009
|
|
|
$
|
68,574
|
|
|
$
|
12,616
|
|
|
$
|
46,435
|
|
Kentucky/Mid-States
|
|
|
47,978
|
|
|
|
48,731
|
|
|
|
42,161
|
|
|
|
(753
|
)
|
|
|
6,570
|
|
Louisiana
|
|
|
43,434
|
|
|
|
39,090
|
|
|
|
44,193
|
|
|
|
4,344
|
|
|
|
(5,103
|
)
|
West Texas
|
|
|
23,338
|
|
|
|
13,843
|
|
|
|
21,036
|
|
|
|
9,495
|
|
|
|
(7,193
|
)
|
Mississippi
|
|
|
21,287
|
|
|
|
19,970
|
|
|
|
23,225
|
|
|
|
1,317
|
|
|
|
(3,255
|
)
|
Colorado-Kansas
|
|
|
21,321
|
|
|
|
20,615
|
|
|
|
22,392
|
|
|
|
706
|
|
|
|
(1,777
|
)
|
Other
|
|
|
4,031
|
|
|
|
3,907
|
|
|
|
(394
|
)
|
|
|
124
|
|
|
|
4,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
289,014
|
|
|
$
|
261,165
|
|
|
$
|
221,187
|
|
|
$
|
27,849
|
|
|
$
|
39,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
Fiscal
year ended September 30, 2009 compared with fiscal year
ended September 30, 2008
The $18.6 million increase in natural gas distribution
gross profit primarily reflects an increase in rates. The major
components of the increase are as follows:
|
|
|
|
|
$13.6 million net increase in rates in the Mid-Tex Division
as a result of the implementation of its 2008 Rate Review
Mechanism (RRM) filing with all incorporated cities in the
division other than the City of Dallas and Environs (the Settled
Cities) and adjustments for customers in the City of Dallas.
|
|
|
|
$16.0 million increase in other rate adjustments primarily
in Georgia, Kansas, Louisiana and West Texas.
|
|
|
|
$7.6 million increase attributable to a non-recurring
update to our estimate for gas delivered to customers but not
yet billed to reflect changes in base rates in several of our
jurisdictions recorded in the fiscal first quarter.
|
|
|
|
$7.0 million uncollectible gas cost accrual recorded in a
prior year that was reversed in the current year period.
|
These increases were partially offset by:
|
|
|
|
|
$17.9 million decrease as a result of a five percent
decrease in consolidated distribution throughput primarily
associated with lower residential, commercial and industrial
consumption and warmer weather in our Colorado service area,
which does not have weather-normalized rates.
|
|
|
|
$10.8 million decrease due to lower revenue related taxes,
partially offset by the associated franchise and state gross
receipts tax expense recorded as a component of taxes other than
income discussed below.
|
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income and asset
impairments decreased $9.3 million, primarily due to the
following:
|
|
|
|
|
$10.6 million decrease due to lower legal, fuel and other
administrative costs.
|
|
|
|
$9.2 million decrease in allowance for doubtful accounts
due to the impact of recent rate design changes in certain
jurisdictions that allow us to recover the gas cost portion of
uncollectible accounts as well as a 23 percent
year-over-year
decline in the average cost of gas.
|
|
|
|
$9.2 million decrease in taxes other than income primarily
associated with lower franchise fees and state gross receipt
taxes.
|
These decreases were partially offset by:
|
|
|
|
|
$15.1 million increase in depreciation and amortization,
due primarily to additional assets placed in service during the
current year.
|
|
|
|
$4.6 million increase due to a noncash charge to impair
certain
available-for-sale
investments as we believed the fair value of these investments
would not recover within a reasonable period of time.
|
Results for the current year include a $10.5 million tax
benefit associated with updating the rates used to determine our
deferred taxes. In addition, results for the prior year included
a $1.2 million gain on the sale of irrigation assets in our
West Texas Division.
Interest charges increased $6.1 million primarily due to
the effect of the Companys March 2009 issuance of
$450 million 8.50% senior notes to repay
$400 million 4.00% senior notes in April 2009. In
addition, we experienced higher average short-term debt
balances, interest rates and commitment fees during the current
year compared to the prior year.
45
Fiscal
year ended September 30, 2008 compared with fiscal year
ended September 30, 2007
The $53.4 million increase in natural gas distribution
gross profit is primarily the result of increased rates and
higher revenue-related taxes. The major components of the
increase are as follows:
|
|
|
|
|
$29.2 million increase in rates in the Mid-Tex Division due
to its 2006 GRIP filing, the fiscal 2008 and 2007 rate cases and
the absence of a one time GRIP refund that occurred in fiscal
2007.
|
|
|
|
$14.4 million increase in rates in the Kansas, Kentucky,
Louisiana, Tennessee and West Texas divisions.
|
|
|
|
$8.6 million increase due to higher revenue related taxes,
partially offset by the associated franchise and state gross
receipts tax expense recorded as a component of taxes other than
income discussed below.
|
|
|
|
$7.5 million increase due to an accrual for estimated
unrecoverable gas costs in fiscal 2007 that did not recur in
fiscal 2008.
|
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income, increased by
a net $13.4 million, primarily due to the following:
|
|
|
|
|
$9.0 million increase primarily due to higher employee and
administrative costs and increased natural gas odorization and
fuel costs.
|
|
|
|
$7.2 increase in franchise and state gross receipts taxes due to
higher revenues.
|
|
|
|
$4.3 million increase due to the absence in the current
year of the deferral of hurricane-related operation and
maintenance expenses in fiscal 2007.
|
|
|
|
$3.3 million noncash charge associated with the write-off
of software costs in fiscal 2007 that did not recur in fiscal
2008.
|
These increases were offset by a $3.2 million decrease in
the provision for doubtful accounts, which reflects our
continued effective collection efforts.
The increase in miscellaneous income primarily reflects the
recognition of a $1.2 million gain on the sale of
irrigation assets in our West Texas Division during the fiscal
2008 second quarter.
Interest charges allocated to the natural gas distribution
segment decreased $3.7 million due to lower average
outstanding short-term debt balances in fiscal 2008 compared
with fiscal 2007.
Regulated
Transmission and Storage Segment
Our regulated transmission and storage segment consists of the
regulated pipeline and storage operations of the Atmos
Pipeline Texas Division. The Atmos
Pipeline Texas Division transports natural gas to
our Mid-Tex Division and 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.
Similar to our natural gas distribution segment, our regulated
transmission and storage segment is impacted by seasonal weather
patterns, competitive factors in the energy industry and
economic conditions in our service areas. Natural gas prices do
not directly impact the results of this segment as revenues are
derived from the transportation of natural gas. However, natural
gas prices could influence the level of drilling activity in the
markets that we serve, which may influence the level of
throughput we may be able to transport on our pipeline.
Additionally, pricing differences that occur between the natural
gas hubs served by our pipeline could significantly impact our
results as we can profit through the arbitrage of these spreads.
Spread differences are influenced by supply and demand
constraints not only in the markets we directly serve but in
other markets as well. 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. Finally, 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.
46
Review of
Financial and Operating Results
Financial and operational highlights for our regulated
transmission and storage segment for the fiscal years ended
September 30, 2009, 2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009 vs. 2008
|
|
|
2008 vs. 2007
|
|
|
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex Division transportation
|
|
$
|
89,348
|
|
|
$
|
86,665
|
|
|
$
|
77,090
|
|
|
$
|
2,683
|
|
|
$
|
9,575
|
|
Third-party transportation
|
|
|
95,314
|
|
|
|
85,256
|
|
|
|
65,158
|
|
|
|
10,058
|
|
|
|
20,098
|
|
Storage and park and lend services
|
|
|
11,858
|
|
|
|
9,746
|
|
|
|
9,374
|
|
|
|
2,112
|
|
|
|
372
|
|
Other
|
|
|
13,138
|
|
|
|
14,250
|
|
|
|
11,607
|
|
|
|
(1,112
|
)
|
|
|
2,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
209,658
|
|
|
|
195,917
|
|
|
|
163,229
|
|
|
|
13,741
|
|
|
|
32,688
|
|
Operating expenses
|
|
|
116,495
|
|
|
|
106,172
|
|
|
|
83,399
|
|
|
|
10,323
|
|
|
|
22,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
93,163
|
|
|
|
89,745
|
|
|
|
79,830
|
|
|
|
3,418
|
|
|
|
9,915
|
|
Miscellaneous income
|
|
|
1,433
|
|
|
|
1,354
|
|
|
|
2,105
|
|
|
|
79
|
|
|
|
(751
|
)
|
Interest charges
|
|
|
30,982
|
|
|
|
27,049
|
|
|
|
27,917
|
|
|
|
3,933
|
|
|
|
(868
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
63,614
|
|
|
|
64,050
|
|
|
|
54,018
|
|
|
|
(436
|
)
|
|
|
10,032
|
|
Income tax expense
|
|
|
22,558
|
|
|
|
22,625
|
|
|
|
19,428
|
|
|
|
(67
|
)
|
|
|
3,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
41,056
|
|
|
$
|
41,425
|
|
|
$
|
34,590
|
|
|
$
|
(369
|
)
|
|
$
|
6,835
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
706,132
|
|
|
|
782,876
|
|
|
|
699,006
|
|
|
|
(76,744
|
)
|
|
|
83,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
528,689
|
|
|
|
595,542
|
|
|
|
505,493
|
|
|
|
(66,853
|
)
|
|
|
90,049
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal
year ended September 30, 2009 compared with fiscal year
ended September 30, 2008
The $13.7 million increase in regulated transmission and
storage gross profit was attributable primarily to the following
factors:
|
|
|
|
|
$13.0 million increase from higher demand-based fees.
|
|
|
|
$5.6 million increase resulting from higher transportation
fees on through-system deliveries due to market conditions.
|
|
|
|
$5.4 million increase due to our GRIP filings.
|
These increases were partially offset by an $8.4 million
decrease associated with a decrease in transportation volumes to
our Mid-Tex Division due to warmer weather and a decrease in
electrical generation, Barnett Shale and HUB deliveries.
Operating expenses increased $10.3 million primarily due to
higher levels of pipeline maintenance activities.
Results for the current-year period also include a
$1.7 million tax benefit associated with updating the rates
used to determine our deferred taxes.
Fiscal
year ended September 30, 2008 compared with fiscal year
ended September 30, 2007
The $32.7 million increase in regulated transmission and
storage gross profit is primarily the result of rate adjustments
and increased volumes. The major components of the increase are
as follows:
|
|
|
|
|
$13.1 million increase from rate adjustments resulting from
our 2006 and 2007 GRIP filings.
|
|
|
|
$8.3 million increase from transportation volumes as
consolidated throughput increased 18 percent primarily due
to increased transportation in the Barnett Shale region of Texas.
|
47
|
|
|
|
|
$8.0 million increase related to increased service fees and
per-unit
transportation margins due to favorable market conditions.
|
|
|
|
$1.5 million increase due to new compression contracts and
transportation capacity enhancements.
|
|
|
|
$1.3 million increase in sales of excess gas compared to
2007.
|
Operating expenses increased $22.8 million primarily due to
increased pipeline integrity and maintenance costs.
Natural
Gas Marketing Segment
AEMs primary business is to aggregate and purchase gas
supply, arrange transportation and storage logistics and
ultimately deliver gas to customers at competitive prices. In
addition, AEM utilizes proprietary and customer-owned
transportation and storage assets to provide 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 financial instruments. As a
result, AEMs margins arise from the types of commercial
transactions we have structured with our customers and our
ability to identify the lowest cost alternative among the
natural gas supplies, transportation and markets to which it has
access to serve those customers.
AEM seeks to enhance its gross profit margin by maximizing,
through asset optimization activities, the economic value
associated with the storage and transportation capacity we own
or control in our natural gas distribution and natural gas
marketing segments. We attempt to meet this objective by
engaging in natural gas storage transactions in which we seek to
find and profit through the arbitrage of pricing differences in
various locations and by recognizing pricing differences that
occur over time. This process involves purchasing physical
natural gas, storing it in the storage and transportation assets
to which AEM has access and selling financial instruments at
advantageous prices to lock in a gross profit margin.
AEM continually manages its net physical position to attempt to
increase the future economic profit that was created when the
original transaction was executed. Therefore, AEM may
subsequently change its originally scheduled storage injection
and withdrawal plans from one time period to another based on
market conditions and recognize any associated gains or losses
at that time. If AEM elects to accelerate the withdrawal of
physical gas, it will execute new financial instruments to hedge
the original financial instruments. If AEM elects to defer the
withdrawal of gas, it will reset its financial instruments by
settling the original financial instruments and executing new
financial instruments to correspond to the revised withdrawal
schedule.
We use financial instruments, designated as fair value hedges,
to hedge our natural gas inventory used in our natural gas
marketing storage activities. These financial instruments 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 hedged natural gas inventory is
marked to market at the end of each month based on the Gas Daily
index with changes in fair value recognized as unrealized gains
and losses in the period of change. Changes in the spreads
between the forward natural gas prices used to value the
financial hedges designated against our physical inventory and
the market (spot) prices used to value our physical storage
result in unrealized margins until the underlying physical gas
is withdrawn and the related financial instruments are settled.
Once the gas is withdrawn and the financial instruments are
settled, the previously unrealized margins associated with these
net positions are realized.
AEM also uses financial instruments to capture additional
storage arbitrage opportunities that may arise after the
original physical inventory hedge and to attempt to insulate and
protect the economic value within its asset optimization
activities. Changes in fair value associated with these
financial instruments are recognized as a component of
unrealized margins until they are settled.
Due to the nature of these operations, natural gas prices have a
significant impact on our natural gas marketing operations.
Within our delivered gas activities, higher natural gas prices
may adversely impact our
48
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. Higher
gas prices, as well as competitive factors in the industry and
general economic conditions may also cause customers to conserve
or use alternative energy sources. Within our asset optimization
activities, higher gas prices could also lead to increased
borrowings under our credit facilities resulting in higher
interest expense.
Volatility in natural gas prices also has a significant impact
on our natural gas marketing segment. Increased price volatility
often has a significant impact on the spreads between the market
(spot) prices and forward natural gas prices, which creates
opportunities to earn higher arbitrage spreads within our asset
optimization activities. However, increased volatility impacts
the amounts of unrealized margins recorded in our gross profit
and could impact the amount of cash required to collateralize
our risk management liabilities.
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
marketing segment for the fiscal years ended September 30,
2009, 2008 and 2007 are presented below. Gross profit margin
consists primarily of margins earned from the delivery of gas
and related services requested by our customers and margins
earned from asset optimization activities, which are derived
from the utilization of our proprietary and managed third party
storage and transportation assets to capture favorable arbitrage
spreads through natural gas trading activities.
Unrealized margins represent the unrealized gains or losses on
our net physical position and the related financial instruments
used to manage commodity price risk as described above. These
margins fluctuate based upon changes in the spreads between the
physical and forward natural gas prices. Generally, if the
physical/financial spread narrows, we will record unrealized
gains or lower unrealized losses. If the physical/financial
spread widens, we will record unrealized losses or lower
unrealized gains. The magnitude of the unrealized gains and
losses is also dependent upon the levels of our net physical
position at the end of the reporting period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009 vs. 2008
|
|
|
2008 vs. 2007
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
75,341
|
|
|
$
|
73,627
|
|
|
$
|
57,054
|
|
|
$
|
1,714
|
|
|
$
|
16,573
|
|
Asset optimization
|
|
|
37,670
|
|
|
|
(6,135
|
)
|
|
|
28,827
|
|
|
|
43,805
|
|
|
|
(34,962
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113,011
|
|
|
|
67,492
|
|
|
|
85,881
|
|
|
|
45,519
|
|
|
|
(18,389
|
)
|
Unrealized margins
|
|
|
(28,399
|
)
|
|
|
25,529
|
|
|
|
18,430
|
|
|
|
(53,928
|
)
|
|
|
7,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
84,612
|
|
|
|
93,021
|
|
|
|
104,311
|
|
|
|
(8,409
|
)
|
|
|
(11,290
|
)
|
Operating expenses
|
|
|
38,208
|
|
|
|
36,629
|
|
|
|
29,271
|
|
|
|
1,579
|
|
|
|
7,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
46,404
|
|
|
|
56,392
|
|
|
|
75,040
|
|
|
|
(9,988
|
)
|
|
|
(18,648
|
)
|
Miscellaneous income
|
|
|
537
|
|
|
|
2,022
|
|
|
|
6,434
|
|
|
|
(1,485
|
)
|
|
|
(4,412
|
)
|
Interest charges
|
|
|
12,911
|
|
|
|
9,036
|
|
|
|
5,767
|
|
|
|
3,875
|
|
|
|
3,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
34,030
|
|
|
|
49,378
|
|
|
|
75,707
|
|
|
|
(15,348
|
)
|
|
|
(26,329
|
)
|
Income tax expense
|
|
|
13,836
|
|
|
|
19,389
|
|
|
|
29,938
|
|
|
|
(5,553
|
)
|
|
|
(10,549
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
20,194
|
|
|
$
|
29,989
|
|
|
$
|
45,769
|
|
|
$
|
(9,795
|
)
|
|
$
|
(15,780
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
441,081
|
|
|
|
457,952
|
|
|
|
423,895
|
|
|
|
(16,871
|
)
|
|
|
34,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
370,569
|
|
|
|
389,392
|
|
|
|
370,668
|
|
|
|
(18,823
|
)
|
|
|
18,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
13.8
|
|
|
|
8.0
|
|
|
|
12.3
|
|
|
|
5.8
|
|
|
|
(4.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
Fiscal
year ended September 30, 2009 compared with fiscal year
ended September 30, 2008
AEMs delivered gas business contributed 67 percent to
total realized margins during fiscal 2009 with asset
optimization activities contributing the remaining
33 percent. In the prior year, delivered gas activities
represented substantially all of AEMs realized gross
profit margin. The $45.5 million increase in realized gross
profit reflected:
|
|
|
|
|
A $43.8 million increase in asset optimization margins. AEM
realized substantially all of its realized asset optimization
margin in the fiscal 2009 first quarter when it realized
substantially all of the economic value that it had captured as
of September 30, 2008 from withdrawing gas and settling the
associated financial instruments. Since that time, as a result
of falling current cash prices, AEM has been deferring storage
withdrawals and has been a net injector of gas into storage to
increase the economic value it could realize in future periods
from its asset optimization activities. In the prior year, AEM
deferred storage withdrawals primarily into fiscal 2009 and
recognized losses on the settlement of the associated financial
instruments.
|
|
|
|
A $1.7 million increase in realized delivered gas margins.
AEM experienced a six percent increase in
per-unit
margins as a result of improved basis spreads in certain market
areas where we were able to better optimize transportation
assets and successful contract renewals. These margin
improvements more than offset a four percent decrease in gross
sales volumes primarily attributable to lower industrial demand
as a result of the current economic climate.
|
The increase in realized gross profit was more than offset by a
$53.9 million decrease in unrealized margins attributable
to the following:
|
|
|
|
|
The realization of unrealized gains recorded during fiscal 2008.
|
|
|
|
A modest widening of the physical/financial spreads, partially
offset by favorable unrealized basis gains in certain markets.
|
|
|
|
A 5.8 Bcf increase in AEMs net physical position.
|
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income taxes, and asset
impairments, increased $1.6 million primarily due the
following factors:
|
|
|
|
|
$4.0 million increase in legal and other administrative
costs.
|
|
|
|
$2.4 million decrease related to tax matters incurred in
the prior year that did not recur in the current year.
|
Asset
Optimization Activities
AEM monitors the impact of its asset optimization efforts by
estimating the gross profit, before related fees, that it
captured through the purchase and sale of physical natural gas
and the execution of the associated financial instruments. This
economic value, combined with the effect of the future reversal
of unrealized gains or losses currently recognized in the income
statement and related fees is referred to as the potential gross
profit.
We define potential gross profit as the change in AEMs
gross profit in future periods if its optimization efforts are
executed as planned. This amount does not include other
operating expenses and associated income taxes that will be
incurred to realize this amount. Therefore, it does not
represent an estimated increase in future net income. There is
no assurance that the economic value or the potential gross
profit will be fully realized in the future.
We consider this measure a non-GAAP financial measure as it is
calculated using both forward-looking storage
injection/withdrawal and hedge settlement estimates and
historical financial information. This measure is presented
because we believe it provides a more comprehensive view to
investors of our asset optimization efforts and thus a better
understanding of these activities than would be presented by
GAAP measures alone.
50
The following table presents AEMs economic value and its
potential gross profit (loss) at September 30, 2009 and
2008.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions, unless otherwise noted)
|
|
|
Economic value
|
|
$
|
28.6
|
|
|
$
|
48.5
|
|
Associated unrealized (gains) losses
|
|
|
11.0
|
|
|
|
(36.4
|
)
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
39.6
|
|
|
|
12.1
|
|
Related
fees(1)
|
|
|
(14.7
|
)
|
|
|
(19.6
|
)
|
|
|
|
|
|
|
|
|
|
Potential gross profit (loss)
|
|
$
|
24.9
|
|
|
$
|
(7.5
|
)
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
13.8
|
|
|
|
8.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Related fees represent AEMs contractual costs to acquire
the storage capacity utilized in its asset optimization
operations. The fees primarily consist of demand fees and
contractual obligations to sell gas below market index prices in
exchange for the right to manage and optimize third party
storage assets for the positions AEM has entered into as of
September 30, 2009 and 2008. |
During the year ended September 30, 2009, AEMs
economic value decreased from $48.5 million, or $6.08/Mcf
at September 30, 2008, to $28.6 million, or $2.07/Mcf.
As discussed above, in the fiscal 2009 first quarter, AEM
withdrew gas and realized substantially all of the economic
value that it captured as of September 30, 2008. During the
remainder of the year, as a result of falling current cash
prices, AEM deferred certain storage withdrawals and has been a
net injector of gas into storage to increase economic value that
it can realize in future periods.
The economic value is based upon planned storage injection and
withdrawal schedules and its realization is contingent upon the
execution of this plan, weather and other execution factors.
Since AEM actively manages and optimizes its portfolio to
attempt to enhance the future profitability of its storage
position, it may change its scheduled storage injection and
withdrawal plans from one time period to another based on market
conditions. Therefore, we cannot ensure that the economic value
or the potential gross profit calculated as of
September 30, 2009 will be fully realized in the future nor
can we ensure in what time periods such realization may occur.
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. Assuming AEM fully
executes its plan in place on September 30, 2009, without
encountering operational or other issues, we anticipate the
majority of the potential gross profit as of September 30,
2009 will be recognized during the first and second quarters of
fiscal 2010.
Fiscal
year ended September 30, 2008 compared with fiscal year
ended September 30, 2007
AEMs delivered gas business represented substantially all
of AEMs realized gross profit margin in fiscal 2008. In
fiscal 2007, AEMs delivered gas business contributed
66 percent to total realized margins during the year with
asset optimization activities contributing the remaining
34 percent. The $18.4 million decrease in realized
gross profit reflected:
|
|
|
|
|
A $35.0 million decrease in realized asset optimization
margins. As a result of less volatile natural gas market
conditions experienced during fiscal 2008, AEM regularly
deferred storage withdrawals and reset the associated financial
instruments to increase the future economic value it could
realize in future periods from its asset optimization
activities. AEM recognized losses on the settlement of the
associated financial instruments without corresponding storage
withdrawal gains. In fiscal 2007, AEM changed its withdrawal
schedule within the fiscal year and recognized substantially
smaller losses from resetting its position. Increased storage
fees during fiscal 2008 also contributed to the decrease.
|
|
|
|
A $16.6 million increase in realized delivered gas margins.
Gross sales volumes increased eight percent due to the
successful execution of our marketing strategies. Basis gains
and contract renewals increased
|
51
|
|
|
|
|
per-unit
margins 19 percent. Excluding the impact of basis gains,
per-unit
margins increased seven percent in fiscal 2008.
|
The decrease in realized gross profit was partially offset by a
$7.1 million increase in unrealized margins attributable to:
|
|
|
|
|
A narrowing of the spreads between current cash prices and
forward natural gas prices. This impact was partially mitigated
by a 4.3 Bcf decrease in the net physical position.
|
|
|
|
The realization of unrealized gains recorded during fiscal 2007.
|
Operating expenses increased $7.4 million primarily due to
the following:
|
|
|
|
|
$5.0 million increase in other administrative costs.
|
|
|
|
$2.4 million increase associated with property taxes.
|
Pipeline,
Storage and Other Segment
Our pipeline, storage and other segment consists primarily of
the operations of Atmos Pipeline and Storage, LLC (APS). APS is
engaged in nonregulated transmission, storage and natural
gas-gathering services. Its primary asset is a proprietary
21 mile pipeline located in New Orleans, Louisiana that is
primarily used to aggregate gas supply for our regulated natural
gas distribution division in Louisiana and for our natural gas
marketing segment, and, on a more limited basis, to third
parties. APS also owns or has an interest in underground storage
fields in Kentucky and Louisiana that are used to reduce the
need of our natural gas distribution divisions to contract for
additional pipeline capacity to meet customer demand during peak
periods.
APS also engages in asset optimization activities whereby it
seeks to maximize the economic value associated with the storage
and transportation capacity it owns or controls. Certain of
these arrangements are with regulated affiliates of the Company
which have been approved by applicable state regulatory
commissions. Generally, these asset management plans require APS
to share with our regulated customers a portion of the profits
earned from these arrangements. APS also seeks to maximize the
economic value associated with the storage and transportation
capacity it owns or controls by engaging in natural gas storage
transactions in which we seek to find and profit from the
pricing differences that occur over time.
Results for this segment are primarily impacted by seasonal
weather patterns and, similar to our natural gas marketing
segment, volatility in the natural gas markets. Additionally,
this segments results include an unrealized component as
APS hedges its risk associated with its asset optimization
activities.
52
Review of
Financial and Operating Results
Financial and operational highlights for our pipeline, storage
and other segment for the fiscal years ended September 30,
2009, 2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009 vs. 2008
|
|
|
2008 vs. 2007
|
|
|
|
(In thousands)
|
|
|
Storage and transportation services
|
|
$
|
12,784
|
|
|
$
|
14,247
|
|
|
$
|
14,213
|
|
|
$
|
(1,463
|
)
|
|
$
|
34
|
|
Asset optimization
|
|
|
21,474
|
|
|
|
5,178
|
|
|
|
12,101
|
|
|
|
16,296
|
|
|
|
(6,923
|
)
|
Other
|
|
|
2,728
|
|
|
|
4,183
|
|
|
|
4,197
|
|
|
|
(1,455
|
)
|
|
|
(14
|
)
|
Unrealized margins
|
|
|
(7,490
|
)
|
|
|
4,705
|
|
|
|
2,097
|
|
|
|
(12,195
|
)
|
|
|
2,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
29,496
|
|
|
|
28,313
|
|
|
|
32,608
|
|
|
|
1,183
|
|
|
|
(4,295
|
)
|
Operating expenses
|
|
|
11,019
|
|
|
|
8,064
|
|
|
|
10,373
|
|
|
|
2,955
|
|
|
|
(2,309
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
18,477
|
|
|
|
20,249
|
|
|
|
22,235
|
|
|
|
(1,772
|
)
|
|
|
(1,986
|
)
|
Miscellaneous income
|
|
|
6,253
|
|
|
|
8,428
|
|
|
|
8,173
|
|
|
|
(2,175
|
)
|
|
|
255
|
|
Interest charges
|
|
|
1,830
|
|
|
|
2,322
|
|
|
|
6,055
|
|
|
|
(492
|
)
|
|
|
(3,733
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
22,900
|
|
|
|
26,355
|
|
|
|
24,353
|
|
|
|
(3,455
|
)
|
|
|
2,002
|
|
Income tax expense
|
|
|
9,979
|
|
|
|
10,086
|
|
|
|
9,503
|
|
|
|
(107
|
)
|
|
|
583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
12,921
|
|
|
$
|
16,269
|
|
|
$
|
14,850
|
|
|
$
|
(3,348
|
)
|
|
$
|
1,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal
year ended September 30, 2009 compared with fiscal year
ended September 30, 2008
Gross profit from our pipeline, storage and other segment
increased $1.2 million primarily due to the following:
|
|
|
|
|
$16.3 million increase in asset optimization margins as a
result of larger realized gains from the settlement of financial
positions associated with storage and trading activities, basis
gains earned from utilizing controlled pipeline capacity and
higher margins earned under asset management plans.
|
|
|
|
$12.2 million decrease in unrealized margins associated
with our asset optimization activities due to a widening of the
spreads between current cash prices and forward natural gas
prices.
|
Operating expenses increased $3.0 million primarily due to
increased employee costs and higher depreciation expense which
was largely attributable to additional assets placed in service
during the year.
Fiscal
year ended September 30, 2008 compared with fiscal year
ended September 30, 2007
Gross profit from our pipeline, storage and other segment
decreased $4.3 million primarily due to the following
factors:
|
|
|
|
|
$6.9 million decrease in asset optimization margins as a
result of a less volatile natural gas market.
|
|
|
|
$2.6 million increase in unrealized margins associated with
asset optimization activities.
|
Operating expenses decreased $2.3 million primarily due to
the absence in fiscal 2008 of a $3.0 million noncash charge
recorded in fiscal 2007 related to the write-off of costs
associated with a natural gas gathering project.
LIQUIDITY
AND CAPITAL RESOURCES
The liquidity required to fund our working capital, capital
expenditures and other cash needs is provided from a variety of
sources including internally generated funds and borrowings
under our commercial paper program and bank credit facilities.
Additionally, we have various uncommitted trade credit lines
with our gas suppliers that we utilize to purchase natural gas
on a monthly basis without using our credit facilities. Finally,
from time to time, we raise funds from the public debt and
equity capital markets to fund our liquidity needs.
53
The primary means we use to fund our working capital needs and
growth is to utilize internally generated funds and to access
the commercial paper markets. Adverse developments in global
financial and credit markets during the first fiscal quarter of
2009 made it more difficult and more expensive for the Company
to access the short-term capital markets, including the
commercial paper market, to satisfy our liquidity requirements.
Consequently, during the first quarter, we experienced higher
than normal borrowings under our five-year credit facility used
to backstop our commercial paper program in lieu of commercial
paper borrowings to fund our working capital needs. However,
subsequent to the end of the first quarter, credit market
conditions improved, both as to availability and interest rates,
and we have been able to access the commercial paper markets on
more reasonably economical terms. Further, as a result of our
financing activities described below, we received credit rating
upgrades from two of the three credit rating agencies, which has
reduced the cost of our commercial paper borrowings. At
September 30, 2009, we had commercial paper outstanding of
$72.6 million under this facility and $494.1 million
was available.
On March 26, 2009, we closed our offering of
$450 million of 8.50% senior notes due 2019. Most of
the net proceeds of approximately $446 million were used to
redeem our $400 million 4.00% unsecured senior notes on
April 30, 2009, prior to their October 2009 maturity. In
connection with the repayment of the $400 million 4.00%
unsecured senior notes, we paid a $6.6 million call premium
in accordance with the terms of the senior notes and accrued
interest of approximately $0.6 million. The remaining net
proceeds were used for general corporate purposes.
In October 2009, we replaced our former $212.5 million
364-day
committed credit facility that was entered into in October 2008
with a new
364-day
credit facility on similar terms that will allow borrowings up
to $200.0 million and expires in October 2010.
In December 2008, we converted AEMs former
$580 million uncommitted credit facility to a
$375 million committed credit facility that will expire in
December 2009. Effective April 1, 2009, we exercised the
accordion feature of this facility to increase the credit
available under the facility to $450 million. We are
currently negotiating to renew this facility. In addition, we
replaced our $18 million unsecured committed credit
facility that expired in March 2009 with a $25 million
unsecured facility effective April 1, 2009. As a result of
executing these new agreements, we have a total of approximately
$1.3 billion available to us under four committed credit
facilities. As of September 30, 2009, the amount available
to us under our credit facilities, net of outstanding letters of
credit, was approximately $902 million.
We believe the liquidity provided by our committed credit
facilities, combined with our operating cash flows, will be
sufficient to fund our working capital needs, capital
expenditures and other expenditures for fiscal year 2010.
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 such products and services, margin requirements
resulting from significant changes in commodity prices,
operational risks and other factors.
Cash flows from operating, investing and financing activities
for the years ended September 30, 2009, 2008 and 2007 are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009 vs. 2008
|
|
|
2008 vs. 2007
|
|
|
|
(In thousands)
|
|
|
Total cash provided by (used in)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
919,233
|
|
|
$
|
370,933
|
|
|
$
|
547,095
|
|
|
$
|
548,300
|
|
|
$
|
(176,162
|
)
|
Investing activities
|
|
|
(517,201
|
)
|
|
|
(483,009
|
)
|
|
|
(402,871
|
)
|
|
|
(34,192
|
)
|
|
|
(80,138
|
)
|
Financing activities
|
|
|
(337,546
|
)
|
|
|
98,068
|
|
|
|
(159,314
|
)
|
|
|
(435,614
|
)
|
|
|
257,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
$
|
64,486
|
|
|
$
|
(14,008
|
)
|
|
$
|
(15,090
|
)
|
|
$
|
78,494
|
|
|
$
|
1,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
Cash
flows from operating activities
Year-over-year
changes in our operating cash flows primarily are attributable
to changes in net income, working capital changes, particularly
within our natural gas distribution segment resulting from the
price of natural gas and the timing of customer collections,
payments for natural gas purchases and purchased gas cost
recoveries. The significant factors impacting our operating cash
flow for the last three fiscal years are summarized below.
Fiscal
Year ended September 30, 2009 compared with fiscal year
ended September 30, 2008
Operating cash flows were $548.3 million higher in fiscal
2009 compared to fiscal 2008, primarily due to the following:
|
|
|
|
|
$368.9 million increase attributable to the favorable
impact on our working capital due to the decline in natural gas
prices in the current year compared to the prior year.
|
|
|
|
$56.8 million increase due to lower cash margin
requirements related to our natural gas marketing financial
instruments.
|
|
|
|
These increases were partially offset by a $21.0 million
decrease due to a contribution made to our pension plans in the
current year.
|
Fiscal
Year ended September 30, 2008 compared with fiscal year
ended September 30, 2007
Operating cash flows were $176.2 million lower in fiscal
2008 compared to fiscal 2007, primarily due to the following:
|
|
|
|
|
$95.7 million decrease due to higher cash margin
requirements related to our natural gas marketing financial
instruments.
|
|
|
|
$92.6 million decrease due to the unfavorable timing of gas
cost collections in our natural gas distribution segment.
|
Cash
flows from investing activities
In recent fiscal years, a substantial portion of our cash
resources has been used to fund acquisitions and growth
projects, our ongoing construction program and improvements to
information technology systems. Our ongoing construction program
enables us to provide natural gas distribution services to our
existing customer base, expand our natural gas distribution
services into new markets, enhance the integrity of our
pipelines and, more recently, expand our intrastate pipeline
network. In executing our current rate strategy, we are focusing
our capital spending in jurisdictions that permit us to earn an
adequate return timely on our investment without compromising
the safety or reliability of our system. Currently, our Mid-Tex,
Louisiana, Mississippi and West Texas natural gas distribution
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 fiscal year ended September 30, 2009, we incurred
$509.5 million for capital expenditures compared with
$472.3 million for the fiscal year ended September 30,
2008 and $392.4 million for the fiscal year ended
September 30, 2007.
The increase in capital expenditures in fiscal 2009 compared to
fiscal 2008 primarily reflects $32.6 million related to
spending for a regulated transmission pipeline project completed
in the fourth quarter of 2009.
The increase in capital expenditures in fiscal 2008 compared to
fiscal 2007 primarily reflects the following:
|
|
|
|
|
$50.3 million increase in compliance spending and main
replacements in our Mid-Tex Division.
|
|
|
|
$12.8 million increase in the natural gas distribution
segment for our new automated meter reading initiative.
|
|
|
|
$4.7 million increase related to spending for two
nonregulated growth projects.
|
55
Cash
flows from financing activities
For the fiscal year ended September 30, 2009, our financing
activities used $337.5 million in cash, while financing
activities for the fiscal year ended September 30, 2008
provided $98.1 million in cash compared with cash of
$159.3 million used for the fiscal year ended
September 30, 2007. Our significant financing activities
for the fiscal years ended September 30, 2009, 2008 and
2007 are summarized as follows:
2009
During the fiscal year ended September 30, 2009, we:
|
|
|
|
|
Paid $407.4 million to repay our $400 million 4.00%
unsecured notes.
|
|
|
|
Repaid a net $284.0 million of short-term borrowings under
our credit facilities.
|
|
|
|
Paid $121.5 million in cash dividends, which reflected a
payout ratio of 63 percent of net income.
|
|
|
|
Received $445.6 million in net proceeds related to the
March 2009 issuance of $450 million of 8.50% Senior
Notes due 2019. The net proceeds were used to repay the
$400 million 4.00% unsecured notes.
|
|
|
|
Received $27.7 million net proceeds related to the issuance
of 1.2 million shares of common stock.
|
|
|
|
Received $1.9 million net proceeds related to the
settlement of the Treasury lock agreement associated with the
March 2009 issuance of the $450 million of
8.50% Senior Notes due 2019.
|
2008
During the fiscal year ended September 30, 2008, we:
|
|
|
|
|
Borrowed a net $200.2 million under our short-term
facilities due to the impact of seasonal natural gas purchases
and the effect of higher natural gas prices.
|
|
|
|
Repaid $10.3 million of long-term debt in accordance with
their normal maturity schedules.
|
|
|
|
Received $25.5 million in net proceeds related to the
issuance of 1.0 million shares of common stock.
|
|
|
|
Paid $117.3 million in dividends, which reflected a payout
ratio of 65 percent of net income.
|
2007
During the fiscal year ended September 30, 2007, we:
|
|
|
|
|
Repaid a net $213.2 million of short-term borrowings under
our credit facilities.
|
|
|
|
Paid $303.2 million to repay our $300 million
unsecured floating rate senior notes as discussed below.
|
|
|
|
Received $247.2 million in net proceeds related to the June
2007 issuance of $250 million of 6.35% Senior Notes
due 2017. We used the net proceeds of $247 million,
together with $53 million of available cash, to repay our
$300 million unsecured floating rate senior notes, which
were redeemed on July 15, 2007.
|
|
|
|
Paid $111.7 million in dividends, which reflected a payout
ratio of 67 percent of net income.
|
|
|
|
Received $24.9 million related to the issuance of common
stock under various plans.
|
|
|
|
Received $4.8 million related to the settlement of of the
Treasury lock agreement associated with the June 2007 issuance
of $250 million of 6.35% Senior Notes due 2017.
|
56
The following table shows the number of shares issued for the
fiscal years ended September 30, 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Shares issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct stock purchase plan
|
|
|
407,262
|
|
|
|
388,485
|
|
|
|
325,338
|
|
Retirement savings plan
|
|
|
640,639
|
|
|
|
558,014
|
|
|
|
422,646
|
|
1998 Long-term incentive plan
|
|
|
686,046
|
|
|
|
538,450
|
|
|
|
511,584
|
|
Outside directors
stock-for-fee
plan
|
|
|
3,079
|
|
|
|
3,197
|
|
|
|
2,453
|
|
December 2006 equity offering
|
|
|
|
|
|
|
|
|
|
|
6,325,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shares issued
|
|
|
1,737,026
|
|
|
|
1,488,146
|
|
|
|
7,587,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit
Facilities
As of September 30, 2009, we had three committed credit
facilities in our regulated operations totaling
$804.2 million. These facilities included (1) a
five-year $566.7 million unsecured facility expiring
December 2011, (2) a $212.5 million unsecured facility
expiring October 2009, and (3) a $25 million unsecured
facility expiring March 31, 2010. At the time the
$566.7 million credit facility was established, borrowings
under the facility were limited to $600 million. However,
in March 2009, the facility was amended to reduce the amount
available to $566.7 million to reflect the bankruptcy of
one lender that participated in the facility. In October 2009,
we replaced our $212.5 million facility at its termination
with a new $200 million unsecured
364-day
facility. After giving effect to these changes, the amount
available to us under our committed credit facilities was
$791.7 million. As of September 30, 2009, we had no
outstanding letters of credit under these facilities.
AEM has a committed credit facility that can provide up to
$450 million to support its nonregulated activities,
primarily the issuance of letters of credit to natural gas
suppliers. As of September 30, 2009, the amount available
to us under this credit facility, net of outstanding letters of
credit, was $170.4 million. 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. However, we believe these credit
facilities, combined with our operating cash flows will be
sufficient to fund our working capital needs, our fiscal 2010
capital expenditure program and our common stock dividends.
These facilities are described in further detail in Note 6
to the consolidated financial statements.
Shelf
Registration
On March 23, 2009, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in common stock
and/or debt
securities available for issuance, including approximately
$450 million of capacity carried over from our prior shelf
registration statement filed with the SEC in December 2006.
Immediately following the filing of the registration statement,
we issued $450 million of 8.50% senior notes due 2019
under the registration statement. Most of the net proceeds of
approximately $446 million were used to repay our
$400 million unsecured 4.00% senior notes on
April 30, 2009. As of September 30, 2009, we had
$450 million of availability remaining under the
registration statement. However, due to certain restrictions
placed by one state regulatory commission on our ability to
issue securities under the registration statement, we now have
remaining and available for issuance a total of approximately
$200 million of equity securities and $250 million of
debt securities.
57
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 regulated and
nonregulated 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).
In December 2008, S&P upgraded our senior long-term debt
credit rating from BBB to BBB+ and changed our rating outlook
from positive to stable. S&P cited improved financial
performance and rate case decisions that have increased cash
flow as the key drivers for the upgrade. In May 2009,
Moodys upgraded the credit rating on our senior long-term
debt from Baa3 to Baa2 and on our commercial paper from
P-3 to
P-2.
Moodys stated that the key drivers for the upgrade were
the completion of a major debt refinancing and the Company
improving its alternate liquidity resources while maintaining
solid financial performance. As of September 30, 2009, all
three rating agencies maintained a stable outlook. None of our
ratings are currently under review. Our current debt ratings are
all considered investment grade and are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S&P
|
|
|
Moodys
|
|
|
Fitch
|
|
|
Unsecured senior long-term debt
|
|
|
BBB+
|
|
|
|
Baa2
|
|
|
|
BBB+
|
|
Commercial paper
|
|
|
A-2
|
|
|
|
P-2
|
|
|
|
F-2
|
|
A significant reduction in our liquidity caused by more limited
access to the private and public credit markets as a result of
the recent adverse global financial and credit conditions could
trigger a negative change in our ratings outlook or even a
reduction in our credit ratings by the three credit rating
agencies. This would mean more limited access to the private and
public credit markets and an increase in the costs of such
borrowings.
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, 2009. Our debt covenants are described in
Note 6 to the consolidated financial statements.
Capitalization
The following table presents our capitalization as of
September 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except percentages)
|
|
|
Short-term debt
|
|
$
|
72,550
|
|
|
|
1.6
|
%
|
|
$
|
350,542
|
|
|
|
7.7
|
%
|
Long-term debt
|
|
|
2,169,531
|
|
|
|
49.1
|
%
|
|
|
2,120,577
|
|
|
|
46.9
|
%
|
Shareholders equity
|
|
|
2,176,761
|
|
|
|
49.3
|
%
|
|
|
2,052,492
|
|
|
|
45.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization, including short-term debt
|
|
$
|
4,418,842
|
|
|
|
100.0
|
%
|
|
$
|
4,523,611
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
Total debt as a percentage of total capitalization, including
short-term debt, was 50.7 percent and 54.6 percent at
September 30, 2009 and 2008. The decrease in the debt to
capitalization ratio primarily reflects a decrease in short-term
debt as of September 30, 2009 compared to the prior year.
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. We consider our optimal
capitalization ratio to be in the range of 50 to 55 percent
and seek to maintain this range 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.
Contractual
Obligations and Commercial Commitments
The following table provides information about contractual
obligations and commercial commitments at September 30,
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
$
|
2,172,827
|
|
|
$
|
131
|
|
|
$
|
362,565
|
|
|
$
|
250,131
|
|
|
$
|
1,560,000
|
|
Short-term
debt(1)
|
|
|
72,550
|
|
|
|
72,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
charges(2)
|
|
|
1,181,236
|
|
|
|
141,085
|
|
|
|
245,278
|
|
|
|
206,841
|
|
|
|
588,032
|
|
Gas purchase
commitments(3)
|
|
|
338,746
|
|
|
|
312,837
|
|
|
|
15,232
|
|
|
|
10,677
|
|
|
|
|
|
Capital lease
obligations(4)
|
|
|
1,565
|
|
|
|
186
|
|
|
|
372
|
|
|
|
372
|
|
|
|
635
|
|
Operating
leases(4)
|
|
|
219,010
|
|
|
|
17,764
|
|
|
|
31,409
|
|
|
|
27,731
|
|
|
|
142,106
|
|
Demand fees for contracted
storage(5)
|
|
|
28,459
|
|
|
|
12,475
|
|
|
|
13,534
|
|
|
|
2,200
|
|
|
|
250
|
|
Demand fees for contracted
transportation(6)
|
|
|
41,948
|
|
|
|
9,810
|
|
|
|
16,783
|
|
|
|
12,198
|
|
|
|
3,157
|
|
Financial instrument
obligations(7)
|
|
|
21,482
|
|
|
|
21,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement benefit plan
contributions(8)
|
|
|
162,782
|
|
|
|
12,242
|
|
|
|
22,857
|
|
|
|
28,686
|
|
|
|
98,997
|
|
Uncertain tax positions (including
interest)(9)
|
|
|
6,731
|
|
|
|
|
|
|
|
6,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
4,247,336
|
|
|
$
|
600,562
|
|
|
$
|
714,761
|
|
|
$
|
538,836
|
|
|
$
|
2,393,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See Note 6 to the consolidated financial statements. |
|
(2) |
|
Interest charges were calculated using the stated rate for each
debt issuance. |
|
(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, 2009. |
|
(4) |
|
See Note 13 to the consolidated financial statements. |
|
(5) |
|
Represents third party contractual demand fees for contracted
storage in our natural gas marketing and pipeline, storage and
other segments. Contractual demand fees for contracted storage
for our natural gas distribution 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 financial
instruments that were valued as of September 30, 2009. The
ultimate settlement amounts of these remaining liabilities are
unknown because they are subject to continuing market risk until
the financial instruments are settled. |
|
(8) |
|
Represents expected contributions to our postretirement benefit
plans. |
|
(9) |
|
Represents liabilities associated with uncertain tax positions
claimed or expected to be claimed on tax returns. |
59
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, 2009, AEM was committed
to purchase 72.6 Bcf within one year, 19.4 Bcf within
one to three years and 2.2 Bcf after three years under
indexed contracts. AEM was committed to purchase 2.9 Bcf
within one year under fixed price contracts with prices ranging
from $2.95 to $7.68 per Mcf.
With the exception of our Mid-Tex Division, our natural gas
distribution 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, 2009 are
reflected in the table above.
Risk
Management Activities
We use financial instruments to mitigate commodity price risk
and, periodically, to manage interest rate risk. We conduct risk
management activities through our natural gas distribution,
natural gas marketing and pipeline, storage and other segments.
In our natural gas distribution segment, we use a combination of
physical 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, storage and other 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
instruments, 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 financial
instruments being treated as mark to market instruments through
earnings.
We use financial instruments, designated as cash flow hedges of
anticipated purchases and sales at index prices, to mitigate the
commodity price risk in our natural gas marketing segment
associated with deliveries under fixed-priced forward contracts
to deliver gas to customers, and we use financial instruments,
designated as fair value hedges, to hedge our natural gas
inventory used in our asset optimization activities in our
natural gas marketing and pipeline, storage and other segments.
Also, in our natural gas marketing segment, we use 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. These financial instruments have
not been designated as hedges.
We record our financial instruments 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 financial instrument. Substantially all of our
financial instruments are valued using external market quotes
and indices.
The following table shows the components of the change in fair
value of our natural gas distribution segments financial
instruments for the fiscal year ended September 30, 2009
(in thousands):
|
|
|
|
|
Fair value of contracts at September 30, 2008
|
|
$
|
(63,677
|
)
|
Contracts realized/settled
|
|
|
(102,943
|
)
|
Fair value of new contracts
|
|
|
353
|
|
Other changes in value
|
|
|
152,101
|
|
|
|
|
|
|
Fair value of contracts at September 30, 2009
|
|
$
|
(14,166
|
)
|
|
|
|
|
|
60
The fair value of our natural gas distribution segments
financial instruments at September 30, 2009, is presented
below by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at September 30, 2009
|
|
|
|
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
|
|
$
|
(15,786
|
)
|
|
$
|
1,620
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(14,166
|
)
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
(15,786
|
)
|
|
$
|
1,620
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(14,166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows the components of the change in fair
value of our natural gas marketing segments financial
instruments for the fiscal year ended September 30, 2009
(in thousands):
|
|
|
|
|
Fair value of contracts at September 30, 2008
|
|
$
|
16,542
|
|
Contracts realized/settled
|
|
|
22,327
|
|
Fair value of new contracts
|
|
|
|
|
Other changes in value
|
|
|
(12,171
|
)
|
|
|
|
|
|
Fair value of contracts at September 30, 2009
|
|
|
26,698
|
|
Netting of cash collateral
|
|
|
11,664
|
|
|
|
|
|
|
Cash collateral and fair value of contracts at
September 30, 2009
|
|
$
|
38,362
|
|
|
|
|
|
|
The fair value of our natural gas marketing segments
financial instruments at September 30, 2009, is presented
below by time period and fair value source.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at September 30, 2009
|
|
|
|
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
|
|
$
|
14,283
|
|
|
$
|
12,415
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
26,698
|
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
14,283
|
|
|
$
|
12,415
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
26,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and Postretirement Benefits Obligations
Net
Periodic Pension and Postretirement Benefit Costs
For the fiscal year ended September 30, 2009, our total net
periodic pension and other benefits costs was
$50.2 million, compared with $47.9 million and
$48.6 million for the fiscal years ended September 30,
2008 and 2007. These costs relating to our natural gas
distribution operations are recoverable through our gas
distribution rates. A portion of these costs is capitalized into
our gas distribution rate base, and the remaining costs are
recorded as a component of operation and maintenance expense.
The increase in total net periodic pension and other benefits
costs during fiscal 2009 compared with fiscal 2008 primarily
reflects the change in assumptions we made during our annual
pension plan valuation completed September 30, 2008. 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. At our September 30, 2008
measurement date, the interest rates were approximately
130 basis points higher than the interest rates at
June 30, 2007, the measurement date used to determine our
fiscal 2008 net periodic cost. The corresponding increase
in the discount rate was the primary
61
driver for the increase in our fiscal 2009 pension and benefit
costs. Our expected return on our pension plan assets remained
constant at 8.25 percent.
The periodic pension and other benefits costs remained
relatively unchanged during fiscal 2008 compared with fiscal
2007 as the assumptions we made during our annual pension plan
valuation completed June 30, 2007 were consistent with the
prior year. At our June 30, 2007 measurement date, the
interest rates were consistent with rates at our prior-year
measurement date, which resulted in no change to our
6.30 percent discount rate used to determine our fiscal
2008 net periodic and post-retirement cost. In addition,
our expected return on our pension plan assets remained constant
at 8.25 percent.
Pension
and Postretirement Plan Funding
Generally, our funding policy is to contribute annually an
amount that will at least equal the minimum amount required to
comply with the Employee Retirement Income Security Act of 1974,
including the funding requirements under the Pension Protection
Act of 2006 (PPA). 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 2009, we contributed $21.0 million in cash to
our pension plans to achieve a desired level of funding for the
2008 plan year while maximizing the tax deductibility of this
payment. The need for this funding reflected the decline in the
fair value of the plans assets resulting from the
unfavorable market conditions experienced during the latter half
of calendar year 2008. This contribution increased the level of
our plan assets to achieve a desirable funding threshold as
established by the PPA. During fiscal 2008, we voluntarily
contributed $2.3 million to the Atmos Energy Corporation
Retirement Plan for Mississippi Valley Gas Union Employees. This
contribution achieved a desired level of funding for this plan
for the 2007 plan year. During fiscal 2007, we did not
contribute to our pension plans.
We contributed $10.1 million, $9.6 million and
$11.8 million to our postretirement benefits plans for the
fiscal years ended September 30, 2009, 2008 and 2007. The
contributions represent the portion of the postretirement costs
we are responsible for under the terms of our plan and minimum
funding required by state regulatory commissions.
Outlook
for Fiscal 2010
As of September 30, 2009, interest and corporate bond rates
utilized to determine our discount rates, which impacted our
fiscal 2010 net periodic pension and postretirement costs,
were lower than the interest and corporate bond rates as of
September 30, 2008, the measurement date for our fiscal
2009 net periodic cost. As a result of the lower interest
and corporate bond rates, we decreased the discount rate used to
determine our fiscal 2010 pension and benefit costs to
5.52 percent. We maintained the expected return on our
pension plan assets at 8.25 percent, despite the recent
decline in the financial markets as we believe this rate
reflects the average rate of expected earnings on plan assets
that will fund our projected benefit obligation. Although the
fair value of our plan assets has declined as the financial
markets have declined, the impact of this decline is mitigated
by the fact that assets are smoothed for purposes of determining
net periodic pension cost which results in asset gains and
losses that are recognized over time as a component of net
periodic pension and benefit costs for our Pension Account Plan,
our largest funded plan. Accordingly, we expect our fiscal 2010
pension and postretirement medical costs to be materially the
same as in fiscal 2009. Based upon market conditions subsequent
to September 30, 2009, the current funded position of the
plans and the new funding requirements under the PPA, we believe
it is reasonably possible that we will be required to contribute
to the Plans in fiscal 2010. Further, we will consider whether
an additional voluntary contribution is prudent to maintain
certain PPA funding thresholds. However, we cannot anticipate
with certainty whether such contributions will be made and the
amount of such contributions. With respect to our postretirement
medical plans, we anticipate contributing approximately
$12.2 million during fiscal 2010.
As of September 30, 2009, the Board of Directors approved a
change to the cost sharing methodology for employees who had not
met the participation requirements by that date for the Retiree
Medical Plan for Retirees and Disabled Employees of Atmos Energy
Corporation (the Retiree Medical Plan). Starting in
five
62
years, on January 1, 2015, the contribution rates that will
apply to all non-grandfathered participants will be determined
using a new cost sharing methodology by which Atmos Energy will
limit its contribution to a three percent cost increase in
claims and administrative costs each year. If medical costs
covered by the Retiree Medical Plan increase more than three
percent annually, participants will be responsible for the
additional cost.
During the last fiscal year, the Company has worked with our
independent compensation consultant to develop and implement a
new SERP design for any new executives or current employees
selected for participation in the SERP arrangement on a
prospective basis. Only those executives who are currently
members of our Management Committee as well as those individuals
who may be selected in the future to serve on the Management
Committee, plus those executives who are active SERP
participants as of August 5, 2009, will continue to
participate in the current SERP arrangement until their
respective retirement dates. The current SERP arrangement is a
60 percent of covered compensation defined benefit
arrangement in which benefits from the underlying qualified
defined benefit plan are an offset to the SERP benefit. The new
SERP arrangement for new participants in the Companys
executive retirement program is a modified defined benefit
approach in which the Company will contribute to a nominal
account for each participant, an amount equal to ten percent of
each participants base salary and bonus following the
participants completion of a plan year of service. Other
provisions of the plan mirror that of the Companys
underlying qualified plan, the Pension Account Plan. At this
time, only one employee has been selected for participation in
the new SERP arrangement.
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.
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 natural
gas distribution and natural gas marketing segments. In our
natural gas distribution segment, we use a combination of
physical 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 instruments 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 4 to the 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 and our other short-term borrowings.
Commodity
Price Risk
Natural
gas distribution segment
We purchase natural gas for our natural gas distribution
operations. Substantially all of the costs of gas purchased for
natural gas distribution operations are recovered from our
customers through purchased gas cost
63
adjustment mechanisms. Therefore, our natural gas distribution
operations have limited commodity price risk exposure.
Natural
gas marketing and pipeline, storage and other
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, 2009 of 0.4 Bcf, a $0.50 change in the
forward NYMEX price would have had a $0.2 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, 2009 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 $5.2 million.
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.
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 $3.7 million during 2009.
As of September 30, 2009, 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.
64
|
|
ITEM 8.
|
Financial
Statements and Supplementary Data.
|
Index to financial statements and financial statement schedule:
|
|
|
|
|
|
|
Page
|
|
|
|
|
66
|
|
Financial statements and supplementary data:
|
|
|
|
|
|
|
|
67
|
|
|
|
|
68
|
|
|
|
|
69
|
|
|
|
|
70
|
|
|
|
|
71
|
|
|
|
|
127
|
|
Financial statement schedule for the years ended
September 30, 2009, 2008 and 2007
|
|
|
|
|
|
|
|
135
|
|
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.
65
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
CONSOLIDATED FINANCIAL STATEMENTS
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have audited the accompanying consolidated balance sheets of
Atmos Energy Corporation as of September 30, 2009 and 2008,
and the related consolidated statements of income,
shareholders equity, and cash flows for each of the three
years in the period ended September 30, 2009. 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, 2009 and 2008, and the consolidated results
of its operations and its cash flows for each of the three years
in the period ended September 30, 2009, 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, 2009,
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 16, 2009 expressed an unqualified opinion thereon.
Dallas, Texas
November 16, 2009
66
ATMOS
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands,
|
|
|
|
except share data)
|
|
|
ASSETS
|
Property, plant and equipment
|
|
$
|
5,981,420
|
|
|
$
|
5,650,096
|
|
Construction in progress
|
|
|
105,198
|
|
|
|
80,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,086,618
|
|
|
|
5,730,156
|
|
Less accumulated depreciation and amortization
|
|
|
1,647,515
|
|
|
|
1,593,297
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
4,439,103
|
|
|
|
4,136,859
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
111,203
|
|
|
|
46,717
|
|
Accounts receivable, less allowance for doubtful accounts of
$11,478 in 2009 and $15,301 in 2008
|
|
|
232,806
|
|
|
|
477,151
|
|
Gas stored underground
|
|
|
352,728
|
|
|
|
576,617
|
|
Other current assets
|
|
|
132,203
|
|
|
|
184,619
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
828,940
|
|
|
|
1,285,104
|
|
Goodwill and intangible assets
|
|
|
740,064
|
|
|
|
739,086
|
|
Deferred charges and other assets
|
|
|
335,659
|
|
|
|
225,650
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,343,766
|
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
Shareholders equity
|
|
|
|
|
|
|
|
|
Common stock, no par value (stated at $.005 per share);
200,000,000 shares authorized; issued and outstanding:
|
|
|
|
|
|
|
|
|
2009 92,551,709 shares, 2008
90,814,683 shares
|
|
$
|
463
|
|
|
$
|
454
|
|
Additional paid-in capital
|
|
|
1,791,129
|
|
|
|
1,744,384
|
|
Accumulated other comprehensive loss
|
|
|
(20,184
|
)
|
|
|
(35,947
|
)
|
Retained earnings
|
|
|
405,353
|
|
|
|
343,601
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
|
2,176,761
|
|
|
|
2,052,492
|
|
Long-term debt
|
|
|
2,169,400
|
|
|
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,346,161
|
|
|
|
4,172,284
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
207,421
|
|
|
|
395,388
|
|
Other current liabilities
|
|
|
457,319
|
|
|
|
460,372
|
|
Short-term debt
|
|
|
72,550
|
|
|
|
350,542
|
|
Current maturities of long-term debt
|
|
|
131
|
|
|
|
785
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
737,421
|
|
|
|
1,207,087
|
|
Deferred income taxes
|
|
|
570,940
|
|
|
|
441,302
|
|
Regulatory cost of removal obligation
|
|
|
321,086
|
|
|
|
298,645
|
|
Deferred credits and other liabilities
|
|
|
368,158
|
|
|
|
267,381
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,343,766
|
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
67
ATMOS
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
2,984,765
|
|
|
$
|
3,655,130
|
|
|
$
|
3,358,765
|
|
Regulated transmission and storage segment
|
|
|
209,658
|
|
|
|
195,917
|
|
|
|
163,229
|
|
Natural gas marketing segment
|
|
|
2,336,847
|
|
|
|
4,287,862
|
|
|
|
3,151,330
|
|
Pipeline, storage and other segment
|
|
|
41,924
|
|
|
|
31,709
|
|
|
|
33,400
|
|
Intersegment eliminations
|
|
|
(604,114
|
)
|
|
|
(949,313
|
)
|
|
|
(808,293
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,969,080
|
|
|
|
7,221,305
|
|
|
|
5,898,431
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
|
1,960,137
|
|
|
|
2,649,064
|
|
|
|
2,406,081
|
|
Regulated transmission and storage segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
2,252,235
|
|
|
|
4,194,841
|
|
|
|
3,047,019
|
|
Pipeline, storage and other segment
|
|
|
12,428
|
|
|
|
3,396
|
|
|
|
792
|
|
Intersegment eliminations
|
|
|
(602,422
|
)
|
|
|
(947,322
|
)
|
|
|
(805,543
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,622,378
|
|
|
|
5,899,979
|
|
|
|
4,648,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
1,346,702
|
|
|
|
1,321,326
|
|
|
|
1,250,082
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
494,010
|
|
|
|
500,234
|
|
|
|
463,373
|
|
Depreciation and amortization
|
|
|
217,208
|
|
|
|
200,442
|
|
|
|
198,863
|
|
Taxes, other than income
|
|
|
182,700
|
|
|
|
192,755
|
|
|
|
182,866
|
|
Asset impairments
|
|
|
5,382
|
|
|
|
|
|
|
|
6,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
899,300
|
|
|
|
893,431
|
|
|
|
851,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
447,402
|
|
|
|
427,895
|
|
|
|
398,636
|
|
Miscellaneous income (expense), net
|
|
|
(3,303
|
)
|
|
|
2,731
|
|
|
|
9,184
|
|
Interest charges
|
|
|
152,830
|
|
|
|
137,922
|
|
|
|
145,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
291,269
|
|
|
|
292,704
|
|
|
|
262,584
|
|
Income tax expense
|
|
|
100,291
|
|
|
|
112,373
|
|
|
|
94,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
190,978
|
|
|
$
|
180,331
|
|
|
$
|
168,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share data
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
2.10
|
|
|
$
|
2.02
|
|
|
$
|
1.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
2.08
|
|
|
$
|
2.00
|
|
|
$
|
1.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
91,117
|
|
|
|
89,385
|
|
|
|
86,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
92,024
|
|
|
|
90,272
|
|
|
|
87,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
68
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 and per share data)
|
|
|
Balance, September 30, 2006
|
|
|
81,739,516
|
|
|
$
|
409
|
|
|
$
|
1,467,240
|
|
|
$
|
(43,850
|
)
|
|
$
|
224,299
|
|
|
$
|
1,648,098
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168,492
|
|
|
|
168,492
|
|
Unrealized holding gains on investments, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,241
|
|
|
|
|
|
|
|
1,241
|
|
Treasury lock agreements, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,288
|
|
|
|
|
|
|
|
6,288
|
|
Cash flow hedges, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,123
|
|
|
|
|
|
|
|
20,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
196,144
|
|
Cash dividends ($1.28 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(111,664
|
)
|
|
|
(111,664
|
)
|
Common stock issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Public offering
|
|
|
6,325,000
|
|
|
|
32
|
|
|
|
191,881
|
|
|
|
|
|
|
|
|
|
|
|
191,913
|
|
Direct stock purchase plan
|
|
|
325,338
|
|
|
|
2
|
|
|
|
9,866
|
|
|
|
|
|
|
|
|
|
|
|
9,868
|
|
Retirement savings plan
|
|
|
422,646
|
|
|
|
2
|
|
|
|
12,929
|
|
|
|
|
|
|
|
|
|
|
|
12,931
|
|
1998 Long-term incentive plan
|
|
|
511,584
|
|
|
|
2
|
|
|
|
7,547
|
|
|
|
|
|
|
|
|
|
|
|
7,549
|
|
Employee stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
10,841
|
|
|
|
|
|
|
|
|
|
|
|
10,841
|
|
Outside directors
stock-for-fee
plan
|
|
|
2,453
|
|
|
|
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2007
|
|
|
89,326,537
|
|
|
|
447
|
|
|
|
1,700,378
|
|
|
|
(16,198
|
)
|
|
|
281,127
|
|
|
|
1,965,754
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
180,331
|
|
|
|
180,331
|
|
Unrealized holding losses on investments, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,897
|
)
|
|
|
|
|
|
|
(1,897
|
)
|
Treasury lock agreements, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,148
|
|
|
|
|
|
|
|
3,148
|
|
Cash flow hedges, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,000
|
)
|
|
|
|
|
|
|
(21,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
160,582
|
|
Retroactive charge to record initial uncertain tax
positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(569
|
)
|
|
|
(569
|
)
|
Cash dividends ($1.30 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(117,288
|
)
|
|
|
(117,288
|
)
|
Common stock issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct stock purchase plan
|
|
|
388,485
|
|
|
|
2
|
|
|
|
10,333
|
|
|
|
|
|
|
|
|
|
|
|
10,335
|
|
Retirement savings plan
|
|
|
558,014
|
|
|
|
3
|
|
|
|
15,116
|
|
|
|
|
|
|
|
|
|
|
|
15,119
|
|
1998 Long-term incentive plan
|
|
|
538,450
|
|
|
|
2
|
|
|
|
5,592
|
|
|
|
|
|
|
|
|
|
|
|
5,594
|
|
Employee stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
12,878
|
|
|
|
|
|
|
|
|
|
|
|
12,878
|
|
Outside directors
stock-for-fee
plan
|
|
|
3,197
|
|
|
|
|
|
|
|
87
|
|
|
|
|
|
|
|
|
|
|
|
87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2008
|
|
|
90,814,683
|
|
|
|
454
|
|
|
|
1,744,384
|
|
|
|
(35,947
|
)
|
|
|
343,601
|
|
|
|
2,052,492
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
190,978
|
|
|
|
190,978
|
|
Unrealized holding losses on investments, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,820
|
)
|
|
|
|
|
|
|
(1,820
|
)
|
Other than temporary impairment of investments, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,370
|
|
|
|
|
|
|
|
3,370
|
|
Treasury lock agreements, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,606
|
|
|
|
|
|
|
|
3,606
|
|
Cash flow hedges, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,607
|
|
|
|
|
|
|
|
10,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
206,741
|
|
Change in measurement date for employee benefit plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,766
|
)
|
|
|
(7,766
|
)
|
Cash dividends ($1.32 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121,460
|
)
|
|
|
(121,460
|
)
|
Common stock issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct stock purchase plan
|
|
|
407,262
|
|
|
|
2
|
|
|
|
8,743
|
|
|
|
|
|
|
|
|
|
|
|
8,745
|
|
Retirement savings plan
|
|
|
640,639
|
|
|
|
3
|
|
|
|
16,571
|
|
|
|
|
|
|
|
|
|
|
|
16,574
|
|
1998 Long-term incentive plan
|
|
|
686,046
|
|
|
|
4
|
|
|
|
8,075
|
|
|
|
|
|
|
|
|
|
|
|
8,079
|
|
Employee stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
13,280
|
|
|
|
|
|
|
|
|
|
|
|
13,280
|
|
Outside directors
stock-for-fee
plan
|
|
|
3,079
|
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2009
|
|
|
92,551,709
|
|
|
$
|
463
|
|
|
$
|
1,791,129
|
|
|
$
|
(20,184
|
)
|
|
$
|
405,353
|
|
|
$
|
2,176,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
69
ATMOS
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
190,978
|
|
|
$
|
180,331
|
|
|
$
|
168,492
|
|
Adjustments to reconcile net income to net cash provided
|
|
|
|
|
|
|
|
|
|
|
|
|
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset impairments
|
|
|
5,382
|
|
|
|
|
|
|
|
6,344
|
|
Depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Charged to depreciation and amortization
|
|
|
217,208
|
|
|
|
200,442
|
|
|
|
198,863
|
|
Charged to other accounts
|
|
|
94
|
|
|
|
147
|
|
|
|
192
|
|
Deferred income taxes
|
|
|
129,759
|
|
|
|
97,940
|
|
|
|
62,121
|
|
Stock-based compensation
|
|
|
14,494
|
|
|
|
14,032
|
|
|
|
11,934
|
|
Debt financing costs
|
|
|
10,364
|
|
|
|
10,665
|
|
|
|
10,852
|
|
Other
|
|
|
(1,177
|
)
|
|
|
(5,492
|
)
|
|
|
(1,516
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) decrease in accounts receivable
|
|
|
244,713
|
|
|
|
(97,018
|
)
|
|
|
(6,407
|
)
|
(Increase) decrease in gas stored underground
|
|
|
194,287
|
|
|
|
(54,726
|
)
|
|
|
(12,317
|
)
|
(Increase) decrease in other current assets
|
|
|
117,737
|
|
|
|
(120,882
|
)
|
|
|
71,279
|
|
(Increase) decrease in deferred charges and other assets
|
|
|
(106,231
|
)
|
|
|
22,476
|
|
|
|
23,506
|
|
Increase (decrease) in accounts payable and accrued liabilities
|
|
|
(181,978
|
)
|
|
|
39,902
|
|
|
|
(8,428
|
)
|
Increase (decrease) in other current liabilities
|
|
|
(717
|
)
|
|
|
60,026
|
|
|
|
11,661
|
|
Increase in deferred credits and other liabilities
|
|
|
84,320
|
|
|
|
23,090
|
|
|
|
10,519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
919,233
|
|
|
|
370,933
|
|
|
|
547,095
|
|
CASH FLOWS USED IN INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(509,494
|
)
|
|
|
(472,273
|
)
|
|
|
(392,435
|
)
|
Other, net
|
|
|
(7,707
|
)
|
|
|
(10,736
|
)
|
|
|
(10,436
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(517,201
|
)
|
|
|
(483,009
|
)
|
|
|
(402,871
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in short-term debt
|
|
|
(283,981
|
)
|
|
|
200,174
|
|
|
|
(213,242
|
)
|
Net proceeds from issuance of long-term debt
|
|
|
445,623
|
|
|
|
|
|
|
|
247,217
|
|
Settlement of Treasury lock agreement
|
|
|
1,938
|
|
|
|
|
|
|
|
4,750
|
|
Repayment of long-term debt
|
|
|
(407,353
|
)
|
|
|
(10,284
|
)
|
|
|
(303,185
|
)
|
Cash dividends paid
|
|
|
(121,460
|
)
|
|
|
(117,288
|
)
|
|
|
(111,664
|
)
|
Issuance of common stock
|
|
|
27,687
|
|
|
|
25,466
|
|
|
|
24,897
|
|
Net proceeds from equity offering
|
|
|
|
|
|
|
|
|
|
|
191,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(337,546
|
)
|
|
|
98,068
|
|
|
|
(159,314
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
64,486
|
|
|
|
(14,008
|
)
|
|
|
(15,090
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
46,717
|
|
|
|
60,725
|
|
|
|
75,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
111,203
|
|
|
$
|
46,717
|
|
|
$
|
60,725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
70
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Atmos Energy Corporation (Atmos Energy or the
Company) and our subsidiaries are engaged primarily
in the regulated natural gas distribution and transmission and
storage businesses as well as certain other nonregulated
businesses. Through our natural gas distribution business, we
deliver natural gas through sales and transportation
arrangements to over 3 million residential, commercial,
public-authority and industrial customers through our six
regulated natural gas distribution divisions in the service
areas described below:
|
|
|
Division
|
|
Service Area
|
|
Atmos Energy Colorado-Kansas Division
|
|
Colorado, Kansas,
Missouri(1)
|
Atmos Energy Kentucky/Mid-States Division
|
|
Georgia(1),
Illinois(1),
Iowa(1),
Kentucky,
Missouri(1),
Tennessee,
Virginia(1)
|
Atmos Energy Louisiana Division
|
|
Louisiana
|
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) |
|
Denotes locations where we have more limited service areas. |
In addition, we transport natural gas for others through our
distribution system. Our natural gas distribution business is
subject to federal and state regulation
and/or
regulation by local authorities in each of the states in which
our natural gas distribution divisions operate. Our corporate
headquarters and shared-services function are located in Dallas,
Texas, and our customer support centers are located in Amarillo
and Waco, Texas.
Our regulated transmission and storage business consists of the
regulated operations of our Atmos Pipeline Texas
Division, a division of the Company. This 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 to 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. Lending
services provide short-term interruptible loans of natural gas
from our pipeline to meet market demands.
Our nonregulated businesses operate primarily in the Midwest and
Southeast and include our natural gas marketing operations and
our pipeline, storage and other operations. These businesses are
operated through various wholly-owned subsidiaries of Atmos
Energy Holdings, Inc. (AEH), which is wholly-owned by the
Company and based in Houston, Texas.
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 Colorado-Kansas, Kentucky/Mid-States and Louisiana
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 financial
instruments.
Our pipeline, storage and other segment consists primarily of
the operations of Atmos Pipeline and Storage, LLC (APS). APS is
engaged in nonregulated transmission, storage and natural
gas-gathering services. Its primary asset is a proprietary
21 mile pipeline located in New Orleans, Louisiana that is
primarily used to aggregate gas supply for our regulated natural
gas distribution division in Louisiana and for our natural gas
71
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
marketing segment, and, on a more limited basis, to third
parties. APS also owns or has an interest in underground storage
fields in Kentucky and Louisiana that are used to reduce the
need of our natural gas distribution divisions to contract for
additional pipeline capacity to meet customer demand during peak
periods.
APS also engages in asset optimization activities whereby it
seeks to maximize the economic value associated with the storage
and transportation capacity it owns or controls. Certain of
these arrangements are with regulated affiliates of the Company
which have been approved by applicable state regulatory
commissions. Generally, these asset management plans require APS
to share with our regulated customers a portion of the profits
earned from these arrangements. APS also seeks to maximize the
economic value associated with the storage and transportation
capacity it owns or controls by engaging in natural gas storage
transactions in which we seek to find and profit from the
pricing differences that occur over time.
|
|
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 obligations, impairment of long-lived assets, risk
management and trading activities, fair value measurements and
the valuation of goodwill, indefinite-lived intangible assets
and other long-lived assets. Actual results could differ from
those estimates.
Regulation Our natural gas distribution and
regulated transmission and storage 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. Accounting principles generally accepted
in the United States require cost-based, rate-regulated entities
that meet certain criteria to reflect the authorized recovery of
costs due to regulatory decisions in their financial statements.
As a result, certain costs are permitted to be capitalized
rather than expensed because they can be recovered through rates.
We record regulatory assets 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
72
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
be reduced for amounts that will be credited to customers
through the ratemaking process. Significant regulatory assets
and liabilities as of September 30, 2009 and 2008 included
the following:
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit costs
|
|
$
|
197,743
|
|
|
$
|
100,563
|
|
Merger and integration costs, net
|
|
|
7,161
|
|
|
|
7,586
|
|
Deferred gas costs
|
|
|
22,233
|
|
|
|
55,103
|
|
Environmental costs
|
|
|
866
|
|
|
|
980
|
|
Rate case costs
|
|
|
5,923
|
|
|
|
12,885
|
|
Deferred franchise fees
|
|
|
10,014
|
|
|
|
651
|
|
Deferred income taxes, net
|
|
|
639
|
|
|
|
343
|
|
Other
|
|
|
6,218
|
|
|
|
8,120
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
250,797
|
|
|
$
|
186,231
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
110,754
|
|
|
$
|
76,979
|
|
Regulatory cost of removal obligation
|
|
|
335,428
|
|
|
|
317,273
|
|
Other
|
|
|
7,960
|
|
|
|
5,639
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
454,142
|
|
|
$
|
399,891
|
|
|
|
|
|
|
|
|
|
|
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. Environmental costs
have been deferred to be included in future rate filings in
accordance with rulings received from various state regulatory
commissions. During the fiscal years ended September 30,
2009, 2008 and 2007, we recognized $0.4 million,
$0.4 million and $0.3 million in amortization expense
related to these costs.
Revenue recognition Sales of natural gas to
our natural gas distribution customers are billed on a monthly
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 natural gas distribution
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. During the year ended September 30, 2009 we
recognized a non-recurring $7.6 million increase in gross
profit associated with a one-time update to our estimate for gas
delivered to customers but not yet billed, resulting from base
rate changes in several jurisdictions.
On occasion, we are permitted to implement new rates that have
not been formally approved by our state regulatory commissions,
which are subject to refund. As permitted by accounting
principles generally accepted in the United States, 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 costs through
purchased gas cost adjustment mechanisms. Purchased gas cost
adjustment mechanisms provide gas utility companies a method of
recovering purchased gas costs on an ongoing basis without
filing a rate case to address all of the utility companys
non-gas costs. There is no gross profit generated through
purchased gas cost adjustments, but they provide a
dollar-for-dollar offset to increases or decreases in our
natural gas
73
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
distribution segments gas costs. The effects of these
purchased gas cost adjustment mechanisms are recorded as
deferred gas costs on our balance sheet.
Operating revenues for our natural gas marketing segment and the
associated carrying value of natural gas inventory (inclusive of
storage costs) are recognized when we sell the gas and
physically deliver it to our customers. Operating revenues
include realized gains and losses arising from the settlement of
financial instruments used in our natural gas marketing
activities and unrealized gains and losses arising from changes
in the fair value of natural gas inventory designated as a
hedged item in a fair value hedge and the associated financial
instruments. For the fiscal years ended September 30, 2009,
2008 and 2007, we included unrealized gains (losses) on open
contracts of $(28.4) million, $25.5 million and
$18.4 million as a component of natural gas marketing
revenues.
Operating revenues for our regulated transmission and storage
and pipeline, storage and other segments are recognized in the
period in which actual volumes are transported and storage
services are provided.
Cash and cash equivalents We consider all
highly liquid investments with an original maturity of three
months or less to be cash equivalents.
Accounts receivable and allowance for doubtful accounts
Accounts receivable arise from natural gas sales
to residential, commercial, industrial, municipal and other
customers. For the majority of our receivables, we establish an
allowance for doubtful accounts based on our collection
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
affected. 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 natural gas
distribution operations and natural gas held by our natural gas
marketing and other nonregulated subsidiaries to conduct their
operations. The average cost method is used for all our
regulated operations, except for certain jurisdictions in the
Kentucky/Mid-States Division, where it is valued on the
first-in
first-out method basis, in accordance with regulatory
requirements. Our natural gas marketing and pipeline, storage
and other segments utilize the average cost method; however,
most of this inventory is hedged and is therefore reported at
fair value 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.
Regulated property, plant and equipment
Regulated 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
$4.9 million, $2.9 million and $3.0 million was
capitalized in 2009, 2008 and 2007.
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 regulated plant in service account included
in the rate base and depreciation begins.
74
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Regulated property, plant and equipment is depreciated at
various rates on a straight-line basis. 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 3.8 percent, 3.7 percent and
3.9 percent for the fiscal years ended September 30,
2009, 2008 and 2007.
Nonregulated property, plant and equipment
Nonregulated 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 three to 35 years.
Asset retirement obligations 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, 2009 and 2008, we recorded asset
retirement obligations of $13.0 million and
$5.9 million. Additionally, we recorded $3.9 million
and $1.3 million of asset retirement costs as a component
of property, plant and equipment that will be depreciated over
the remaining life of the underlying associated assets.
We believe we have a legal obligation to retire our natural gas
storage wells when we take them out of service period
permanently. However, we have not recognized an asset retirement
obligation associated with our storage wells because we are not
able to determine the settlement date of this obligation as we
do not anticipate taking our storage wells out of service
permanently. Therefore, we cannot reasonably estimate the fair
value of this obligation.
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 value of the asset, an impairment loss equal
to the excess of the assets carrying value over its fair
value is recorded.
During fiscal 2007, we recorded a $6.3 million charge
associated with the write-off of approximately $3.0 million
of costs related to a nonregulated natural gas gathering project
and approximately $3.3 million of obsolete software costs.
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. No impairment has been
recognized.
75
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Marketable securities As of
September 30, 2009 and 2008, all of our marketable
securities were classified as available-for-sale. In accordance
with the authoritative accounting standards, 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.
Due to the deterioration of the financial markets in late
calendar 2008 and early calendar 2009 and the uncertainty of a
full recovery of these investments given the current economic
environment, we recorded a $5.4 million noncash charge to
impair certain available-for-sale investments during fiscal 2009.
Financial instruments and hedging activities
We currently use financial instruments to
mitigate commodity price risk. Additionally, we periodically use
financial instruments to manage interest rate risk. The
objectives and strategies for using financial instruments have
been tailored for our regulated and nonregulated businesses.
Currently, we utilize financial instruments in our natural gas
distribution, natural gas marketing and pipeline, storage and
other segments. The objectives and strategies for the use of
financial instruments are discussed in Note 4.
We record all of our financial instruments on the balance sheet
at fair value, with changes in fair value ultimately
recorded in the income statement. These financial instruments
are reported as risk management assets and liabilities and are
classified as current or noncurrent other assets or liabilities
based upon the anticipated settlement date of the underlying
financial instrument.
The timing of when changes in fair value of our financial
instruments are recorded in the income statement depends on
whether the financial instrument has been designated and
qualifies as a part of a hedging relationship or if regulatory
rulings require a different accounting treatment. Changes in
fair value for financial instruments that do not meet one of
these criteria are recognized in the income statement as they
occur.
Financial
Instruments Associated with Commodity Price Risk
In our natural gas distribution segment, the costs associated
with and the gains and losses arising from the use of financial
instruments to mitigate commodity price risk are included in our
purchased gas cost adjustment mechanisms in accordance with
regulatory requirements. Therefore, changes in the fair value of
these financial instruments are initially recorded as a
component of deferred gas costs and recognized in the
consolidated statement of income as a component of purchased gas
cost when the related costs are recovered through our rates and
recognized in revenue in accordance with accounting principles
generally accepted in the United States. Accordingly, there is
no earnings impact to our natural gas distribution segment as a
result of the use of financial instruments.
In our natural gas marketing and pipeline, storage and other
segments, we have designated the natural gas inventory held by
these operating segments as the hedged item in a fair-value
hedge. This inventory is marked to market at the end of each
month based on the Gas Daily index, with changes in fair value
recognized as unrealized gains or losses in revenue in the
period of change. The financial instruments associated with this
natural gas inventory have been designated as fair-value hedges
and are marked to market each month based upon the NYMEX price
with changes in fair value recognized as unrealized gains or
losses in revenue in the period of change. Changes in the
spreads between the forward natural gas prices used to value the
financial hedges designated against our physical inventory
(NYMEX) and the market (spot) prices used to value our physical
storage (Gas Daily) result in unrealized margins until the
underlying physical gas is withdrawn and the related financial
instruments are settled. Once the gas is withdrawn and the
financial instruments are settled, the previously unrealized
margins associated with these net positions are realized. We
have elected to exclude this spot/forward differential for
purposes of assessing the effectiveness of these fair-value
hedges.
76
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
In our natural gas marketing segment, we have elected to treat
fixed-price forward contracts to deliver natural gas as normal
purchases and normal sales. As such, these deliveries are
recorded on an accrual basis in accordance with our revenue
recognition policy. Financial instruments used to mitigate the
commodity price risk associated with these contracts have been
designated as cash flow hedges of anticipated purchases and
sales at indexed prices. Accordingly, unrealized gains and
losses on these open financial instruments are 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.
Gains and losses from hedge ineffectiveness are recognized in
the income statement. Fair value and cash flow hedge
ineffectiveness arising from natural gas market price
differences between the locations of the hedged inventory and
the delivery location specified in the financial instruments is
referred to as basis ineffectiveness. Ineffectiveness arising
from changes in the fair value of the fair value hedges due to
changes in the difference between the spot price and the futures
price, as well as the difference between the timing of the
settlement of the futures and the valuation of the underlying
physical commodity are referred to as timing ineffectiveness.
In our natural gas marketing segment, we also utilize master
netting agreements with significant counterparties that allow us
to offset gains and losses arising from financial instruments
that may be settled in cash with gains and losses arising from
financial 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. Additionally, the
accounting guidance for master netting arrangements requires us
to include the fair value of cash collateral or the obligation
to return cash in the amounts that have been netted under master
netting agreements used to offset gains and losses arising from
financial instruments. The Company adopted this standard as of
September 30, 2008. As of September 30, 2009 and 2008,
the Company netted $11.7 million and $56.6 million of
cash held in margin accounts into its current risk management
assets and liabilities.
Financial
Instruments Associated with Interest Rate Risk
We periodically manage interest rate risk, typically when we
issue new or refinance existing long-term debt. Currently, we do
not have any financial instruments in place to manage interest
rate risk. However, in prior years, we entered into Treasury
lock agreements to fix the Treasury yield component of the
interest cost associated with anticipated financings. We
designated these Treasury lock agreements as a cash flow hedge
of an anticipated transaction at the time the agreements were
executed. Accordingly, unrealized gains and losses associated
with the Treasury lock agreements were recorded as a component
of accumulated other comprehensive income (loss). When the
Treasury locks were settled, the realized gain or loss was
recorded as a component of accumulated other comprehensive
income (loss) and is being recognized as a component of interest
expense over the life of the related financing arrangement.
Fair Value Measurements We report certain
assets and liabilities at fair value, which is defined as the
price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). We primarily
use quoted market prices and other observable market pricing
information in valuing our financial assets and liabilities and
minimize the use of unobservable pricing inputs in our
measurements.
Prices actively quoted on national exchanges are used to
determine the fair value of most of our assets and liabilities
recorded on our balance sheet at fair value. Within our
nonregulated operations, we utilize a
77
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
mid-market pricing convention (the mid-point between the bid and
ask prices) as a practical expedient for determining fair value
measurement, as permitted under current accounting standards.
Values derived from these sources reflect the market in which
transactions involving these financial instruments are executed.
We utilize models and other valuation methods to determine fair
value when external sources are not available. 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. We believe the market
prices and models used to value these assets and liabilities
represent the best information available with respect to closing
exchange and over-the-counter quotations, time value and
volatility factors underlying the assets and liabilities.
Fair-value estimates also consider our own creditworthiness and
the creditworthiness of the counterparties involved. Our
counterparties consist primarily of financial institutions and
major energy companies. This concentration of counterparties may
materially impact our exposure to credit risk resulting from
market, economic or regulatory conditions. Recent adverse
developments in the global financial and credit markets have
made it more difficult and more expensive for companies to
access the short-term capital markets, which may negatively
impact the creditworthiness of our counterparties. A continued
tightening of the credit markets could cause more of our
counterparties to fail to perform. We seek to minimize
counterparty credit risk through an evaluation of their
financial condition and credit ratings and the use of collateral
requirements under certain circumstances.
Amounts reported at fair value are subject to potentially
significant volatility based upon 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
financial instruments. We believe the market prices and models
used to value these financial instruments 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.
Authoritative accounting literature establishes a fair value
hierarchy that prioritizes the inputs used to measure fair value
based on observable and unobservable data. The hierarchy
categorizes the inputs into three levels, with the highest
priority given to unadjusted quoted prices in active markets for
identical assets and liabilities (Level 1) and the
lowest priority given to unobservable inputs (Level 3). The
levels of the hierarchy are described below:
Level 1 Unadjusted quoted prices in
active markets for identical assets or liabilities. An active
market for the asset or liability is defined as a market in
which transactions for the asset or liability occur with
sufficient frequency and volume to provide pricing information
on an ongoing basis. Our Level 1 measurements consist
primarily of exchange-traded financial instruments, gas stored
underground that has been designated as the hedged item in a
fair value hedge and our available-for-sale securities.
Level 2 Pricing inputs other than quoted
prices included in Level 1 that are either directly or
indirectly observable for the asset or liability as of the
reporting date. These inputs are derived principally from, or
corroborated by, observable market data. Our Level 2
measurements primarily consist of non-exchange-traded financial
instruments, such as over-the-counter options and swaps where
market data for pricing is observable.
Level 3 Generally unobservable pricing
inputs which are developed based on the best information
available, including our own internal data, in situations where
there is little if any market activity for the asset or
liability at the measurement date. The pricing inputs utilized
reflect what a market participant would use to determine fair
value. Currently, we have no assets or liabilities recorded at
fair value that would qualify for Level 3 reporting.
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
78
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
demographic and actuarial mortality data. Through fiscal 2008,
we reviewed the estimates and assumptions underlying our pension
and other postretirement plan costs and liabilities annually
based upon a June 30 measurement date. To comply with the new
measurement date requirements established by the Financial
Accounting Standards Board (FASB) and incorporated into
accounting principles generally accepted in the United States,
effective October 1, 2008, we changed our measurement date
from June 30 to our fiscal year end, September 30. This
change is more fully discussed in Note 8. 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, 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 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 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 costs over a period of
approximately ten to twelve years.
We estimate the assumed health care cost trend rate used in
determining our annual 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 the 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.
The Company may recognize the tax benefit from uncertain tax
positions only if it is at least more likely than not that the
tax position will be sustained on examination by the taxing
authorities, based on the technical merits of the position. The
tax benefits recognized in the financial statements from such a
position should be measured based on the largest benefit that
has a greater than fifty percent likelihood of being realized
upon settlement with the taxing authorities. We recognize
accrued interest related to unrecognized tax benefits as a
component of interest expense. We recognize penalties related to
unrecognized tax benefits as a component of miscellaneous income
(expense) in accordance with regulatory requirements.
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,
time-lapse restricted stock units, 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
79
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
Accumulated other comprehensive loss
Accumulated other comprehensive loss, net of
tax, as of September 30, 2009 and 2008 consisted of the
following unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Unrealized holding gains on investments
|
|
$
|
2,460
|
|
|
$
|
910
|
|
Treasury lock agreements
|
|
|
(7,498
|
)
|
|
|
(11,104
|
)
|
Cash flow hedges
|
|
|
(15,146
|
)
|
|
|
(25,753
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(20,184
|
)
|
|
$
|
(35,947
|
)
|
|
|
|
|
|
|
|
|
|
Subsequent events In May 2009, the FASB
issued guidance related to subsequent events which establishes
general standards of accounting for and disclosure of events
that occur after the balance sheet date but before the date the
financial statements are issued or available to be issued.
Companies are required to reflect in their financial statements
the effects of subsequent events that provide additional
evidence about conditions at the balance-sheet date. Subsequent
events that provide evidence about conditions that arose after
the balance-sheet date should be disclosed if the financial
statements would otherwise be misleading. We adopted the
provisions of this guidance as of June 30, 2009.
We have evaluated subsequent events from the September 30,
2009 balance sheet date through the date these financial
statements were filed with the Securities and Exchange
Commission. No events occurred subsequent to the balance sheet
date that would require recognition or disclosure in the
financial statements.
Recent accounting pronouncements In June
2009, the FASB issued an update to the accounting for transfers
of financial assets. This guidance clarifies the information
that must be disclosed related to a transfer of financial
assets; the effects of a transfer on the transferors
financial position, financial performance, and cash flows; and a
transferors continuing involvement, if any, in transferred
financial assets. The standard also removes the concept of a
qualifying special-purpose entity for accounting purposes.
Therefore, after the effective date, formerly qualifying
special-purpose entities (as defined under previous accounting
standards) must be evaluated for consolidation by companies on
and after the effective date in accordance with the applicable
consolidation guidance. The provisions of this standard will be
effective for us beginning October 1, 2009. The adoption of
this standard is not expected to have a material impact on our
financial position, results of operations or cash flows.
In June 2009, the FASB issued an update to the criteria used to
determine if an entity has a controlling interest in a variable
interest entity. The updated criteria are intended to be
primarily qualitative and result in a more effective method for
identifying which enterprise has a controlling financial
interest in a variable interest entity. Additionally, the
standard enhances the disclosure requirements for entities that
hold a variable interest in a variable interest entity. The
provisions of this standard will be effective for us beginning
October 1, 2009. The adoption of this standard is not
expected to have a material impact on our financial position,
results of operations or cash flows.
In June 2009, the FASB issued the FASB Accounting Standards
Codification (Codification) which supersedes all existing
non-SEC accounting and reporting standards and becomes the
source of authoritative U.S. generally accepted accounting
principles (GAAP) recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the
Securities and Exchange Commission (SEC) under authority of
federal securities laws are also sources of authoritative GAAP
for SEC registrants. All other nongrandfathered non-SEC
accounting literature not included in the Codification will
become nonauthoritative
80
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
upon the effective date. The Codification is effective for us
for the year ended September 30, 2009. The adoption of this
standard did not have an impact on our financial position,
results of operations or cash flows.
In December 2008, the FASB issued guidance which requires
employers to disclose information about fair value measurements
of plan assets of a defined benefit pension or other
postretirement plan in a manner similar to the requirements
established for financial and non-financial assets. The
objectives of the required disclosures are to provide users of
financial statements with an understanding of how investment
allocation decisions are made, the major categories of plan
assets, the inputs and valuation techniques used to measure fair
value of plan assets and significant concentrations of risk
within plan assets. The provisions of this standard will be
effective for us beginning October 1, 2009. This standard
is not expected to have a material impact on our financial
position, results of operations or cash flows.
In June 2008, the FASB issued guidance related to determining
whether instruments granted in share-based payment transactions
are participating securities. Based on this guidance, the
Company will include non-vested shares granted under its 1998
Long-Term Incentive Plan in the basic earnings per share
calculation. The provisions of this standard will be effective
for us beginning October 1, 2009, at which time all
prior-period earnings per share data will be adjusted. This
standard is not expected to have a material impact on our
financial position, results of operations or cash flows.
In April 2008, the FASB issued guidance which amends the factors
that should be considered in developing renewal or extension
assumptions used to determine the useful life of intangible
assets. The objective of the standard is to better match the
useful life of intangible assets to the cash flow generated. The
provisions of this standard will be effective for us beginning
October 1, 2009. This standard is not expected to have a
material impact on our financial position, results of operations
or cash flows.
In December 2007, the FASB issued an update to business
combination accounting. The new pronouncement establishes
principles and requirements for how the acquirer in a business
combination recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed and
any noncontrolling interest in the acquiree at the acquisition
date fair value. This update significantly changes the
accounting for business combinations in a number of areas,
including the treatment of contingent consideration,
preacquisition contingencies, transaction costs and
restructuring costs. In addition, under the new guidelines,
changes in an acquired entitys deferred tax assets and
uncertain tax positions after the measurement period could
impact income tax expense. The provisions of this standard will
apply to any acquisitions we complete after October 1, 2009.
In December 2007, the FASB issued guidance related to the
accounting and reporting for minority interests, which will be
recharacterized as noncontrolling interests and classified as a
component of equity. This new consolidation method significantly
changes the accounting for transactions with minority interest
holders. The provisions of the standard will be effective for us
beginning October 1, 2009. This standard is not expected to
have a material impact on our financial position, results of
operations or cash flows.
|
|
3.
|
Goodwill
and Intangible Assets
|
Goodwill and intangible assets were comprised of the following
as of September 30, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Goodwill
|
|
$
|
738,603
|
|
|
$
|
736,998
|
|
Intangible assets
|
|
|
1,461
|
|
|
|
2,088
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
740,064
|
|
|
$
|
739,086
|
|
|
|
|
|
|
|
|
|
|
81
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following presents our goodwill balance allocated by segment
and changes in the balance for the fiscal year ended
September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Transmission
|
|
|
Natural Gas
|
|
|
Pipeline, Storage
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
and Other
|
|
|
|
|
|
|
Segment
|
|
|
Segment
|
|
|
Segment
|
|
|
Segment
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance as of September 30, 2008
|
|
$
|
569,920
|
|
|
$
|
132,367
|
|
|
$
|
24,282
|
|
|
$
|
10,429
|
|
|
$
|
736,998
|
|
Deferred tax adjustments on prior
acquisitions(1)
|
|
|
1,672
|
|
|
|
(67
|
)
|
|
|
|
|
|
|
|
|
|
|
1,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2009
|
|
$
|
571,592
|
|
|
$
|
132,300
|
|
|
$
|
24,282
|
|
|
$
|
10,429
|
|
|
$
|
738,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the preparation of the fiscal 2009 tax provision, we
adjusted certain deferred taxes recorded in connection with
acquisitions completed in fiscal 2001 and fiscal 2004, which
resulted in an increase to goodwill and net deferred tax
liabilities of $1.6 million. |
Information regarding our intangible assets is reflected in the
following table. As of September 30, 2009 and 2008, we had
no intangible assets with indefinite lives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009
|
|
September 30, 2008
|
|
|
Useful
|
|
Gross
|
|
|
|
|
|
Gross
|
|
|
|
|
|
|
Life
|
|
Carrying
|
|
Accumulated
|
|
|
|
Carrying
|
|
Accumulated
|
|
|
|
|
(Years)
|
|
Amount
|
|
Amortization
|
|
Net
|
|
Amount
|
|
Amortization
|
|
Net
|
|
|
(In thousands)
|
|
Customer contracts
|
|
|
10
|
|
|
$
|
6,926
|
|
|
$
|
(5,465
|
)
|
|
$
|
1,461
|
|
|
$
|
6,926
|
|
|
$
|
(4,838
|
)
|
|
$
|
2,088
|
|
The following table presents actual amortization expense
recognized during 2009 and an estimate of future amortization
expense based upon our intangible assets at September 30,
2009.
|
|
|
|
|
Amortization expense (in thousands):
|
|
|
|
|
Actual for the fiscal year ending September 30, 2009
|
|
$
|
627
|
|
Estimated for the fiscal year ending:
|
|
|
|
|
September 30, 2010
|
|
|
627
|
|
September 30, 2011
|
|
|
627
|
|
September 30, 2012
|
|
|
43
|
|
September 30, 2013
|
|
|
43
|
|
September 30, 2014
|
|
|
43
|
|
We currently use financial instruments to mitigate commodity
price risk. Additionally, we periodically utilize financial
instruments to manage interest rate risk. The objectives and
strategies for using financial instruments have been tailored to
our regulated and nonregulated businesses. Currently, we utilize
financial instruments in our natural gas distribution, natural
gas marketing and pipeline, storage and other segments. However,
our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment.
As discussed in Note 2, we report our financial instruments
as risk management assets and liabilities, each of which is
classified as current or noncurrent based upon the anticipated
settlement date of the
82
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
underlying financial instrument. The following table shows the
fair values of our risk management assets and liabilities by
segment at September 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management activities,
current(1)
|
|
$
|
4,395
|
|
|
$
|
27,248
|
|
|
$
|
31,643
|
|
Assets from risk management activities, noncurrent
|
|
|
1,620
|
|
|
|
12,415
|
|
|
|
14,035
|
|
Liabilities from risk management activities, current
|
|
|
(20,181
|
)
|
|
|
(1,301
|
)
|
|
|
(21,482
|
)
|
Liabilities from risk management activities, noncurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
(14,166
|
)
|
|
$
|
38,362
|
|
|
$
|
24,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management activities,
current(2)
|
|
$
|
|
|
|
$
|
68,291
|
|
|
$
|
68,291
|
|
Assets from risk management activities, noncurrent
|
|
|
|
|
|
|
5,473
|
|
|
|
5,473
|
|
Liabilities from risk management activities,
current(2)
|
|
|
(58,566
|
)
|
|
|
(348
|
)
|
|
|
(58,914
|
)
|
Liabilities from risk management activities, noncurrent
|
|
|
(5,111
|
)
|
|
|
(258
|
)
|
|
|
(5,369
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
(63,677
|
)
|
|
$
|
73,158
|
|
|
$
|
9,481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $11.7 million of cash held on deposit to
collateralize certain financial instruments which is classified
as current risk management assets. |
|
(2) |
|
Includes $56.6 million of cash held on deposit in margin
accounts to collateralize certain financial instruments. Of this
amount, $29.8 million was used to offset current risk
management liabilities under master netting agreements and the
remaining $26.8 million is classified as current risk
management assets. |
Regulated
Commodity Risk Management Activities
Although our purchased gas cost adjustment mechanisms
essentially insulate our natural gas distribution segment from
commodity price risk, our natural gas distribution customers are
exposed to the effect of volatile natural gas prices. We manage
this exposure through a combination of physical storage,
fixed-price forward contracts and financial instruments,
primarily over-the-counter swap and option contracts, in an
effort to minimize the impact of natural gas price volatility on
our customers during the winter heating season.
Our natural gas distribution gas supply department is
responsible for executing this segments commodity risk
management activities in conformity with regulatory
requirements. In jurisdictions where we are permitted to
mitigate commodity price risk through financial instruments, the
relevant regulatory authorities may establish the level of
heating season gas purchases that can be hedged. Historically,
if the regulatory authority does not establish this level, we
seek to hedge between 25 and 50 percent of anticipated
heating season gas purchases using financial instruments. For
the
2008-2009
heating season, in the jurisdictions where we are permitted to
utilize financial instruments, we hedged approximately
27 percent, or 24.3 Bcf of the planned winter flowing
gas requirements at a weighted average cost of approximately
$10.15 per Mcf.
We currently do not manage commodity price risk with financial
instruments in our regulated transmission and storage segment.
Nonregulated
Commodity Risk Management Activities
Our natural gas marketing segment, through AEM, aggregates and
purchases gas supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To
83
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
facilitate this process, we utilize proprietary and
customer-owned transportation and storage assets to provide the
various services our customers request.
We also perform asset optimization activities in both our
natural gas marketing segment and pipeline, storage and other
segment. Through asset optimization activities, we seek to
enhance our gross profit by maximizing the economic value
associated with the storage and transportation capacity we own
or control. We attempt to meet this objective by engaging 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
instruments at advantageous prices to lock in a gross profit
margin. Through the use of transportation and storage services
and financial instruments, we also seek to capture gross profit
margin through the arbitrage of pricing differences that exist
in various locations and by recognizing pricing differences that
occur over time. Over time, gains and losses on the sale of
storage gas inventory will be offset by gains and losses on the
financial instruments, resulting in the realization of the
economic gross profit margin we anticipated at the time we
structured the original transaction.
As a result of these activities, our nonregulated operations are
exposed to risks associated with changes in the market price of
natural gas. We manage our exposure to such risks through a
combination of physical storage and financial instruments,
including futures, over-the-counter and exchange-traded options
and swap contracts with counterparties. Future contracts provide
the right to buy or sell the commodity at a fixed price in the
future. 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.
We use financial instruments, designated as cash flow hedges of
anticipated purchases and sales at index prices, to mitigate the
commodity price risk in our natural gas marketing segment
associated with deliveries under fixed-priced forward contracts
to deliver gas to customers, and we use financial instruments,
designated as fair value hedges, to hedge our natural gas
inventory used in our asset optimization activities in our
natural gas marketing and pipeline, storage and other segments.
Also, in our natural gas marketing segment, we use 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. These financial
instruments have not been designated as hedges.
Our nonregulated risk management activities are controlled
through various risk management policies and procedures. Our
Audit Committee has oversight responsibility for our
nonregulated risk management limits and policies. Our risk
management committee, comprised of corporate and business unit
officers, is responsible for establishing and enforcing our
nonregulated risk management policies and procedures.
Under our risk management policies, we seek to match our
financial instrument 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. At the close of business on September 30, 2009,
AEH had a net open position (including existing storage) of
0.4 Bcf.
84
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Interest
Rate Risk Management Activities
Currently, we are not managing interest rate risk with financial
instruments. However, in prior years, we periodically managed
interest rate risk by entering into Treasury lock agreements to
fix the Treasury yield component of the interest cost associated
with anticipated financings.
In 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 issued in October 2004 in
connection with the permanent financing for our TXU Gas
acquisition. These Treasury lock agreements were settled in
October 2004 with a net $43.8 million payment to the
counterparties.
In March 2007, we entered into a Treasury lock agreement to fix
the Treasury yield component of the interest cost associated
with $100 million of our $250 million
6.35% Senior Notes issued in June 2007. This Treasury lock
agreement was settled in June 2007, which resulted in the
receipt of $2.9 million from the counterparties.
In March 2009, we entered into a Treasury lock agreement to fix
the Treasury yield component of the interest cost associated
with our $450 million 8.50% senior notes (the Senior
Notes Offering) issued on March 23, 2009. The Senior Notes
Offering is discussed in Note 6. We designated this
Treasury lock as a cash flow hedge of an anticipated
transaction. This Treasury lock agreement was settled on
March 23, 2009 with the receipt of $1.9 million from
the counterparty due to an increase in the 10 year Treasury
rates between inception of the Treasury lock and settlement.
The gains and losses realized upon settlement were recorded as a
component of accumulated other comprehensive income (loss) and
are being recognized as a component of interest expense over the
life of the associated notes from the date of settlement.
Quantitative
Disclosures Related to Financial Instruments
The following tables present detailed information concerning the
impact of financial instruments on our consolidated balance
sheet and income statements.
As of September 30, 2009, our financial instruments were
comprised of both long and short commodity positions. A long
position is a contract to purchase the commodity, while a short
position is a contract to sell the commodity. As of
September 30, 2009, we had net long/(short) commodity
contracts outstanding in the following quantities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
Hedge
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
Contract Type
|
|
Designation
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
|
|
|
Quantity (MMcf)
|
|
|
Commodity contracts
|
|
Fair Value
|
|
|
|
|
|
|
(15,623
|
)
|
|
|
(2,550
|
)
|
|
|
Cash Flow
|
|
|
|
|
|
|
32,874
|
|
|
|
(4,267
|
)
|
|
|
Not designated
|
|
|
32,369
|
|
|
|
83,384
|
|
|
|
(499
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,369
|
|
|
|
100,635
|
|
|
|
(7,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Instruments on the Balance Sheet
The following tables present the fair value and balance sheet
classification of our financial instruments by operating segment
as of September 30, 2009 and 2008. As required by
authoritative accounting literature, the fair value amounts
below are presented on a gross basis and do not reflect the
netting of asset and liability positions permitted under the
terms of our master netting arrangements. Further, the amounts
below do not include $11.7 million and $56.6 million
of cash held on deposit in margin accounts as of
September 30, 2009 and 2008 to collateralize certain
financial instruments. Therefore, these gross balances are not
indicative of
85
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
either our actual credit exposure or net economic exposure.
Additionally, the amounts below will not be equal to the amounts
presented on our consolidated balance sheet, nor will they be
equal to the fair value information presented for our financial
instruments in Note 5.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing(1)
|
|
|
Total
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
53,526
|
|
|
$
|
53,526
|
|
|
|
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
6,800
|
|
|
|
6,800
|
|
|
|
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(47,146
|
)
|
|
|
(47,146
|
)
|
|
|
|
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(999
|
)
|
|
|
(999
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
12,181
|
|
|
|
12,181
|
|
|
|
|
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
4,395
|
|
|
|
27,559
|
|
|
|
31,954
|
|
|
|
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
1,620
|
|
|
|
7,964
|
|
|
|
9,584
|
|
|
|
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(20,181
|
)
|
|
|
(19,657
|
)
|
|
|
(39,838
|
)
|
|
|
|
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(1,349
|
)
|
|
|
(1,349
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(14,166
|
)
|
|
|
14,517
|
|
|
|
351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(14,166
|
)
|
|
$
|
26,698
|
|
|
$
|
12,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
86
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing(1)
|
|
|
Total
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
101,191
|
|
|
$
|
101,191
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
4,984
|
|
|
|
4,984
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(89,397
|
)
|
|
|
(89,397
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(206
|
)
|
|
|
(206
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
16,572
|
|
|
|
16,572
|
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
|
|
|
|
20,104
|
|
|
|
20,104
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
999
|
|
|
|
999
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(58,566
|
)
|
|
|
(20,145
|
)
|
|
|
(78,711
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
(5,111
|
)
|
|
|
(988
|
)
|
|
|
(6,099
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(63,677
|
)
|
|
|
(30
|
)
|
|
|
(63,707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(63,677
|
)
|
|
$
|
16,542
|
|
|
$
|
(47,135
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
Impact of
Financial Instruments on the Income Statement
The following tables present the impact that financial
instruments had on our consolidated income statement, by
operating segment, as applicable, for the years ended
September 30, 2009 and 2008.
Hedge ineffectiveness for our natural gas marketing and pipeline
storage and other segments is recorded as a component of
unrealized gross profit and primarily results from differences
in the location and timing of the derivative instrument and the
hedged item. Hedge ineffectiveness could materially affect our
results of operations for the reported period. For the years
ended September 30, 2009 and 2008 we recognized a gain
arising from fair value and cash flow hedge ineffectiveness of
$6.4 million and $46.0 million. Additional information
regarding ineffectiveness recognized in the income statement is
included in the tables below.
87
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Fair
Value Hedges
The impact of commodity contracts designated as fair value
hedges and the related hedged item on our consolidated income
statement for the years ended September 30, 2009 and 2008
is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30, 2009
|
|
|
|
Natural Gas
|
|
|
Pipeline, Storage
|
|
|
|
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Commodity contracts
|
|
$
|
37,967
|
|
|
$
|
7,153
|
|
|
$
|
45,120
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
(25,501
|
)
|
|
|
(3,330
|
)
|
|
|
(28,831
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
12,466
|
|
|
$
|
3,823
|
|
|
$
|
16,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
5,958
|
|
|
$
|
|
|
|
$
|
5,958
|
|
Timing ineffectiveness
|
|
|
6,508
|
|
|
|
3,823
|
|
|
|
10,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,466
|
|
|
$
|
3,823
|
|
|
$
|
16,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30, 2008
|
|
|
|
Natural Gas
|
|
|
Pipeline, Storage
|
|
|
|
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
30,572
|
|
|
$
|
4,941
|
|
|
$
|
35,513
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
6,281
|
|
|
|
482
|
|
|
|
6,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
36,853
|
|
|
$
|
5,423
|
|
|
$
|
42,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
(2,841
|
)
|
|
$
|
|
|
|
$
|
(2,841
|
)
|
Timing ineffectiveness
|
|
|
39,694
|
|
|
|
5,423
|
|
|
|
45,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,853
|
|
|
$
|
5,423
|
|
|
$
|
42,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness arises from natural gas market price
differences between the locations of the hedged inventory and
the delivery location specified in the hedge instruments. Timing
ineffectiveness arises due to changes in the difference between
the spot price and the futures price, as well as the difference
between the timing of the settlement of the futures and the
valuation of the underlying physical commodity. As the commodity
contract nears the settlement date, spot to forward price
differences should converge, which should reduce or eliminate
the impact of this ineffectiveness on revenue.
88
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
Flow Hedges
The impact of cash flow hedges on our consolidated income
statements for the years ended September 30, 2009 and 2008
is presented below. Note that this presentation does not reflect
the financial impact arising from the hedged physical
transaction. Therefore, this presentation is not indicative of
the economic gross profit we realized when the underlying
physical and financial transactions were settled.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30, 2009
|
|
|
|
Natural
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Natural Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(162,283
|
)
|
|
$
|
25,743
|
|
|
$
|
(136,540
|
)
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(9,888
|
)
|
|
|
|
|
|
|
(9,888
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(172,171
|
)
|
|
|
25,743
|
|
|
|
(146,428
|
)
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(4,070
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,070
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(4,070
|
)
|
|
$
|
(172,171
|
)
|
|
$
|
25,743
|
|
|
$
|
(150,498
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30, 2008
|
|
|
|
Natural
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Natural Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(12,739
|
)
|
|
$
|
9,468
|
|
|
$
|
(3,271
|
)
|
Gain arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
3,720
|
|
|
|
|
|
|
|
3,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(9,019
|
)
|
|
|
9,468
|
|
|
|
449
|
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(5,076
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(5,076
|
)
|
|
$
|
(9,019
|
)
|
|
$
|
9,468
|
|
|
$
|
(4,627
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the gains and losses arising from
hedging transactions that were recognized as a component of
other comprehensive income (loss), net of taxes, for the fiscal
years ended September 30, 2009 and 2008. The amounts
included in the table below exclude gains and losses arising
from ineffectiveness because these amounts are immediately
recognized in the income statement as incurred.
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Increase (decrease) in fair value:
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
$
|
1,221
|
|
|
$
|
|
|
Forward commodity contracts
|
|
|
(72,683
|
)
|
|
|
(23,029
|
)
|
Recognition of losses in earnings due to settlements:
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
|
2,385
|
|
|
|
3,148
|
|
Forward commodity contracts
|
|
|
83,290
|
|
|
|
2,029
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss) from hedging, net of
tax(1)
|
|
$
|
14,213
|
|
|
$
|
(17,852
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction. |
The following amounts, net of deferred taxes, represent the
expected recognition in earnings of the deferred losses recorded
in AOCI associated with our financial instruments, based upon
the fair values of these financial instruments as of
September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
|
|
|
|
|
|
|
|
|
|
Lock
|
|
|
Commodity
|
|
|
|
|
|
|
Agreements
|
|
|
Contracts
|
|
|
Total
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
2010
|
|
$
|
(1,687
|
)
|
|
$
|
(15,272
|
)
|
|
$
|
(16,959
|
)
|
2011
|
|
|
(1,687
|
)
|
|
|
(408
|
)
|
|
|
(2,095
|
)
|
2012
|
|
|
(1,687
|
)
|
|
|
39
|
|
|
|
(1,648
|
)
|
2013
|
|
|
(1,687
|
)
|
|
|
214
|
|
|
|
(1,473
|
)
|
2014
|
|
|
(1,687
|
)
|
|
|
281
|
|
|
|
(1,406
|
)
|
Thereafter
|
|
|
937
|
|
|
|
|
|
|
|
937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(1)
|
|
$
|
(7,498
|
)
|
|
$
|
(15,146
|
)
|
|
$
|
(22,644
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction. |
Financial
Instruments Not Designated as Hedges
The impact of financial instruments that have not been
designated as hedges on our consolidated income statements for
the fiscal years ended September 30, 2009 and 2008 is
presented below. Note that this presentation does not reflect
the expected gains or losses arising from the underlying
physical transactions associated with these financial
instruments. Therefore, this presentation is not indicative of
the economic gross profit we realized when the underlying
physical and financial transactions were settled.
As discussed above, financial instruments used in our natural
gas distribution segment are not designated as hedges. However,
there is no earnings impact to our natural gas distribution
segment as a result of the use of these financial instruments
because the gains and losses arising from the use of these
financial instruments
90
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
are recognized in the consolidated statement of income as a
component of purchased gas cost when the related costs are
recovered through our rates and recognized in revenue.
Accordingly, the impact of these financial instruments is
excluded from this presentation.
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Natural gas marketing commodity contracts
|
|
$
|
43,483
|
|
|
$
|
(37,200
|
)
|
Pipeline, storage and other commodity contracts
|
|
|
(6,614
|
)
|
|
|
1,139
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
36,869
|
|
|
$
|
(36,061
|
)
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
Fair
Value Measurements
|
In September 2006, the FASB issued authoritative accounting
literature that defines fair value, establishes a framework for
measuring fair value in GAAP and expands disclosures about fair
value measurements. This guidance does not require any new fair
value measurements; rather it provides guidance on how to
perform fair value measurements as required or permitted under
previous accounting pronouncements. We prospectively adopted the
provisions of this guidance on October 1, 2008 for most of
the financial assets and liabilities recorded on our balance
sheet at fair value. Adoption of this guidance for these assets
and liabilities did not have a material impact on our financial
position, results of operations or cash flows. Subsequent to the
issuance of the guidance related to fair value measurements, the
FASB provided a one-year deferral for nonrecurring fair value
measurements associated with our nonfinancial assets and
liabilities. Under this partial deferral, the guidance related
to fair value measurements will not be effective until
October 1, 2009 for fair value measurements for the
following:
|
|
|
|
|
Asset retirement obligations
|
|
|
|
Most nonfinancial assets and liabilities that may be acquired in
a business combination
|
|
|
|
Impairment analyses performed for nonfinancial assets
|
We believe the adoption of the FASBs fair value guidance
for the reporting of these nonfinancial assets and liabilities
will not have a material impact on our financial position,
results of operations or cash flows.
Fair value measurements also apply to the valuation of our
pension and post-retirement plan assets. The adoption of the
authoritative accounting literature published by the FASB in
September 2006 did not affect these valuations because pension
and post-retirement assets were specifically excluded from its
prescribed disclosure provisions. Accordingly, these plan assets
are not included in the tabular disclosures below. However, in
December 2008, the FASB issued additional guidance, which will,
among other things, require similar disclosure about fair value
measurements for our pension plan assets. This guidance will
impact our annual disclosure requirements beginning in fiscal
2010.
Quantitative
Disclosures
Financial
Instruments
The classification of our fair value measurements requires
judgment regarding the degree to which market data are
observable or corroborated by observable market data. The
following table summarizes, by level within the fair value
hierarchy, our assets and liabilities that were accounted for at
fair value on a recurring
91
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
basis as of September 30, 2009. As required under
authoritative accounting literature, assets and liabilities are
categorized in their entirety based on the lowest level of input
that is significant to the fair value measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
Other
|
|
|
Other
|
|
|
Netting
|
|
|
|
|
|
|
Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
and
|
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Cash
|
|
|
September 30,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Collateral(1)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
6,015
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6,015
|
|
Natural gas marketing segment
|
|
|
34,281
|
|
|
|
61,568
|
|
|
|
|
|
|
|
(56,186
|
)
|
|
|
39,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments
|
|
|
34,281
|
|
|
|
67,583
|
|
|
|
|
|
|
|
(56,186
|
)
|
|
|
45,678
|
|
Hedged portion of gas stored underground
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
47,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,967
|
|
Pipeline, storage and other
segment(2)
|
|
|
6,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas stored underground
|
|
|
54,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54,756
|
|
Available-for-sale securities
|
|
|
41,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
130,736
|
|
|
$
|
67,583
|
|
|
$
|
|
|
|
$
|
(56,186
|
)
|
|
$
|
142,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
20,181
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
20,181
|
|
Natural gas marketing segment
|
|
|
48,268
|
|
|
|
20,883
|
|
|
|
|
|
|
|
(67,850
|
)
|
|
|
1,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
48,268
|
|
|
$
|
41,064
|
|
|
$
|
|
|
|
$
|
(67,850
|
)
|
|
$
|
21,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This column reflects adjustments to our gross financial
instrument assets and liabilities to reflect netting permitted
under our master netting agreements and the relevant
authoritative accounting literature. In addition, as of
September 30, 2009, we had $11.7 million of cash held
in margin accounts to collateralize certain financial
instruments which has been reflected as a financial instrument
asset. |
|
(2) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
Other
Fair Value Measures
In addition to the financial instruments above, we have several
financial and nonfinancial assets and liabilities subject to
fair value measures. These financial assets and liabilities
include cash and cash equivalents, accounts receivable, accounts
payable and debt. The nonfinancial assets and liabilities
include asset retirement obligations and pension and
post-retirement plan assets. As noted above, fair value
disclosures for asset retirement obligations and pension and
post-retirement plan assets are not currently effective for us.
We record cash and cash equivalents, accounts receivable,
accounts payable and debt at carrying value. For cash and cash
equivalents, accounts receivable and accounts payable, we
consider carrying value to materially approximate fair value due
to the short-term nature of these assets and liabilities.
92
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The fair value of our debt is determined using third party
market value quotations. The following table presents the
carrying value and fair value of our debt as of
September 30, 2009:
|
|
|
|
|
|
|
September 30, 2009
|
|
|
(In thousands)
|
|
Carrying Amount
|
|
$
|
2,172,827
|
|
Fair Value
|
|
$
|
2,317,572
|
|
Long-term
debt
Long-term debt at September 30, 2009 and 2008 consisted of
the following:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Unsecured 4.00% Senior Notes, redeemed April 2009
|
|
$
|
|
|
|
$
|
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 6.35% Senior Notes, due 2017
|
|
|
250,000
|
|
|
|
250,000
|
|
Unsecured 8.50% Senior Notes, due 2019
|
|
|
450,000
|
|
|
|
|
|
Unsecured 5.95% Senior Notes, due 2034
|
|
|
200,000
|
|
|
|
200,000
|
|
Medium term notes
|
|
|
|
|
|
|
|
|
Series A,
1995-2,
6.27%, due December 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
|
|
Rental property, propane and other term notes due in
installments through 2013
|
|
|
524
|
|
|
|
1,309
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,172,827
|
|
|
|
2,123,612
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on unsecured senior notes and debentures
|
|
|
(3,296
|
)
|
|
|
(3,035
|
)
|
Current maturities
|
|
|
(131
|
)
|
|
|
(785
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,169,400
|
|
|
$
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
On March 26, 2009, we closed our Senior Notes Offering. The
effective interest rate on these notes is 8.69 percent,
after giving effect to the settlement of the $450 million
Treasury lock discussed in Note 4. Most of the net proceeds
of approximately $446 million were used to redeem our
$400 million 4.00% unsecured senior notes on April 30,
2009, prior to their October 2009 maturity. In connection with
the repayment of the $400 million 4.00% unsecured senior
notes, we paid a $6.6 million call premium in accordance
with the terms of the senior notes and accrued interest of
approximately $0.6 million. The remaining net proceeds were
used for general corporate purposes.
Short-term
debt
Our short-term borrowing requirements are affected by the
seasonal nature of the natural gas business. Changes in the
price of natural gas and the amount of natural gas we need to
supply our customers needs
93
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
could significantly affect our borrowing requirements. Our
short-term borrowings typically reach their highest levels in
the winter months.
We finance our short-term borrowing requirements through a
combination of a $566.7 million commercial paper program
and four committed revolving credit facilities with third-party
lenders that provide approximately $1.3 billion of working
capital funding. At September 30, 2009, there was
$72.6 million outstanding under our commercial paper
program. At September 30, 2008, there was
$350.5 million of short-term debt outstanding, comprised of
$330.5 million outstanding under our bank credit facilities
and $20.0 million outstanding under our commercial paper
program. As of September 30, 2009, our commercial paper had
maturities of one day with an interest rate of
0.25 percent. We also use intercompany credit facilities to
supplement the funding provided by these third-party committed
credit facilities. These facilities are described in greater
detail below.
Regulated
Operations
We fund our regulated operations as needed primarily through a
$566.7 million commercial paper program and three committed
revolving credit facilities with third-party lenders that
provide approximately $800 million of working capital
funding. The first facility is a five-year unsecured facility,
expiring December 2011, that bears interest at a base rate or at
a LIBOR-based rate for the applicable interest period, plus a
spread ranging from 0.30 percent to 0.75 percent,
based on the Companys credit ratings. This credit facility
serves as a backup liquidity facility for our commercial paper
program. At the time this credit facility was established,
borrowings under this facility were limited to
$600 million. However, in September 2008, the limit on
borrowings was effectively reduced to $566.7 million after
one lender with a 5.55% share of the commitments ceased funding
under the facility. On March 30, 2009, the credit facility
was amended to reflect this reduction. At September 30,
2009, there were no borrowings under this facility, but we had
$72.6 million of commercial paper outstanding leaving
$494.1 million available.
The second facility is a $212.5 million unsecured
364-day
facility expiring October 2009, that bears interest at a base
rate or at a LIBOR-based rate for the applicable interest
period, plus a spread ranging from 1.25 percent to
2.50 percent, based on the Companys credit ratings.
At September 30, 2009, there were no borrowings outstanding
under this facility. In October 2009, this facility was renewed
on substantially the same terms for $200 million, which
expires October 2010.
The third facility was an $18 million unsecured facility
that bore interest at a daily negotiated rate, generally based
on the Federal Funds rate plus a variable margin. This facility
expired on March 31, 2009 and was replaced with a
$25 million unsecured facility effective April 1, 2009
that bears interest at a daily negotiated rate. At
September 30, 2009, there were no borrowings outstanding
under this facility.
The availability of funds under these 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 each of these 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, 2009, our
total-debt-to-total-capitalization
ratio, as defined, was 53 percent. In addition, both the
interest margin over the Eurodollar rate and the fee that we pay
on unused amounts under each of these facilities are subject to
adjustment depending upon our credit ratings.
In addition to these third-party facilities, our regulated
operations have a $200 million intercompany revolving
credit facility with AEH. Through December 31, 2008, this
facility bore interest at the one-month LIBOR rate plus
0.20 percent. In January 2009, this facility was replaced
with a new $200 million 364 day-facility that bears
interest at the lower of (i) the one-month LIBOR rate plus
0.45 percent or (ii) the marginal borrowing rate
available to the Company on the date of borrowing. The marginal
borrowing rate is defined as
94
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the lower of (i) a rate based upon the lower of the Prime
Rate or the Eurodollar rate under the five year revolving credit
facility or (ii) the lowest rate outstanding under the
commercial paper program. Applicable state regulatory
commissions have approved the new facility through
December 31, 2009. There was $86.4 million outstanding
under this facility at September 30, 2009.
Nonregulated
Operations
On December 30, 2008, AEM and the participating banks
amended and restated AEMs former uncommitted credit
facility, primarily to convert the $580 million uncommitted
demand credit facility to a
364-day
$375 million committed revolving credit facility and extend
it to December 29, 2009. Effective April 1, 2009, the
borrowing base was increased to $450 million through the
exercise of an accordion feature in the facility.
The amended facility also adds a swing line loan feature;
adjusts the interest rate on borrowings as discussed below and
increases the fees paid to reflect the facilitys
conversion to a committed facility and current credit market
conditions. The swing line loan feature allows AEM to borrow, on
a same day basis, an amount ranging from $17 million to
$27 million based on the terms of an election within the
agreement.
AEM uses this facility primarily to issue letters of credit and,
on a less frequent basis, to borrow funds for gas purchases and
other working capital needs. At AEMs option, borrowings
made under the credit facility are based on a base rate or an
offshore rate, in each case plus an applicable margin. The base
rate is a floating rate equal to the higher of:
(a) 0.50 percent per annum above the latest federal
funds rate; (b) the per annum rate of interest established
by BNP Paribas from time to time as its prime rate
or base rate for U.S. dollar loans; (c) an
offshore rate (based on LIBOR with a one-month interest period)
as in effect from time to time; and (d) the cost of
funds rate based on an average of interest rates reported
by one or more of the lenders to the administrative agent. The
offshore rate is a floating rate equal to the higher of
(a) an offshore rate based upon LIBOR for the applicable
interest period; and (b) a cost of funds rate
referred to above. In the case of both base rate and offshore
rate loans, the applicable margin ranges from 2.250 percent
to 2.625 percent per annum, depending on the excess
tangible net worth of AEM, as defined in the credit facility.
This facility is collateralized by substantially all of the
assets of AEM and is guaranteed by AEH.
At September 30, 2009, there were no borrowings outstanding
under this credit facility. However, at September 30, 2009,
AEM letters of credit totaling $19.2 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 $170.4 million at September 30, 2009.
AEM is required by the financial covenants in this facility to
maintain a ratio of total liabilities to tangible net worth that
does not exceed a maximum of 5 to 1. At September 30, 2009,
AEMs ratio of total liabilities to tangible net worth, as
defined, was 0.84 to 1. Additionally, AEM must maintain minimum
levels of net working capital and net worth ranging from
$75 million to $112.5 million. As defined in the
financial covenants, at September 30, 2009, AEMs net
working capital was $155.9 million and its tangible net
worth was $168.5 million.
To supplement borrowings under this facility, through
December 31, 2008, AEM had a $200 million intercompany
demand credit facility with AEH, which bore interest at the rate
for AEMs offshore borrowings under its committed credit
facility plus 0.75 percent. Amounts outstanding under this
facility are subordinated to AEMs committed credit
facility. This facility was replaced with another
$200 million
364-day
facility in January 2009 with no material changes to its terms
except for the rate of interest, which is the greater of
(i) the one-month LIBOR rate plus 2.00 percent or
(ii) the rate for AEMs offshore borrowings under its
committed credit facility plus 0.75 percent. There were no
borrowings outstanding under this facility at September 30,
2009.
95
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Finally, through December 31, 2008, AEH had a
$200 million intercompany demand credit facility with AEC,
which bore interest at the rate for AEMs offshore
borrowings under its committed credit facility plus
0.75 percent. This facility was replaced with another
$200 million
364-day
facility in January 2009 with no material changes to its terms
except for the rate of interest, which is the greater of
(i) the one-month LIBOR rate plus 2.00 percent or
(ii) the rate for AEMs offshore borrowings under its
committed credit facility plus 0.75 percent. Applicable
state regulatory commissions have approved the new facility
through December 31, 2009. There were no borrowings
outstanding under this facility at September 30, 2009.
Shelf
Registration
On March 23, 2009, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in common stock
and/or debt
securities available for issuance, including approximately
$450 million of capacity carried over from our prior shelf
registration statement filed with the SEC in December 2006.
As of September 30, 2009, we had approximately
$450 million of availability remaining under the
registration statement after completing our Senior Notes
Offering. However, due to certain restrictions placed by one
state regulatory commission on our ability to issue securities
under the registration statement, we now have remaining and
available for issuance a total of approximately
$200 million of equity securities and $250 million of
subordinated debt securities.
Debt
Covenants
In addition to the financial covenants described above, our debt
instruments contain various covenants that are usual and
customary for debt instruments of these types.
Additionally, our public debt indentures relating to our senior
notes and debentures, as well as 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.
Further, 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.
Finally, AEMs credit agreement contains a provision that
would limit the amount of credit available if Atmos Energy were
downgraded below an S&P rating of BBB and a Moodys
rating of Baa2. We have no other 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.
We were in compliance with all of our debt covenants as of
September 30, 2009. If we were unable to comply with our
debt covenants, we would likely be required to repay our
outstanding balances on demand, provide additional collateral or
take other corrective actions.
96
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Maturities of long-term debt at September 30, 2009 were as
follows (in thousands):
|
|
|
|
|
2010
|
|
$
|
131
|
|
2011
|
|
|
360,131
|
|
2012
|
|
|
2,434
|
|
2013
|
|
|
250,131
|
|
2014
|
|
|
|
|
Thereafter
|
|
|
1,560,000
|
|
|
|
|
|
|
|
|
$
|
2,172,827
|
|
|
|
|
|
|
|
|
7.
|
Stock and
Other Compensation Plans
|
Stock-Based
Compensation Plans
Total stock-based compensation expense was $14.5 million,
$14.0 million and $11.9 million for the fiscal years
ended September 30, 2009, 2008 and 2007, primarily related
to restricted stock costs.
1998
Long-Term Incentive Plan
In August 1998, the Board of Directors approved and adopted the
1998 Long-Term Incentive Plan (LTIP), which became effective in
October 1998 after approval by our shareholders. The LTIP 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, time-lapse restricted stock
units, performance-based restricted stock units and stock units
to certain employees and non-employee directors of the Company
and our 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
6.5 million shares of common stock under this plan subject
to certain adjustment provisions. As of September 30, 2009,
non-qualified stock options, bonus stock, time-lapse restricted
stock, time-lapse restricted stock units, performance-based
restricted stock units and stock units had been issued under
this plan, and 1,473,531 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. However, no stock options have been
granted under this plan since fiscal 2003, except for a limited
number of options that were converted from bonuses paid under
our Annual Incentive Plan, the last of which occurred in fiscal
2006.
Restricted
Stock Plans
As noted above, the LTIP provides for discretionary awards of
restricted stock to help attract, retain and reward employees of
Atmos Energy and its subsidiaries. Certain of these awards vest
based upon the passage of time and other awards vest based upon
the passage of time and the achievement of specified performance
targets. The associated expense is recognized ratably over the
vesting period. The following summarizes
97
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
information regarding the restricted stock issued under the plan
during the fiscal years ended September 30, 2009, 2008 and
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Grant-Date
|
|
|
Number of
|
|
|
Grant-Date
|
|
|
Number of
|
|
|
Grant-Date
|
|
|
|
Restricted
|
|
|
Fair
|
|
|
Restricted
|
|
|
Fair
|
|
|
Restricted
|
|
|
Fair
|
|
|
|
Shares
|
|
|
Value
|
|
|
Shares
|
|
|
Value
|
|
|
Shares
|
|
|
Value
|
|
|
Nonvested at beginning of year
|
|
|
1,096,770
|
|
|
$
|
29.04
|
|
|
|
948,717
|
|
|
$
|
28.95
|
|
|
|
746,776
|
|
|
$
|
26.49
|
|
Granted
|
|
|
711,909
|
|
|
|
25.76
|
|
|
|
547,845
|
|
|
|
27.90
|
|
|
|
485,260
|
|
|
|
30.85
|
|
Vested
|
|
|
(499,267
|
)
|
|
|
29.05
|
|
|
|
(380,895
|
)
|
|
|
27.17
|
|
|
|
(271,075
|
)
|
|
|
26.12
|
|
Forfeited
|
|
|
(13,571
|
)
|
|
|
28.92
|
|
|
|
(18,897
|
)
|
|
|
29.32
|
|
|
|
(12,244
|
)
|
|
|
28.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of year
|
|
|
1,295,841
|
|
|
$
|
27.23
|
|
|
|
1,096,770
|
|
|
$
|
29.04
|
|
|
|
948,717
|
|
|
$
|
28.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2009, there was $17.1 million of
total unrecognized compensation cost related to nonvested
restricted shares granted under the LTIP. That cost is expected
to be recognized over a weighted-average period of
1.5 years. The fair value of restricted stock vested during
the fiscal years ended September 30, 2009, 2008 and 2007
was $14.5 million, $10.3 million and $7.1 million.
Stock
Option Plan
A summary of stock option activity under the LTIP follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
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
|
|
|
913,841
|
|
|
$
|
22.54
|
|
|
|
920,841
|
|
|
$
|
22.54
|
|
|
|
1,017,152
|
|
|
$
|
22.57
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(130,965
|
)
|
|
|
21.99
|
|
|
|
(7,000
|
)
|
|
|
21.90
|
|
|
|
(92,071
|
)
|
|
|
22.84
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,240
|
)
|
|
|
23.11
|
|
Expired
|
|
|
(171,649
|
)
|
|
|
25.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of
year(1)
|
|
|
611,227
|
|
|
$
|
21.88
|
|
|
|
913,841
|
|
|
$
|
22.54
|
|
|
|
920,841
|
|
|
$
|
22.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of
year(2)
|
|
|
611,227
|
|
|
$
|
21.88
|
|
|
|
911,492
|
|
|
$
|
22.53
|
|
|
|
908,332
|
|
|
$
|
22.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted-average remaining contractual life for outstanding
options was 2.4 years, 3.4 years, and 4.4 years
for fiscal years 2009, 2008 and 2007. The aggregate intrinsic
value of outstanding options was $2.1 million,
$3.3 million and $3.3 million for fiscal years 2009,
2008 and 2007. |
|
(2) |
|
The weighted-average remaining contractual life for exercisable
options was 2.4 years, 3.4 years, and 4.3 years
for fiscal years 2009, 2008 and 2007. The aggregate intrinsic
value of exercisable options was $2.1 million,
$3.3 million and $3.3 million for fiscal years 2009,
2008 and 2007. |
98
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Information about outstanding and exercisable options under the
LTIP, as of September 30, 2009, is reflected in the
following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding and Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
Number of
|
|
|
Contractual Life
|
|
|
Exercise
|
|
Range of Exercise Prices
|
|
Options
|
|
|
(In years)
|
|
|
Price
|
|
|
$15.65 to $20.24
|
|
|
52,000
|
|
|
|
0.4
|
|
|
$
|
15.66
|
|
$20.25 to $22.99
|
|
|
406,470
|
|
|
|
2.7
|
|
|
$
|
21.88
|
|
$23.00 to $26.19
|
|
|
152,757
|
|
|
|
2.1
|
|
|
$
|
24.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$15.65 to $26.19
|
|
|
611,227
|
|
|
|
2.4
|
|
|
$
|
21.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Grant date weighted average fair value per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash proceeds from stock option exercises
|
|
$
|
2,880
|
|
|
$
|
153
|
|
|
$
|
2,103
|
|
Income tax benefit from stock option exercises
|
|
$
|
177
|
|
|
$
|
12
|
|
|
$
|
296
|
|
Total intrinsic value of options exercised
|
|
$
|
262
|
|
|
$
|
26
|
|
|
$
|
347
|
|
As of September 30, 2009, there was no unrecognized
compensation cost related to nonvested stock options.
Other
Plans
Direct
Stock Purchase Plan
We maintain a Direct Stock Purchase Plan, open to all investors,
which allows participants to have all or part of their cash
dividends paid quarterly in additional shares of our common
stock. The minimum initial investment required to join the plan
is $1,250. Direct Stock Purchase Plan participants may purchase
additional shares of our 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 our shareholders 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 our shareholders 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 our
Retirement Plan for Non-Employee Directors. The plan provides
non-employee directors of Atmos Energy 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.
99
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
Discretionary Compensation Plans
We adopted the Variable Pay Plan in fiscal 1999 for our
regulated segments employees to give each employee an
opportunity to share in our financial success based on the
achievement of key performance measures considered critical to
achieving business objectives for a given year and has minimum
and maximum thresholds. The plan must meet the minimum threshold
for the plan to be funded and distributed to employees. 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. During the last
several fiscal years, we have used earnings per share as our
sole performance measure.
We adopted our Annual Incentive Plan in October 2001 to give the
employees in our nonregulated segments an opportunity to share
in the success of the nonregulated operations. The plan is based
upon the net earnings of the nonregulated 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.
|
|
8.
|
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.
Effective September 30, 2007, we adopted the guidance
issued by the FASB in September 2006 related to changes in the
accounting rules for defined benefit pension and other
postretirement plans. The new standard made 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 our measurement date
correspond to the fiscal year end balance sheet date. Effective
October 1, 2008, the Company adopted the measurement date
requirement using the remeasurement approach. Under this
approach, the Company remeasured its projected benefit
obligation, fair value of plan assets and its fiscal
2009 net periodic cost. In accordance with the transition
rules of the new standard, the impact of changing the
measurement date decreased retained earnings by
$7.8 million, net of tax, decreased the unrecognized
actuarial loss by $9.0 million and increased our
postretirement liabilities by $3.5 million as of
October 1, 2008.
As a rate regulated entity, we generally recover our pension
costs in our rates over a period of up to 15 years.
Therefore, the decrease in the unrecognized actuarial loss that
would have been recorded as a component of accumulated other
comprehensive loss, net of tax, was recorded as a reduction to a
regulatory asset as a component of deferred charges and other
assets in fiscal 2009. The change in the measurement date did
not materially impact the level of net periodic pension cost we
recorded in fiscal 2009.
100
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The amounts that have not yet been recognized in net periodic
pension cost that have been recorded as regulatory assets are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
|
|
|
|
|
|
|
|
|
|
Defined
|
|
|
Executive
|
|
|
Postretirement
|
|
|
|
|
|
|
Benefits Plans
|
|
|
Retirement Plans
|
|
|
Plans
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
September 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized transition obligation
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6,242
|
|
|
$
|
6,242
|
|
Unrecognized prior service cost
|
|
|
(1,802
|
)
|
|
|
187
|
|
|
|
(11,761
|
)
|
|
|
(13,376
|
)
|
Unrecognized actuarial loss
|
|
|
150,989
|
|
|
|
29,709
|
|
|
|
24,179
|
|
|
|
204,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
149,187
|
|
|
$
|
29,896
|
|
|
$
|
18,660
|
|
|
$
|
197,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized transition obligation
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8,131
|
|
|
$
|
8,131
|
|
Unrecognized prior service cost
|
|
|
(2,984
|
)
|
|
|
452
|
|
|
|
|
|
|
|
(2,532
|
)
|
Unrecognized actuarial loss
|
|
|
64,815
|
|
|
|
17,308
|
|
|
|
12,841
|
|
|
|
94,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
61,831
|
|
|
$
|
17,760
|
|
|
$
|
20,972
|
|
|
$
|
100,563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined
Benefit Plans
Employee
Pension Plans
As of September 30, 2009, 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 assets of 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 Energys regulated operations. 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 credited 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 applied 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 are fully vested in their account balances
after three 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, including the funding
requirements under the Pension Protection Act of 2006 (PPA).
However, additional voluntary contributions are made from time
to time as
101
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 2009, we contributed $21.0 million in cash to
the Plans to achieve a desired level of funding for the 2008
plan year while maximizing the tax deductibility of this
payment. In fiscal 2008, we voluntarily contributed
$2.3 million to the Union Plan, which achieved the desired
level of funding for this plan for the 2007 plan year. During
fiscal 2007, we did not make any contributions to the Plans.
Based upon market conditions subsequent to September 30,
2009, the current funded position of the plans and the new
funding requirements under the PPA, we believe it is reasonably
possible that we will be required to contribute to the Plans in
fiscal 2010. Further, we will consider whether an additional
voluntary contribution is prudent to maintain certain PPA
funding thresholds. However, we cannot anticipate with certainty
whether such contributions will be made and the amount of such
contributions.
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
investment policy adopted by the Board of Directors.
To achieve these objectives, we invest the Master Trusts
assets in equity securities, fixed income securities, interests
in commingled pension trust funds, other investment assets and
cash and cash equivalents. Investments in equity securities are
diversified among the markets various subsectors in an
effort 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, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Allocation
|
|
|
|
Targeted
|
|
September 30
|
|
Security Class
|
|
Allocation Range
|
|
2009
|
|
|
2008
|
|
|
Domestic equities
|
|
35%-55%
|
|
|
38.5
|
%
|
|
|
42.0
|
%
|
International equities
|
|
10%-20%
|
|
|
12.8
|
%
|
|
|
11.0
|
%
|
Fixed income
|
|
10%-30%
|
|
|
19.6
|
%
|
|
|
24.2
|
%
|
Company stock
|
|
0%-10%
|
|
|
10.9
|
%
|
|
|
10.2
|
%
|
Other assets
|
|
10%-20%
|
|
|
18.2
|
%
|
|
|
12.6
|
%
|
At September 30, 2009 and 2008, the Plan held
1,169,700 shares of our common stock, which represented
10.9 percent and 10.2 percent of total Master Trust
assets. These shares generated dividend income for the Plan of
approximately $1.5 million during fiscal 2009 and 2008.
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 September 30 measurement date. Prior to
October 1, 2008, the estimates and assumptions were
determined based on a June 30 measurement date. As described
above, the adoption of new accounting guidance in accordance
with accounting principles generally accepted in the United
States necessitated a change in our measurement date during
fiscal 2009. 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
September 30,
102
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2009 and June 30, 2008 and the actuarial assumptions used
to determine the net periodic pension cost for the Plans were
determined as of September 30, 2008, June 30, 2007 and
2006. These assumptions are presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Liability
|
|
|
Pension Cost
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Discount rate
|
|
|
5.52
|
%
|
|
|
6.68
|
%
|
|
|
7.57
|
%
|
|
|
6.30
|
%
|
|
|
6.30
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
Expected return on plan assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
The following table presents the Plans accumulated benefit
obligation, projected benefit obligation and funded status as of
September 30, 2009 and 2008 based upon a September 30,
2009 and June 30, 2008 measurement date.
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Accumulated benefit obligation
|
|
$
|
366,770
|
|
|
$
|
329,023
|
|
|
|
|
|
|
|
|
|
|
Change in projected benefit obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
337,640
|
|
|
$
|
335,581
|
|
Measurement date change
|
|
|
(18,446
|
)
|
|
|
|
|
Service cost
|
|
|
12,951
|
|
|
|
13,329
|
|
Interest cost
|
|
|
24,060
|
|
|
|
21,129
|
|
Actuarial loss (gain)
|
|
|
49,807
|
|
|
|
(6,939
|
)
|
Benefits paid
|
|
|
(25,967
|
)
|
|
|
(25,721
|
)
|
Plan amendments
|
|
|
|
|
|
|
261
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
380,045
|
|
|
|
337,640
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
341,380
|
|
|
|
389,073
|
|
Measurement date change
|
|
|
(34,935
|
)
|
|
|
|
|
Actual return on plan assets
|
|
|
(332
|
)
|
|
|
(21,972
|
)
|
Employer
contributions(1)
|
|
|
21,000
|
|
|
|
|
|
Benefits paid
|
|
|
(25,967
|
)
|
|
|
(25,721
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
301,146
|
|
|
|
341,380
|
|
|
|
|
|
|
|
|
|
|
Reconciliation:
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(78,899
|
)
|
|
|
3,740
|
|
Unrecognized prior service cost
|
|
|
|
|
|
|
|
|
Unrecognized net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(78,899
|
)
|
|
$
|
3,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the fourth quarter of fiscal 2008, we voluntarily
contributed $2.3 million to the Union Plan. However, this
contribution was not reflected in this table for the 2008 period
because it occurred after the June 30, 2008 measurement
date. It is reflected in the 2009 period as a portion of the
measurement date change in both the benefit obligation and the
fair value of plan assets rollforwards as this represents the
period from June 30, 2008 to September 30, 2009. |
103
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Net periodic pension cost for the Plans for fiscal 2009, 2008
and 2007 is recorded as operating expense and included the
following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
12,951
|
|
|
$
|
13,329
|
|
|
$
|
13,090
|
|
Interest cost
|
|
|
24,060
|
|
|
|
21,129
|
|
|
|
20,396
|
|
Expected return on assets
|
|
|
(24,950
|
)
|
|
|
(25,242
|
)
|
|
|
(24,357
|
)
|
Amortization of prior service cost
|
|
|
(946
|
)
|
|
|
(897
|
)
|
|
|
(838
|
)
|
Recognized actuarial loss
|
|
|
3,742
|
|
|
|
6,482
|
|
|
|
8,253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
14,857
|
|
|
$
|
14,801
|
|
|
$
|
16,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Executive Benefits Plans
We have a nonqualified Supplemental Executive Benefits Plan
which provides additional pension, disability and death benefits
to our officers, division presidents and certain other employees
of the Company who were employed on or before August 12,
1998. In addition, in August 1998, we adopted the Supplemental
Executive Retirement Plan (formerly known as 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.
During the last fiscal year, the Company has worked with our
independent compensation consultant to develop and implement a
new Supplemental Executive Retirement Plan (SERP) design for any
new executives or current employees selected for participation
in the SERP arrangement on a prospective basis. Only those
executives who are currently members of our Management Committee
as well as those individuals who may be selected in the future
to serve on the Management Committee, plus those executives who
are active SERP participants as of August 5, 2009, will
continue to participate in the current SERP arrangement until
their respective retirement dates. The current SERP arrangement
is a 60 percent of covered compensation defined benefit
arrangement in which benefits from the underlying qualified
defined benefit plan are an offset to the SERP benefit. The new
SERP arrangement for new participants in the Companys
executive retirement program is a modified defined benefit
approach in which the Company will contribute to a nominal
account for each participant, an amount equal to ten percent of
each participants base salary and bonus following the
participants completion of a plan year of service. Other
provisions of the plan mirror that of the Companys
underlying qualified plan, the Pension Account Plan. At this
time, only one employee has been selected for participation in
the new SERP arrangement.
Similar to our employee pension plans, we review the estimates
and assumptions underlying our supplemental executive benefit
plans annually based upon a September 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 September 30, 2009
and June 30, 2008 and the actuarial assumptions used to
determine the net periodic pension cost for the supplemental
plans were determined as of September 30, 2008,
June 30, 2007 and 2006. These assumptions are presented in
the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Liability
|
|
Pension Cost
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
2007
|
|
Discount rate
|
|
|
5.52
|
%
|
|
|
6.68
|
%
|
|
|
7.57
|
%
|
|
|
6.30
|
%
|
|
|
6.30
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
104
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, 2009 and 2008, based upon
a September 30, 2009 and June 30, 2008 measurement
date.
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Accumulated benefit obligation
|
|
$
|
93,906
|
|
|
$
|
83,871
|
|
|
|
|
|
|
|
|
|
|
Change in projected benefit obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
91,986
|
|
|
$
|
92,350
|
|
Measurement date change
|
|
|
(8,569
|
)
|
|
|
|
|
Service cost
|
|
|
1,985
|
|
|
|
2,184
|
|
Interest cost
|
|
|
6,056
|
|
|
|
5,816
|
|
Actuarial loss (gain)
|
|
|
22,366
|
|
|
|
(3,634
|
)
|
Benefits paid
|
|
|
(12,722
|
)
|
|
|
(4,730
|
)
|
Curtailment
|
|
|
1,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
102,747
|
|
|
|
91,986
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
|
|
|
|
|
|
Employer contribution
|
|
|
12,722
|
|
|
|
4,730
|
|
Benefits paid
|
|
|
(12,722
|
)
|
|
|
(4,730
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation:
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(102,747
|
)
|
|
|
(91,986
|
)
|
Unrecognized prior service cost
|
|
|
|
|
|
|
|
|
Unrecognized net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued pension cost
|
|
$
|
(102,747
|
)
|
|
$
|
(91,986
|
)
|
|
|
|
|
|
|
|
|
|
Assets for the supplemental plans are held in separate rabbi
trusts and comprise the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Gross
|
|
|
|
|
|
|
Amortized
|
|
|
Unrealized
|
|
|
Unrealized
|
|
|
Fair
|
|
|
|
Cost
|
|
|
Gain
|
|
|
Loss
|
|
|
Value
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
As of September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
26,012
|
|
|
$
|
3,012
|
|
|
$
|
|
|
|
$
|
29,024
|
|
Foreign equity mutual funds
|
|
|
4,047
|
|
|
|
893
|
|
|
|
|
|
|
|
4,940
|
|
Money market funds
|
|
|
7,735
|
|
|
|
|
|
|
|
|
|
|
|
7,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
37,794
|
|
|
$
|
3,905
|
|
|
$
|
|
|
|
$
|
41,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
31,041
|
|
|
$
|
1,625
|
|
|
$
|
(394
|
)
|
|
$
|
32,272
|
|
Foreign equity mutual funds
|
|
|
5,309
|
|
|
|
359
|
|
|
|
|
|
|
|
5,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,350
|
|
|
$
|
1,984
|
|
|
$
|
(394
|
)
|
|
$
|
37,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Due to the deterioration of the financial markets in late
calendar 2008 and early calendar 2009 and the uncertainty of a
full recovery of these investments given the current economic
environment, we recorded a
105
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$5.4 million noncash charge to impair certain available-for
sale investments during the year ended September 30, 2009.
As a result of this impairment and the recent improvement in
market conditions, at September 30, 2009, we did not
maintain any investments that are in an unrealized loss position.
Net periodic pension cost for the supplemental plans for fiscal
2009, 2008 and 2007 is recorded as operating expense and
included the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
1,985
|
|
|
$
|
2,184
|
|
|
$
|
2,981
|
|
Interest cost
|
|
|
6,056
|
|
|
|
5,816
|
|
|
|
5,585
|
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost
|
|
|
212
|
|
|
|
212
|
|
|
|
1,020
|
|
Recognized actuarial loss
|
|
|
324
|
|
|
|
1,222
|
|
|
|
1,482
|
|
Curtailment
|
|
|
1,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
10,222
|
|
|
$
|
9,434
|
|
|
$
|
11,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 2009 and 2008 the accumulated benefit
obligation for our supplemental plans exceeded the fair value of
plan assets.
|
|
|
|
|
|
|
|
|
|
|
Supplemental Plans
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Projected Benefit Obligation
|
|
$
|
102,747
|
|
|
$
|
91,986
|
|
Accumulated Benefit Obligation
|
|
|
93,906
|
|
|
|
83,871
|
|
Fair Value of Plan Assets
|
|
|
|
|
|
|
|
|
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 fiscal years:
|
|
|
|
|
|
|
|
|
|
|
Pension
|
|
|
Supplemental
|
|
|
|
Plans
|
|
|
Plans
|
|
|
|
(In thousands)
|
|
|
2010
|
|
$
|
31,334
|
|
|
$
|
21,410
|
|
2011
|
|
|
30,633
|
|
|
|
4,511
|
|
2012
|
|
|
30,806
|
|
|
|
10,527
|
|
2013
|
|
|
31,099
|
|
|
|
6,664
|
|
2014
|
|
|
31,467
|
|
|
|
4,664
|
|
2015-2019
|
|
|
168,140
|
|
|
|
37,965
|
|
106
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Postretirement
Benefits
We sponsor the Retiree Medical Plan for Retirees and Disabled
Employees of Atmos Energy Corporation (the Atmos Retiree Medical
Plan). This plan provides medical and prescription drug
protection to all qualified participants based on their date of
retirement. The Atmos Retiree Medical 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.
As of September 30, 2009, the Board of Directors approved a
change to the cost sharing methodology for employees who had not
met the participation requirements by that date for the Atmos
Retiree Medical Plan. Starting in five years, on January 1,
2015, the contribution rates that will apply to all
non-grandfathered participants will be determined using a new
cost sharing methodology by which Atmos Energy will limit its
contribution to a three percent cost increase in claims and
administrative costs each year. If medical costs covered by the
Atmos Retiree Medical Plan increase more than three percent
annually, participants will be responsible for the additional
cost.
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
$12.2 million to our postretirement benefits plan during
fiscal 2010.
We maintain a formal investment policy with respect to the
assets in our postretirement benefits plan to ensure the assets
funding the postretirement benefit plan 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 plan.
We currently invest the assets funding our postretirement
benefit plan in diversified investment funds which consist of
common stocks, preferred stocks and fixed income securities. The
diversified investment funds may invest up to 75 percent of
assets in common stocks and convertible securities. The
following table presents asset allocation information for the
postretirement benefit plan assets as of September 30, 2009
and 2008.
|
|
|
|
|
|
|
|
|
|
|
Actual Allocation
|
|
|
September 30
|
Security Class
|
|
2009
|
|
2008
|
|
Diversified investment funds
|
|
|
98.1
|
%
|
|
|
98.1
|
%
|
Cash and cash equivalents
|
|
|
1.9
|
%
|
|
|
1.9
|
%
|
Similar to our employee pension and supplemental plans, we
review the estimates and assumptions underlying our
postretirement benefit plan annually based upon a September 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 September 30, 2009 and June 30, 2008 and the
actuarial assumptions used to determine the net periodic pension
cost for the postretirement plan were
107
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
determined as of September 30, 2008, June 30, 2007 and
2006. The assumptions are presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement Liability
|
|
|
Postretirement Cost
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Discount rate
|
|
|
5.52
|
%
|
|
|
6.68
|
%
|
|
|
7.57
|
%
|
|
|
6.30
|
%
|
|
|
6.30
|
%
|
Expected return on plan assets
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.20
|
%
|
Initial trend rate
|
|
|
7.50
|
%
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
Ultimate trend rate
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
Ultimate trend reached in
|
|
|
2014
|
|
|
|
2014
|
|
|
|
2015
|
|
|
|
2011
|
|
|
|
2010
|
|
The following table presents the postretirement plans
benefit obligation and funded status as of September 30,
2009 and 2008, based upon a September 30, 2009 and
June 30, 2008 measurement date.
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
193,997
|
|
|
$
|
175,585
|
|
Measurement date change
|
|
|
(15,024
|
)
|
|
|
|
|
Service cost
|
|
|
11,786
|
|
|
|
13,367
|
|
Interest cost
|
|
|
14,080
|
|
|
|
11,648
|
|
Plan participants contributions
|
|
|
2,741
|
|
|
|
2,879
|
|
Actuarial loss (gain)
|
|
|
24,334
|
|
|
|
1,401
|
|
Benefits paid
|
|
|
(10,537
|
)
|
|
|
(11,008
|
)
|
Subsidy payments
|
|
|
116
|
|
|
|
125
|
|
Plan amendments
|
|
|
(11,761
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
209,732
|
|
|
|
193,997
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
48,072
|
|
|
|
55,370
|
|
Measurement date change
|
|
|
(4,128
|
)
|
|
|
|
|
Actual return on plan assets
|
|
|
1,394
|
|
|
|
(8,782
|
)
|
Employer contributions
|
|
|
10,104
|
|
|
|
9,613
|
|
Plan participants contributions
|
|
|
2,741
|
|
|
|
2,879
|
|
Benefits paid
|
|
|
(10,537
|
)
|
|
|
(11,008
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
47,646
|
|
|
|
48,072
|
|
|
|
|
|
|
|
|
|
|
Reconciliation:
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(162,086
|
)
|
|
|
(145,925
|
)
|
Unrecognized transition obligation
|
|
|
|
|
|
|
|
|
Unrecognized prior service cost
|
|
|
|
|
|
|
|
|
Unrecognized net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued postretirement cost
|
|
$
|
(162,086
|
)
|
|
$
|
(145,925
|
)
|
|
|
|
|
|
|
|
|
|
108
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Net periodic postretirement cost for fiscal 2009, 2008 and 2007
is recorded as operating expense and included the components
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Components of net periodic postretirement cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
11,786
|
|
|
$
|
13,367
|
|
|
$
|
11,228
|
|
Interest cost
|
|
|
14,080
|
|
|
|
11,648
|
|
|
|
10,561
|
|
Expected return on assets
|
|
|
(2,292
|
)
|
|
|
(2,861
|
)
|
|
|
(2,388
|
)
|
Amortization of transition obligation
|
|
|
1,511
|
|
|
|
1,511
|
|
|
|
1,512
|
|
Amortization of prior service cost
|
|
|
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement cost
|
|
$
|
25,085
|
|
|
$
|
23,665
|
|
|
$
|
20,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
3,740
|
|
|
$
|
(3,106
|
)
|
Effect on postretirement benefit obligation
|
|
$
|
24,463
|
|
|
$
|
(20,692
|
)
|
We are currently recovering other postretirement benefits costs
through our regulated rates under accrual accounting as
prescribed by accounting principles generally accepted in the
United States in substantially all of our service areas. Other
postretirement benefits costs have been specifically addressed
in rate orders in each jurisdiction served by our
Kentucky/Mid-States Division and our Mississippi Division or
have been included in a rate case and not disallowed. Management
believes that this accounting method 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 fiscal
years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Company
|
|
Retiree
|
|
Subsidy
|
|
Postretirement
|
|
|
Payments
|
|
Payments
|
|
Payments
|
|
Benefits
|
|
|
(In thousands)
|
|
2010
|
|
$
|
12,242
|
|
|
$
|
2,740
|
|
|
$
|
92
|
|
|
$
|
15,074
|
|
2011
|
|
|
10,696
|
|
|
|
3,179
|
|
|
|
76
|
|
|
|
13,951
|
|
2012
|
|
|
12,161
|
|
|
|
3,596
|
|
|
|
87
|
|
|
|
15,844
|
|
2013
|
|
|
13,519
|
|
|
|
4,008
|
|
|
|
100
|
|
|
|
17,627
|
|
2014
|
|
|
15,167
|
|
|
|
4,531
|
|
|
|
115
|
|
|
|
19,813
|
|
2015-2019
|
|
|
98,997
|
|
|
|
33,946
|
|
|
|
62
|
|
|
|
133,005
|
|
109
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Defined
Contribution Plans
As of September 30, 2009, we maintained three defined
contribution benefit plans: the Atmos Energy Corporation
Retirement Savings Plan and Trust (the Retirement Savings Plan),
the Atmos Energy Corporation Savings Plan for MVG Union
Employees (the Union 401K Plan) and the Atmos Energy Marketing,
LLC 401K Profit-Sharing Plan (the AEM 401K Profit-Sharing Plan).
The Retirement Savings Plan covers substantially all employees
in our regulated operations and is subject to the provisions of
Section 401(k) of the Internal Revenue Code. Effective
January 1, 2007, employees automatically became
participants of the Retirement Savings Plan on the date of
employment. 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. New
participants are automatically enrolled in the Plan at a salary
reduction amount of four percent of eligible compensation, from
which they may opt out. We match 100 percent of a
participants contributions, limited to four percent of the
participants salary, in our 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 membership. We match 50 percent
of a participants contribution in cash, 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 the Retirement Savings Plan and the
Union 401K Plan are expensed as incurred and amounted to
$9.3 million, $8.9 million, and $8.3 million for
fiscal years 2009, 2008 and 2007. 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 fiscal years 2009, 2008 or 2007. At
September 30, 2009 and 2008, the Retirement Savings Plan
held 3.8 percent and 3.4 percent of our outstanding
common stock.
The AEM 401K Profit-Sharing Plan covers substantially all AEM
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. The Company may elect
to make safe harbor contributions up to three percent of the
employees salary which vest immediately. The Company may
also make discretionary profit sharing contributions to the AEM
401K Profit-Sharing Plan. Participants become fully vested in
the discretionary profit-sharing contributions after three years
of service. Participants are also permitted to take out loans
against their accounts subject to certain restrictions.
Discretionary contributions to the AEM 401K Profit-Sharing Plan
are expensed as incurred and amounted to $0.7 million,
$0.5 million and $0.8 million for fiscal years 2009,
2008 and 2007.
110
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
9.
|
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, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Billed accounts receivable
|
|
$
|
179,667
|
|
|
$
|
411,225
|
|
Unbilled revenue
|
|
|
42,618
|
|
|
|
49,496
|
|
Other accounts receivable
|
|
|
21,999
|
|
|
|
31,731
|
|
|
|
|
|
|
|
|
|
|
Total accounts receivable
|
|
|
244,284
|
|
|
|
492,452
|
|
Less: allowance for doubtful accounts
|
|
|
(11,478
|
)
|
|
|
(15,301
|
)
|
|
|
|
|
|
|
|
|
|
Net accounts receivable
|
|
$
|
232,806
|
|
|
$
|
477,151
|
|
|
|
|
|
|
|
|
|
|
Other
current assets
Other current assets as of September 30, 2009 and 2008 were
comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Assets from risk management activities
|
|
$
|
31,643
|
|
|
$
|
68,291
|
|
Deferred gas costs
|
|
|
22,233
|
|
|
|
55,103
|
|
Taxes receivable
|
|
|
15,115
|
|
|
|
22,052
|
|
Prepaid expenses
|
|
|
21,807
|
|
|
|
16,738
|
|
Current portion of leased assets receivable
|
|
|
2,973
|
|
|
|
2,973
|
|
Materials and supplies
|
|
|
3,349
|
|
|
|
4,304
|
|
Asset held for sale
|
|
|
19,925
|
|
|
|
|
|
Other
|
|
|
15,158
|
|
|
|
15,158
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
132,203
|
|
|
$
|
184,619
|
|
|
|
|
|
|
|
|
|
|
In February 2008, Atmos Pipeline and Storage, LLC, a subsidiary
of AEH, announced plans to construct and operate a salt-cavern
storage project in Franklin Parish, Louisiana. During the fiscal
year ended September 30, 2009, management approved a plan
to pursue the sale of the storage facility project, which is
expected to be completed within the next fiscal year.
Accordingly, the assets associated with this project have been
classified as an asset held for sale as of September 30,
2009.
111
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Property,
plant and equipment
Property, plant and equipment was comprised of the following as
of September 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Production plant
|
|
$
|
23,359
|
|
|
$
|
21,958
|
|
Storage plant
|
|
|
156,466
|
|
|
|
150,984
|
|
Transmission plant
|
|
|
1,029,487
|
|
|
|
942,169
|
|
Distribution plant
|
|
|
4,103,531
|
|
|
|
3,870,606
|
|
General plant
|
|
|
614,324
|
|
|
|
597,460
|
|
Intangible plant
|
|
|
54,253
|
|
|
|
66,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,981,420
|
|
|
|
5,650,096
|
|
Construction in progress
|
|
|
105,198
|
|
|
|
80,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,086,618
|
|
|
|
5,730,156
|
|
Less: accumulated depreciation and amortization
|
|
|
(1,647,515
|
)
|
|
|
(1,593,297
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
4,439,103
|
|
|
$
|
4,136,859
|
|
|
|
|
|
|
|
|
|
|
Deferred
charges and other assets
Deferred charges and other assets as of September 30, 2009
and 2008 were comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Pension plan assets in excess of plan obligations
|
|
$
|
|
|
|
$
|
7,997
|
|
Marketable securities
|
|
|
41,699
|
|
|
|
37,940
|
|
Regulatory assets
|
|
|
227,925
|
|
|
|
130,785
|
|
Deferred financing costs
|
|
|
40,854
|
|
|
|
35,378
|
|
Assets from risk management activities
|
|
|
14,035
|
|
|
|
5,473
|
|
Other
|
|
|
11,146
|
|
|
|
8,077
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
335,659
|
|
|
$
|
225,650
|
|
|
|
|
|
|
|
|
|
|
112
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
current liabilities
Other current liabilities as of September 30, 2009 and 2008
were comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Customer deposits
|
|
$
|
69,966
|
|
|
$
|
75,297
|
|
Accrued employee costs
|
|
|
40,582
|
|
|
|
42,956
|
|
Deferred gas costs
|
|
|
110,754
|
|
|
|
76,979
|
|
Accrued interest
|
|
|
46,495
|
|
|
|
52,366
|
|
Liabilities from risk management activities
|
|
|
21,482
|
|
|
|
58,914
|
|
Taxes payable
|
|
|
49,821
|
|
|
|
53,639
|
|
Pension and postretirement obligations
|
|
|
28,712
|
|
|
|
16,950
|
|
Regulatory cost of removal accrual
|
|
|
14,342
|
|
|
|
18,628
|
|
Current deferred tax liability
|
|
|
9,054
|
|
|
|
1,833
|
|
Other
|
|
|
66,111
|
|
|
|
62,810
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
457,319
|
|
|
$
|
460,372
|
|
|
|
|
|
|
|
|
|
|
Deferred
credits and other liabilities
Deferred credits and other liabilities as of September 30,
2009 and 2008 were comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Postretirement obligations
|
|
$
|
154,784
|
|
|
$
|
137,075
|
|
Retirement plan obligations
|
|
|
160,236
|
|
|
|
88,143
|
|
Customer advances for construction
|
|
|
16,907
|
|
|
|
17,814
|
|
Regulatory liabilities
|
|
|
7,960
|
|
|
|
5,639
|
|
Asset retirement obligation
|
|
|
13,037
|
|
|
|
5,883
|
|
Uncertain tax positions
|
|
|
6,731
|
|
|
|
6,731
|
|
Liabilities from risk management activities
|
|
|
|
|
|
|
5,369
|
|
Other
|
|
|
8,503
|
|
|
|
727
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
368,158
|
|
|
$
|
267,381
|
|
|
|
|
|
|
|
|
|
|
113
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Basic and diluted earnings per share for the fiscal years ended
September 30 are calculated as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Net income
|
|
$
|
190,978
|
|
|
$
|
180,331
|
|
|
$
|
168,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic income per share weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
average common shares
|
|
|
91,117
|
|
|
|
89,385
|
|
|
|
86,975
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted and other shares
|
|
|
858
|
|
|
|
790
|
|
|
|
620
|
|
Stock options
|
|
|
49
|
|
|
|
97
|
|
|
|
150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted income per share weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
average common shares
|
|
|
92,024
|
|
|
|
90,272
|
|
|
|
87,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share basic
|
|
$
|
2.10
|
|
|
$
|
2.02
|
|
|
$
|
1.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted
|
|
$
|
2.08
|
|
|
$
|
2.00
|
|
|
$
|
1.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were approximately 70,000
out-of-the-money
options excluded from the computation of diluted earnings per
share for the fiscal year ended September 30, 2009. There
were no
out-of-the-money
options excluded from the computation of diluted earnings per
share for the fiscal year ended September 30, 2008 and 2007.
The components of income tax expense from continuing operations
for 2009, 2008 and 2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(37,042
|
)
|
|
$
|
7,161
|
|
|
$
|
22,616
|
|
State
|
|
|
7,964
|
|
|
|
7,696
|
|
|
|
9,810
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
138,959
|
|
|
|
85,573
|
|
|
|
56,349
|
|
State
|
|
|
(9,200
|
)
|
|
|
12,367
|
|
|
|
5,772
|
|
Investment tax credits
|
|
|
(390
|
)
|
|
|
(424
|
)
|
|
|
(455
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
100,291
|
|
|
$
|
112,373
|
|
|
$
|
94,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
114
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Reconciliations of the provision for income taxes computed at
the statutory rate to the reported provisions for income taxes
from continuing operations for 2009, 2008 and 2007 are set forth
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Tax at statutory rate of 35%
|
|
$
|
101,944
|
|
|
$
|
102,446
|
|
|
$
|
91,904
|
|
Common stock dividends deductible for tax reporting
|
|
|
(1,591
|
)
|
|
|
(1,363
|
)
|
|
|
(1,233
|
)
|
Depreciation/amortization
|
|
|
|
|
|
|
|
|
|
|
(4,727
|
)
|
Tax exempt income
|
|
|
(153
|
)
|
|
|
|
|
|
|
(1,890
|
)
|
State taxes (net of federal benefit)
|
|
|
(803
|
)
|
|
|
12,523
|
|
|
|
10,253
|
|
Other, net
|
|
|
894
|
|
|
|
(1,233
|
)
|
|
|
(215
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
100,291
|
|
|
$
|
112,373
|
|
|
$
|
94,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 gave rise
to significant components of the deferred tax liabilities and
deferred tax assets at September 30, 2009 and 2008 are
presented below:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Costs expensed for book purposes and capitalized for tax purposes
|
|
$
|
6,771
|
|
|
$
|
16,305
|
|
Accruals not currently deductible for tax purposes
|
|
|
7,664
|
|
|
|
11,627
|
|
Customer advances
|
|
|
6,256
|
|
|
|
6,769
|
|
Nonqualified benefit plans
|
|
|
41,359
|
|
|
|
39,632
|
|
Postretirement benefits
|
|
|
53,074
|
|
|
|
46,319
|
|
Treasury lock agreement
|
|
|
4,404
|
|
|
|
6,806
|
|
Unamortized investment tax credit
|
|
|
192
|
|
|
|
345
|
|
Regulatory liabilities
|
|
|
834
|
|
|
|
911
|
|
Tax net operating loss and credit carryforwards
|
|
|
1,997
|
|
|
|
616
|
|
Other, net
|
|
|
6,311
|
|
|
|
543
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
128,862
|
|
|
|
129,873
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Difference in net book value and net tax value of assets
|
|
|
(672,763
|
)
|
|
|
(534,607
|
)
|
Pension funding
|
|
|
(21,379
|
)
|
|
|
(25,777
|
)
|
Gas cost adjustments
|
|
|
(2,459
|
)
|
|
|
(5,362
|
)
|
Regulatory assets
|
|
|
(195
|
)
|
|
|
(568
|
)
|
Difference between book and tax on mark to market accounting
|
|
|
(12,060
|
)
|
|
|
(6,694
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(708,856
|
)
|
|
|
(573,008
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities
|
|
$
|
(579,994
|
)
|
|
$
|
(443,135
|
)
|
|
|
|
|
|
|
|
|
|
Deferred credits for rate regulated entities
|
|
$
|
2,253
|
|
|
$
|
2,397
|
|
|
|
|
|
|
|
|
|
|
We have tax carryforwards relating to state net operating losses
amounting to $1.9 million. Depending on the jurisdiction in
which the net operating loss was generated, the state net
operating losses will begin to expire between 2014 and 2027.
115
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of September 30, 2009 and 2008, we had recorded
liabilities associated with uncertain tax positions totaling
$6.7 million. The realization of all of these tax benefits
would reduce our income tax expense by approximately
$6.7 million. There were no changes in unrecognized tax
benefits as a result of tax positions taken during the current
or prior years or as a result of settlements with taxing
authorities for the year ended September 30, 2009.
We file income tax returns in the U.S. federal jurisdiction
as well as in various states where we have operations. We have
concluded substantially all U.S. federal income tax matters
through fiscal year 2004.
|
|
12.
|
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. In
September 2009, the court ruled that the plaintiffs in both
cases had not provided sufficient evidence to meet the standards
of a class action and denied class action status to each of the
plaintiffs in both cases. We believe that the plaintiffs
claims in both cases 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 condition, results of operations or cash flows. We are
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. In October 2006, the District Court
granted the defendants motion to dismiss this lawsuit for
lack of subject matter jurisdiction. The plaintiffs appealed
this dismissal order on which oral arguments were heard by the
United States Court of Appeals for the Tenth Circuit in
September 2008. In May 2009, the Tenth Circuit denied such
appeal and motion for rehearing. In August 2009, the plaintiffs
filed for a Writ of Certiorari with the Supreme Court of the
United States appealing the Tenth Circuits order
dismissing the lawsuit, which the Supreme Court denied on
October 5, 2009.
We are a party to other litigation and claims that have arisen
in the ordinary course of our business. While the results of
such litigation and claims cannot be predicted with certainty,
we believe the final outcome of such litigation and claims will
not have a material adverse effect on our financial condition,
results of operations or 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, Hannibal, Missouri and Owensboro, Kentucky, 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
116
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
actions are necessary. We have taken removal actions with
respect to the sites that have been approved by the applicable
regulatory authorities in Tennessee, Iowa, Missouri, Kentucky
and the United States Environmental Protection Agency.
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 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.
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, 2009, AEM was committed
to purchase 72.6 Bcf within one year, 19.4 Bcf within
one to three years and 2.2 Bcf after three years under
indexed contracts. AEM is committed to purchase 2.9 Bcf
within one year under fixed price contracts with prices ranging
from $2.95 to $7.68 per Mcf. Purchases under these contracts
totaled $1,484.5 million, $3,075.0 million and
$2,065.1 million for 2009, 2008 and 2007.
Our natural gas distribution 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
and fixed prices. The estimated commitments under these
contracts as of September 30, 2009 are as follows (in
thousands):
|
|
|
|
|
2010
|
|
$
|
312,837
|
|
2011
|
|
|
7,600
|
|
2012
|
|
|
7,632
|
|
2013
|
|
|
7,974
|
|
2014
|
|
|
2,703
|
|
|
|
|
|
|
|
|
$
|
338,746
|
|
|
|
|
|
|
117
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our natural gas marketing and pipeline, storage and other
segments maintain long-term contracts related to storage and
transportation. The estimated contractual demand fees for
contracted storage and transportation under these contracts as
of September 30, 2009 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline,
|
|
|
|
Natural Gas
|
|
|
Storage and
|
|
|
|
Marketing
|
|
|
Other
|
|
|
2010
|
|
$
|
20,510
|
|
|
$
|
1,775
|
|
2011
|
|
|
15,994
|
|
|
|
500
|
|
2012
|
|
|
13,323
|
|
|
|
500
|
|
2013
|
|
|
8,556
|
|
|
|
500
|
|
2014
|
|
|
4,842
|
|
|
|
500
|
|
Thereafter
|
|
|
3,157
|
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
66,382
|
|
|
$
|
4,025
|
|
|
|
|
|
|
|
|
|
|
Other
Contingencies
In December 2007, the Company received data requests from the
Division of Investigations of the Office of Enforcement of the
Federal Energy Regulatory Commission (the
Commission) in connection with its investigation
into possible violations of the Commissions posting and
competitive bidding regulations for pre-arranged released firm
capacity on natural gas pipelines. We have responded timely to
data requests received from the Commission and are fully
cooperating with the Commission during this investigation.
The Commission agreed to allow the Company to conduct our own
internal investigation into compliance with the
Commissions rules. We have completed the investigation and
have provided a report on the results of the investigation to
the Commission, which report is currently under review by the
Commission. We currently are unable to predict the final outcome
of this investigation or the potential impact it could have on
our financial position, results of operations or cash flows.
In September 2008, the Texas Railroad Commission issued a final
rule requiring the replacement of known compression couplings at
pre-bent gas meter risers by November 2009. Compliance with this
rule has not had a significant impact on our West Texas Division
but has required us to spend significant amounts of capital in
our Mid-Tex Division. As of September 30, 2009 we had
substantially completed our pre-bent riser replacement program
in the Mid-Tex Division.
Leasing
Operations
A subsidiary of AEH has constructed electric peaking
power-generating plants and associated facilities and entered
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, 2009 and 2008, we had
receivables of $10.8 million and $13.8 million and
recognized income of $1.2 million, $1.3 million and
$1.5 million for
118
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
fiscal years 2009, 2008 and 2007. The future minimum lease
payments to be received for each of the five succeeding fiscal
years are as follows:
|
|
|
|
|
|
|
Minimum
|
|
|
|
Lease
|
|
|
|
Receipts
|
|
|
|
(In thousands)
|
|
|
2010
|
|
$
|
2,973
|
|
2011
|
|
|
2,973
|
|
2012
|
|
|
2,973
|
|
2013
|
|
|
1,897
|
|
2014
|
|
|
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
Total minimum lease receipts
|
|
$
|
10,816
|
|
|
|
|
|
|
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 22 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 $1.3 million at both September 30,
2009 and 2008. Accumulated depreciation for these capital leases
totaled $0.8 million and $0.7 million at
September 30, 2009 and 2008. 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,
2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Capital
|
|
|
Operating
|
|
|
|
Leases
|
|
|
Leases
|
|
|
|
(In thousands)
|
|
|
2010
|
|
$
|
186
|
|
|
$
|
17,764
|
|
2011
|
|
|
186
|
|
|
|
16,402
|
|
2012
|
|
|
186
|
|
|
|
15,007
|
|
2013
|
|
|
186
|
|
|
|
13,873
|
|
2014
|
|
|
186
|
|
|
|
13,858
|
|
Thereafter
|
|
|
635
|
|
|
|
142,106
|
|
|
|
|
|
|
|
|
|
|
Total minimum lease payments
|
|
|
1,565
|
|
|
$
|
219,010
|
|
|
|
|
|
|
|
|
|
|
Less amount representing interest
|
|
|
617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value of net minimum lease payments
|
|
$
|
948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated lease and rental expense amounted to
$13.6 million, $14.2 million and $11.3 million
for fiscal 2009, 2008 and 2007.
|
|
14.
|
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
119
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
concentration does not contribute significantly to our overall
exposure to credit risk. Credit risk associated with trade
accounts receivable for the natural gas distribution segment is
mitigated by the large number of individual customers and
diversity in our customer base. The credit risk for our other
segments 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, primarily consisting of letters of
credit, 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,
consideration of the current credit environment and other
information. We believe, based on our credit policies and our
provisions for credit losses as of September 30, 2009, 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, including affiliate 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, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
Investment grade
|
|
|
53
|
%
|
|
|
52
|
%
|
Non-investment grade
|
|
|
47
|
%
|
|
|
48
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
The following table presents our financial instrument
counterparty credit exposure by operating segment based upon the
unrealized fair value of our financial instruments that
represent assets as of September 30, 2009. Investment grade
counterparties have minimum credit ratings of BBB-, assigned by
S&P; or Baa3, assigned by Moodys. 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
|
|
|
Natural Gas
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
|
|
|
|
Segment(1)
|
|
|
Segment
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Investment grade counterparties
|
|
$
|
|
|
|
$
|
20,523
|
|
|
$
|
20,523
|
|
Non-investment grade counterparties
|
|
|
|
|
|
|
7,476
|
|
|
|
7,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
27,999
|
|
|
$
|
27,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Counterparty risk for our natural gas distribution segment is
minimized because hedging gains and losses are passed through to
our customers. |
120
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
15.
|
Supplemental
Cash Flow Disclosures
|
Supplemental disclosures of cash flow information for fiscal
2009, 2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
2008
|
|
2007
|
|
|
(In thousands)
|
|
Cash paid for interest
|
|
$
|
163,554
|
|
|
$
|
139,958
|
|
|
$
|
151,616
|
|
Cash paid (received) for income taxes
|
|
$
|
(36,405
|
)
|
|
$
|
3,483
|
|
|
$
|
8,939
|
|
There were no significant noncash investing and financing
transactions during fiscal 2009, 2008 and 2007. All cash flows
and noncash activities related to our commodity financial
instruments are considered as operating activities.
Atmos Energy Corporation and its subsidiaries are engaged
primarily in the regulated natural gas distribution,
transmission and storage business as well as other nonregulated
businesses. We distribute natural gas through sales and
transportation arrangements to over 3 million residential,
commercial, public authority and industrial customers through
our six regulated natural gas distribution divisions, which
cover service areas located in 12 states. In addition, we
transport natural gas for others through our distribution system.
Through our nonregulated businesses, we primarily provide
natural gas management and marketing services to municipalities,
other local distribution companies and industrial customers
primarily in the Midwest and Southeast. Additionally, we provide
natural gas transportation and storage services to certain of
our natural gas distribution operations and to third parties.
We operate the Company through the following four segments:
|
|
|
|
|
The natural gas distribution segment, which includes our
regulated natural gas distribution and related sales operations.
|
|
|
|
The regulated transmission and storage segment, which
includes the regulated pipeline and storage operations of the
Atmos Pipeline Texas Division.
|
|
|
|
The natural gas marketing segment, which includes a
variety of nonregulated natural gas management services.
|
|
|
|
The pipeline, storage and other segment, which includes
our nonregulated natural gas transmission and storage services.
|
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 natural gas distribution segment operations are
geographically dispersed, they are reported as a single segment
as each natural gas distribution 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.
121
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, 2009
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Transmission
|
|
|
Natural Gas
|
|
|
Storage
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
and Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
2,983,966
|
|
|
$
|
119,427
|
|
|
$
|
1,832,912
|
|
|
$
|
32,775
|
|
|
$
|
|
|
|
$
|
4,969,080
|
|
Intersegment revenues
|
|
|
799
|
|
|
|
90,231
|
|
|
|
503,935
|
|
|
|
9,149
|
|
|
|
(604,114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,984,765
|
|
|
|
209,658
|
|
|
|
2,336,847
|
|
|
|
41,924
|
|
|
|
(604,114
|
)
|
|
|
4,969,080
|
|
Purchased gas cost
|
|
|
1,960,137
|
|
|
|
|
|
|
|
2,252,235
|
|
|
|
12,428
|
|
|
|
(602,422
|
)
|
|
|
3,622,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
1,024,628
|
|
|
|
209,658
|
|
|
|
84,612
|
|
|
|
29,496
|
|
|
|
(1,692
|
)
|
|
|
1,346,702
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
369,429
|
|
|
|
85,249
|
|
|
|
34,201
|
|
|
|
7,167
|
|
|
|
(2,036
|
)
|
|
|
494,010
|
|
Depreciation and amortization
|
|
|
192,274
|
|
|
|
20,413
|
|
|
|
1,590
|
|
|
|
2,931
|
|
|
|
|
|
|
|
217,208
|
|
Taxes, other than income
|
|
|
169,312
|
|
|
|
10,231
|
|
|
|
2,271
|
|
|
|
886
|
|
|
|
|
|
|
|
182,700
|
|
Asset impairments
|
|
|
4,599
|
|
|
|
602
|
|
|
|
146
|
|
|
|
35
|
|
|
|
|
|
|
|
5,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
735,614
|
|
|
|
116,495
|
|
|
|
38,208
|
|
|
|
11,019
|
|
|
|
(2,036
|
)
|
|
|
899,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
289,014
|
|
|
|
93,163
|
|
|
|
46,404
|
|
|
|
18,477
|
|
|
|
344
|
|
|
|
447,402
|
|
Miscellaneous income (expense)
|
|
|
5,766
|
|
|
|
1,433
|
|
|
|
537
|
|
|
|
6,253
|
|
|
|
(17,292
|
)
|
|
|
(3,303
|
)
|
Interest charges
|
|
|
124,055
|
|
|
|
30,982
|
|
|
|
12,911
|
|
|
|
1,830
|
|
|
|
(16,948
|
)
|
|
|
152,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
170,725
|
|
|
|
63,614
|
|
|
|
34,030
|
|
|
|
22,900
|
|
|
|
|
|
|
|
291,269
|
|
Income tax expense
|
|
|
53,918
|
|
|
|
22,558
|
|
|
|
13,836
|
|
|
|
9,979
|
|
|
|
|
|
|
|
100,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
116,807
|
|
|
$
|
41,056
|
|
|
$
|
20,194
|
|
|
$
|
12,921
|
|
|
$
|
|
|
|
$
|
190,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
379,500
|
|
|
$
|
108,332
|
|
|
$
|
242
|
|
|
$
|
21,420
|
|
|
$
|
|
|
|
$
|
509,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2008
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Transmission
|
|
|
Natural Gas
|
|
|
Storage
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
and Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
3,654,338
|
|
|
$
|
108,116
|
|
|
$
|
3,436,563
|
|
|
$
|
22,288
|
|
|
$
|
|
|
|
$
|
7,221,305
|
|
Intersegment revenues
|
|
|
792
|
|
|
|
87,801
|
|
|
|
851,299
|
|
|
|
9,421
|
|
|
|
(949,313
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,655,130
|
|
|
|
195,917
|
|
|
|
4,287,862
|
|
|
|
31,709
|
|
|
|
(949,313
|
)
|
|
|
7,221,305
|
|
Purchased gas cost
|
|
|
2,649,064
|
|
|
|
|
|
|
|
4,194,841
|
|
|
|
3,396
|
|
|
|
(947,322
|
)
|
|
|
5,899,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
1,006,066
|
|
|
|
195,917
|
|
|
|
93,021
|
|
|
|
28,313
|
|
|
|
(1,991
|
)
|
|
|
1,321,326
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
389,244
|
|
|
|
77,439
|
|
|
|
30,903
|
|
|
|
4,983
|
|
|
|
(2,335
|
)
|
|
|
500,234
|
|
Depreciation and amortization
|
|
|
177,205
|
|
|
|
19,899
|
|
|
|
1,546
|
|
|
|
1,792
|
|
|
|
|
|
|
|
200,442
|
|
Taxes, other than income
|
|
|
178,452
|
|
|
|
8,834
|
|
|
|
4,180
|
|
|
|
1,289
|
|
|
|
|
|
|
|
192,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
744,901
|
|
|
|
106,172
|
|
|
|
36,629
|
|
|
|
8,064
|
|
|
|
(2,335
|
)
|
|
|
893,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
261,165
|
|
|
|
89,745
|
|
|
|
56,392
|
|
|
|
20,249
|
|
|
|
344
|
|
|
|
427,895
|
|
Miscellaneous income
|
|
|
9,689
|
|
|
|
1,354
|
|
|
|
2,022
|
|
|
|
8,428
|
|
|
|
(18,762
|
)
|
|
|
2,731
|
|
Interest charges
|
|
|
117,933
|
|
|
|
27,049
|
|
|
|
9,036
|
|
|
|
2,322
|
|
|
|
(18,418
|
)
|
|
|
137,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
152,921
|
|
|
|
64,050
|
|
|
|
49,378
|
|
|
|
26,355
|
|
|
|
|
|
|
|
292,704
|
|
Income tax expense
|
|
|
60,273
|
|
|
|
22,625
|
|
|
|
19,389
|
|
|
|
10,086
|
|
|
|
|
|
|
|
112,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
92,648
|
|
|
$
|
41,425
|
|
|
$
|
29,989
|
|
|
$
|
16,269
|
|
|
$
|
|
|
|
$
|
180,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
386,542
|
|
|
$
|
75,071
|
|
|
$
|
340
|
|
|
$
|
10,320
|
|
|
$
|
|
|
|
$
|
472,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2007
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Transmission
|
|
|
Natural Gas
|
|
|
Storage
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
and Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
3,358,147
|
|
|
$
|
84,344
|
|
|
$
|
2,432,280
|
|
|
$
|
23,660
|
|
|
$
|
|
|
|
$
|
5,898,431
|
|
Intersegment revenues
|
|
|
618
|
|
|
|
78,885
|
|
|
|
719,050
|
|
|
|
9,740
|
|
|
|
(808,293
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,358,765
|
|
|
|
163,229
|
|
|
|
3,151,330
|
|
|
|
33,400
|
|
|
|
(808,293
|
)
|
|
|
5,898,431
|
|
Purchased gas cost
|
|
|
2,406,081
|
|
|
|
|
|
|
|
3,047,019
|
|
|
|
792
|
|
|
|
(805,543
|
)
|
|
|
4,648,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
952,684
|
|
|
|
163,229
|
|
|
|
104,311
|
|
|
|
32,608
|
|
|
|
(2,750
|
)
|
|
|
1,250,082
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
379,175
|
|
|
|
56,231
|
|
|
|
26,480
|
|
|
|
4,581
|
|
|
|
(3,094
|
)
|
|
|
463,373
|
|
Depreciation and amortization
|
|
|
177,188
|
|
|
|
18,565
|
|
|
|
1,536
|
|
|
|
1,574
|
|
|
|
|
|
|
|
198,863
|
|
Taxes, other than income
|
|
|
171,845
|
|
|
|
8,603
|
|
|
|
1,255
|
|
|
|
1,163
|
|
|
|
|
|
|
|
182,866
|
|
Asset impairments
|
|
|
3,289
|
|
|
|
|
|
|
|
|
|
|
|
3,055
|
|
|
|
|
|
|
|
6,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
731,497
|
|
|
|
83,399
|
|
|
|
29,271
|
|
|
|
10,373
|
|
|
|
(3,094
|
)
|
|
|
851,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
221,187
|
|
|
|
79,830
|
|
|
|
75,040
|
|
|
|
22,235
|
|
|
|
344
|
|
|
|
398,636
|
|
Miscellaneous income
|
|
|
8,945
|
|
|
|
2,105
|
|
|
|
6,434
|
|
|
|
8,173
|
|
|
|
(16,473
|
)
|
|
|
9,184
|
|
Interest charges
|
|
|
121,626
|
|
|
|
27,917
|
|
|
|
5,767
|
|
|
|
6,055
|
|
|
|
(16,129
|
)
|
|
|
145,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
108,506
|
|
|
|
54,018
|
|
|
|
75,707
|
|
|
|
24,353
|
|
|
|
|
|
|
|
262,584
|
|
Income tax expense
|
|
|
35,223
|
|
|
|
19,428
|
|
|
|
29,938
|
|
|
|
9,503
|
|
|
|
|
|
|
|
94,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
73,283
|
|
|
$
|
34,590
|
|
|
$
|
45,769
|
|
|
$
|
14,850
|
|
|
$
|
|
|
|
$
|
168,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
327,442
|
|
|
$
|
59,276
|
|
|
$
|
1,069
|
|
|
$
|
4,648
|
|
|
$
|
|
|
|
$
|
392,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes our revenues by products and
services for the fiscal year ended September 30.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
1,830,140
|
|
|
$
|
2,131,447
|
|
|
$
|
1,982,801
|
|
Commercial
|
|
|
838,184
|
|
|
|
1,077,056
|
|
|
|
970,949
|
|
Industrial
|
|
|
135,633
|
|
|
|
212,531
|
|
|
|
195,060
|
|
Public authority and other
|
|
|
89,183
|
|
|
|
137,821
|
|
|
|
114,298
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales revenues
|
|
|
2,893,140
|
|
|
|
3,558,855
|
|
|
|
3,263,108
|
|
Transportation revenues
|
|
|
59,115
|
|
|
|
59,712
|
|
|
|
59,195
|
|
Other gas revenues
|
|
|
31,711
|
|
|
|
35,771
|
|
|
|
35,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas distribution revenues
|
|
|
2,983,966
|
|
|
|
3,654,338
|
|
|
|
3,358,147
|
|
Regulated transmission and storage revenues
|
|
|
119,427
|
|
|
|
108,116
|
|
|
|
84,344
|
|
Natural gas marketing revenues
|
|
|
1,832,912
|
|
|
|
3,436,563
|
|
|
|
2,432,280
|
|
Pipeline, storage and other revenues
|
|
|
32,775
|
|
|
|
22,288
|
|
|
|
23,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
4,969,080
|
|
|
$
|
7,221,305
|
|
|
$
|
5,898,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
124
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at September 30, 2009 and 2008 by
segment is presented in the following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Transmission
|
|
|
Natural Gas
|
|
|
Storage
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
and Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Property, plant and equipment, net
|
|
$
|
3,703,471
|
|
|
$
|
672,829
|
|
|
$
|
7,112
|
|
|
$
|
55,691
|
|
|
$
|
|
|
|
$
|
4,439,103
|
|
Investment in subsidiaries
|
|
|
547,936
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(545,840
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
23,655
|
|
|
|
|
|
|
|
87,266
|
|
|
|
282
|
|
|
|
|
|
|
|
111,203
|
|
Assets from risk management activities
|
|
|
4,395
|
|
|
|
|
|
|
|
27,424
|
|
|
|
2,765
|
|
|
|
(2,941
|
)
|
|
|
31,643
|
|
Other current assets
|
|
|
499,155
|
|
|
|
17,017
|
|
|
|
157,846
|
|
|
|
112,551
|
|
|
|
(100,475
|
)
|
|
|
686,094
|
|
Intercompany receivables
|
|
|
552,408
|
|
|
|
|
|
|
|
|
|
|
|
128,104
|
|
|
|
(680,512
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,079,613
|
|
|
|
17,017
|
|
|
|
272,536
|
|
|
|
243,702
|
|
|
|
(783,928
|
)
|
|
|
828,940
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
1,461
|
|
|
|
|
|
|
|
|
|
|
|
1,461
|
|
Goodwill
|
|
|
571,592
|
|
|
|
132,300
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
738,603
|
|
Noncurrent assets from risk management activities
|
|
|
1,620
|
|
|
|
|
|
|
|
12,415
|
|
|
|
6
|
|
|
|
(6
|
)
|
|
|
14,035
|
|
Deferred charges and other assets
|
|
|
290,327
|
|
|
|
11,932
|
|
|
|
1,065
|
|
|
|
18,300
|
|
|
|
|
|
|
|
321,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,194,559
|
|
|
$
|
834,078
|
|
|
$
|
316,775
|
|
|
$
|
328,128
|
|
|
$
|
(1,329,774
|
)
|
|
$
|
6,343,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
Shareholders equity
|
|
$
|
2,176,761
|
|
|
$
|
171,200
|
|
|
$
|
83,354
|
|
|
$
|
293,382
|
|
|
$
|
(547,936
|
)
|
|
$
|
2,176,761
|
|
Long-term debt
|
|
|
2,169,007
|
|
|
|
|
|
|
|
|
|
|
|
393
|
|
|
|
|
|
|
|
2,169,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,345,768
|
|
|
|
171,200
|
|
|
|
83,354
|
|
|
|
293,775
|
|
|
|
(547,936
|
)
|
|
|
4,346,161
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131
|
|
|
|
|
|
|
|
131
|
|
Short-term debt
|
|
|
158,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(86,392
|
)
|
|
|
72,550
|
|
Liabilities from risk management activities
|
|
|
20,181
|
|
|
|
|
|
|
|
4,060
|
|
|
|
182
|
|
|
|
(2,941
|
)
|
|
|
21,482
|
|
Other current liabilities
|
|
|
510,749
|
|
|
|
9,251
|
|
|
|
116,078
|
|
|
|
19,167
|
|
|
|
(11,987
|
)
|
|
|
643,258
|
|
Intercompany payables
|
|
|
|
|
|
|
557,190
|
|
|
|
123,322
|
|
|
|
|
|
|
|
(680,512
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
689,872
|
|
|
|
566,441
|
|
|
|
243,460
|
|
|
|
19,480
|
|
|
|
(781,832
|
)
|
|
|
737,421
|
|
Deferred income taxes
|
|
|
477,352
|
|
|
|
92,250
|
|
|
|
(10,675
|
)
|
|
|
12,013
|
|
|
|
|
|
|
|
570,940
|
|
Noncurrent liabilities from risk management activities
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
Regulatory cost of removal obligation
|
|
|
321,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
321,086
|
|
Deferred credits and other liabilities
|
|
|
360,481
|
|
|
|
4,187
|
|
|
|
630
|
|
|
|
2,860
|
|
|
|
|
|
|
|
368,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,194,559
|
|
|
$
|
834,078
|
|
|
$
|
316,775
|
|
|
$
|
328,128
|
|
|
$
|
(1,329,774
|
)
|
|
$
|
6,343,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Transmission
|
|
|
Natural Gas
|
|
|
Storage
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
and Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Property, plant and equipment, net
|
|
$
|
3,483,556
|
|
|
$
|
585,160
|
|
|
$
|
7,520
|
|
|
$
|
60,623
|
|
|
$
|
|
|
|
$
|
4,136,859
|
|
Investment in subsidiaries
|
|
|
463,158
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(461,062
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
30,878
|
|
|
|
|
|
|
|
9,120
|
|
|
|
6,719
|
|
|
|
|
|
|
|
46,717
|
|
Assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
69,008
|
|
|
|
20,239
|
|
|
|
(20,956
|
)
|
|
|
68,291
|
|
Other current assets
|
|
|
774,933
|
|
|
|
18,396
|
|
|
|
411,648
|
|
|
|
56,791
|
|
|
|
(91,672
|
)
|
|
|
1,170,096
|
|
Intercompany receivables
|
|
|
578,833
|
|
|
|
|
|
|
|
|
|
|
|
135,795
|
|
|
|
(714,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,384,644
|
|
|
|
18,396
|
|
|
|
489,776
|
|
|
|
219,544
|
|
|
|
(827,256
|
)
|
|
|
1,285,104
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
2,088
|
|
|
|
|
|
|
|
|
|
|
|
2,088
|
|
Goodwill
|
|
|
569,920
|
|
|
|
132,367
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
736,998
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
5,473
|
|
|
|
|
|
|
|
|
|
|
|
5,473
|
|
Deferred charges and other assets
|
|
|
195,985
|
|
|
|
11,212
|
|
|
|
1,182
|
|
|
|
11,798
|
|
|
|
|
|
|
|
220,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,097,263
|
|
|
$
|
747,135
|
|
|
$
|
528,225
|
|
|
$
|
302,394
|
|
|
$
|
(1,288,318
|
)
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
Shareholders equity
|
|
$
|
2,052,492
|
|
|
$
|
130,144
|
|
|
$
|
114,559
|
|
|
$
|
218,455
|
|
|
$
|
(463,158
|
)
|
|
$
|
2,052,492
|
|
Long-term debt
|
|
|
2,119,267
|
|
|
|
|
|
|
|
|
|
|
|
525
|
|
|
|
|
|
|
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,171,759
|
|
|
|
130,144
|
|
|
|
114,559
|
|
|
|
218,980
|
|
|
|
(463,158
|
)
|
|
|
4,172,284
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
785
|
|
|
|
|
|
|
|
785
|
|
Short-term debt
|
|
|
385,592
|
|
|
|
|
|
|
|
6,500
|
|
|
|
|
|
|
|
(41,550
|
)
|
|
|
350,542
|
|
Liabilities from risk management activities
|
|
|
58,566
|
|
|
|
|
|
|
|
20,688
|
|
|
|
616
|
|
|
|
(20,956
|
)
|
|
|
58,914
|
|
Other current liabilities
|
|
|
538,777
|
|
|
|
7,053
|
|
|
|
236,217
|
|
|
|
62,796
|
|
|
|
(47,997
|
)
|
|
|
796,846
|
|
Intercompany payables
|
|
|
|
|
|
|
543,384
|
|
|
|
171,244
|
|
|
|
|
|
|
|
(714,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
982,935
|
|
|
|
550,437
|
|
|
|
434,649
|
|
|
|
64,197
|
|
|
|
(825,131
|
)
|
|
|
1,207,087
|
|
Deferred income taxes
|
|
|
384,860
|
|
|
|
62,720
|
|
|
|
(21,936
|
)
|
|
|
15,687
|
|
|
|
(29
|
)
|
|
|
441,302
|
|
Noncurrent liabilities from risk management activities
|
|
|
5,111
|
|
|
|
|
|
|
|
258
|
|
|
|
|
|
|
|
|
|
|
|
5,369
|
|
Regulatory cost of removal obligation
|
|
|
298,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
298,645
|
|
Deferred credits and other liabilities
|
|
|
253,953
|
|
|
|
3,834
|
|
|
|
695
|
|
|
|
3,530
|
|
|
|
|
|
|
|
262,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,097,263
|
|
|
$
|
747,135
|
|
|
$
|
528,225
|
|
|
$
|
302,394
|
|
|
$
|
(1,288,318
|
)
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
17.
|
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 fiscal 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 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution
|
|
$
|
1,055,968
|
|
|
$
|
1,230,420
|
|
|
$
|
386,985
|
|
|
$
|
311,392
|
|
Regulated transmission and storage
|
|
|
54,682
|
|
|
|
59,234
|
|
|
|
49,345
|
|
|
|
46,397
|
|
Natural gas marketing
|
|
|
787,495
|
|
|
|
708,658
|
|
|
|
453,504
|
|
|
|
387,190
|
|
Pipeline, storage and other
|
|
|
16,448
|
|
|
|
12,272
|
|
|
|
8,226
|
|
|
|
4,978
|
|
Intersegment eliminations
|
|
|
(198,261
|
)
|
|
|
(189,178
|
)
|
|
|
(117,285
|
)
|
|
|
(99,390
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,716,332
|
|
|
|
1,821,406
|
|
|
|
780,775
|
|
|
|
650,567
|
|
Gross profit
|
|
|
395,212
|
|
|
|
460,051
|
|
|
|
259,640
|
|
|
|
231,799
|
|
Operating income
|
|
|
163,194
|
|
|
|
226,547
|
|
|
|
43,683
|
|
|
|
13,978
|
|
Net income (loss)
|
|
|
75,963
|
|
|
|
129,003
|
|
|
|
1,964
|
|
|
|
(15,952
|
)
|
Net income (loss) per basic share
|
|
$
|
0.84
|
|
|
$
|
1.42
|
|
|
$
|
0.02
|
|
|
$
|
(0.17
|
)
|
Net income (loss) per diluted share
|
|
$
|
0.83
|
|
|
$
|
1.41
|
|
|
$
|
0.02
|
|
|
$
|
(0.17
|
)
|
Fiscal year 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution
|
|
$
|
928,177
|
|
|
$
|
1,521,856
|
|
|
$
|
676,639
|
|
|
$
|
528,458
|
|
Regulated transmission and storage
|
|
|
45,046
|
|
|
|
51,440
|
|
|
|
46,286
|
|
|
|
53,145
|
|
Natural gas marketing
|
|
|
840,717
|
|
|
|
1,128,653
|
|
|
|
1,189,722
|
|
|
|
1,128,770
|
|
Pipeline, storage and other
|
|
|
6,727
|
|
|
|
10,022
|
|
|
|
3,880
|
|
|
|
11,080
|
|
Intersegment eliminations
|
|
|
(163,157
|
)
|
|
|
(227,986
|
)
|
|
|
(277,382
|
)
|
|
|
(280,788
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,657,510
|
|
|
|
2,483,985
|
|
|
|
1,639,145
|
|
|
|
1,440,665
|
|
Gross profit
|
|
|
369,638
|
|
|
|
434,394
|
|
|
|
246,222
|
|
|
|
271,072
|
|
Operating income
|
|
|
158,509
|
|
|
|
211,143
|
|
|
|
20,709
|
|
|
|
37,534
|
|
Net income (loss)
|
|
|
73,803
|
|
|
|
111,534
|
|
|
|
(6,588
|
)
|
|
|
1,582
|
|
Net income (loss) per basic share
|
|
$
|
0.83
|
|
|
$
|
1.25
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.02
|
|
Net income (loss) per diluted share
|
|
$
|
0.82
|
|
|
$
|
1.24
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.02
|
|
127
|
|
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 carried out an evaluation, under the supervision and with the
participation of our management, including our principal
executive officer and principal financial officer, of the
effectiveness of the Companys disclosure controls and
procedures, as such term is defined in
Rule 13a-15(e)
under the Securities Exchange Act of 1934, as amended (Exchange
Act). Based on this evaluation, the Companys principal
executive officer and principal financial officer have concluded
that the Companys disclosure controls and procedures were
effective as of September 30, 2009 to provide reasonable
assurance that information required to be disclosed by us,
including our consolidated entities, in the reports that we file
or submit under the Exchange Act is recorded, processed,
summarized, and reported within the time periods specified by
the SECs rules and forms, including a reasonable level of
assurance that such information is 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, 2009, 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.
Ernst & Young LLP has issued its report on the
effectiveness of the Companys internal control over
financial reporting. That report appears below.
|
|
|
/s/ ROBERT
W. BEST
|
|
/s/ FRED
E.
MEISENHEIMER
|
Robert W. Best
|
|
Fred E. Meisenheimer
|
Chairman and Chief Executive Officer
|
|
Senior Vice President and Chief Financial Officer
|
November 16, 2009
128
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have audited Atmos Energy Corporations internal control
over financial reporting as of September 30, 2009, 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 included in the accompanying
Managements Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on 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, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, 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, Atmos Energy Corporation maintained, in all
material respects, effective internal control over financial
reporting as of September 30, 2009, 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 as of September 30, 2009 and
2008, and the related statements of income, stockholders
equity, and cash flows for each of the three years in the period
ended September 30, 2009 of Atmos Energy Corporation and
our report dated November 16, 2009 expressed an unqualified
opinion thereon.
Dallas, Texas
November 16, 2009
129
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, 2009 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,
Executive Officers and Corporate Governance.
|
Information regarding directors and compliance with
Section 16(a) of the Securities Exchange Act of 1934 is
incorporated herein by reference to the Companys
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 3, 2010. Information regarding
executive officers is included in Part I of this Annual
Report on
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 to the
Companys Definitive Proxy Statement for the Annual Meeting
of Shareholders on February 3, 2010.
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.
|
Information on executive compensation is incorporated herein by
reference to the Companys Definitive Proxy Statement for
the Annual Meeting of Shareholders on February 3, 2010.
|
|
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 to the
Companys Definitive Proxy Statement for the Annual Meeting
of Shareholders on February 3, 2010. 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, and Director
Independence.
|
Information on certain relationships and related transactions as
well as director independence is incorporated herein by
reference to the Companys Definitive Proxy Statement for
the Annual Meeting of Shareholders on February 3, 2010.
|
|
ITEM 14.
|
Principal
Accountant Fees and Services.
|
Information on our principal accountants fees and services
is incorporated herein by reference to the Companys
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 3, 2010.
130
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.
The exhibits listed in the accompanying Exhibits Index are
filed as part of this
Form 10-K.
The exhibits numbered 10.5(a) through 10.12(g) are management
contracts or compensatory plans or arrangements.
131
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
ATMOS ENERGY CORPORATION
(Registrant)
|
|
|
|
By:
|
/s/ FRED
E. MEISENHEIMER
|
Fred E. Meisenheimer
Senior Vice President
and Chief Financial Officer
Date: November 16, 2009
132
POWER OF
ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below hereby constitutes and appoints Robert W. Best and
Fred. E. Meisenheimer, 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 Annual Report on
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 and Chief Executive Officer
|
|
November 16, 2009
|
|
|
|
|
|
/s/ KIM
R. COCKLIN
Kim
R. Cocklin
|
|
President, Chief Operating Officer and Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ FRED
E. MEISENHEIMER
Fred
E. Meisenheimer
|
|
Senior Vice President and Chief Financial Officer
|
|
November 16, 2009
|
|
|
|
|
|
/s/ CHRISTOPHER
T. FORSYTHE
Christopher
T. Forsythe
|
|
Vice President and Controller (Principal Accounting Officer)
|
|
November 16, 2009
|
|
|
|
|
|
/s/ TRAVIS
W. BAIN, II
Travis
W. Bain, II
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ RICHARD
W. CARDIN
Richard
W. Cardin
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ RICHARD
W. DOUGLAS
Richard
W. Douglas
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ RUBEN
E. ESQUIVEL
Ruben
E. Esquivel
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ THOMAS
J. GARLAND
Thomas
J. Garland
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ RICHARD
K. GORDON
Richard
K. Gordon
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ ROBERT
C. GRABLE
Robert
C. Grable
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ THOMAS
C. MEREDITH
Thomas
C. Meredith
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ PHILLIP
E. NICHOL
Phillip
E. Nichol
|
|
Director
|
|
November 16, 2009
|
133
|
|
|
|
|
|
|
|
|
|
|
|
/s/ NANCY
K. QUINN
Nancy
K. Quinn
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ STEPHEN
R. SPRINGER
Stephen
R. Springer
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ CHARLES
K. VAUGHAN
Charles
K. Vaughan
|
|
Director
|
|
November 16, 2009
|
|
|
|
|
|
/s/ RICHARD
WARE II
Richard
Ware II
|
|
Director
|
|
November 16, 2009
|
134
Schedule II
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
Charged to
|
|
|
|
|
|
Balance
|
|
|
|
Beginning
|
|
|
Cost &
|
|
|
Other
|
|
|
|
|
|
at End
|
|
|
|
of Period
|
|
|
Expenses
|
|
|
Accounts
|
|
|
Deductions
|
|
|
of Period
|
|
|
|
(In thousands)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
15,301
|
|
|
$
|
7,769
|
|
|
$
|
|
|
|
$
|
11,592(1
|
)
|
|
$
|
11,478
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
16,160
|
|
|
$
|
15,655
|
|
|
$
|
|
|
|
$
|
16,514(1
|
)
|
|
$
|
15,301
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
13,686
|
|
|
$
|
19,718
|
|
|
$
|
|
|
|
$
|
17,244(1
|
)
|
|
$
|
16,160
|
|
|
|
|
(1) |
|
Uncollectible accounts written off. |
135
EXHIBITS INDEX
Item 14.(a)(3)
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
|
|
|
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
May 2, 2007)
|
|
Exhibit 3.1 to Form 8-K dated May 2, 2007 (File No. 1-10042)
|
|
|
|
|
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
|
|
Indenture dated as of November 15, 1995 between United
Cities Gas Company and Bank of America Illinois, Trustee
|
|
Exhibit 4.11(a) to Form S-3 dated August 31, 2004 (File No.
333-118706)
|
|
4
|
.3
|
|
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
|
.4
|
|
Indenture dated as of May 22, 2001 between Atmos Energy
Corporation and SunTrust Bank, Trustee
|
|
Exhibit 99.3 to Form 8-K dated May 15, 2001 (File No. 1-10042)
|
|
4
|
.5
|
|
Indenture dated as of June 14, 2007, between Atmos Energy
Corporation and U.S. Bank National Association, Trustee
|
|
Exhibit 4.1 to Form 8-K dated June 11, 2007 (File No. 1-10042)
|
|
4
|
.6
|
|
Indenture dated as of March 23, 2009 between Atmos Energy
Corporation and U.S. Bank National Corporation, Trustee
|
|
Exhibit 4.1 to Form 8-K dated March 26, 2009 (File No. 1-10042)
|
|
4
|
.7(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
|
.7(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
|
.7(c)
|
|
Global Security for the
51/8% Senior
Notes due 2013
|
|
Exhibit 10(2)(c) to Form 10-K for fiscal year ended September
30, 2004 (File No. 1-10042)
|
|
4
|
.7(d)
|
|
Global Security for the 4.95% Senior Notes due 2014
|
|
Exhibit 10(2)(f) to Form 10-K for fiscal year ended September
30, 2004 (File No. 1-10042)
|
|
4
|
.7(e)
|
|
Global Security for the 5.95% Senior Notes due 2034
|
|
Exhibit 10(2)(g) to Form 10-K for fiscal year ended September
30, 2004 (File No. 1-10042)
|
|
4
|
.7(f)
|
|
Global Security for the 6.35% Senior Notes due 2017
|
|
Exhibit 4.2 to Form 8-K dated June 11, 2007 (File No. 1-10042)
|
|
4
|
.7(g)
|
|
Global Security for the 8.50% Senior Notes due 2019
|
|
Exhibit 4.2 to Form 8-K dated March 26, 2009 (File No. 1-10042)
|
|
|
|
|
Material Contracts
|
|
|
|
10
|
.1
|
|
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)
|
136
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
10
|
.2
|
|
Revolving Credit Agreement (5 Year Facility), dated as of
December 15, 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 December 15, 2006 (File No.
1-10042)
|
|
10
|
.3
|
|
Revolving Credit Agreement (364 Day Facility), dated as of
October 22, 2009, among Atmos Energy Corporation, the
Lenders from time to time parties thereto, SunTrust Bank as
Administrative Agent, Wells Fargo Bank, N.A. as Syndication
Agent, and Bank of America, N.A. and U.S. Bank National
Association as co-Documentation Agents
|
|
Exhibit 10.1 to Form 8-K dated October 22, 2009 (File No.
1-10042)
|
|
10
|
.4(a)
|
|
Third Amended and Restated Credit Agreement, dated as of
December 30, 2008, among Atmos Energy Marketing, LLC, BNP
Paribas, Fortis Bank SA/NV, New York Branch, Societe Generale
and the other financial institutions which may become parties
thereto
|
|
Exhibit 10.1 to Form 8-K dated December 30, 2008 (File No.
1-10042)
|
|
10
|
.4(b)
|
|
First Amendment dated as of April 1, 2009, to the Third
Amended and Restated Credit Agreement and the amended and
restated Intercreditor Agreement
|
|
|
|
10
|
.4(c)
|
|
Intercreditor Agreement, dated as of March 31, 2008, among
Fortis Capital Corp. and the other financial institutions which
may become parties thereto
|
|
Exhibit 10.2 to Form 8-K dated March 31, 2008 (File No. 1-10042)
|
|
|
|
|
Executive Compensation Plans and Arrangements
|
|
|
|
10
|
.5(a)*
|
|
Form of Atmos Energy Corporation Change in Control Severance
Agreement Tier I
|
|
Exhibit 10.5(a) to Form 10-K for fiscal year ended September 30,
2008 (File No. 1-10042)
|
|
10
|
.5(b)*
|
|
Form of Atmos Energy Corporation Change in Control Severance
Agreement Tier II
|
|
Exhibit 10.5(b) to Form 10-K for fiscal year ended September 30,
2008 (File No. 1-10042)
|
|
10
|
.6(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
|
.6(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
|
.7(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
|
.7(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
|
.8(a)*
|
|
Atmos Energy Corporation Supplemental Executive Benefits Plan,
Amended and Restated in its Entirety August 7, 2007
|
|
Exhibit 10.8(a) to Form 10-K for fiscal year ended September 30,
2008 (File No. 1-10042)
|
137
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
10
|
.8(b)*
|
|
Atmos Energy Corporation Supplemental Executive Retirement Plan,
(An Amendment and Restatement of the Performance-Based
Supplemental Executive Benefits Plan), Effective Date
August 7, 2007
|
|
Exhibit 10.8(b) to Form 10-K for fiscal year ended September 30,
2008 (File No. 1-10042)
|
|
10
|
.8(c)*
|
|
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
|
.8(d)*
|
|
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
|
.9(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
|
.9(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
|
.9(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
|
.10*
|
|
Atmos Energy Corporation Equity Incentive and Deferred
Compensation Plan for Non-Employee Directors
|
|
Exhibit 10.10 to Form 10-K for fiscal year ended September 30,
2008 (File No. 1-10042)
|
|
10
|
.11*
|
|
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
|
.12(a)*
|
|
Atmos Energy Corporation 1998 Long-Term Incentive Plan (as
amended and restated February 9, 2007)
|
|
Exhibit 10.2 to Form 10-Q for quarter ended March 31, 2007 (File
No. 1-10042)
|
|
10
|
.12(b)*
|
|
Amendment No. 1 to Atmos Energy Corporation 1998 Long-Term
Incentive Plan (as amended and restated February 9, 2007)
|
|
Exhibit 10.12(b) to Form 10-K for fiscal year ended September
30, 2008 (File No. 1-10042)
|
|
10
|
.12(c)*
|
|
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
|
.12(d)*
|
|
Form of Award Agreement of Restricted Stock With Time-Lapse
Vesting under the Atmos Energy Corporation 1998 Long-Term
Incentive Plan
|
|
Exhibit 10.12(d) to Form 10-K for fiscal year ended September
30, 2008 (File No. 1-10042)
|
|
10
|
.12(e)*
|
|
Form of Award Agreement of Time-Lapse Restricted Stock Units
under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
|
|
Exhibit 10.1 to Form 10-Q for quarter ended June 30, 2009 (File
No. 1-10042)
|
|
10
|
.12(f)*
|
|
Form of Award Agreement of Performance-Based Restricted Stock
Units under the Atmos Energy Corporation 1998 Long-Term
Incentive Plan
|
|
Exhibit 10.2 to Form 10-Q for quarter ended June 30, 2009 (File
No. 1-10042)
|
|
10
|
.12(g)*
|
|
Atmos Energy Corporation Annual Incentive Plan for Management
(as amended and restated August 8, 2007)
|
|
Exhibit 10.12(f) to Form 10-K for fiscal year ended September
30, 2008 (File No. 1-10042)
|
138
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
12
|
|
|
Statement of computation of ratio of earnings to fixed charges
|
|
|
|
|
|
|
Other Exhibits, as indicated
|
|
|
|
21
|
|
|
Subsidiaries of the registrant
|
|
|
|
23
|
.1
|
|
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,
2009
|
|
31
|
|
|
Rule 13a-14(a)/15d-14(a)
Certifications
|
|
|
|
32
|
|
|
Section 1350 Certifications**
|
|
|
|
|
|
* |
|
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. |
139