ATMOS ENERGY CORP
10-Ks and 10-Qs
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Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
| (Mark One) | ||
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the fiscal year ended September 30, 2011 | ||
| OR | ||
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period from to |
Commission file number 1-10042
Atmos Energy
Corporation
(Exact name of registrant as
specified in its charter)
| Texas and Virginia | 75-1743247 | |
|
(State or other jurisdiction
of
incorporation or organization) |
(IRS employer
identification no.) |
|
|
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas (Address of principal executive offices) |
75240
(Zip code) |
Registrant’s telephone number, including area code:
(972) 934-9227
Securities registered pursuant to Section 12(b) of the
Act:
|
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 | New York Stock Exchange |
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
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes
þ
No
o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K.
þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer
or a smaller reporting company. See definitions of “large
accelerated filer,” “accelerated filer” and
“smaller reporting company” in Rule
12b-2
of the
Exchange Act. (Check one):
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
(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 registrant’s most recently completed second fiscal
quarter, March 31, 2011, was $3,008,806,271.
As of November 14, 2011, the registrant had
90,364,061 shares of common stock outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrant’s Definitive Proxy Statement to
be filed for the Annual Meeting of Shareholders on
February 8, 2012, are incorporated by reference into
Part III of this report.
TABLE OF
CONTENTS
Table of Contents
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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Moody’s
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Moody’s 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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PAP
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Pension Account Plan
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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 & Poor’s 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 439 of the 440 incorporated cities, or approximately
80 percent of the Mid-Tex Division’s customers, with
whom a settlement agreement was reached during the fiscal 2008
second quarter.
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SRF
|
Stable Rate Filing
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WNA
|
Weather Normalization Adjustment
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3
Table of Contents
The terms “we,” “our,” “us”,
“Atmos Energy” and the “Company” refer to
Atmos Energy Corporation and its subsidiaries, unless the
context suggests otherwise.
| ITEM 1. | Business. |
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 three million residential,
commercial, public authority and industrial customers in
12 states located primarily in the South, which makes us
one of the country’s largest natural-gas-only distributors
based on number of customers. In May 2011, we announced that we
had entered into a definitive agreement to sell our natural gas
distribution operations in Missouri, Illinois and Iowa,
representing approximately 84,000 customers. After the closing
of this transaction, we will operate in nine states. 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
principally 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:
| • | deliver superior shareholder value, | |
| • | improve the quality and consistency of earnings growth, while safely operating our regulated and nonregulated businesses exceptionally well and | |
| • | enhance and strengthen a culture built on our core values. |
We have continued to grow our earnings after giving effect to
our acquisitions and have experienced more than 25 consecutive
years of increasing dividends. 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.
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 three 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 our Atmos Pipeline — Texas Division and |
4
Table of Contents
| • | The nonregulated segment , which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services. |
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 rate base,
covering service areas in 12 states:
| • | Atmos Energy Mid-Tex Division, | |
| • | Atmos Energy Kentucky/Mid-States Division, | |
| • | Atmos Energy Louisiana Division, | |
| • | Atmos Energy West Texas Division, | |
| • | Atmos Energy Mississippi Division and | |
| • | Atmos Energy Colorado-Kansas Division |
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. See Note 6 in the consolidated financial
statements for a complete description of the anticipated sale of
our Illinois, Iowa and Missouri service areas. 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 adjustment 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 approximately
94 percent of residential and commercial margins 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
Table of Contents
As of September 30, 2011 we had WNA for our residential and
commercial meters in the following service areas for the
following periods:
|
Georgia, Kansas, West Texas
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October — May | |
|
Kentucky, Mississippi, Tennessee, Mid-Tex
|
November — April | |
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Louisiana
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December — March | |
|
Virginia
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January — December |
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.
Except for local production purchases, we select our natural gas
suppliers through a competitive bidding process by periodically
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 2011 were Anadarko Energy Services, BP Energy
Company, ConocoPhillips, 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
4.4 Bcf. The
peak-day
demand for our natural gas distribution operations in fiscal
2011 was on February 2, 2011, when sales to customers
reached approximately 4.4 Bcf.
Currently, our natural gas distribution divisions, except for
our Mid-Tex Division, utilize 45 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 primarily by our
Atmos Pipeline — Texas Division.
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
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.
Below, we briefly describe 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, 2011, we held
1,116 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”.
6
Table of Contents
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 fiscal 2008, we reached
a settlement with cities representing approximately
80 percent of this division’s customers (Settled
Cities) that has allowed us, beginning in fiscal 2008, to update
rates for customers in these cities through an annual rate
review mechanism (RRM). Rates for the remaining 20 percent
of this division’s 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. In June 2011, we reached an
agreement with the City of Dallas to enter into the Dallas
Annual Rate Review (DARR). This rate review provides for an
annual rate review without the necessity of filing a general
rate case. The first filing made under this mechanism will be in
January 2012.
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 state’s public service commission.
In May 2011, we announced that we had entered into a definitive
agreement to sell our natural gas distribution operations in
Missouri, Illinois and Iowa, representing approximately 189
communities, some of which of the Missouri communities are
located in our Atmos Energy Colorado-Kansas Division.
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 nonregulated 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
fiscal 2008 and its Amarillo and Lubbock service areas during
fiscal 2009 to update rates for customers in these service areas
through an RRM.
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
Table of Contents
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 state’s 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
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| Division | Jurisdiction | Rate/GRIP Action | (thousands) (1) | Return (1) | on Equity (1) | |||||||
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Atmos Pipeline — Texas
|
Texas | 05/01/2011 | $807,733 | 9.36% | 11.80% | |||||||
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Atmos Pipeline —
Texas — GRIP |
Texas | 08/01/2011 | 816,976 | 9.36% | 11.80% | |||||||
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Colorado-Kansas
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Colorado | 01/04/2010 | 86,189 | 8.57% | 10.25% | |||||||
| Kansas | 08/01/2010 | 144,583 | (2) | (2) | ||||||||
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Kentucky/Mid-States
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Georgia | 03/31/2010 | 96,330 (3) | 8.61% | 10.70% | |||||||
| Illinois | 11/01/2000 | 24,564 | 9.18% | 11.56% | ||||||||
| Iowa | 03/01/2001 | 5,000 | (2) | 11.00% | ||||||||
| Kentucky | 06/01/2010 | 208,702 (4) | (2) | (2) | ||||||||
| Missouri | 09/01/2010 | 66,459 | (2) | (2) | ||||||||
| Tennessee | 04/01/2009 | 190,100 | 8.24% | 10.30% | ||||||||
| Virginia | 11/23/2009 | 36,861 | 8.48% | 9.50% - 10.50% | ||||||||
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Louisiana
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Trans LA | 04/01/2011 | 93,260 | 8.37% | 10.00% - 10.80% | |||||||
| LGS | 07/01/2011 | 273,775 | 8.56% | 10.40% | ||||||||
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Mid-Tex — Settled Cities
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Texas | 09/01/2011 | 1,389,187 (5) | 8.29% | 9.70% | |||||||
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Mid-Tex — Dallas
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Texas | 06/22/2011 | 1,268,601 (5) | 8.45% | 10.10% | |||||||
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Mid-Tex — Environs GRIP
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Texas | 06/27/2011 | 1,268,601 (5) | 8.60% | 10.40% | |||||||
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Mississippi
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Mississippi | 04/05/2011 | 239,197 | (2) | 9.86% | |||||||
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West Texas
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Amarillo | 08/01/2011 | (2) | (2) | 9.60% | |||||||
| Lubbock | 09/09/2011 | 60,892 | 8.19% | 9.60% | ||||||||
| West Texas | 08/01/2011 | 146,039 | 8.19% | 9.60% | ||||||||
8
Table of Contents
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Authorized Debt/
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Bad Debt
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Performance-Based
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Customer
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| Division | Jurisdiction | Equity Ratio | Rider (6) | WNA | Rate Program (7) | Meters | ||||||||||||||
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Atmos Pipeline — Texas
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Texas | 50/50 | No | N/A | N/A | N/A | ||||||||||||||
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Colorado-Kansas
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Colorado | 50/50 | Yes | (8) | No | No | 110,709 | |||||||||||||
| Kansas | (2) | Yes | Yes | No | 128,679 | |||||||||||||||
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Kentucky/Mid-States
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Georgia | 52/48 | No | Yes | Yes | 63,897 | ||||||||||||||
| Illinois | 67/33 | No | No | No | 22,778 | |||||||||||||||
| Iowa | 57/43 | No | No | No | 4,334 | |||||||||||||||
| Kentucky | (2) | Yes | Yes | Yes | 176,246 | |||||||||||||||
| Missouri | 49/51 | No | No | No | 56,643 | |||||||||||||||
| Tennessee | 52/48 | Yes | Yes | Yes | 133,634 | |||||||||||||||
| Virginia | 51/49 | Yes | Yes | No | 23,310 | |||||||||||||||
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Louisiana
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Trans LA | 52/48 | No | Yes | No | 75,813 | ||||||||||||||
| LGS | 52/48 | No | Yes | No | 277,838 | |||||||||||||||
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Mid-Tex — Settled Cities
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Texas | 50/50 | Yes | Yes | No | 1,259,042 | ||||||||||||||
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Mid-Tex — Dallas & Environs
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Texas | 51/49 | Yes | Yes | No | 314,760 | ||||||||||||||
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Mississippi
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Mississippi | 50/50 | No | Yes | No | 266,074 | ||||||||||||||
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West Texas
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Amarillo | 52/48 | Yes | Yes | No | 70,431 | ||||||||||||||
| Lubbock | 52/48 | Yes | Yes | No | 73,748 | |||||||||||||||
| West Texas | 52/48 | Yes | Yes | No | 155,255 | |||||||||||||||
| (1) | The rate base, authorized rate of return and authorized return on equity presented in this table are those from the most recent 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 commission’s final decision. | |
| (3) | Georgia rate base consists of $60.2 million included in the March 2010 rate case and $36.1 million included in the October 2011 Pipeline Replacement Program (PRP) surcharge. A total of $36.1 million of the Georgia rate base amount was awarded in the latest PRP annual filing with an effective date of October 1, 2011, an authorized rate of return of 8.56 percent and an authorized return on equity of 10.70 percent. | |
| (4) | Kentucky rate base consists of $184.7 million included in the June 2010 rate case and $24.0 million included in the October 2011 PRP surcharge. A total of $24.0 million of the Kentucky rate base amount was awarded in the latest PRP annual filing with an effective date of October 1, 2011, an authorized rate of return of 8.74 percent and an authorized return on equity of 10.50 percent. | |
| (5) | The Mid-Tex Rate Base amounts for the Settled Cities and Dallas & Environs areas represent “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base. | |
| (6) | The bad debt rider allows us to recover from ratepayers the gas cost portion of uncollectible accounts. | |
| (7) | 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. | |
| (8) | The recovery of the gas portion of uncollectible accounts gas cost adjustment has been approved for a two-year pilot program. |
9
Table of Contents
Natural
Gas Distribution Sales and Statistical Data - Continuing
Operations
| Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
|
METERS IN SERVICE, end of year
|
||||||||||||||||||||
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Residential
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2,855,998 | 2,836,483 | 2,826,814 | 2,834,884 | 2,815,974 | |||||||||||||||
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Commercial
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261,220 | 253,339 | 256,384 | 259,154 | 262,260 | |||||||||||||||
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Industrial
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2,008 | 2,029 | 2,136 | 2,183 | 2,281 | |||||||||||||||
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Public authority and other
|
10,212 | 10,178 | 9,211 | 9,197 | 19,143 | |||||||||||||||
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Total meters
|
3,129,438 | 3,102,029 | 3,094,545 | 3,105,418 | 3,099,658 | |||||||||||||||
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SALES VOLUMES —
MMcf
(2)
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||||||||||||||||||||
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Gas Sales Volumes
|
||||||||||||||||||||
|
Residential
|
161,012 | 185,143 | 154,475 | 157,816 | 161,493 | |||||||||||||||
|
Commercial
|
91,215 | 99,924 | 88,445 | 90,992 | 92,601 | |||||||||||||||
|
Industrial
|
18,757 | 18,714 | 18,242 | 21,352 | 22,479 | |||||||||||||||
|
Public authority and other
|
10,482 | 10,107 | 12,393 | 13,739 | 12,265 | |||||||||||||||
|
Total gas sales volumes
|
281,466 | 313,888 | 273,555 | 283,899 | 288,838 | |||||||||||||||
|
Transportation volumes
|
132,357 | 128,965 | 123,972 | 133,997 | 127,066 | |||||||||||||||
|
Total throughput
|
413,823 | 442,853 | 397,527 | 417,896 | 415,904 | |||||||||||||||
|
OPERATING REVENUES
(000’s)
(2)
|
||||||||||||||||||||
|
Gas Sales Revenues
|
||||||||||||||||||||
|
Residential
|
$ | 1,570,723 | $ | 1,784,051 | $ | 1,768,082 | $ | 2,068,040 | $ | 1,924,523 | ||||||||||
|
Commercial
|
698,366 | 787,433 | 807,109 | 1,044,768 | 941,827 | |||||||||||||||
|
Industrial
|
106,569 | 110,280 | 132,487 | 208,681 | 190,812 | |||||||||||||||
|
Public authority and other
|
69,176 | 70,402 | 88,972 | 137,585 | 114,087 | |||||||||||||||
|
Total gas sales revenues
|
2,444,834 | 2,752,166 | 2,796,650 | 3,459,074 | 3,171,249 | |||||||||||||||
|
Transportation revenues
|
60,430 | 59,381 | 56,961 | 57,405 | 56,814 | |||||||||||||||
|
Other gas revenues
|
26,599 | 31,091 | 31,185 | 35,183 | 35,448 | |||||||||||||||
|
Total operating revenues
|
$ | 2,531,863 | $ | 2,842,638 | $ | 2,884,796 | $ | 3,551,662 | $ | 3,263,511 | ||||||||||
Natural
Gas Distribution Sales and Statistical Data - Discontinued
Operations
| Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
|
Meters in service, end of period
|
83,753 | 84,011 | 84,299 | 86,361 | 87,469 | |||||||||||||||
|
Sales volumes — MMcf
|
||||||||||||||||||||
|
Total gas sales volumes
|
8,461 | 8,740 | 8,562 | 8,777 | 8,489 | |||||||||||||||
|
Transportation volumes
|
6,190 | 6,900 | 6,719 | 7,086 | 8,043 | |||||||||||||||
|
Total throughput
|
14,651 | 15,640 | 15,281 | 15,863 | 16,532 | |||||||||||||||
|
Operating revenues (000’s)
|
$ | 80,028 | $ | 69,855 | $ | 99,969 | $ | 103,468 | $ | 95,254 | ||||||||||
See footnotes following these tables.
10
Table of Contents
Natural
Gas Distribution Sales and Statistical Data - Other Consolidated
Statistics
| Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
|
Inventory storage balance — Bcf
|
55.0 | 54.3 | 57.0 | 58.3 | 58.0 | |||||||||||||||
|
Heating degree
days
(1)
|
||||||||||||||||||||
|
Actual (weighted average)
|
2,733 | 2,780 | 2,713 | 2,820 | 2,879 | |||||||||||||||
|
Percent of normal
|
99 | % | 102 | % | 100 | % | 100 | % | 100 | % | ||||||||||
|
Average transportation revenue per Mcf
|
$ | 0.46 | $ | 0.46 | $ | 0.46 | $ | 0.43 | $ | 0.44 | ||||||||||
|
Average cost of gas per Mcf sold
|
$ | 5.30 | $ | 5.77 | $ | 6.95 | $ | 9.05 | $ | 8.09 | ||||||||||
|
Employees
|
4,753 | 4,714 | 4,691 | 4,558 | 4,472 | |||||||||||||||
Natural
Gas Distribution Sales and Statistical Data by
Division
| Fiscal Year Ended September 30, 2011 | ||||||||||||||||||||||||||||||||
|
Kentucky/
|
West
|
Colorado-
|
||||||||||||||||||||||||||||||
| Mid-Tex | Mid-States | Louisiana | Texas | Mississippi | Kansas | Other (3) | Total | |||||||||||||||||||||||||
|
METERS IN SERVICE FROM
CONTINUING OPERATIONS |
||||||||||||||||||||||||||||||||
|
Residential
|
1,449,673 | 349,993 | 331,272 | 271,346 | 237,059 | 216,655 | — | 2,855,998 | ||||||||||||||||||||||||
|
Commercial
|
123,993 | 43,875 | 22,379 | 24,773 | 25,617 | 20,583 | — | 261,220 | ||||||||||||||||||||||||
|
Industrial
|
136 | 798 | — | 482 | 501 | 91 | — | 2,008 | ||||||||||||||||||||||||
|
Public authority and other
|
— | 2,423 | — | 2,833 | 2,897 | 2,059 | — | 10,212 | ||||||||||||||||||||||||
|
Total meters
|
1,573,802 | 397,089 | 353,651 | 299,434 | 266,074 | 239,388 | — | 3,129,438 | ||||||||||||||||||||||||
|
SALES VOLUMES FROM CONTINUING OPERATIONS —
MMcf
(2)
|
||||||||||||||||||||||||||||||||
|
Gas Sales Volumes
|
||||||||||||||||||||||||||||||||
|
Residential
|
77,075 | 22,273 | 13,939 | 16,280 | 14,077 | 17,368 | — | 161,012 | ||||||||||||||||||||||||
|
Commercial
|
50,056 | 13,407 | 7,448 | 6,932 | 6,630 | 6,742 | — | 91,215 | ||||||||||||||||||||||||
|
Industrial
|
3,105 | 5,626 | — | 4,108 | 5,823 | 95 | — | 18,757 | ||||||||||||||||||||||||
|
Public authority and other
|
— | 1,395 | — | 3,294 | 3,418 | 2,375 | — | 10,482 | ||||||||||||||||||||||||
|
Total
|
130,236 | 42,701 | 21,387 | 30,614 | 29,948 | 26,580 | — | 281,466 | ||||||||||||||||||||||||
|
Transportation volumes
|
46,594 | 38,801 | 5,893 | 24,162 | 5,237 | 11,670 | — | 132,357 | ||||||||||||||||||||||||
|
Total throughput
|
176,830 | 81,502 | 27,280 | 54,776 | 35,185 | 38,250 | — | 413,823 | ||||||||||||||||||||||||
|
OPERATING MARGIN FROM CONTINUING OPERATIONS
(000’s)
(2)
|
$ | 490,484 | $ | 152,293 | $ | 125,894 | $ | 99,353 | $ | 93,042 | $ | 83,298 | $ | — | $ | 1,044,364 | ||||||||||||||||
|
OPERATING EXPENSES FROM CONTINUING OPERATIONS
(000’s)
(2)
|
||||||||||||||||||||||||||||||||
|
Operation and maintenance
|
$ | 147,967 | $ | 58,315 | $ | 42,219 | $ | 35,908 | $ | 39,895 | $ | 31,684 | $ | (7,905 | ) | $ | 348,083 | |||||||||||||||
|
Depreciation and amortization
|
$ | 95,798 | $ | 29,644 | $ | 24,460 | $ | 16,735 | $ | 13,188 | $ | 17,084 | $ | — | $ | 196,909 | ||||||||||||||||
|
Taxes, other than income
|
$ | 102,515 | $ | 10,828 | $ | 8,773 | $ | 17,024 | $ | 13,621 | $ | 8,610 | $ | — | $ | 161,371 | ||||||||||||||||
|
OPERATING INCOME FROM CONTINUING OPERATIONS
(000’s)
(2)
|
$ | 144,204 | $ | 53,506 | $ | 50,442 | $ | 29,686 | $ | 26,338 | $ | 25,920 | $ | 7,905 | $ | 338,001 | ||||||||||||||||
|
CONSOLIDATED CAPITAL EXPENDITURES (000’s)
|
$ | 220,032 | $ | 65,766 | $ | 41,489 | $ | 40,387 | $ | 37,115 | $ | 31,399 | $ | 60,711 | $ | 496,899 | ||||||||||||||||
|
PROPERTY, PLANT AND EQUIPMENT, EXCLUDING ASSETS HELD FOR SALE
(000’s)
|
$ | 1,965,351 | $ | 663,837 | $ | 431,773 | $ | 393,545 | $ | 308,891 | $ | 311,013 | $ | 173,788 | $ | 4,248,198 | ||||||||||||||||
|
OTHER CONSOLIDATED STATISTICS
|
||||||||||||||||||||||||||||||||
|
Heating Degree
Days
(1)
|
||||||||||||||||||||||||||||||||
|
Actual
|
2,100 | 3,920 | 1,431 | 3,541 | 2,707 | 5,692 | — | 2,733 | ||||||||||||||||||||||||
|
Percent of normal
|
100 | % | 99 | % | 94 | % | 99 | % | 101 | % | 101 | % | — | 99 | % | |||||||||||||||||
|
Miles of pipe
|
29,296 | 12,215 | 8,333 | 7,712 | 6,563 | 6,750 | — | 70,869 | ||||||||||||||||||||||||
|
Employees
|
1,668 | 568 | 438 | 351 | 363 | 287 | 1,078 | 4,753 | ||||||||||||||||||||||||
See footnotes following these tables.
11
Table of Contents
| Fiscal Year Ended September 30, 2010 | ||||||||||||||||||||||||||||||||
|
Kentucky/
|
West
|
Colorado-
|
||||||||||||||||||||||||||||||
| Mid-Tex | Mid-States | Louisiana | Texas | Mississippi | Kansas | Other (3) | Total | |||||||||||||||||||||||||
|
METERS IN SERVICE FROM CONTINUING OPERATIONS
|
||||||||||||||||||||||||||||||||
|
Residential
|
1,429,287 | 350,238 | 331,784 | 271,418 | 237,304 | 216,452 | — | 2,836,483 | ||||||||||||||||||||||||
|
Commercial
|
116,240 | 43,554 | 22,420 | 24,919 | 25,520 | 20,686 | — | 253,339 | ||||||||||||||||||||||||
|
Industrial
|
145 | 801 | — | 484 | 513 | 86 | — | 2,029 | ||||||||||||||||||||||||
|
Public authority and other
|
— | 2,411 | — | 2,809 | 2,896 | 2,062 | — | 10,178 | ||||||||||||||||||||||||
|
Total meters
|
1,545,672 | 397,004 | 354,204 | 299,630 | 266,233 | 239,286 | — | 3,102,029 | ||||||||||||||||||||||||
|
SALES VOLUMES FROM CONTINUING OPERATIONS —
MMcf
(2)
|
||||||||||||||||||||||||||||||||
|
Gas Sales Volumes
|
||||||||||||||||||||||||||||||||
|
Residential
|
92,489 | 22,897 | 15,810 | 19,772 | 15,775 | 18,400 | — | 185,143 | ||||||||||||||||||||||||
|
Commercial
|
55,916 | 13,948 | 7,821 | 7,892 | 7,209 | 7,138 | — | 99,924 | ||||||||||||||||||||||||
|
Industrial
|
3,227 | 5,615 | — | 4,317 | 5,424 | 131 | — | 18,714 | ||||||||||||||||||||||||
|
Public authority and other
|
— | 1,422 | — | 3,482 | 3,103 | 2,100 | — | 10,107 | ||||||||||||||||||||||||
|
Total
|
151,632 | 43,882 | 23,631 | 35,463 | 31,511 | 27,769 | — | 313,888 | ||||||||||||||||||||||||
|
Transportation volumes
|
45,822 | 36,882 | 5,626 | 22,429 | 5,551 | 12,655 | — | 128,965 | ||||||||||||||||||||||||
|
Total throughput
|
197,454 | 80,764 | 29,257 | 57,892 | 37,062 | 40,424 | — | 442,853 | ||||||||||||||||||||||||
|
OPERATING MARGIN FROM CONTINUING OPERATIONS
(000’s)
(2)
|
$ | 475,852 | $ | 143,347 | $ | 123,344 | $ | 105,476 | $ | 94,203 | $ | 79,789 | $ | — | $ | 1,022,011 | ||||||||||||||||
|
OPERATING EXPENSES FROM CONTINUING OPERATIONS
(000’s)
(2)
|
||||||||||||||||||||||||||||||||
|
Operation and maintenance
|
$ | 145,166 | $ | 56,481 | $ | 43,604 | $ | 36,696 | $ | 41,542 | $ | 30,892 | $ | 976 | $ | 355,357 | ||||||||||||||||
|
Depreciation and amortization
|
$ | 89,411 | $ | 28,066 | $ | 22,986 | $ | 15,881 | $ | 12,621 | $ | 16,182 | $ | — | $ | 185,147 | ||||||||||||||||
|
Taxes, other than income
|
$ | 106,620 | $ | 12,562 | $ | 10,995 | $ | 19,390 | $ | 13,599 | $ | 8,172 | $ | — | $ | 171,338 | ||||||||||||||||
|
OPERATING INCOME FROM CONTINUING OPERATIONS
(000’s)
(2)
|
$ | 134,655 | $ | 46,238 | $ | 45,759 | $ | 33,509 | $ | 26,441 | $ | 24,543 | $ | (976 | ) | $ | 310,169 | |||||||||||||||
|
CONSOLIDATED CAPITAL EXPENDITURES (000’s)
|
$ | 196,109 | $ | 62,808 | $ | 47,193 | $ | 39,387 | $ | 28,538 | $ | 29,792 | $ | 33,988 | $ | 437,815 | ||||||||||||||||
|
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (000’s)
|
$ | 1,761,087 | $ | 750,225 | $ | 413,189 | $ | 319,053 | $ | 284,195 | $ | 300,380 | $ | 130,983 | $ | 3,959,112 | ||||||||||||||||
|
OTHER CONSOLIDATED STATISTICS
|
||||||||||||||||||||||||||||||||
|
Heating Degree
Days
(1)
|
||||||||||||||||||||||||||||||||
|
Actual
|
2,100 | 3,924 | 1,532 | 3,537 | 2,734 | 5,909 | — | 2,780 | ||||||||||||||||||||||||
|
Percent of normal
|
103 | % | 100 | % | 96 | % | 99 | % | 102 | % | 106 | % | — | 102 | % | |||||||||||||||||
|
Miles of pipe
|
29,156 | 12,196 | 8,381 | 7,666 | 6,546 | 7,175 | — | 71,120 | ||||||||||||||||||||||||
|
Employees
|
1,650 | 587 | 439 | 344 | 371 | 284 | 1,039 | 4,714 | ||||||||||||||||||||||||
Natural
Gas Distribution Sales and Statistical Data by Division -
Discontinued Operations
| Fiscal Year Ended September 30, 2011 | Fiscal Year Ended September 30, 2010 | |||||||||||||||||||||||
|
Kentucky/
|
Colorado-
|
Kentucky/
|
Colorado-
|
|||||||||||||||||||||
| Mid-States | Kansas | Total | Mid-States | Kansas | Total | |||||||||||||||||||
|
Meters in service, end of period
|
83,325 | 428 | 83,753 | 83,577 | 434 | 84,011 | ||||||||||||||||||
|
Sales volumes — MMcf
|
||||||||||||||||||||||||
|
Total gas sales volumes
|
7,963 | 498 | 8,461 | 8,251 | 489 | 8,740 | ||||||||||||||||||
|
Transportation volumes
|
6,190 | — | 6,190 | 6,900 | — | 6,900 | ||||||||||||||||||
|
Total throughput
|
14,153 | 498 | 14,651 | 15,151 | 489 | 15,640 | ||||||||||||||||||
|
Operating income (000’s)
|
$ | 13,395 | $ | 1,020 | $ | 14,415 | $ | 11,628 | $ | 657 | $ | 12,285 | ||||||||||||
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. |
12
Table of Contents
| 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 and lending arrangements 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. 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. Rates are 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
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 nation’s 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 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
|
CUSTOMERS, end of year
|
||||||||||||||||||||
|
Industrial
|
71 | 65 | 68 | 62 | 65 | |||||||||||||||
|
Other
|
156 | 176 | 168 | 189 | 196 | |||||||||||||||
|
Total
|
227 | 241 | 236 | 251 | 261 | |||||||||||||||
|
PIPELINE TRANSPORTATION VOLUMES —
MMcf
(1)
|
620,904 | 634,885 | 706,132 | 782,876 | 699,006 | |||||||||||||||
|
OPERATING REVENUES
(000’s)
(1)
|
$ | 219,373 | $ | 203,013 | $ | 209,658 | $ | 195,917 | $ | 163,229 | ||||||||||
|
Employees, at year end
|
64 | 62 | 62 | 60 | 54 | |||||||||||||||
| (1) | Transportation volumes and operating revenues reflect segment operations, including intercompany sales and transportation amounts. |
Nonregulated
Segment Overview
Our nonregulated activities are conducted through Atmos Energy
Holdings, Inc. (AEH), which is a wholly-owned subsidiary of
Atmos Energy Corporation and operates primarily in the Midwest
and Southeast areas of the United States.
13
Table of Contents
AEH’s primary business is to deliver gas and provide
related services by aggregating and purchasing gas supply,
arranging transportation and storage logistics and ultimately
delivering gas to customers at competitive prices. In addition,
AEH utilizes proprietary and customer-owned transportation and
storage assets to provide various delivered gas 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, AEH’s gas delivery and related services 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.
AEH’s storage and transportation margins arise from
(i) utilizing its proprietary
21-mile
pipeline located in New Orleans, Louisiana to aggregate gas
supply for our regulated natural gas distribution division in
Louisiana, its gas delivery activities and, on a more limited
basis, for third parties and (ii) managing proprietary
storage in Kentucky and Louisiana to supplement the natural gas
needs of our natural gas distribution divisions during peak
periods.
AEH also seeks to enhance its gross profit margin by maximizing,
through asset optimization activities, the economic value
associated with the storage and transportation capacity it owns
or controls in our natural gas distribution and by its
subsidiaries. We attempt to meet these objectives 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 AEH
has access and selling financial instruments at advantageous
prices to lock in a gross profit margin. Certain of these
arrangements are with regulatory affiliates, which have been
approved by applicable state regulatory commissions.
Due to the nature of these operations, natural gas prices and
differences in natural gas prices between the various markets
that we serve (commonly referred to as basis differentials) have
a significant impact on our nonregulated businesses. Within our
delivered gas activities, basis differentials impact our ability
to create value from identifying the lowest cost alternative
among the natural gas supplies, transportation and markets to
which we have access. Further, higher natural gas prices may
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. 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 natural 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 nonregulated 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. Volatility could also impact the basis
differentials we capture in our delivered gas 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.
14
Table of Contents
Nonregulated
Sales and Statistical Data
| Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
|
CUSTOMERS, end of year
|
||||||||||||||||||||
|
Industrial
|
697 | 652 | 631 | 624 | 677 | |||||||||||||||
|
Municipal
|
65 | 61 | 63 | 55 | 68 | |||||||||||||||
|
Other
|
362 | 339 | 321 | 312 | 281 | |||||||||||||||
|
Total
|
1,124 | 1,052 | 1,015 | 991 | 1,026 | |||||||||||||||
|
INVENTORY STORAGE BALANCE — Bcf
|
15.7 | 17.9 | 19.9 | 12.4 | 21.3 | |||||||||||||||
|
NONREGULATED DELIVERED GAS SALES VOLUMES —
MMcf
(1)
|
446,903 | 420,203 | 441,081 | 457,952 | 423,895 | |||||||||||||||
|
OPERATING REVENUES
(000’s)
(1)
|
$ | 2,024,893 | $ | 2,146,658 | $ | 2,283,988 | $ | 4,117,299 | $ | 2,901,879 | ||||||||||
| (1) | Sales volumes 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 rate strategy focuses 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
73 percent of our gross margin. We also have accelerated
recovery of capital for approximately 11 percent of our
gross margin. Combined, we have rate structures with accelerated
recovery of all or a portion of our expenditures for
approximately 84 percent of our gross margin. Additionally,
we have WNA mechanisms in eight states that serve to minimize
the effects of weather on approximately 94 percent of our
gross margin. Finally, we have the ability to recover the gas
cost portion of bad debts for approximately 73 percent of
our gross margin. These mechanisms work in tandem to provide
substantial 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 and inclusion of
other taxes in gas costs 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 Energy’s operating
areas, 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
Table of Contents
Recent
Ratemaking Activity
Substantially all of our natural gas distribution revenues in
the fiscal years ended September 30, 2011, 2010 and 2009
were derived from sales at rates set by or subject to approval
by local or state authorities. Net operating income increases
resulting from ratemaking activity totaling $72.4 million,
$56.8 million and $54.4 million, became effective in
fiscal 2011, 2010 and 2009 as summarized below:
|
Annual Increase to Operating
|
||||||||||||
| Income For the Fiscal Year Ended September 30 | ||||||||||||
| Rate Action | 2011 | 2010 | 2009 | |||||||||
| (In thousands) | ||||||||||||
|
Rate case filings
|
$ | 20,502 | $ | 23,663 | $ | 2,959 | ||||||
|
Infrastructure programs
|
15,033 | 18,989 | 12,049 | |||||||||
|
Annual rate filing mechanisms
|
35,216 | 13,757 | 38,764 | |||||||||
|
Other ratemaking activity
|
1,675 | 392 | 631 | |||||||||
| $ | 72,426 | $ | 56,801 | $ | 54,403 | |||||||
Additionally, the following ratemaking efforts were initiated
during fiscal 2011 but had not been completed as of
September 30, 2011:
|
Operating Income
|
||||||||
| Division | Rate Action | Jurisdiction | Requested | |||||
| (In thousands) | ||||||||
|
Kentucky/Mid-States
|
PRP (1)(2) | Georgia | $ | 1,192 | ||||
| PRP (1)(3) | Kentucky | 2,529 | ||||||
|
Mississippi
|
Stable Rate Filing | Mississippi | 5,303 | |||||
|
West Texas & Lubbock Environs
|
Rate Case (4) | Railroad Commission of Texas (RRC) | 545 | |||||
| $ | 9,569 | |||||||
| (1) | The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program. | |
| (2) | The Georgia Commission issued a final order on October 5, 2011 approving a $1.2 million increase to operating income. | |
| (3) | The Kentucky Commission approved an increase of $2.5 million effective October 1, 2011. | |
| (4) | On September 30, 2011 the Company and Commission Staff signed a settlement and submitted to the Commission for their approval. |
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 Company’s costs
as well as a fair rate of return to our shareholders and ensure
that we continue to
16
Table of Contents
safely deliver reliable, reasonably priced natural gas service
to our customers. The following table summarizes our recent rate
cases:
|
Increase in Annual
|
||||||||||
| Division | State | Operating Income | Effective Date | |||||||
| (In thousands) | ||||||||||
|
2011 Rate Case Filings:
|
||||||||||
|
West Texas — Amarillo Environs
|
Texas | $ | 78 | 07/26/2011 | ||||||
|
Atmos Pipeline — Texas
|
Texas | 20,424 | 05/01/2011 | |||||||
|
Total 2011 Rate Case Filings
|
$ | 20,502 | ||||||||
|
2010 Rate Case Filings:
|
||||||||||
|
Kentucky/Mid-States
|
Missouri | $ | 3,977 | 09/01/2010 | ||||||
|
Colorado-Kansas
|
Kansas | 3,855 | 08/01/2010 | |||||||
|
Kentucky/Mid-States
|
Kentucky | 6,636 | 06/01/2010 | |||||||
|
Kentucky/Mid-States
|
Georgia | 2,935 | 03/31/2010 | |||||||
|
Mid-Tex
|
Texas (1) | 2,963 | 01/26/2010 | |||||||
|
Colorado-Kansas
|
Colorado | 1,900 | 01/04/2010 | |||||||
|
Kentucky/Mid-States
|
Virginia | 1,397 | 11/23/2009 | |||||||
|
Total 2010 Rate Case Filings
|
$ | 23,663 | ||||||||
|
2009 Rate Case Filings:
|
||||||||||
|
Kentucky/Mid-States
|
Tennessee | $ | 2,513 | 04/01/2009 | ||||||
|
West Texas
|
Texas | 446 | Various | |||||||
|
Total 2009 Rate Case Filings
|
$ | 2,959 | ||||||||
| (1) | In its final order, the RRC approved a $3.0 million increase in operating income from customers in the Dallas & Environs portion of the Mid-Tex Division. Operating income should increase $0.2 million, net of the GRIP 2008 rates that will be superseded. The ruling also provided for regulatory accounting treatment for certain costs related to storage assets and costs moving from our Mid-Tex Division within our natural gas distribution segment to our regulated transmission and storage segment. |
17
Table of Contents
Infrastructure
Programs
As discussed above in “Natural Gas Distribution Segment
Overview,” infrastructure programs such as GRIP allow
natural gas distribution companies the opportunity to include in
their rate base annually approved capital costs incurred in the
prior calendar year. We currently have infrastructure programs
in Texas, Georgia, Missouri and Kentucky. The following table
summarizes our infrastructure program filings with effective
dates during the fiscal years ended September 30, 2011,
2010 and 2009:
|
Increase in
|
||||||||||||
|
Incremental Net
|
Annual
|
|||||||||||
|
Utility Plant
|
Operating
|
Effective
|
||||||||||
| Division | Period End | Investment | Income | Date | ||||||||
| (In thousands) | (In thousands) | |||||||||||
|
2011 Infrastructure Programs:
|
||||||||||||
|
Atmos Pipeline — Texas
|
12/2010 | $ | 72,980 | $ | 12,605 | 07/26/2011 | ||||||
|
Mid-Tex/Environs
|
12/2010 | 107,840 | 576 | 06/27/2011 | ||||||||
|
West Texas/Lubbock & WT Cities Environs
|
12/2010 | 17,677 | 343 | 06/01/2011 | ||||||||
|
Kentucky/Mid-States-Kentucky
(1)
|
09/2011 | 3,329 | 468 | 06/01/2011 | ||||||||
|
Kentucky/Mid-States-Missouri
(2)
|
09/2010 | 2,367 | 277 | 02/14/2011 | ||||||||
|
Kentucky/Mid-States-Georgia
(1)
|
09/2009 | 5,359 | 764 | 10/01/2010 | ||||||||
|
Total 2011 Infrastructure Programs
|
$ | 209,552 | $ | 15,033 | ||||||||
|
2010 Infrastructure Programs:
|
||||||||||||
|
Mid-Tex
(3)
|
12/2009 | $ | 16,957 | $ | 2,983 | 09/01/2010 | ||||||
|
West Texas
|
12/2009 | 19,158 | 363 | 06/14/2010 | ||||||||
|
Atmos Pipeline — Texas
|
12/2009 | 95,504 | 13,405 | 04/20/2010 | ||||||||
|
Kentucky/Mid-States-Missouri
(2)
|
06/2009 | 3,578 | 563 | 03/02/2010 | ||||||||
|
Colorado-Kansas-Kansas
(4)
|
08/2009 | 6,917 | 766 | 12/12/2009 | ||||||||
|
Kentucky/Mid-States-Georgia
(1)
|
09/2008 | 6,327 | 909 | 10/01/2009 | ||||||||
|
Total 2010 Infrastructure Programs
|
$ | 148,441 | $ | 18,989 | ||||||||
|
2009 Infrastructure Programs:
|
||||||||||||
|
Mid-Tex
(5)
|
12/2008 | $ | 105,777 | $ | 2,732 | 09/09/2009 | ||||||
|
Atmos Pipeline — Texas
|
12/2008 | 51,308 | 6,342 | 04/28/2009 | ||||||||
|
Mid-Tex
(3)
|
12/2007 | 57,385 | 1,837 | 01/26/2009 | ||||||||
|
Kentucky/Mid-States-Missouri
(2)
|
03/2008 | 3,367 | 408 | 11/04/2008 | ||||||||
|
Kentucky/Mid-States-Georgia
(1)
|
09/2007 | 748 | 198 | 10/01/2008 | ||||||||
|
West
Texas
(6)
|
2007/08 | 27,425 | 532 | Various | ||||||||
|
Total 2009 Infrastructure Programs
|
$ | 246,010 | $ | 12,049 | ||||||||
| (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) | Increase relates to the City of Dallas and Environs areas of the Mid-Tex Division. | |
| (4) | Gas System Reliability Surcharge (GSRS) relates to safety related investments made since the previous rate case. | |
| (5) | Increase relates only to the City of Dallas area of the Mid-Tex Division. | |
| (6) | 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 revenue is applicable to environs customers only. |
18
Table of Contents
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 divisions, stable rate filings in the
Mississippi Division and the rate stabilization clause in the
Louisiana Division. The following table summarizes filings made
under our various annual rate filing mechanisms:
|
Increase
|
||||||||||||||
|
(Decrease) in
|
||||||||||||||
|
Annual
|
||||||||||||||
|
Operating
|
Effective
|
|||||||||||||
| Division | Jurisdiction | Test Year Ended | Income | Date | ||||||||||
| (In thousands) | ||||||||||||||
|
2011 Filings:
|
||||||||||||||
|
Mid-Tex
|
Settled Cities | 12/31/2010 | $ | 5,126 | 09/27/2011 | |||||||||
|
Mid-Tex
|
Dallas | 12/31/2010 | 1,084 | 09/27/2011 | ||||||||||
|
West Texas
|
Lubbock | 12/31/2010 | 319 | 09/08/2011 | ||||||||||
|
West Texas
|
Amarillo | 12/31/2010 | (492 | ) | 08/01/2011 | |||||||||
|
Louisiana
|
LGS | 12/31/2010 | 4,109 | 07/01/2011 | ||||||||||
|
Mid-Tex
|
Dallas | 12/31/2010 | 1,598 | 07/01/2011 | ||||||||||
|
Louisiana
|
TransLa | 09/30/2010 | 350 | 04/01/2011 | ||||||||||
|
Mid-Tex
|
Settled Cities | 12/31/2009 | 23,122 | 10/01/2010 | ||||||||||
|
Total 2011 Filings
|
$ | 35,216 | ||||||||||||
|
2010 Filings:
|
||||||||||||||
|
West Texas
|
Lubbock | 12/31/2009 | $ | (902 | ) | 09/01/2010 | ||||||||
|
West Texas
|
WT Cities | 12/31/2009 | 700 | 08/15/2010 | ||||||||||
|
West Texas
|
Amarillo | 12/31/2009 | 1,200 | 08/01/2010 | ||||||||||
|
Louisiana
|
LGS | 12/31/2009 | 3,854 | 07/01/2010 | ||||||||||
|
Louisiana
|
TransLa | 09/30/2009 | 1,733 | 04/01/2010 | ||||||||||
|
Mississippi
|
Mississippi | 06/30/2009 | 3,183 | 12/15/2009 | ||||||||||
|
West Texas
|
Lubbock | 12/31/2008 | 2,704 | 10/01/2009 | ||||||||||
|
West Texas
|
Amarillo | 12/31/2008 | 1,285 | 10/01/2009 | ||||||||||
|
Total 2010 Filings
|
$ | 13,757 | ||||||||||||
|
2009 Filings:
|
||||||||||||||
|
Mid-Tex
|
Settled Cities | 12/31/2008 | $ | 1,979 | 08/01/2009 | |||||||||
|
West Texas
|
WT Cities | 12/31/2008 | 6,599 | 08/01/2009 | ||||||||||
|
Louisiana
|
LGS | 12/31/2008 | 3,307 | 07/01/2009 | ||||||||||
|
Louisiana
|
TransLa | 09/30/2008 | 611 | 04/01/2009 | ||||||||||
|
Mississippi
|
Mississippi | 06/30/2008 | — | N/A | ||||||||||
|
Mid-Tex
|
Settled Cities | 12/31/2007 | 21,800 | 11/08/2008 | ||||||||||
|
West Texas
|
WT Cities | 12/31/2007 | 4,468 | 11/20/2008 | ||||||||||
|
Total 2009 Filings
|
$ | 38,764 | ||||||||||||
In June 2011, we reached an agreement with the City of Dallas to
enter into the DARR. This rate review provides for an annual
rate review without the necessity of filing a general rate case.
The first filing made under this mechanism will be in January
2012.
19
Table of Contents
In August 2010, we reached an agreement to extend the RRM in our
Mid-Tex Division for an additional two-year period beginning
October 1, 2010; however, the Mid-Tex Division will be
required to file a general system-wide rate case on or before
June 1, 2013. This extension provides for an annual rate
adjustment to reflect changes in the Mid-Tex Division’s
costs of service and additions to capital investment from year
to year, without the necessity of filing a general rate case.
The settlement also allows us to expand our existing program to
replace steel service lines in the Mid-Tex Division’s
natural gas delivery system. On October 13, 2010, the City
of Dallas approved the recovery of the return, depreciation and
taxes associated with the replacement of 100,000 steel service
lines across the Mid-Tex Division by September 30, 2012.
The RRM 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 440
incorporated cities served by the Mid-Tex Division, 439 of these
cities are part of the RRM process.
The West Texas RRM was entered into in August 2008 as a result
of a settlement with the West Texas Coalition of Cities. The
Lubbock and Amarillo RRMs were entered into in the spring of
2009. The West Texas Coalition of Cities agreed to extend its
RRM for one additional cycle as part of the settlement of this
fiscal year’s filing.
During fiscal 2011, the RRC’s Division of Public Safety
issued a new rule requiring natural gas distribution companies
to develop and implement a risk-based program for the renewal or
replacement of distribution facilities, including steel service
lines. The rule allows for the deferral of all expense
associated with capital expenditures incurred pursuant to this
rule, including the recording of interest on the deferred
expenses.
Other
Ratemaking Activity
The following table summarizes other ratemaking activity during
the fiscal years ended September 30, 2011, 2010 and 2009:
|
Increase in
|
||||||||||
|
Annual
|
||||||||||
|
Operating
|
Effective
|
|||||||||
| Division | Jurisdiction | Rate Activity | Income | Date | ||||||
| (In thousands) | ||||||||||
|
2011 Other Rate Activity:
|
||||||||||
|
West Texas
|
Triangle | Special Contract | $ | 641 | 07/01/2011 | |||||
|
Colorado-Kansas
|
Kansas | Ad Valorem (1) | 685 | 01/01/2011 | ||||||
|
Colorado-Kansas
|
Colorado | AMI (2) | 349 | 12/01/2010 | ||||||
|
Total 2011 Other Rate Activity
|
$ | 1,675 | ||||||||
|
2010 Other Rate Activity:
|
||||||||||
|
Colorado-Kansas
|
Kansas | Ad Valorem (1) | $ | 392 | 01/05/2010 | |||||
|
Total 2010 Other Rate Activity
|
$ | 392 | ||||||||
|
2009 Other Rate Activity:
|
||||||||||
|
Colorado-Kansas
|
Kansas | Tax Surcharge (3) | $ | 631 | 02/01/2009 | |||||
|
Total 2009 Other Rate Activity
|
$ | 631 | ||||||||
| (1) | The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas service area’s base rates. | |
| (2) | Automated Meter Infrastructure (AMI) relates to a pilot program in the Weld County area of our Colorado service area. | |
| (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. |
20
Table of Contents
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 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 FERC’s 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 the necessary and appropriate
steps to comply with these regulations.
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.
Our regulated transmission and storage operations historically
have faced limited competition from other existing intrastate
pipelines and gas marketers seeking to provide or arrange
transportation, storage and other services for customers.
However, in the last few years, several new pipelines have been
completed, which has increased the level of competition in this
segment of our business.
Within our nonregulated operations, AEM competes with other
natural gas marketers to provide natural gas management and
other related services primarily to smaller customers requiring
higher levels of balancing, scheduling and other related
management services. AEM has experienced increased competition
in recent years primarily from investment banks and major
integrated oil and natural gas companies who offer lower cost,
basic services. The increased competition has reduced margins
most notably on its high-volume accounts.
Employees
At September 30, 2011, we had 4,949 employees,
consisting of 4,817 employees in our regulated operations
and 132 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
21
Table of Contents
“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
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 during fiscal 2011, Kim R. Cocklin, certified to the New
York Stock Exchange that he was not aware of any violations 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.
| ITEM 1A. | Risk Factors. |
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 few 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.
Our long-term debt is currently rated as “investment
grade” by Standard & Poor’s Corporation,
Moody’s 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 nonregulated
segment because the commodity financial instruments markets
could become unavailable to us. Our nonregulated segment depends
primarily upon a committed credit facility to finance its
working capital needs, which it uses primarily to issue standby
letters of credit to its natural gas 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 nonregulated 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.
22
Table of Contents
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 in the last few years,
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
improving current economic conditions, 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. Additionally, our industrial
customers may seek alternative energy sources, which could
result in lower sales volumes.
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. In addition, the passage of the Health
Care Reform Act in 2010 could significantly increase the cost of
the health care benefits for our employees.
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 few 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. Also, our costs of providing
such benefits are subject to the continuing recovery of these
costs through rates.
In addition, the costs of providing health care benefits to our
employees could significantly increase over the next five to ten
years. Although the full effects of the Health Care Reform Act
should not impact the Company until 2014, the future cost of
compliance with the provisions of this legislation is difficult
to measure at this time.
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 caused by market supply and demand dynamics 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, particularly in
our nonregulated business segments, which could lead to
volatility in our earnings.
23
Table of Contents
Physical trading in our nonregulated business segments 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. 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 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. 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. 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
before the open positions can be closed.
Further, the timing of the recognition for financial accounting
purposes of gains or losses resulting from changes in the fair
value of derivative financial instruments designated as hedges
usually does not match 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. Also, if the local
physical markets in which we trade do not move consistently with
the NYMEX futures market upon which most of our commodity
derivative financial instruments are valued, we could experience
increased volatility in the financial results of our
nonregulated segment.
Our nonregulated segment manages margins and limits risk
exposure on the sale of natural gas inventory or the offsetting
fixed-price purchase or sale commitments for physical quantities
of natural gas through the use of a variety of financial
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. Any significant 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 compared to historical norms for both
short and long-term 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 they 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
rapid changes in the capital markets.
24
Table of Contents
We may
experience increased federal, state and local regulation of the
safety of our operations.
We are committed to constantly monitoring and maintaining our
pipeline and distribution system to ensure that natural gas is
delivered safely, reliably and efficiently through our network
of more than 76,000 miles of pipeline and distribution
lines. The pipeline replacement programs currently underway in
several of our divisions typify the preventive maintenance and
continual renewal that we perform on our natural gas
distribution system in the 12 states in which we currently
operate. The safety and protection of the public, our customers
and our employees is our top priority. However, due primarily to
the recent unfortunate pipeline incident in California, we
anticipate companies in the natural gas distribution business
may be subjected to even greater federal, state and local
oversight of the safety of their operations in the future.
Although we believe these costs are ultimately recoverable
through our rates, costs of complying with such increased
regulations may have at least a short-term adverse impact on our
operating costs and financial results.
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
FERC’s 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 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. 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 have been a number of new federal and state legislative
and regulatory initiatives proposed 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. However, neither this bill nor a related bill
in the U.S. Senate, the Clean Energy and Emissions Power
Act was passed by Congress. The adoption of this type of
legislation by Congress or similar legislation by states or the
adoption of related regulations by federal or state governments
mandating a substantial
25
Table of Contents
reduction in greenhouse gas emissions in the future 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 that
may be adopted 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.
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
nonregulated 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. Additionally, sustained cold
weather could challenge our ability to adequately meet customer
demand in our natural gas distribution and regulated
transmission and storage operations.
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 serve any growth in the
number of our customers. The cost of adding this capacity may be
affected by a number of factors, including the general state of
the economy and weather. In addition, although we should
ultimately recover the cost of the expenditures through rates,
we must make significant capital expenditures during the next
fiscal year in executing our steel service line replacement
program in the Mid-Tex Division. 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
26
Table of Contents
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 storage operations
historically have faced limited competition from other existing
intrastate pipelines and gas marketers seeking to provide or
arrange transportation, storage and other services for
customers. However, in the last few years, several new pipelines
have been completed, which has increased the level of
competition in this segment of our business. Within our
nonregulated operations, AEM competes with other natural gas
marketers to provide natural gas management and other related
services primarily to smaller customers requiring higher levels
of balancing, scheduling and other related management services.
AEM has experienced increased competition in recent years
primarily from investment banks and major integrated oil and
natural gas companies who offer lower cost, basic services.
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.
27
Table of Contents
| ITEM 2. | Properties. |
Distribution,
transmission and related assets
At September 30, 2011, our natural gas distribution segment
owned an aggregate of 70,869 miles of underground
distribution and transmission mains throughout our gas
distribution systems. These mains are located on easements or
rights-of-way
which generally provide for perpetual use. We maintain our mains
through a program of continuous inspection and repair and
believe that our system of mains is in good condition. Our
regulated transmission and storage segment owned
5,861 miles of gas transmission and gathering lines and our
nonregulated segment owned 105 miles of gas transmission
and gathering lines.
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 at September 30, 2011:
|
Maximum
|
||||||||||||||||
|
Cushion
|
Total
|
Daily 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
|
46,143,226 | 15,878,025 | 62,021,251 | 1,235,000 | ||||||||||||
|
Nonregulated 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
|
60,458,299 | 30,549,198 | 91,007,497 | 1,594,100 | ||||||||||||
| (1) | Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure. |
28
Table of Contents
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 at
September 30, 2011:
|
Maximum
|
||||||||||
|
Maximum
|
Daily
|
|||||||||
|
Storage
|
Withdrawal
|
|||||||||
|
Quantity
|
Quantity
|
|||||||||
| Segment | Division/Company | (MMBtu) | (MDWQ) (1) | |||||||
|
Natural Gas Distribution
Segment
(2)
|
||||||||||
| Colorado-Kansas Division | 4,243,909 | 108,039 | ||||||||
| Kentucky/Mid-States Division | 16,835,380 | 444,339 | ||||||||
| Louisiana Division | 2,643,192 | 161,473 | ||||||||
| Mississippi Division | 3,875,429 | 165,402 | ||||||||
| West Texas Division | 2,375,000 | 81,000 | ||||||||
|
Total
|
29,972,910 | 960,253 | ||||||||
|
Nonregulated Segment
|
||||||||||
| Atmos Energy Marketing, LLC | 8,026,869 | 250,937 | ||||||||
| Trans Louisiana Gas Pipeline, Inc. | 1,674,000 | 67,507 | ||||||||
|
Total
|
9,700,869 | 318,444 | ||||||||
|
Total Contracted Storage Capacity
|
39,673,779 | 1,278,697 | ||||||||
| (1) | Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate depending upon the season and the month. Unless otherwise noted, MDWQ amounts represent the MDWQ amounts as of November 1, which is the beginning of the winter heating season. | |
| (2) | On October 1, 2011, our Mid-Tex Division signed a new storage contract with a maximum storage quantity of 500,000 MMBtu and maximum daily withdrawal quantity of 50,000 MMBtu. |
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. The
headquarters for our nonregulated operations are in Houston,
Texas, with offices in Houston and other locations, primarily in
leased facilities.
| ITEM 3. | Legal Proceedings. |
See Note 13 to the consolidated financial statements.
29
Table of Contents
| ITEM 5. | Market for Registrant’s 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 2011 and
2010 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:
| Fiscal 2011 | Fiscal 2010 | |||||||||||||||||||||||
|
Dividends
|
Dividends
|
|||||||||||||||||||||||
| High | Low | Paid | High | Low | Paid | |||||||||||||||||||
|
Quarter ended:
|
||||||||||||||||||||||||
|
December 31
|
$ | 31.72 | $ | 29.10 | $ | .340 | $ | 30.06 | $ | 27.39 | $ | .335 | ||||||||||||
|
March 31
|
34.98 | 31.51 | .340 | 29.52 | 26.52 | .335 | ||||||||||||||||||
|
June 30
|
34.94 | 31.34 | .340 | 29.98 | 26.41 | .335 | ||||||||||||||||||
|
September 30
|
34.32 | 28.87 | .340 | 29.81 | 26.82 | .335 | ||||||||||||||||||
| $ | 1.36 | $ | 1.34 | |||||||||||||||||||||
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, 2011 was 18,746. 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 2011 that were not registered under the Securities Act of
1933, as amended.
30
Table of Contents
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
Poor’s 500 Stock Index and the cumulative total return of a
customized peer company group, the Comparison Company Index,
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, 2006 in our common stock, the
S&P 500 Index and in the common stock of the companies in
the Comparison Company Index, 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
among Atmos Energy Corporation, S&P 500 Index
and Comparison Company Indices
| Cumulative Total Return | ||||||||||||||||||||||||
| 9/30/06 | 9/30/07 | 9/30/08 | 9/30/09 | 9/30/10 | 9/30/11 | |||||||||||||||||||
|
Atmos Energy Corporation
|
100.00 | 103.36 | 101.92 | 113.82 | 123.97 | 143.45 | ||||||||||||||||||
|
S&P 500
|
100.00 | 116.44 | 90.85 | 84.58 | 93.17 | 94.24 | ||||||||||||||||||
|
Peer Group
|
100.00 | 116.52 | 103.24 | 104.34 | 128.20 | 157.38 | ||||||||||||||||||
The 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, Integrys
Energy Group, Inc., National Fuel Gas, Nicor Inc., NiSource
Inc., ONEOK Inc., Piedmont Natural Gas Company, Inc., Vectren
Corporation and WGL Holdings, Inc.
31
Table of Contents
The following table sets forth the number of securities
authorized for issuance under our equity compensation plans at
September 30, 2011.
|
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
|
86,766 | $ | 22.16 | 319,700 | ||||||||
|
Total equity compensation plans approved by security
holders
|
86,766 | 22.16 | 319,700 | |||||||||
|
Equity compensation plans not approved by security holders
|
— | — | — | |||||||||
|
Total
|
86,766 | $ | 22.16 | 319,700 | ||||||||
32
Table of Contents
| 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 | ||||||||||||||||||||
| 2011 (1) | 2010 | 2009 (1) | 2008 | 2007 (1) | ||||||||||||||||
| (In thousands, except per share data and ratios) | ||||||||||||||||||||
|
Results of Operations
|
||||||||||||||||||||
|
Operating revenues
|
$ | 4,347,634 | $ | 4,719,835 | $ | 4,869,111 | $ | 7,117,837 | $ | 5,803,177 | ||||||||||
|
Gross profit
|
1,327,241 | 1,337,505 | 1,319,678 | 1,293,922 | 1,221,078 | |||||||||||||||
|
Operating
expenses
(1)
|
885,342 | 860,354 | 883,312 | 878,399 | 835,353 | |||||||||||||||
|
Operating income
|
441,899 | 477,151 | 436,366 | 415,523 | 385,725 | |||||||||||||||
|
Miscellaneous income (expense)
|
21,499 | (156 | ) | (3,067 | ) | 3,017 | 9,227 | |||||||||||||
|
Interest charges
|
150,825 | 154,360 | 152,638 | 137,218 | 145,019 | |||||||||||||||
|
Income from continuing operations before income taxes
|
312,573 | 322,635 | 280,661 | 281,322 | 249,933 | |||||||||||||||
|
Income tax expense
|
113,689 | 124,362 | 97,362 | 107,837 | 89,105 | |||||||||||||||
|
Income from continuing operations
|
198,884 | 198,273 | 183,299 | 173,485 | 160,828 | |||||||||||||||
|
Income from discontinued operations, net of tax
|
8,717 | 7,566 | 7,679 | 6,846 | 7,664 | |||||||||||||||
|
Net income
|
$ | 207,601 | $ | 205,839 | $ | 190,978 | $ | 180,331 | $ | 168,492 | ||||||||||
|
Weighted average diluted shares outstanding
|
90,652 | 92,422 | 91,620 | 89,941 | 87,486 | |||||||||||||||
|
Income per share from continuing operations — diluted
|
$ | 2.17 | $ | 2.12 | $ | 1.98 | $ | 1.91 | $ | 1.82 | ||||||||||
|
Income per share from discontinued operations — diluted
|
0.10 | 0.08 | 0.09 | 0.08 | 0.09 | |||||||||||||||
|
Diluted net income per share
|
$ | 2.27 | $ | 2.20 | $ | 2.07 | $ | 1.99 | $ | 1.91 | ||||||||||
|
Cash flows from operations
|
$ | 582,844 | $ | 726,476 | $ | 919,233 | $ | 370,933 | $ | 547,095 | ||||||||||
|
Cash dividends paid per share
|
$ | 1.36 | $ | 1.34 | $ | 1.32 | $ | 1.30 | $ | 1.28 | ||||||||||
|
Natural gas distribution throughput from continuing operations
(MMcf)
(2)
|
409,369 | 438,535 | 393,604 | 413,491 | 411,337 | |||||||||||||||
|
Natural gas distribution throughput from discontinued operations
(MMcf)
(2)
|
14,651 | 15,640 | 15,281 | 15,863 | 16,532 | |||||||||||||||
|
Total regulated transmission and storage transportation volumes
(MMcf)
(2)
|
435,012 | 428,599 | 528,689 | 595,542 | 505,493 | |||||||||||||||
|
Total nonregulated delivered gas sales volumes
(MMcf)
(2)
|
384,799 | 353,853 | 370,569 | 389,392 | 370,668 | |||||||||||||||
|
Financial Condition
|
||||||||||||||||||||
|
Net property, plant and
equipment
(5)
|
$ | 5,147,918 | $ | 4,793,075 | $ | 4,439,103 | $ | 4,136,859 | $ | 3,836,836 | ||||||||||
|
Working
capital
(6)
|
143,355 | (290,887 | ) | 91,519 | 78,017 | 149,217 | ||||||||||||||
|
Total assets
|
7,282,871 | 6,763,791 | 6,367,083 | 6,386,699 | 5,895,197 | |||||||||||||||
|
Short-term debt, inclusive of current maturities of long-term
debt
|
208,830 | 486,231 | 72,681 | 351,327 | 154,430 | |||||||||||||||
|
Capitalization:
|
||||||||||||||||||||
|
Shareholders’ equity
|
2,255,421 | 2,178,348 | 2,176,761 | 2,052,492 | 1,965,754 | |||||||||||||||
|
Long-term debt (excluding current maturities)
|
2,206,117 | 1,809,551 | 2,169,400 | 2,119,792 | 2,126,315 | |||||||||||||||
|
Total capitalization
|
4,461,538 | 3,987,899 | 4,346,161 | 4,172,284 | 4,092,069 | |||||||||||||||
|
Capital expenditures
|
622,965 | 542,636 | 509,494 | 472,273 | 392,435 | |||||||||||||||
|
Financial Ratios
|
||||||||||||||||||||
|
Capitalization
ratio
(3)
|
48.3 | % | 48.7 | % | 49.3 | % | 45.4 | % | 46.3 | % | ||||||||||
|
Return on average shareholders’
equity
(4)
|
9.1 | % | 9.1 | % | 8.9 | % | 8.8 | % | 8.8 | % | ||||||||||
| (1) | Financial results for fiscal years 2011, 2009 and 2007 include a $30.3 million, $5.4 million and a $6.3 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. | |
| (5) | Amount shown for fiscal 2011 are net of assets held for sale. | |
| (6) | Amount shown for fiscal 2011 includes assets held for sale. |
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Table of Contents
| ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
INTRODUCTION
This section provides management’s discussion of the
financial condition, changes in financial condition and results
of operations of Atmos Energy Corporation and its consolidated
subsidiaries with specific information on results of operations
and liquidity and capital resources. It includes
management’s interpretation of our financial results, the
factors affecting these results, the major factors expected to
affect future operating results and future investment and
financing plans. This discussion should be read in conjunction
with our consolidated financial statements and notes thereto.
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 adverse
economic conditions on our customers; increased costs of
providing pension and postretirement health care benefits and
increased funding requirements along with increased costs of
health care benefits; 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; possible increased federal, state and
local regulation of the safety of our operations; increased
federal regulatory oversight and potential penalties; the impact
of environmental regulations on our business; the impact of
possible future additional regulatory and financial risks
associated with global warming and climate change on our
business; 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, 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
34
Table of Contents
other assumptions that we believe to be reasonable under the
circumstances. On an ongoing basis, we evaluate our estimates,
including those related to risk management and trading
activities, 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 periodically. 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 company’s
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 company’s other
costs, (ii) represents a large component of the utility
company’s 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 nonregulated segments are recognized in the period in which
actual volumes are transported and storage services are provided.
Operating revenues for our nonregulated 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
35
Table of Contents
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.
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
customer’s inability or reluctance to pay, we record an
allowance for doubtful accounts against amounts due to reduce
the net receivable balance to the amount we reasonably expect to
collect. However, if circumstances change, our estimate of the
recoverability of accounts receivable could be 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 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.
Our nonregulated 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 which we seek to maximize the economic value
associated with storage and transportation capacity we own or
control in both our natural gas distribution and nonregulated
businesses. 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 nonregulated segment, we have designated the natural gas
inventory held by this operating segment 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
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Table of Contents
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 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 nonregulated 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 nonregulated 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 with Treasury
lock agreements to fix the Treasury yield component of the
interest cost associated with anticipated financings. We
designate these Treasury lock agreements as cash flow hedges at
the time the agreements are executed. Accordingly, unrealized
gains and losses associated with the Treasury lock agreements
are recorded as a component of accumulated other comprehensive
income (loss). The realized gain or loss recognized upon
settlement of each Treasury lock agreement is 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. Hedge
ineffectiveness, to the extent incurred, is reported as a
component of interest expense.
Impairment assessments
— We perform impairment
assessments of our goodwill, intangible assets subject to
amortization and long-lived assets. As of September 30,
2011, 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 unit’s 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.
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Table of Contents
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 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 using a September 30
measurement date 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. 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 periodic pension and postretirement benefit
plan costs. When establishing our discount rate, we consider
high quality corporate bond rates based on bonds available in
the marketplace that are suitable for settling the obligations,
changes in those rates from the prior year and the implied
discount rate that is derived from matching our projected
benefit disbursements with currently available high quality
corporate bonds.
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 year’s 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.
The market-related value of our plan assets represents the fair
market value of the plan assets, adjusted to smooth out
short-term market fluctuations over a five-year period. The use
of this calculation will delay the impact of current market
fluctuations on the pension expense for the period.
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 and 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 $1.9 million. A 0.25 percent change
in our expected rate of return would impact our pension and
postretirement costs by approximately $0.8 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
38
Table of Contents
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. Adverse developments
in the global financial and credit markets in the last few years
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 further
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
62 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 fiscal 2011, we earned $207.6 million, or $2.27 per
diluted share, which represents a one percent increase in net
income and a three percent increase in diluted net income per
share over fiscal 2010. During fiscal 2011, recent improvements
in rate designs in our natural gas distribution segment and a
successful regulatory outcome in our regulated transmission and
storage segment offset a seven percent
year-over-year
decline in consolidated natural gas distribution throughput due
to warmer weather and a 108 percent decrease in asset
optimization margins as a result of weak natural gas market
fundamentals. Results for fiscal 2011 were influenced by several
non-recurring items, which increased diluted earnings per share
by $0.03. The increase in fiscal 2011 earnings per share also
reflects the favorable impact of our accelerated share buyback
39
Table of Contents
agreement initiated in the fourth quarter of fiscal 2010 and
completed in the second quarter of fiscal 2011, which increased
diluted earnings per share by $0.08.
On May 12, 2011, we entered into a definitive agreement to
sell all of our natural gas distribution assets located in
Missouri, Illinois and Iowa to Liberty Energy (Midstates)
Corporation, an affiliate of Algonquin Power &
Utilities Corp. for a cash price of approximately
$124 million. The agreement contains terms and conditions
customary for transactions of this type, including typical
adjustments to the purchase price at closing, if applicable. The
closing of the transaction is subject to the satisfaction of
customary conditions including the receipt of applicable
regulatory approvals. Due to the pending sales transaction, the
results of operations for these three service areas are shown in
discontinued operations.
On June 10, 2011 we issued $400 million of
5.50% senior notes. The effective interest rate on these
notes is 5.381 percent, after giving effect to offering
costs and the settlement of the $300 million Treasury locks
associated with the offering. Substantially all of the net
proceeds of approximately $394 million were used to repay
$350 million of outstanding commercial paper. The remainder
of the net proceeds was used for general corporate purposes. The
Treasury locks were settled on June 7, 2011 with the
receipt of $20.1 million from the counterparties due to an
increase in the
30-year
Treasury lock rates between inception of the Treasury locks and
settlement. Because the Treasury locks were effective, the net
$12.6 million unrealized gain was recorded as a component
of accumulated other comprehensive income and will be recognized
as a component of interest expense over the
30-year
life
of the senior notes.
During the year ended September 30, 2011, we executed on
our strategy to streamline our credit facilities, as follows:
| • | On May 2, 2011, we replaced our five-year $566.7 million unsecured credit facility, due to expire in December 2011, with a five-year $750 million unsecured credit facility with an accordion feature that could increase our borrowing capacity to $1.0 billion. | |
| • | In December 2010, we replaced AEM’s $450 million 364-day facility with a $200 million, three-year facility. The reduced amount of the new facility is due to the current low cost of gas and AEM’s ability to access an intercompany facility that was increased in fiscal 2011; however, this facility contains an accordion feature that could increase our borrowing capacity to $500 million. | |
| • | In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement that expired in April 2011. As planned, we did not replace or extend this agreement. |
After giving effect to these changes, we now have
$985 million of liquidity available to us from our
commercial paper program and four committed credit facilities
and have reduced our financing costs. We believe this
availability provides sufficient liquidity to fund our working
capital needs.
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Table of Contents
Consolidated
Results
The following table presents our consolidated financial
highlights for the fiscal years ended September 30, 2011,
2010 and 2009.
| For the Fiscal Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands, except per share data) | ||||||||||||
|
Operating revenues
|
$ | 4,347,634 | $ | 4,719,835 | $ | 4,869,111 | ||||||
|
Gross profit
|
1,327,241 | 1,337,505 | 1,319,678 | |||||||||
|
Operating expenses
|
885,342 | 860,354 | 883,312 | |||||||||
|
Operating income
|
441,899 | 477,151 | 436,366 | |||||||||
|
Miscellaneous income (expense)
|
21,499 | (156 | ) | (3,067 | ) | |||||||
|
Interest charges
|
150,825 | 154,360 | 152,638 | |||||||||
|
Income from continuing operations before income taxes
|
312,573 | 322,635 | 280,661 | |||||||||
|
Income tax expense
|
113,689 | 124,362 | 97,362 | |||||||||
|
Income from continuing operations
|
198,884 | 198,273 | 183,299 | |||||||||
|
Income from discontinued operations, net of tax
|
8,717 | 7,566 | 7,679 | |||||||||
|
Net income
|
$ | 207,601 | $ | 205,839 | $ | 190,978 | ||||||
|
Diluted net income per share from continuing operations
|
$ | 2.17 | $ | 2.12 | $ | 1.98 | ||||||
|
Diluted net income per share from discontinued operations
|
$ | 0.10 | $ | 0.08 | $ | 0.09 | ||||||
|
Diluted net income per share
|
$ | 2.27 | $ | 2.20 | $ | 2.07 | ||||||
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 104 percent,
81 percent and 83 percent to our consolidated net
income for fiscal years 2011, 2010, and 2009. 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 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Natural gas distribution segment
|
$ | 162,718 | $ | 125,949 | $ | 116,807 | ||||||
|
Regulated transmission and storage segment
|
52,415 | 41,486 | 41,056 | |||||||||
|
Nonregulated segment
|
(7,532 | ) | 38,404 | 33,115 | ||||||||
|
Net income
|
$ | 207,601 | $ | 205,839 | $ | 190,978 | ||||||
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 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands, except per share data) | ||||||||||||
|
Regulated operations
|
$ | 215,133 | $ | 167,435 | $ | 157,863 | ||||||
|
Nonregulated operations
|
(7,532 | ) | 38,404 | 33,115 | ||||||||
|
Consolidated net income
|
$ | 207,601 | $ | 205,839 | $ | 190,978 | ||||||
|
Diluted EPS from regulated operations
|
$ | 2.35 | $ | 1.79 | $ | 1.71 | ||||||
|
Diluted EPS from nonregulated operations
|
(0.08 | ) | 0.41 | 0.36 | ||||||||
|
Consolidated diluted EPS
|
$ | 2.27 | $ | 2.20 | $ | 2.07 | ||||||
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We reported net income of $207.6 million, or $2.27 per
diluted share for the year ended September 30, 2011,
compared with net income of $205.8 million or $2.20 per
diluted share in the prior year. Income from continuing
operations was $198.9 million, or $2.17 per diluted share
compared with $198.3 million, or $2.12 per diluted share in
the prior-year period. Income from discontinued operations was
$8.7 million or $0.10 per diluted share for the year,
compared with $7.6 million or $0.08 per diluted share in
the prior year. Unrealized losses in our nonregulated operations
during the current year reduced net income by $6.6 million
or $0.07 per diluted share compared with net losses recorded in
the prior year of $4.3 million, or $0.05 per diluted share.
Additionally, net income in both periods was impacted by
nonrecurring items. In the prior year, net income included the
net positive impact of a state sales tax refund of
$4.6 million, or $0.05 per diluted share. In the current
year, net income includes the net positive impact of several
one-time items totaling $3.2 million, or $0.03 per diluted
share related to the following pre-tax amounts:
| • | $27.8 million favorable impact related to the cash gain recorded in association with the unwinding of two Treasury locks in conjunction with the cancellation of a planned debt offering in November 2011. | |
| • | $30.3 million unfavorable impact related to the non-cash impairment of certain assets in our nonregulated business. | |
| • | $5.0 million favorable impact related to the administrative settlement of various income tax positions. |
Net income during fiscal 2010 increased eight percent over
fiscal 2009. Net income from our regulated operations increased
six percent during fiscal 2010. The increase primarily reflects
colder than normal weather in most of our service areas during
fiscal 2010 as well as the net favorable impact of various
ratemaking activities in our natural gas distribution segment.
Net income in our nonregulated operations increased
$5.3 million during fiscal 2010 primarily due to the impact
of unrealized margins. Non-cash, net unrealized losses totaled
$4.3 million which reduced earnings per share by $0.05 per
diluted share in fiscal 2010 compared to fiscal 2009, when net
unrealized losses totaled $21.6 million, which reduced
earnings per share by $0.23 per diluted share.
See the following discussion regarding the results of operations
for each of our business operating segments.
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, progress towards
implementing that strategy and recent ratemaking initiatives in
more detail.
We are generally able to pass the cost of gas through to our
customers without markup under purchased gas cost adjustment
mechanisms; therefore the cost of gas typically does not have an
impact on our gross profit as 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.
As discussed above, the cost of gas typically does not have a
direct impact on our gross profit. However, higher gas costs may
adversely impact our accounts receivable collections, resulting
in higher bad debt
42
Table of Contents
expense, and may require us to increase borrowings under our
credit facilities resulting in higher interest expense. In
addition, higher gas costs, as well as competitive factors in
the industry and general economic conditions may cause customers
to conserve or, in the case of industrial consumers, to use
alternative energy sources. However, gas cost risk has been
mitigated in recent years through improvements in rate design
that allow us to collect from our customers the gas cost portion
of our bad debt expense on approximately 73 percent of our
residential and commercial margins.
In May 2011, we announced that we had entered into a definitive
agreement to sell our natural gas distribution operations in
Missouri, Illinois and Iowa. The results of these operations
have been separately reported in the following tables and
exclude general corporate overhead and interest expense that
would normally be allocated to these operations.
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the fiscal years ended
September 30, 2011, 2010 and 2009 are presented below.
| For the Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 vs. 2010 | 2010 vs. 2009 | ||||||||||||||||
| (In thousands, unless otherwise noted) | ||||||||||||||||||||
|
Gross profit
|
$ | 1,044,364 | $ | 1,022,011 | $ | 997,604 | $ | 22,353 | $ | 24,407 | ||||||||||
|
Operating expenses
|
706,363 | 711,842 | 719,626 | (5,479 | ) | (7,784 | ) | |||||||||||||
|
Operating income
|
338,001 | 310,169 | 277,978 | 27,832 | 32,191 | |||||||||||||||
|
Miscellaneous income
|
16,557 | 1,567 | 6,002 | 14,990 | (4,435 | ) | ||||||||||||||
|
Interest charges
|
115,802 | 118,319 | 123,863 | (2,517 | ) | (5,544 | ) | |||||||||||||
|
Income from continuing operations before income taxes
|
238,756 | 193,417 | 160,117 | 45,339 | 33,300 | |||||||||||||||
|
Income tax expense
|
84,755 | 75,034 | 50,989 | 9,721 | 24,045 | |||||||||||||||
|
Income from continuing operations
|
154,001 | 118,383 | 109,128 | 35,618 | 9,255 | |||||||||||||||
|
Income from discontinued operations, net of tax
|
8,717 | 7,566 | 7,679 | 1,151 | (113 | ) | ||||||||||||||
|
Net Income
|
$ | 162,718 | $ | 125,949 | $ | 116,807 | $ | 36,769 | $ | 9,142 | ||||||||||
|
Consolidated natural gas distribution sales volumes from
continuing operations — MMcf
|
281,466 | 313,888 | 273,555 | (32,422 | ) | 40,333 | ||||||||||||||
|
Consolidated natural gas distribution transportation volumes
from continuing operations — MMcf
|
127,903 | 124,647 | 120,049 | 3,256 | 4,598 | |||||||||||||||
|
Consolidated natural gas distribution throughput from continuing
operations — MMcf
|
409,369 | 438,535 | 393,604 | (29,166 | ) | 44,931 | ||||||||||||||
|
Consolidated natural gas distribution throughput from
discontinued operations — MMcf
|
14,651 | 15,640 | 15,281 | (989 | ) | 359 | ||||||||||||||
|
Total consolidated natural gas distribution
throughput — MMcf
|
424,020 | 454,175 | 408,885 | (30,155 | ) | 45,290 | ||||||||||||||
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
$ | 0.47 | $ | 0.47 | $ | 0.47 | $ | — | $ | — | ||||||||||
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
$ | 5.30 | $ | 5.77 | $ | 6.95 | $ | (0.47 | ) | $ | (1.18 | ) | ||||||||
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Table of Contents
The following table shows our operating income from continuing
operations by natural gas distribution division, in order of
total rate base, for the fiscal years ended September 30,
2011, 2010 and 2009. 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 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 vs. 2010 | 2010 vs. 2009 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Mid-Tex
|
$ | 144,204 | $ | 134,655 | $ | 127,625 | $ | 9,549 | $ | 7,030 | ||||||||||
|
Kentucky/Mid-States
|
53,506 | 46,238 | 37,683 | 7,268 | 8,555 | |||||||||||||||
|
Louisiana
|
50,442 | 45,759 | 43,434 | 4,683 | 2,325 | |||||||||||||||
|
West Texas
|
29,686 | 33,509 | 23,338 | (3,823 | ) | 10,171 | ||||||||||||||
|
Mississippi
|
26,338 | 26,441 | 21,287 | (103 | ) | 5,154 | ||||||||||||||
|
Colorado-Kansas
|
25,920 | 24,543 | 20,580 | 1,377 | 3,963 | |||||||||||||||
|
Other
|
7,905 | (976 | ) | 4,031 | 8,881 | (5,007 | ) | |||||||||||||
|
Total
|
$ | 338,001 | $ | 310,169 | $ | 277,978 | $ | 27,832 | $ | 32,191 | ||||||||||
Fiscal
year ended September 30, 2011 compared with fiscal year
ended September 30, 2010
The $22.4 million increase in natural gas distribution
gross profit primarily reflects a $40.4 million net
increase in rate adjustments, primarily in the Mid-Tex,
Louisiana, Kentucky and Kansas service areas.
These increases were partially offset by:
| • | $12.0 million decrease due to a seven percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather this fiscal year compared to the same period last year in most of our service areas. | |
| • | $8.1 million decrease in revenue-related taxes, primarily due to lower revenues on which the tax is calculated. |
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income decreased
$5.5 million, primarily due to the following:
| • | $10.0 million decrease in taxes, other than income, due to lower revenue-related taxes. | |
| • | $6.4 million decrease in employee-related expenses. |
These decreases were partially offset by:
| • | $5.4 million increase due to the absence of a state sales tax reimbursement received in the prior year. | |
| • | $11.8 million increase in depreciation and amortization expense. | |
| • | $1.8 million increase in vehicles and equipment expense. |
Net income for this segment for the
year-to-date
period was also favorably impacted by a $21.8 million
pre-tax gain recognized in March 2011 as a result of unwinding
two Treasury locks and a $5.0 million income tax benefit
related to the administrative settlement of various income tax
positions.
Fiscal
year ended September 30, 2010 compared with fiscal year
ended September 30, 2009
The $24.4 million increase in natural gas distribution
gross profit primarily reflects rate adjustments and increased
throughput as follows:
| • | $33.4 million net increase in rate adjustments, primarily in the West Texas, Mid-Tex, Louisiana, Kentucky, Tennessee, Virginia and Mississippi service areas. |
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Table of Contents
| • | $10.6 million increase as a result of an 11 percent increase in consolidated throughput primarily associated with higher residential and commercial consumption and colder weather in most of our service areas. |
These increases were partially offset by:
| • | $7.6 million decrease due to a non-recurring adjustment recorded in the prior-year period to update the estimate for gas delivered to customers but not yet billed to reflect base rate changes. | |
| • | $7.0 million decrease related to a prior-year reversal of an accrual for estimated unrecoverable gas costs that did not recur in the current year. | |
| • | $1.6 million decrease in revenue-related taxes, primarily due to a decrease in revenues on which the tax is calculated. |
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income and asset
impairments decreased $7.8 million, primarily due to the
following:
| • | $5.4 million decrease due to a state sales tax reimbursement received in March 2010. | |
| • | $4.6 million decrease due to the absence of an impairment charge for available-for-sale securities recorded in the prior year. | |
| • | $4.5 million decrease in contract labor expenses. | |
| • | $4.6 million decrease in travel, legal and other administrative costs. |
These decreases were partially offset by:
| • | $7.5 million increase in employee-related expenses. | |
| • | $4.5 million increase in taxes, other than income. |
Miscellaneous income decreased $4.4 million due to lower
interest income. Interest charges decreased $5.5 million
primarily due to lower short-term debt balances and interest
rates.
Additionally, results for the fiscal year ended
September 30, 2009, were favorably impacted by a one-time
tax benefit of $10.5 million. During the second quarter of
fiscal 2009, the Company completed a study of the calculations
used to estimate its deferred tax rate, and concluded that
revisions to these calculations to include more specific
jurisdictional tax rates would result in a more accurate
calculation of the tax rate at which deferred taxes would
reverse in the future. Accordingly, the Company modified the tax
rate used to calculate deferred taxes from 38 percent to an
individual rate for each legal entity. These rates vary from
36-41 percent
depending on the jurisdiction of the legal entity.
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 excess gas.
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 Mid-Tex service area. 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 and demand for natural gas 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. Further, natural gas price
differences between the various hubs that we serve could
influence customers to transport gas through our pipeline to
capture arbitrage gains.
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Table of Contents
The results of Atmos Pipeline — Texas Division are
also significantly impacted by the natural gas requirements of
the Mid-Tex Division because it is the primary supplier of
natural gas for our 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.
Review of
Financial and Operating Results
Financial and operational highlights for our regulated
transmission and storage segment for the fiscal years ended
September 30, 2011, 2010, and 2009 are presented below.
| For the Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 vs. 2010 | 2010 vs. 2009 | ||||||||||||||||
| (In thousands, unless otherwise noted) | ||||||||||||||||||||
|
Mid-Tex Division transportation
|
$ | 125,973 | $ | 102,891 | $ | 89,348 | $ | 23,082 | $ | 13,543 | ||||||||||
|
Third-party transportation
|
73,676 | 73,648 | 95,314 | 28 | (21,666 | ) | ||||||||||||||
|
Storage and park and lend services
|
7,995 | 10,657 | 11,858 | (2,662 | ) | (1,201 | ) | |||||||||||||
|
Other
|
11,729 | 15,817 | 13,138 | (4,088 | ) | 2,679 | ||||||||||||||
|
Gross profit
|
219,373 | 203,013 | 209,658 | 16,360 | (6,645 | ) | ||||||||||||||
|
Operating expenses
|
111,098 | 105,975 | 116,495 | 5,123 | (10,520 | ) | ||||||||||||||
|
Operating income
|
108,275 | 97,038 | 93,163 | 11,237 | 3,875 | |||||||||||||||
|
Miscellaneous income
|
4,715 | 135 | 1,433 | 4,580 | (1,298 | ) | ||||||||||||||
|
Interest charges
|
31,432 | 31,174 | 30,982 | 258 | 192 | |||||||||||||||
|
Income before income taxes
|
81,558 | 65,999 | 63,614 | 15,559 | 2,385 | |||||||||||||||
|
Income tax expense
|
29,143 | 24,513 | 22,558 | 4,630 | 1,955 | |||||||||||||||
|
Net income
|
$ | 52,415 | $ | 41,486 | $ | 41,056 | $ | 10,929 | $ | 430 | ||||||||||
|
Gross pipeline transportation volumes — MMcf
|
620,904 | 634,885 | 706,132 | (13,981 | ) | (71,247 | ) | |||||||||||||
|
Consolidated pipeline transportation volumes — MMcf
|
435,012 | 428,599 | 528,689 | 6,413 | (100,090 | ) | ||||||||||||||
Fiscal
year ended September 30, 2011 compared with fiscal year
ended September 30, 2010
On April 18, 2011, the Railroad Commission of Texas (RRC)
issued an order in the rate case of Atmos Pipeline —
Texas (APT) that was originally filed in September 2010. The RRC
approved an annual operating income increase of
$20.4 million as well as the following major provisions
that went into effect with bills rendered on and after
May 1, 2011:
| • | Authorized return on equity of 11.8 percent. | |
| • | A capital structure of 49.5 percent debt/50.5 percent equity | |
| • | Approval of a rate base of $807.7 million, compared to the $417.1 million rate base from the prior rate case. | |
| • | An annual adjustment mechanism, which was approved for a three-year pilot program, that will adjust regulated rates up or down by 75 percent of the difference between APT’s non-regulated annual revenue and a pre-defined base credit. | |
| • | Approval of a straight fixed variable rate design, under which all fixed costs associated with transportation and storage services are recovered through monthly customer charges. |
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Table of Contents
The $16.4 million increase in regulated transmission and
storage gross profit was attributable primarily to the following:
| • | $23.4 million net increase as a result of the rate case that was finalized and became effective in May 2011. | |
| • | $3.2 million increase associated with our most recent GRIP filing. |
These increases were partially offset by the following:
| • | $4.8 million decrease due to the absence of the sale of excess gas, which occurred in the prior year. | |
| • | $4.4 million decrease due to a decline in throughput to our Mid-Tex Division primarily due to warmer than normal weather during fiscal 2011. |
Operating expenses increased $5.1 million primarily due to
the following:
| • | $4.6 million increase due to higher depreciation expense. | |
| • | $2.0 million increase due to the absence of a state sales tax reimbursement received in the prior year. |
These increases were partially offset by the following:
| • | $0.8 million decrease related to lower levels of pipeline maintenance activities. | |
| • | $0.7 million decrease due to lower employee-related expenses. |
Miscellaneous income includes a $6.0 million gain
recognized in March 2011 as a result of unwinding two Treasury
locks.
Fiscal
year ended September 30, 2010 compared with fiscal year
ended September 30, 2009
The $6.6 million decrease in regulated transmission and
storage gross profit was attributable primarily to the following
factors:
| • | $13.3 million decrease due to lower transportation fees on through-system deliveries due to narrower basis spreads. | |
| • | $2.6 million decrease due to decreased through-system volumes primarily associated with market conditions that resulted in reduced wellhead production, decreased drilling activity and increased competition, partially offset by increased deliveries to our Mid-Tex Division. | |
| • | $1.6 million net decrease in market-based demand fees, priority reservation fees and compression activity associated with lower throughput. |
These decreases were partially offset by the following:
| • | $9.3 million increase associated with our GRIP filings. | |
| • | $2.0 million increase of excess inventory sales in the current-year period. |
Operating expenses decreased $10.5 million primarily due to:
| • | $11.8 million decrease related to reduced contract labor. | |
| • | $2.0 million decrease due to a state sales tax reimbursement received in March 2010. |
These decreases were partially offset by a $2.1 million
increase in taxes, other than income due to higher ad valorem
and payroll taxes.
Miscellaneous income decreased $1.3 million due primarily
to a decline in intercompany interest income.
47
Table of Contents
Nonregulated
Segment
Our nonregulated activities are conducted through Atmos Energy
Holdings, Inc. (AEH), which is a wholly-owned subsidiary of
Atmos Energy Corporation and operates primarily in the Midwest
and Southeast areas of the United States.
AEH’s primary business is to deliver gas and provide
related services by aggregating and purchasing gas supply,
arranging transportation and storage logistics and ultimately
delivering gas to customers at competitive prices. In addition,
AEH utilizes proprietary and customer-owned transportation and
storage assets to provide various delivered gas 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, AEH’s gas delivery and related services 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.
AEH’s storage and transportation margins arise from
(i) utilizing its proprietary
21-mile
pipeline located in New Orleans, Louisiana to aggregate gas
supply for our regulated natural gas distribution division in
Louisiana, its gas delivery activities and, on a more limited
basis, for third parties and (ii) managing proprietary
storage in Kentucky and Louisiana to supplement the natural gas
needs of our natural gas distribution divisions during peak
periods.
AEH also seeks to enhance its gross profit margin by maximizing,
through asset optimization activities, the economic value
associated with the storage and transportation capacity it owns
or controls in our natural gas distribution and by its
subsidiaries. We attempt to meet these objectives 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 AEH
has access and selling financial instruments at advantageous
prices to lock in a gross profit margin.
AEH continually manages its net physical position to attempt to
increase the future economic profit that was created when the
original transaction was executed. Therefore, AEH may
subsequently change its originally scheduled storage injection
and withdrawal plans from one time period to another based on
market conditions. If AEH elects to accelerate the withdrawal of
physical gas, it will execute new financial instruments to
offset the original financial instruments. If AEH elects to
defer the withdrawal of gas, it will execute new financial
instruments to correspond to the revised withdrawal schedule and
allow the original financial instrument to settle as contracted.
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.
AEH 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 and
differences in natural gas prices between the various markets
that we serve (commonly referred to as basis differentials),
have a significant impact on our
48
Table of Contents
nonregulated businesses. Within our delivered gas activities,
basis differentials impact our ability to create value from
identifying the lowest cost alternative among the natural gas
supplies, transportation and markets to which we have access.
Further, higher natural gas prices may 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. 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 nonregulated 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. Volatility could also impact the basis
differentials we capture in our delivered gas activities.
However, increased volatility impacts the amounts of unrealized
margins recorded in our gross profit and could cause an increase
in the amount of cash required to collateralize our risk
management liabilities.
Review of
Financial and Operating Results
Financial and operational highlights for our nonregulated
segment for the fiscal years ended September 30, 2011, 2010
and 2009 are presented below. Gross profit margin consists
primarily of margins earned from the delivery of gas and related
services requested by our customers, margins earned from storage
and transportation services 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 gas 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 contingent upon the levels
of our net physical position at the end of the reporting period.
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| For the Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 vs. 2010 | 2010 vs. 2009 | ||||||||||||||||
| (In thousands, unless otherwise noted) | ||||||||||||||||||||
|
Realized margins
|
||||||||||||||||||||
|
Gas delivery and related services
|
$ | 58,990 | $ | 59,523 | $ | 75,341 | $ | (533 | ) | $ | (15,818 | ) | ||||||||
|
Storage and transportation services
|
14,570 | 13,206 | 12,784 | 1,364 | 422 | |||||||||||||||
|
Other
|
5,265 | 5,347 | 9,365 | (82 | ) | (4,018 | ) | |||||||||||||
| 78,825 | 78,076 | 97,490 | 749 | (19,414 | ) | |||||||||||||||
|
Asset
optimization
(1)
|
(3,424 | ) | 43,805 | 52,507 | (47,229 | ) | (8,702 | ) | ||||||||||||
|
Total realized margins
|
75,401 | 121,881 | 149,997 | (46,480 | ) | (28,116 | ) | |||||||||||||
|
Unrealized margins
|
(10,401 | ) | (7,790 | ) | (35,889 | ) | (2,611 | ) | 28,099 | |||||||||||
|
Gross profit
|
65,000 | 114,091 | 114,108 | (49,091 | ) | (17 | ) | |||||||||||||
|
Operating expenses, excluding asset impairment
|
39,113 | 44,147 | 49,046 | (5,034 | ) | (4,899 | ) | |||||||||||||
|
Asset impairment
|
30,270 | — | 181 | 30,270 | (181 | ) | ||||||||||||||
|
Operating income (loss)
|
(4,383 | ) | 69,944 | 64,881 | (74,327 | ) | 5,063 | |||||||||||||
|
Miscellaneous income
|
657 | 3,859 | 6,399 | (3,202 | ) | (2,540 | ) | |||||||||||||
|
Interest charges
|
4,015 | 10,584 | 14,350 | (6,569 | ) | (3,766 | ) | |||||||||||||
|
Income (loss) before income taxes
|
(7,741 | ) | 63,219 | 56,930 | (70,960 | ) | 6,289 | |||||||||||||
|
Income tax expense (benefit)
|
(209 | ) | 24,815 | 23,815 | (25,024 | ) | 1,000 | |||||||||||||
|
Net income (loss)
|
$ | (7,532 | ) | $ | 38,404 | $ | 33,115 | $ | (45,936 | ) | $ | 5,289 | ||||||||
|
Gross nonregulated delivered gas sales volumes — MMcf
|
446,903 | 420,203 | 441,081 | 26,700 | (20,878 | ) | ||||||||||||||
|
Consolidated nonregulated delivered gas sales
volumes — MMcf
|
384,799 | 353,853 | 370,569 | 30,946 | (16,716 | ) | ||||||||||||||
|
Net physical position (Bcf)
|
21.0 | 15.7 | 15.9 | 5.3 | (0.2 | ) | ||||||||||||||
| (1) | Net of storage fees of $15.2 million, $13.2 million and $10.8 million. |
Fiscal
year ended September 30, 2011 compared with fiscal year
ended September 30, 2010
Realized margins for gas delivery, storage and transportation
services and other services were $78.8 million during the
year ended September 30, 2011 compared with
$78.1 million for the prior-year period. The increase
primarily reflects the following:
| • | $1.4 million increase in margins from storage and transportation services, primarily attributable to new drilling projects in the Barnett Shale area. | |
| • | $0.6 million decrease in gas delivery and other services primarily due to lower per-unit margins partially offset by a nine percent increase in consolidated delivered gas sales volumes due to new customers in the power generation market. Per-unit margins were $0.13/Mcf in the current year compared with $0.14/Mcf in the prior year. The year-over-year decrease in per-unit margins reflects the impact of increased competition and lower basis spreads. |
The $47.2 million decrease in realized asset optimization
margins from the prior year primarily reflects the unfavorable
impact of weak natural gas market fundamentals which provided
fewer favorable trading opportunities.
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Unrealized margins decreased $2.6 million in the current
period compared to the prior-year period primarily due to the
timing of
year-over-year
realized margins.
Operating expenses decreased $5.0 million primarily due to
lower employee-related expenses and ad valorem taxes.
During fiscal 2011, our nonregulated segment recognized
$30.3 million of non-cash asset impairment charges
associated with two projects. In March 2011, we recorded a
$19.3 million charge to substantially write off our
investment in Fort Necessity. This project began in
February 2008 when Atmos Pipeline and Storage, LLC, a subsidiary
of AEH, announced plans to construct and operate a salt-cavern
storage project in Franklin Parish, Louisiana. In March 2010, we
entered into an option and acquisition agreement with a third
party, which provided the third party with the exclusive option
to develop the proposed Fort Necessity salt-dome natural
gas storage project. In July 2010, we agreed with the third
party to extend the option period to March 2011. In January
2011, the third party developer notified us that it did not plan
to commence the activities required to allow it to exercise the
option by March 2011; accordingly, the option was terminated. At
that time, we evaluated our strategic alternatives and concluded
the project’s returns did not meet our investment
objectives. Additionally, during the third quarter of fiscal
2011, we recorded an $11.0 million non-cash charge to
impair certain natural gas gathering assets of Atmos Gathering
Company. The charge reflected a reduction in the value of the
project due to the current low natural gas price environment and
the adverse impact of an ongoing lawsuit associated with the
project.
Interest charges decreased $6.6 million primarily due to a
decrease in intercompany borrowings.
Asset
Optimization Activities
AEH 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 AEH’s
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. Because there is no assurance that the
economic value or potential gross profit will be realized in the
future, corresponding future GAAP amounts are not available.
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The following table presents AEH’s economic value and its
potential gross profit (loss) at September 30, 2011 and
2010.
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In millions, unless otherwise noted) | ||||||||
|
Economic value
|
$ | 4.9 | $ | (7.5 | ) | |||
|
Associated unrealized losses
|
14.7 | 12.8 | ||||||
|
Subtotal
|
19.6 | 5.3 | ||||||
|
Related
fees
(1)
|
(17.7 | ) | (10.6 | ) | ||||
|
Potential gross profit (loss)
|
$ | 1.9 | $ | (5.3 | ) | |||
|
Net physical position (Bcf)
|
21.0 | 15.7 | ||||||
| (1) | Related fees represent the contractual costs to acquire the storage capacity utilized in our nonregulated segment’s asset optimization operations. The fees primarily consist of demand fees and contractual obligations to sell gas below market index in exchange for the right to manage and optimize third party storage assets for the positions we have entered into as of September 30, 2011 and 2010. |
During the 2011 fiscal year, our nonregulated segment’s
economic value increased from a negative economic value of
($7.5) million, or ($0.48)/Mcf at September 30, 2010
to $4.9 million, or $0.23/Mcf at September 30, 2011.
The increase in economic value was attributable to several
factors including an increase in the captured spread value
resulting from realizing financial instruments with lower spread
values, entering into financial hedges with higher average
prices and rolling financial instruments to forward periods to
capture incremental value. Additionally, as a result of falling
gas prices throughout the year, we injected a net 5.3 Bcf,
which reduced the overall weighted average cost of gas held in
storage.
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 AEH 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 as of September 30, 2011 will
be fully realized in the future nor can we predict 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.
Fiscal
year ended September 30, 2010 compared with fiscal year
ended September 30, 2009
Realized margins for gas delivery, storage and transportation
services and other services contributed 64 percent to total
realized margins during fiscal 2010, with asset optimization
activities contributing the remaining 36 percent. In fiscal
2009, gas delivery, storage and transportation services and
other services represented 65 percent of the nonregulated
segment’s realized margins with asset optimization
contributing the remaining 35 percent. The
$28.1 million decrease in realized gross profit reflected:
| • | $19.4 million decrease in gas delivery, storage and transportation services and other services as a result of narrowing basis spreads, combined with lower delivered sales volumes. Per-unit delivered gas margins were $0.14/Mcf in fiscal 2010, compared with $0.17/Mcf in fiscal 2009, while delivered gas volumes were 5 percent lower in fiscal 2010 when compared with fiscal 2009. | |
| • | $8.7 million decrease in asset optimization due to lower margins earned on storage optimization activities, lower basis gains earned from utilizing leased capacity and lower margins earned on asset management plans, partially offset by higher realized storage and trading gains during fiscal 2010. |
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The decrease in realized gross profit was offset by a
$28.1 million increase in unrealized margins due to the
period-over-period
timing of storage withdrawal gains and the associated reversal
of unrealized gains into realized gains.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income taxes, and asset
impairments decreased $5.1 million primarily due a decrease
in employee and other administrative costs, partially offset by
an increase in gas gathering activities.
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. Finally, from time to time, we raise funds
from the public debt and equity capital markets to fund our
liquidity needs.
We regularly evaluate our funding strategy and profile to ensure
that we have sufficient liquidity for our short-term and
long-term needs in a cost-effective manner. We also evaluate the
levels of committed borrowing capacity that we require. During
fiscal 2011, we executed on our strategy of consolidating our
short-term facilities used for our regulated operations into a
single line of credit, including the following:
| • | On May 2, 2011, we replaced our five-year $566.7 million unsecured credit facility, due to expire in December 2011, with a five-year $750 million unsecured credit facility with an accordion feature that could increase our borrowing capacity to $1.0 billion. | |
| • | In December 2010, we replaced AEM’s $450 million 364-day facility with a $200 million, three-year facility. The reduced amount of the new facility is due to the current low cost of gas and AEM’s ability to access an intercompany facility that was increased during fiscal 2011; however, this facility contains an accordion feature that could increase our borrowing capacity to $500 million. | |
| • | In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement that expired in April 2011. As planned, we did not replace or extend this agreement. |
As a result of these changes, we now have $985 million of
availability from our commercial paper program and four
committed revolving credit facilities with third parties.
Our $350 million 7.375% senior notes were paid on
their maturity date on May 15, 2011 using commercial paper
borrowings. In effect, we refinanced this debt on a long-term
basis through the issuance of $400 million 5.50%
30-year
unsecured senior notes on June 10, 2011. On
September 30, 2010, we entered into three Treasury lock
agreements to fix the Treasury yield component of the interest
cost of financing the anticipated issuances of senior notes. The
Treasury locks were settled on June 7, 2011 with the
receipt of $20.1 million from the counterparties due to an
increase in the
30-year
Treasury lock rates between inception of the Treasury lock and
settlement. The effective interest rate on these notes is
5.381 percent, after giving effect to offering costs and
the settlement of the $300 million Treasury locks.
Substantially all of the net proceeds of approximately
$394 million were used to repay $350 million of
outstanding commercial paper. The remainder of the net proceeds
was used for general corporate purposes.
Additionally, we had planned to issue $250 million of
30-year
unsecured notes in November 2011 to fund our capital expenditure
program. In September 2010, we entered into two Treasury lock
agreements to fix the Treasury yield component of the interest
cost associated with the anticipated issuance of these senior
notes, which were designated as cash flow hedges. Due primarily
to stronger than anticipated cash flows primarily resulting from
the extension of the Bush tax cuts that allow the continued use
of bonus depreciation on qualifying expenditures through
December 31, 2011, the need to issue $250 million of
debt in November was eliminated and the related Treasury lock
agreements were unwound. A pretax cash gain of approximately
$28 million was recorded in March 2011.
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Finally, we intend to refinance our $250 million unsecured
5.125% Senior Notes that mature in January 2013 through the
issuance of $350 million
30-year
unsecured notes. In August 2011, we entered into three Treasury
lock agreements to fix the Treasury yield component of the
interest cost associated with the anticipated issuances of these
senior notes. We designated all of these Treasury locks as cash
flow hedges.
We believe the liquidity provided by our senior notes and
committed credit facilities, combined with our operating cash
flows, will be sufficient to fund our working capital needs and
capital expenditure program for fiscal year 2012.
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, 2011, 2010 and 2009 are
presented below.
| For the Fiscal Year Ended September 30 | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 vs. 2010 | 2010 vs. 2009 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Total cash provided by (used in)
|
||||||||||||||||||||
|
Operating activities
|
$ | 582,844 | $ | 726,476 | $ | 919,233 | $ | (143,632 | ) | $ | (192,757 | ) | ||||||||
|
Investing activities
|
(627,386 | ) | (542,702 | ) | (517,201 | ) | (84,684 | ) | (25,501 | ) | ||||||||||
|
Financing activities
|
44,009 | (163,025 | ) | (337,546 | ) | 207,034 | 174,521 | |||||||||||||
|
Change in cash and cash equivalents
|
(533 | ) | 20,749 | 64,486 | (21,282 | ) | (43,737 | ) | ||||||||||||
|
Cash and cash equivalents at beginning of period
|
131,952 | 111,203 | 46,717 | 20,749 | 64,486 | |||||||||||||||
|
Cash and cash equivalents at end of period
|
$ | 131,419 | $ | 131,952 | $ | 111,203 | $ | (533 | ) | $ | 20,749 | |||||||||
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, 2011 compared with fiscal year
ended September 30, 2010
For the fiscal year ended September 30, 2011, we generated
operating cash flow of $582.8 million from operating
activities compared with $726.5 million in the prior year.
The
year-over-year
decrease reflects the absence of an $85 million income tax
refund received in the prior year coupled with the timing of gas
cost recoveries under our purchased gas cost mechanisms and
other net working capital changes.
Fiscal
Year ended September 30, 2010 compared with fiscal year
ended September 30, 2009
For the fiscal year ended September 30, 2010, we generated
operating cash flow of $726.5 million from operating
activities compared with $919.2 million in fiscal 2009,
primarily due to the fluctuation in gas costs. Gas costs, which
reached historically high levels during the 2008 injection
season, declined sharply when the economy slipped into the
recession and have remained relatively stable since that time.
Operating cash flows for the fiscal 2010 period reflect the
recovery of lower gas costs through purchased gas recovery
mechanisms
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Table of Contents
and sales. This is in contrast to the fiscal 2009 period, where
operating cash flows were favorably influenced by the recovery
of high gas costs during a period of falling prices.
Cash
flows from investing activities
In recent fiscal years, a substantial portion of our cash
resources has been used to fund our ongoing construction program
and improvements to information technology systems. Our ongoing
construction program enables us to provide safe and reliable
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.
In early fiscal 2010, two coalitions of cities, representing the
majority of the cities our Mid-Tex Division serves, agreed to a
program of installing, beginning in the first quarter of fiscal
2011, 100,000 steel service line replacements during fiscal 2011
and 2012, with approved recovery of the associated return,
depreciation and taxes. During fiscal 2011, we replaced 35,852
lines for a cost of $49.7 million. The program is
progressing on schedule for completion in September 2012. As a
result of this project and spending to replace our regulated
customer service systems and our nonregulated energy trading
risk management system, we anticipate capital expenditures will
remain elevated during the next fiscal year.
For the fiscal year ended September 30, 2011, we incurred
$623.0 million for capital expenditures compared with
$542.6 million for the fiscal year ended September 30,
2010 and $509.5 million for the fiscal year ended
September 30, 2009.
The $80.4 million increase in capital expenditures in
fiscal 2011 compared to fiscal 2010 primarily reflects spending
for the steel service line replacement program in the Mid-Tex
Division, the development of new customer billing and
information systems for our natural gas distribution and our
nonregulated segments and the construction of a new customer
contact center in Amarillo, Texas, partially offset by costs
incurred in the prior fiscal year to relocate the company’s
information technology data center.
The $33.1 million increase in capital expenditures in
fiscal 2010 compared to fiscal 2009 primarily reflects spending
for the relocation of our information technology data center to
a new facility, the construction of two service centers and the
steel service line replacement program in our Mid-Tex Division.
Cash
flows from financing activities
For the fiscal year ended September 30, 2011, our financing
activities generated $44.0 million in cash, while financing
activities for the fiscal year ended September 30, 2010
used $163.0 million in cash compared with cash of
$337.5 million used for the fiscal year ended
September 30, 2009. Our significant financing activities
for the fiscal years ended September 30, 2011, 2010 and
2009 are summarized as follows:
2011
During the fiscal year ended September 30, 2011, we:
| • | Received $394.5 million net cash proceeds in June 2011 related to the issuance of $400 million 5.50% senior notes due 2041. | |
| • | Borrowed a net $83.3 million under our short-term facilities to fund working capital needs. | |
| • | Received $27.8 million cash in March 2011 related to the unwinding of two Treasury locks. | |
| • | Received $20.1 million cash in June 2011 related to the settlement of three Treasury locks associated with the $400 million 5.50% senior notes offering. | |
| • | Received $7.8 million net proceeds related to the issuance of 0.3 million shares of common stock. |
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| • | Paid $360.1 million for scheduled long-term debt repayments, including our $350 million 7.375% senior notes that were paid on their maturity date on May 15, 2011. | |
| • | Paid $124.0 million in cash dividends which reflected a payout ratio of 60 percent of net income. | |
| • | Paid $5.3 million for the repurchase of equity awards. |
2010
During the fiscal year ended September 30, 2010, we:
| • | Paid $124.3 million in cash dividends which reflected a payout ratio of 61 percent of net income. | |
| • | Paid $100.5 million for the repurchase of common stock under an accelerated share repurchase agreement. | |
| • | Borrowed a net $54.3 million under our short-term facilities due to the impact of seasonal natural gas purchases. | |
| • | Received $8.8 million net proceeds related to the issuance of 0.4 million shares of common stock, which is a 68 percent decrease compared to the prior year due primarily to the fact that beginning in fiscal 2010 shares were purchased on the open market rather than being issued by us to the Direct Stock Purchase Plan and the Retirement Savings Plan. | |
| • | Paid $1.2 million to repurchase equity awards. |
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 short-term borrowings under our credit facilities. | |
| • | Paid $121.5 million in cash dividends which reflected a payout ratio of 64 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. |
The following table shows the number of shares issued for the
fiscal years ended September 30, 2011, 2010 and 2009:
| For the Fiscal Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
|
Shares issued:
|
||||||||||||
|
Direct stock purchase plan
|
— | 103,529 | 407,262 | |||||||||
|
Retirement savings plan
|
— | 79,722 | 640,639 | |||||||||
|
1998 Long-term incentive plan
|
675,255 | 421,706 | 686,046 | |||||||||
|
Outside directors
stock-for-fee
plan
|
2,385 | 3,382 | 3,079 | |||||||||
|
Total shares issued
|
677,640 | 608,339 | 1,737,026 | |||||||||
The number of shares issued in fiscal 2011 compared with the
number of shares issued in fiscal 2010 primarily reflects an
increased number of shares issued under our 1998 Long-Term
Incentive Plan due to the exercise of stock options during the
current fiscal year. This increase was partially offset by the
fact that we
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Table of Contents
are purchasing shares in the open market rather than issuing new
shares for the Direct Stock Purchase Plan and the Retirement
Savings Plan. During fiscal 2011, we cancelled and retired
169,793 shares attributable to federal withholdings on
equity awards and repurchased and retired 375,468 shares
attributable to our 2010 accelerated share repurchase agreement
described below, which are not included in the table above.
The
year-over-year
decrease in the number of shares issued in fiscal 2010 compared
with the number of shares issued in fiscal 2009, primarily
reflects the fact that in fiscal 2010, we began to purchase
shares in the open market rather than issuing new shares for the
Direct Stock Purchase Plan and the Retirement Savings Plan.
Further, a higher average stock price during the second and
third quarters of fiscal 2010 compared to the second and third
quarters of 2009 enabled us to issue fewer shares during fiscal
2010. Additionally, during fiscal 2010, we cancelled and retired
37,365 shares attributable to federal withholdings on
equity awards and repurchased and retired 2,958,580 common
shares as part of our 2010 accelerated share repurchase
agreement described below, which are not included in the table
above.
Share
Repurchase Agreement
On, July 1, 2010, we entered into an accelerated share
repurchase agreement with Goldman Sachs & Co. under
which we repurchased $100 million of our outstanding common
stock in order to offset stock grants made under our various
employee and director incentive compensation plans.
We paid $100 million to Goldman Sachs & Co. on
July 7, 2010 for shares of Atmos Energy common stock in a
share forward transaction and received 2,958,580 shares. On
March 4, 2011, we received and retired an additional
375,468 common shares, which concluded our share repurchase
agreement. In total, we received and retired 3,334,048 common
shares under the repurchase agreement. The final number of
shares we ultimately repurchased in the transaction was based
generally on the average of the effective share repurchase price
of our common stock over the duration of the agreement, which
was $29.99. As a result of this transaction, beginning in our
fourth quarter of fiscal 2010, the number of outstanding shares
used to calculate our earnings per share was reduced by the
number of shares received and the $100 million purchase
price was recorded as a reduction in shareholders’ equity.
Share
Repurchase Program
On September 28, 2011 the Board of Directors approved a new
program authorizing the repurchase of up to five million shares
of common stock over a five-year period. Although the program is
authorized for a five-year period, it may be terminated or
limited at any time. Shares may be repurchased in the open
market or in privately negotiated transactions in amounts the
company deems appropriate. The program is primarily intended to
minimize the dilutive effect of equity grants under various
benefit related incentive compensation plans of the company.
Credit
Facilities
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 to meet our customers’ needs could significantly
affect our borrowing requirements. However, our short-term
borrowings typically reach their highest levels in the winter
months.
As of September 30, 2011, we financed our short-term
borrowing requirements through a combination of a
$750.0 million commercial paper program and four committed
revolving credit facilities with third-party lenders that
provided $985 million of working capital funding. As of
September 30, 2011, the amount available to us under our
credit facilities, net of outstanding letters of credit, was
$702.5 million. These facilities are described in further
detail in Note 7 to the consolidated financial statements.
On May 2, 2011, we replaced our five-year
$566.7 million unsecured credit facility, due to expire in
December 2011, with a five-year $750 million unsecured
credit facility with an accordion feature that could increase
our borrowing capacity to $1.0 billion.
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In December 2010, we replaced AEM’s $450 million
364-day
facility with a $200 million, three-year facility. The
reduced amount of the new facility is due to the current low
cost of gas and AEM’s ability to access an intercompany
facility that was increased in fiscal 2011; however, this
facility contains an accordion feature that could increase our
borrowing capacity to $500 million.
In October 2010, we replaced our $200 million
364-day
revolving credit agreement with a $200 million
180-day
revolving credit agreement that expired in April 2011. As
planned, we did not replace or extend this agreement.
Shelf
Registration
We have an effective shelf registration statement with the
Securities and Exchange Commission (SEC) that permits us to
issue a total of $1.3 billion in common stock
and/or
debt
securities. The shelf registration statement has been approved
by all requisite state regulatory commissions. Due to certain
restrictions imposed by one state regulatory commission on our
ability to issue securities under the new registration
statement, we were able to issue a total of $950 million in
debt securities and $350 million in equity securities. At
September 30, 2011, $900 million was available for
issuance. Of this amount, $550 million is available for the
issuance of debt securities and $350 million remains
available for the issuance of equity securities under the shelf
until March 2013.
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 environment in the
states where we operate.
Our debt is rated by three rating agencies: Standard &
Poor’s Corporation (S&P), Moody’s Investors
Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). On
May 11, 2011, Moody’s upgraded our senior unsecured
debt rating to Baa1 from Baa2, with a ratings outlook of stable,
citing steady rate increases, improving credit metrics and a
strategic focus on lower risk regulated activities as reasons
for the upgrade. On June 2, 2011, Fitch upgraded our senior
unsecured debt rating to A- from BBB+, with a ratings outlook of
stable, citing a constructive regulatory environment, strategic
focus on lower risk regulated activities and the geographic
diversity of our regulated operations as key rating factors. As
of September 30, 2011, S&P maintained a stable
outlook. Our current debt ratings are all considered investment
grade and are as follows:
| S&P | Moody’s | Fitch | ||||||||||
|
Unsecured senior long-term debt
|
BBB+ | Baa1 | A- | |||||||||
|
Commercial paper
|
A-2 | P-2 | F-2 | |||||||||
A significant degradation in our operating performance or a
significant reduction in our liquidity caused by more limited
access to the private and public credit markets as a result of
deteriorating global or national 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 is AAA
for S&P, Aaa for Moody’s and AAA for Fitch. The lowest
investment grade credit rating is BBB-for S&P, Baa3 for
Moody’s and BBB- for Fitch. Our credit ratings may be
revised or withdrawn at any time by the rating agencies, and
each rating should be evaluated independently of any other
rating. There can be no assurance that a rating will remain in
effect for any given period of time or that a rating will not be
lowered, or withdrawn entirely, by a rating agency if, in its
judgment, circumstances so warrant.
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Table of Contents
Debt
Covenants
We were in compliance with all of our debt covenants as of
September 30, 2011. Our debt covenants are described in
Note 7 to the consolidated financial statements.
Capitalization
The following table presents our capitalization as of
September 30, 2011 and 2010:
| September 30 | ||||||||||||||||
| 2011 | 2010 | |||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||
|
Short-term debt
|
$ | 206,396 | 4.4 | % | $ | 126,100 | 2.8 | % | ||||||||
|
Long-term debt
|
2,208,551 | 47.3 | % | 2,169,682 | 48.5 | % | ||||||||||
|
Shareholders’ equity
|
2,255,421 | 48.3 | % | 2,178,348 | 48.7 | % | ||||||||||
|
Total capitalization, including short-term debt
|
$ | 4,670,368 | 100.0 | % | $ | 4,474,130 | 100.0 | % | ||||||||
Total debt as a percentage of total capitalization, including
short-term debt, was 51.7 percent and 51.3 percent at
September 30, 2011 and 2010. The increase in the debt to
capitalization ratio primarily reflects an increase in
short-term debt as of September 30, 2011 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 intend to continue
to maintain our debt to capitalization ratio in a target range
of 50 to 55 percent.
Contractual
Obligations and Commercial Commitments
The following table provides information about contractual
obligations and commercial commitments at September 30,
2011.
| 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)
|
$ | 2,212,565 | $ | 2,434 | $ | 250,131 | $ | 500,000 | $ | 1,460,000 | ||||||||||
|
Short-term
debt
(1)
|
206,396 | 206,396 | — | — | — | |||||||||||||||
|
Interest
charges
(2)
|
1,574,702 | 136,452 | 250,841 | 198,596 | 988,813 | |||||||||||||||
|
Gas purchase
commitments
(3)
|
460,179 | 274,985 | 185,194 | — | — | |||||||||||||||
|
Capital lease
obligations
(4)
|
1,194 | 186 | 372 | 372 | 264 | |||||||||||||||
|
Operating
leases
(4)
|
199,567 | 17,718 | 33,365 | 30,376 | 118,108 | |||||||||||||||
|
Demand fees for contracted
storage
(5)
|
19,339 | 11,421 | 6,770 | 983 | 165 | |||||||||||||||
|
Demand fees for contracted
transportation
(6)
|
37,295 | 13,941 | 19,929 | 3,425 | — | |||||||||||||||
|
Financial instrument
obligations
(7)
|
93,542 | 15,453 | 78,089 | — | — | |||||||||||||||
|
Postretirement benefit plan
contributions
(8)
|
194,323 | 31,519 | 28,543 | 35,122 | 99,139 | |||||||||||||||
|
Total contractual obligations
|
$ | 4,999,102 | $ | 710,505 | $ | 853,234 | $ | 768,874 | $ | 2,666,489 | ||||||||||
| (1) | See Note 7 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, 2011. |
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Table of Contents
| (4) | See Note 14 to the consolidated financial statements. | |
| (5) | Represents third party contractual demand fees for contracted storage in our nonregulated segment. 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 nonregulated segment. | |
| (7) | Represents liabilities for natural gas commodity financial instruments that were valued as of September 30, 2011. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled. The table above excludes $1.3 million of current liabilities from risk management activities that are classified as liabilities held for sale in conjunction with the sale of our Iowa, Illinois and Missouri operations. | |
| (8) | Represents expected contributions to our postretirement benefit plans. |
AEH has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At September 30, 2011, AEH was committed
to purchase 103.3 Bcf within one year, 46.4 Bcf within
one to three years and 0.9 Bcf after three years under
indexed contracts. AEH is committed to purchase 4.2 Bcf
within one year and 0.3 Bcf within one to three years under
fixed price contracts with prices ranging from $3.49 to $6.36
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 natural 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, 2011 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 and
nonregulated 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
nonregulated 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 nonregulated 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 nonregulated segment.
Also, in our nonregulated 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.
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Table of Contents
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 segment’s financial
instruments for the fiscal year ended September 30, 2011
(in thousands):
|
Fair value of contracts at September 30, 2010
|
$ | (49,600 | ) | |
|
Contracts realized/settled
|
(51,136 | ) | ||
|
Fair value of new contracts
|
2,584 | |||
|
Other changes in value
|
18,875 | |||
|
Fair value of contracts at September 30, 2011
|
$ | (79,277 | ) | |
The fair value of our natural gas distribution segment’s
financial instruments at September 30, 2011, is presented
below by time period and fair value source:
| Fair Value of Contracts at September 30, 2011 | ||||||||||||||||||||
| 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
|
$ | (12,413 | ) | $ | (66,864 | ) | $ | — | $ | — | $ | (79,277 | ) | |||||||
|
Prices based on models and other valuation methods
|
— | — | — | — | — | |||||||||||||||
|
Total Fair Value
|
$ | (12,413 | ) | $ | (66,864 | ) | $ | — | $ | — | $ | (79,277 | ) | |||||||
The tables above include $1.3 million of current
liabilities from risk management activities that are classified
as liabilities held for sale in conjunction with the sale of our
Iowa, Illinois and Missouri operations.
The following table shows the components of the change in fair
value of our nonregulated segment’s financial instruments
for the fiscal year ended September 30, 2011 (in thousands):
|
Fair value of contracts at September 30, 2010
|
$ | (12,374 | ) | |
|
Contracts realized/settled
|
4,017 | |||
|
Fair value of new contracts
|
— | |||
|
Other changes in value
|
(16,693 | ) | ||
|
Fair value of contracts at September 30, 2011
|
(25,050 | ) | ||
|
Netting of cash collateral
|
28,787 | |||
|
Cash collateral and fair value of contracts at
September 30, 2011
|
$ | 3,737 | ||
The fair value of our nonregulated segment’s financial
instruments at September 30, 2011, is presented below by
time period and fair value source.
| Fair Value of Contracts at September 30, 2011 | ||||||||||||||||||||||||
| 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
|
$ | (14,823 | ) | $ | (10,050 | ) | $ | (177 | ) | $ | — | $ | (25,050 | ) | ||||||||||
|
Prices based on models and other valuation methods
|
— | — | — | — | — | |||||||||||||||||||
|
Total Fair Value
|
$ | (14,823 | ) | $ | (10,050 | ) | $ | (177 | ) | $ | — | $ | (25,050 | ) | ||||||||||
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Table of Contents
Employee
Benefit Programs
An important element of our total compensation program, and a
significant component of our operation and maintenance expense,
is the offering of various benefit programs to our employees.
These programs include medical and dental insurance coverage and
pension and postretirement programs.
Medical
and Dental Insurance
We offer medical and dental insurance programs to substantially
all of our employees, and we believe these programs are
consistent with other programs in our industry. Since 2005, we
have experienced medical and prescription inflation of
approximately seven percent. In recent years, we have strived to
actively manage our health care costs through the introduction
of a wellness strategy that is focused on helping employees to
identify health risks and to manage these risks through improved
lifestyle choices.
In March 2010, President Obama signed
The Patient Protection
and Affordable Care Act
into law (the “Health Care
Reform Act”). The Health Care Reform Act will be phased in
over an eight-year period. Although we are still assessing the
impact of the Health Care Reform Act on the health care benefits
we provide to our employees, the design of our health care plans
has already changed in order to comply with provisions of the
Health Care Reform Act that have already gone into effect or
will be going into effect in fiscal 2012. For example, lifetime
maximums on benefits have been eliminated, coverage for
dependent children has been extended to age 26 and all
costs of preventive coverage must be paid for by the insurer. In
2014, health insurance exchanges will open in each state in
order to provide a competitive marketplace for purchasing health
insurance by individuals. Companies who offer health insurance
to their employees could face a substantial increase in premiums
at that time if they choose to continue to provide such
coverage. However, companies who elect to cease providing health
insurance to their employees will be faced with paying
significant penalties to the federal government for each
employee who receives coverage through an exchange. We will
continue to monitor all developments on health care reform and
continue to comply with all existing relevant laws and
regulations.
For fiscal 2012, we anticipate an approximate 10 percent
medical and prescription drug inflation rate, primarily due to
anticipated higher claims costs and the implementation of the
Health Care Reform Act.
Net
Periodic Pension and Postretirement Benefit Costs
For the fiscal year ended September 30, 2011, our total net
periodic pension and other benefits costs was
$56.6 million, compared with $50.8 million and
$50.2 million for the fiscal years ended September 30,
2010 and 2009. 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.
Our fiscal 2011 costs were determined using a September 30,
2010 measurement date. As of September 30, 2010, interest
and corporate bond rates utilized to determine our discount
rates were significantly higher than the interest and corporate
bond rates as of September 30, 2009, the measurement date
for our fiscal 2010 net periodic cost. Accordingly, we
decreased our discount rate used to determine our fiscal 2011
pension and benefit costs to 5.39 percent. Our expected
return on our pension plan assets remained constant at
8.25 percent. Accordingly, our fiscal 2011 pension and
postretirement medical costs were higher than in the prior year.
The increase in total net periodic pension and other benefits
costs during fiscal 2010 compared with fiscal 2009 primarily
reflects the decline in fair value of our plan assets. The
discount rate used to compute the present value of a plan’s
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, 2009
measurement date, the interest rates were slightly lower than
the interest rates at September 30, 2008, the measurement
date used to determine our fiscal 2009 net periodic cost.
Our expected return on our pension plan assets remained constant
at 8.25 percent.
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Table of Contents
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.
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.
In accordance with the Pension Protection Act of 2006 (PPA), we
determined the funded status of our plans as of January 1,
2011. Based on this valuation, we were required to contribute
cash of $0.9 million to our pension plans during fiscal
2011. The need for this funding reflects the decline in the fair
value of the plans’ assets resulting from the unfavorable
market conditions experienced during 2008 and 2009. This
contribution will increase the level of our plan assets to
achieve a desirable PPA funding threshold.
During fiscal 2010, we did not contribute cash to our pension
plans as the fair value of the plans’ assets recovered
somewhat during the year from the unfavorable market conditions
experienced in the latter half of calendar year 2008 and our
plan assets were sufficient to achieve a desirable funding
threshold as established by the PPA. During fiscal 2009, we
contributed $21.0 million to our pension plans to achieve
the same desired level of funding as established by the PPA.
We contributed $11.3 million, $11.8 million and
$10.1 million to our postretirement benefits plans for the
fiscal years ended September 30, 2011, 2010 and 2009. 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 2012 and Beyond
As of September 30, 2011, interest and corporate bond rates
utilized to determine our discount rates, which impacted our
fiscal 2012 net periodic pension and postretirement costs,
were lower than the interest and corporate bond rates as of
September 30, 2010, the measurement date for our fiscal
2011 net periodic cost. As a result of the lower interest
and corporate bond rates, we decreased the discount rate used to
determine our fiscal 2012 pension and benefit costs to
5.05 percent. We reduced the expected return on our pension
plan assets to 7.75 percent, based on historical experience
and the current market projection of the target asset
allocation. Although the fair value of our plan assets has
declined as the financial markets have declined, the impact of
this decline is partially 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. Due to
the decrease in our discount rate and our expected return on
plan assets as well as the decline in the fair value of our plan
assets, we expect our fiscal 2012 pension and postretirement
medical costs to increase compared to fiscal 2011.
Based upon market conditions subsequent to September 30,
2011 the current funded position of the plans and the new
funding requirements under the PPA, we anticipate contributing
between $25 million and $30 million to the Plans in
fiscal 2012. Further, we will consider whether an additional
voluntary contribution is prudent to maintain certain PPA
funding thresholds. With respect to our postretirement medical
plans, we anticipate contributing approximately $32 million
during fiscal 2012.
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.
In August 2010, the Board of Directors of Atmos Energy approved
a proposal to close the Pension Account Plan (PAP) to new
participants, effective October 1, 2010. Employees
participating in the PAP as of October 1, 2010 were allowed
to make a one-time election to migrate from the PAP into our
defined contribution plan with enhanced features, effective
January 1, 2011. Participants who chose to remain in the
PAP will continue to earn benefits and interest allocations with
no changes to their existing benefits.
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Table of Contents
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 nonregulated 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 nonregulated 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 adjustment mechanisms.
Therefore, our natural gas distribution operations have limited
commodity price risk exposure.
Nonregulated
segment
Our nonregulated segment is also exposed to risks associated
with changes in the market price of natural gas. For our
nonregulated 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 AEH’s net open position (including existing
storage and related financial contracts) at September 30,
2011 of 0.1 Bcf, a $0.50 change in the forward NYMEX price
would have had a $0.1 million impact on our consolidated
net income.
Changes in the difference between the indices used to mark to
market our physical inventory (Gas Daily) and the related
fair-value hedge (NYMEX) can result in volatility in our
reported net income; but, over time, gains and losses on the
sale of storage gas inventory will be offset by gains and losses
on the fair-value hedges. Based upon our net physical position
at September 30, 2011 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 $6.7 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 $1.2 million during 2011.
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 | ||||
| 132 | ||||
|
Financial statement schedule for the years ended
September 30, 2011, 2010 and 2009
|
||||
| 140 | ||||
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
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2011 and 2010,
and the related consolidated statements of income,
shareholders’ equity, and cash flows for each of the three
years in the period ended September 30, 2011. 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 Company’s management. Our
responsibility is to express an opinion on these financial
statements and schedule based on our audits.
We conducted our audits in accordance with 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, 2011 and 2010, and the consolidated results
of its operations and its cash flows for each of the three years
in the period ended September 30, 2011, 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), Atmos
Energy Corporation’s internal control over financial
reporting as of September 30, 2011, 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 22, 2011
expressed an unqualified opinion thereon.
/s/
ERNST &
YOUNG LLP
Dallas, Texas
November 22, 2011
66
Table of Contents
ATMOS
ENERGY CORPORATION
| September 30 | ||||||||
| 2011 | 2010 | |||||||
|
(In thousands,
|
||||||||
| except share data) | ||||||||
|
ASSETS
|
||||||||
|
Property, plant and equipment
|
$ | 6,607,552 | $ | 6,384,396 | ||||
|
Construction in progress
|
209,242 | 157,922 | ||||||
| 6,816,794 | 6,542,318 | |||||||
|
Less accumulated depreciation and amortization
|
1,668,876 | 1,749,243 | ||||||
|
Net property, plant and equipment
|
5,147,918 | 4,793,075 | ||||||
|
Current assets
|
||||||||
|
Cash and cash equivalents
|
131,419 | 131,952 | ||||||
|
Accounts receivable, less allowance for doubtful accounts of
$7,440 in 2011 and $12,701 in 2010
|
273,303 | 273,207 | ||||||
|
Gas stored underground
|
289,760 | 319,038 | ||||||
|
Other current assets
|
316,471 | 150,995 | ||||||
|
Total current assets
|
1,010,953 | 875,192 | ||||||
|
Goodwill and intangible assets
|
740,207 | 740,148 | ||||||
|
Deferred charges and other assets
|
383,793 | 355,376 | ||||||
| $ | 7,282,871 | $ | 6,763,791 | |||||
|
CAPITALIZATION AND LIABILITIES
|
||||||||
|
Shareholders’ equity
|
||||||||
|
Common stock, no par value (stated at $.005 per share);
200,000,000 shares authorized; issued and outstanding: 2011 — 90,296,482 shares, 2010 — 90,164,103 shares |
$ | 451 | $ | 451 | ||||
|
Additional paid-in capital
|
1,732,935 | 1,714,364 | ||||||
|
Accumulated other comprehensive loss
|
(48,460 | ) | (23,372 | ) | ||||
|
Retained earnings
|
570,495 | 486,905 | ||||||
|
Shareholders’ equity
|
2,255,421 | 2,178,348 | ||||||
|
Long-term debt
|
2,206,117 | 1,809,551 | ||||||
|
Total capitalization
|
4,461,538 | 3,987,899 | ||||||
|
Commitments and contingencies
|
||||||||
|
Current liabilities
|
||||||||
|
Accounts payable and accrued liabilities
|
291,205 | 266,208 | ||||||
|
Other current liabilities
|
367,563 | 413,640 | ||||||
|
Short-term debt
|
206,396 | 126,100 | ||||||
|
Current maturities of long-term debt
|
2,434 | 360,131 | ||||||
|
Total current liabilities
|
867,598 | 1,166,079 | ||||||
|
Deferred income taxes
|
960,093 | 829,128 | ||||||
|
Regulatory cost of removal obligation
|
428,947 | 350,521 | ||||||
|
Deferred credits and other liabilities
|
564,695 | 430,164 | ||||||
| $ | 7,282,871 | $ | 6,763,791 | |||||
See accompanying notes to consolidated financial statements
67
Table of Contents
| Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands, except per share data) | ||||||||||||
|
Operating revenues
|
||||||||||||
|
Natural gas distribution segment
|
$ | 2,531,863 | $ | 2,842,638 | $ | 2,884,796 | ||||||
|
Regulated transmission and storage segment
|
219,373 | 203,013 | 209,658 | |||||||||
|
Nonregulated segment
|
2,024,893 | 2,146,658 | 2,283,988 | |||||||||
|
Intersegment eliminations
|
(428,495 | ) | (472,474 | ) | (509,331 | ) | ||||||
| 4,347,634 | 4,719,835 | 4,869,111 | ||||||||||
|
Purchased gas cost
|
||||||||||||
|
Natural gas distribution segment
|
1,487,499 | 1,820,627 | 1,887,192 | |||||||||
|
Regulated transmission and storage segment
|
— | — | — | |||||||||
|
Nonregulated segment
|
1,959,893 | 2,032,567 | 2,169,880 | |||||||||
|
Intersegment eliminations
|
(426,999 | ) | (470,864 | ) | (507,639 | ) | ||||||
| 3,020,393 | 3,382,330 | 3,549,433 | ||||||||||
|
Gross profit
|
1,327,241 | 1,337,505 | 1,319,678 | |||||||||
|
Operating expenses
|
||||||||||||
|
Operation and maintenance
|
449,290 | 460,513 | 485,704 | |||||||||
|
Depreciation and amortization
|
227,099 | 211,589 | 211,984 | |||||||||
|
Taxes, other than income
|
178,683 | 188,252 | 180,242 | |||||||||
|
Asset impairments
|
30,270 | — | 5,382 | |||||||||
|
Total operating expenses
|
885,342 | 860,354 | 883,312 | |||||||||
|
Operating income
|
441,899 | 477,151 | 436,366 | |||||||||
|
Miscellaneous income (expense), net
|
21,499 | (156 | ) | (3,067 | ) | |||||||
|
Interest charges
|
150,825 | 154,360 | 152,638 | |||||||||
|
Income from continuing operations before income taxes
|
312,573 | 322,635 | 280,661 | |||||||||
|
Income tax expense
|
113,689 | 124,362 | 97,362 | |||||||||
|
Income from continuing operations
|
198,884 | 198,273 | 183,299 | |||||||||
|
Income from discontinued operations, net of tax ($5,502, $4,425
and $2,929)
|
8,717 | 7,566 | 7,679 | |||||||||
|
Net income
|
$ | 207,601 | $ | 205,839 | $ | 190,978 | ||||||
|
Basic earnings per share
|
||||||||||||
|
Income per share from continuing operations
|
$ | 2.18 | $ | 2.14 | $ | 1.99 | ||||||
|
Income per share from discontinued operations
|
0.10 | 0.08 | 0.09 | |||||||||
|
Net income per share — basic
|
$ | 2.28 | $ | 2.22 | $ | 2.08 | ||||||
|
Diluted earnings per share
|
||||||||||||
|
Income per share from continuing operations
|
$ | 2.17 | $ | 2.12 | $ | 1.98 | ||||||
|
Income per share from discontinued operations
|
0.10 | 0.08 | 0.09 | |||||||||
|
Net income per share — diluted
|
$ | 2.27 | $ | 2.20 | $ | 2.07 | ||||||
|
Weighted average shares outstanding:
|
||||||||||||
|
Basic
|
90,201 | 91,852 | 91,117 | |||||||||
|
Diluted
|
90,652 | 92,422 | 91,620 | |||||||||
See accompanying notes to consolidated financial statements
68
Table of Contents
|
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, 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 | |||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||
|
Net income
|
— | — | — | — | 205,839 | 205,839 | ||||||||||||||||||
|
Unrealized holding gains on investments, net
|
— | — | — | 1,745 | — | 1,745 | ||||||||||||||||||
|
Treasury lock agreements, net
|
— | — | — | 2,030 | — | 2,030 | ||||||||||||||||||
|
Cash flow hedges, net
|
— | — | — | (6,963 | ) | — | (6,963 | ) | ||||||||||||||||
|
Total comprehensive income
|
202,651 | |||||||||||||||||||||||
|
Repurchase of common stock
|
(2,958,580 | ) | (15 | ) | (100,435 | ) | — | — | (100,450 | ) | ||||||||||||||
|
Repurchase of equity awards
|
(37,365 | ) | — | (1,191 | ) | — | — | (1,191 | ) | |||||||||||||||
|
Cash dividends ($1.34 per share)
|
— | — | — | — | (124,287 | ) | (124,287 | ) | ||||||||||||||||
|
Common stock issued:
|
||||||||||||||||||||||||
|
Direct stock purchase plan
|
103,529 | 1 | 2,881 | — | — | 2,882 | ||||||||||||||||||
|
Retirement savings plan
|
79,722 | — | 2,281 | — | — | 2,281 | ||||||||||||||||||
|
1998 Long-term incentive plan
|
421,706 | 2 | 8,708 | — | — | 8,710 | ||||||||||||||||||
|
Employee stock-based compensation
|
— | — | 10,894 | — | — | 10,894 | ||||||||||||||||||
|
Outside directors
stock-for-fee
plan
|
3,382 | — | 97 | — | — | 97 | ||||||||||||||||||
|
Balance, September 30, 2010
|
90,164,103 | 451 | 1,714,364 | (23,372 | ) | 486,905 | 2,178,348 | |||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||
|
Net income
|
— | — | — | — | 207,601 | 207,601 | ||||||||||||||||||
|
Unrealized holding losses on investments, net
|
— | — | — | (1,647 | ) | — | (1,647 | ) | ||||||||||||||||
|
Treasury lock agreements, net
|
— | — | — | (28,689 | ) | — | (28,689 | ) | ||||||||||||||||
|
Cash flow hedges, net
|
— | — | — | 5,248 | — | 5,248 | ||||||||||||||||||
|
Total comprehensive income
|
182,513 | |||||||||||||||||||||||
|
Repurchase of common stock
|
(375,468 | ) | (2 | ) | 2 | — | — | — | ||||||||||||||||
|
Repurchase of equity awards
|
(169,793 | ) | (1 | ) | (5,298 | ) | — | — | (5,299 | ) | ||||||||||||||
|
Cash dividends ($1.36 per share)
|
— | — | — | — | (124,011 | ) | (124,011 | ) | ||||||||||||||||
|
Common stock issued:
|
||||||||||||||||||||||||
|
Direct stock purchase plan
|
— | — | (54 | ) | — | — | (54 | ) | ||||||||||||||||
|
1998 Long-term incentive plan
|
675,255 | 3 | 13,886 | — | — | 13,889 | ||||||||||||||||||
|
Employee stock-based compensation
|
— | — | 9,958 | — | — | 9,958 | ||||||||||||||||||
|
Outside directors
stock-for-fee
plan
|
2,385 | — | 77 | — | — | 77 | ||||||||||||||||||
|
Balance, September 30, 2011
|
90,296,482 | $ | 451 | $ | 1,732,935 | $ | (48,460 | ) | $ | 570,495 | $ | 2,255,421 | ||||||||||||
See accompanying notes to consolidated financial statements
69
Table of Contents
| Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net income
|
$ | 207,601 | $ | 205,839 | $ | 190,978 | ||||||
|
Adjustments to reconcile net income to net cash provided
by operating activities:
|
||||||||||||
|
Asset impairments
|
30,270 | — | 5,382 | |||||||||
|
Depreciation and amortization:
|
||||||||||||
|
Charged to depreciation and amortization
|
233,155 | 216,960 | 217,208 | |||||||||
|
Charged to other accounts
|
228 | 173 | 94 | |||||||||
|
Deferred income taxes
|
117,353 | 196,731 | 129,759 | |||||||||
|
Stock-based compensation
|
11,586 | 12,655 | 14,494 | |||||||||
|
Debt financing costs
|
9,438 | 11,908 | 10,364 | |||||||||
|
Other
|
(961 | ) | (1,245 | ) | (1,177 | ) | ||||||
|
Changes in assets and liabilities:
|
||||||||||||
|
(Increase) decrease in accounts receivable
|
(96 | ) | (40,401 | ) | 244,713 | |||||||
|
Decrease in gas stored underground
|
27,737 | 54,014 | 194,287 | |||||||||
|
(Increase) decrease in other current assets
|
(38,048 | ) | (18,387 | ) | 117,737 | |||||||
|
(Increase) decrease in deferred charges and other assets
|
(53,519 | ) | 14,886 | (106,231 | ) | |||||||
|
Increase (decrease) in accounts payable and accrued liabilities
|
23,904 | 58,069 | (181,978 | ) | ||||||||
|
Decrease in other current liabilities
|
(57,495 | ) | (48,992 | ) | (717 | ) | ||||||
|
Increase in deferred credits and other liabilities
|
71,691 | 64,266 | 84,320 | |||||||||
|
Net cash provided by operating activities
|
582,844 | 726,476 | 919,233 | |||||||||
|
CASH FLOWS USED IN INVESTING ACTIVITIES
|
||||||||||||
|
Capital expenditures
|
(622,965 | ) | (542,636 | ) | (509,494 | ) | ||||||
|
Other, net
|
(4,421 | ) | (66 | ) | (7,707 | ) | ||||||
|
Net cash used in investing activities
|
(627,386 | ) | (542,702 | ) | (517,201 | ) | ||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Net increase (decrease) in short-term debt
|
83,306 | 54,268 | (283,981 | ) | ||||||||
|
Net proceeds from issuance of long-term debt
|
394,466 | — | 445,623 | |||||||||
|
Settlement of Treasury lock agreements
|
20,079 | — | 1,938 | |||||||||
|
Unwinding of Treasury lock agreements
|
27,803 | — | — | |||||||||
|
Repayment of long-term debt
|
(360,131 | ) | (131 | ) | (407,353 | ) | ||||||
|
Cash dividends paid
|
(124,011 | ) | (124,287 | ) | (121,460 | ) | ||||||
|
Repurchase of common stock
|
— | (100,450 | ) | — | ||||||||
|
Repurchase of equity awards
|
(5,299 | ) | (1,191 | ) | — | |||||||
|
Issuance of common stock
|
7,796 | 8,766 | 27,687 | |||||||||
|
Net cash provided by (used in) financing activities
|
44,009 | (163,025 | ) | (337,546 | ) | |||||||
|
Net increase (decrease) in cash and cash equivalents
|
(533 | ) | 20,749 | 64,486 | ||||||||
|
Cash and cash equivalents at beginning of year
|
131,952 | 111,203 | 46,717 | |||||||||
|
Cash and cash equivalents at end of year
|
$ | 131,419 | $ | 131,952 | $ | 111,203 | ||||||
See accompanying notes to consolidated financial statements
70
Table of Contents
ATMOS
ENERGY CORPORATION
| 1. | Nature of Business |
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 three 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.
In May 2011, we announced that we had entered into a definitive
agreement to sell our natural gas distribution operations in
Missouri, Illinois and Iowa, representing approximately 84,000
customers. The results of these operations have been separately
reported as discontinued operations.
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 through various wholly-owned subsidiaries of Atmos
Energy Holdings, Inc., (AEH). AEH is wholly owned by the Company
and based in Houston, Texas. Through AEH, we provide natural gas
management and transportation services to municipalities,
natural gas distribution companies, including certain divisions
of Atmos Energy and third parties.
AEH’s primary business is to deliver gas and provide
related services by aggregating and purchasing gas supply,
arranging transportation and storage logistics and ultimately
delivering gas to customers at competitive prices. In addition,
AEH utilizes proprietary and customer-owned transportation and
storage assets to provide various delivered gas 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. AEH also
seeks to maximize, through asset optimization activities, the
economic value associated with 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.
71
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 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;
however, we have not eliminated intercompany profits when such
amounts are probable of recovery under the affiliates’ rate
regulation process.
Basis of comparison
— Certain prior-year
amounts have been reclassified to conform with the current year
presentation.
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
Table of Contents
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, 2011 and 2010 included
the following:
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Regulatory assets:
|
||||||||
|
Pension and postretirement benefit costs
|
$ | 254,666 | $ | 209,564 | ||||
|
Merger and integration costs, net
|
6,242 | 6,714 | ||||||
|
Deferred gas costs
|
33,976 | 22,701 | ||||||
|
Regulatory cost of removal asset
|
8,852 | 31,014 | ||||||
|
Environmental costs
|
385 | 805 | ||||||
|
Rate case costs
|
4,862 | 4,505 | ||||||
|
Deferred franchise fees
|
379 | 1,161 | ||||||
|
Other
|
3,534 | 1,046 | ||||||
| $ | 312,896 | $ | 277,510 | |||||
|
Regulatory liabilities:
|
||||||||
|
Deferred gas costs
|
$ | 8,130 | $ | 43,333 | ||||
|
Regulatory cost of removal obligation
|
464,025 | 381,474 | ||||||
|
Other
|
14,025 | 6,112 | ||||||
| $ | 486,180 | $ | 430,919 | |||||
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,
2011, 2010 and 2009, we recognized $0.5 million,
$0.4 million and $0.4 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 company’s
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 distribution
segment’s gas costs. The effects of these purchased gas
cost adjustment mechanisms are recorded as deferred gas costs on
our balance sheet.
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ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Operating revenues for our nonregulated 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 nonregulated 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, 2011, 2010 and 2009,
we included unrealized gains (losses) on open contracts of
$(10.4) million, $(7.8) million and
$(35.9) million as a component of nonregulated revenues.
Operating revenues for our regulated transmission and storage
and nonregulated 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 substantially all 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 customer’s inability or reluctance to
pay, we record an allowance for doubtful accounts against
amounts due to reduce the net receivable balance to the amount
we reasonably expect to collect. However, if circumstances
change, our estimate of the recoverability of accounts
receivable could be 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 nonregulated
segment 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 nonregulated segment utilizes 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
$1.7 million, $3.9 million and $4.9 million was
capitalized in 2011, 2010 and 2009.
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.
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
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ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
expenses less salvage, are charged to the regulatory cost of
removal accrual. The composite depreciation rate was
3.6 percent, 3.5 percent and 3.8 percent for the
fiscal years ended September 30, 2011, 2010 and 2009.
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 50 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, 2011 and 2010, we recorded asset
retirement obligations of $14.0 million and
$11.4 million. Additionally, we recorded $5.4 million
and $3.8 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 facilities. However, we have not recognized an asset
retirement obligation associated with our storage facilities
because we are not able to determine the settlement date of this
obligation as we do not anticipate taking our storage facilities
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 asset’s carrying value over its fair
value is recorded.
During fiscal 2011, we recorded pretax noncash impairment losses
of $19.3 million related to our Fort Necessity storage
project and $11.0 million related to our gathering system,
as discussed in Note 5.
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 unit’s 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 asset’s carrying
value over its fair value is recorded. No impairment has been
recognized.
Marketable securities
— As of
September 30, 2011 and 2010, 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 fund’s 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.
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ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 then 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 to our regulated and nonregulated businesses.
Currently, we utilize financial instruments in our natural gas
distribution and nonregulated 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 on our natural gas distribution segment as a
result of the use of financial instruments.
In our nonregulated segment, we have designated most of the
natural gas inventory held by this operating segment 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. 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 nonregulated 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
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 is referred to as timing ineffectiveness.
In our nonregulated 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. As of September 30, 2011 and 2010,
the Company netted $28.8 million and $24.9 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. In fiscal 2011
and 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 cash flow hedges 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.
Hedge ineffectiveness to the extent incurred is reported as a
component of interest expense.
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 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.
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ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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. Adverse developments
in the last few years in the global financial and credit markets
have periodically 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.
Any further 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
— Represents 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. The Level 1 measurements for investments in our
Master Trust, Supplemental Executive Benefit Plan and
postretirement benefit plan consist primarily of exchange-traded
financial instruments.
Level 2
— Represents 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 and municipal and corporate bonds where market
data for pricing is observable. The Level 2 measurements
for investments in our Master Trust, Supplemental Executive
Benefit Plan and postretirement benefit plan consist primarily
of non-exchange traded financial instruments such as common
collective trusts and investments in limited partnerships.
Level 3
— Represents 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. Our Master Trust has investments in real
estate that qualify as Level 3 fair value measurements.
Currently, we have no other 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 demographic and
actuarial mortality data. Through fiscal 2008, we reviewed the
estimates and assumptions
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 9. 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.
In August 2010, the Board of Directors of Atmos Energy approved
a proposal to close the Pension Account Plan (PAP) to new
participants, effective October 1, 2010. Employees
participating in the PAP as of October 1, 2010 were allowed
to make a one-time election to migrate from the PAP into our
defined contribution plan which was enhanced, effective
January 1, 2011. Participants who chose to remain in the
PAP will continue to earn benefits and interest allocations with
no changes to their existing benefits.
The discount rate is utilized principally in calculating the
actuarial present value of our pension and postretirement
obligation and net pension and postretirement cost. When
establishing our discount rate, we consider high quality
corporate bond rates based on bonds available in the marketplace
that are suitable for settling the obligations, changes in those
rates from the prior year and the implied discount rate that is
derived from matching our projected benefit disbursements with
currently available high quality corporate bonds.
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 year’s 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.
The market-related value of our plan assets represents the fair
market value of the plan assets, adjusted to smooth out
short-term market fluctuations over a five-year period. The use
of this calculation will delay the impact of current market
fluctuations on the pension expense for the period.
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
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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,
performance-based restricted stock units and stock units to
officers, division presidents and other key employees.
Non-employee directors are also eligible to receive stock-based
compensation under the 1998 Long-Term Incentive Plan. The
objectives of this plan include attracting and retaining the
best personnel, providing for additional performance incentives
and promoting our success by providing employees with the
opportunity to acquire our common stock.
Accumulated other comprehensive loss
— Accumulated other comprehensive loss, net of
tax, as of September 30, 2011 and 2010, consisted of the
following unrealized gains (losses):
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Unrealized holding gains on investments
|
$ | 2,558 | $ | 4,205 | ||||
|
Treasury lock agreements
|
(34,157 | ) | (5,468 | ) | ||||
|
Cash flow hedges
|
(16,861 | ) | (22,109 | ) | ||||
| $ | (48,460 | ) | $ | (23,372 | ) | |||
Subsequent events —
We have evaluated
subsequent events from the September 30, 2011 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
— During the
year ended September 30, 2011, two new accounting standards
became applicable to the Company pertaining to goodwill
impairment testing for reporting units with zero or negative
carrying amounts and disclosure of supplementary pro forma
information for business combinations. The adoption of these
standards had no impact on our financial position, results of
operations or cash flows. There were no other significant
changes to our accounting policies during the year ended
September 30, 2011.
For interim and annual periods beginning after December 15,
2011, three new accounting pronouncements will become applicable
to the Company including guidance that will change certain fair
value measurement principles and enhances the disclosure
requirements particularly for Level 3 fair value
measurements, guidance related to the presentation of other
comprehensive income which will require that all nonowner
changes in shareholders’ equity be presented either in a
single continuous statement of comprehensive income or in two
separate but consecutive statements and new guidance related to
goodwill impairment testing that will permit an entity to first
assess qualitative factors to determine whether it is more
likely than not that the fair value of a reporting unit is less
than its carrying amount as a basis for determining whether it
is necessary to perform the traditional two-step goodwill
impairment test. The adoption of these standards should not
impact our financial position, results of operations or cash
flows.
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 3. | Goodwill and Intangible Assets |
Goodwill and intangible assets were comprised of the following
as of September 30, 2011 and 2010:
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Goodwill
|
$ | 740,000 | $ | 739,314 | ||||
|
Intangible assets
|
207 | 834 | ||||||
|
Total
|
$ | 740,207 | $ | 740,148 | ||||
The following presents our goodwill balance allocated by segment
and changes in the balance for the fiscal year ended
September 30, 2011:
|
Regulated
|
||||||||||||||||
|
Natural Gas
|
Transmission
|
|||||||||||||||
| Distribution | and Storage | Nonregulated | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Balance as of September 30, 2010
|
$ | 572,262 | $ | 132,341 | $ | 34,711 | $ | 739,314 | ||||||||
|
Deferred tax adjustments on prior
acquisitions
(1)
|
646 | 40 | — | 686 | ||||||||||||
|
Balance as of September 30, 2011
|
$ | 572,908 | $ | 132,381 | $ | 34,711 | $ | 740,000 | ||||||||
| (1) | During the preparation of the fiscal 2011 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 $0.7 million. |
Information regarding our intangible assets is reflected in the
following table. As of September 30, 2011 and 2010, we had
no intangible assets with indefinite lives.
| September 30, 2011 | September 30, 2010 | |||||||||||||||||||||||||||
|
Useful
|
Gross
|
Gross
|
||||||||||||||||||||||||||
|
Life
|
Carrying
|
Accumulated
|
Carrying
|
Accumulated
|
||||||||||||||||||||||||
| (Years) | Amount | Amortization | Net | Amount | Amortization | Net | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||
|
Customer contracts
|
10 | $ | 6,926 | $ | (6,719 | ) | $ | 207 | $ | 6,926 | $ | (6,092 | ) | $ | 834 | |||||||||||||
The following table presents actual amortization expense
recognized during 2011 and an estimate of future amortization
expense based upon our intangible assets at September 30,
2011.
|
Amortization expense (in thousands):
|
||||
|
Actual for the fiscal year ending September 30, 2011
|
$ | 627 | ||
|
Estimated for the fiscal year ending:
|
||||
|
September 30, 2012
|
$ | 43 | ||
|
September 30, 2013
|
43 | |||
|
September 30, 2014
|
43 | |||
|
September 30, 2015
|
43 | |||
|
September 30, 2016
|
35 |
| 4. | Financial Instruments |
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
81
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
instruments have been tailored to our regulated and nonregulated
businesses. Currently, we utilize financial instruments in our
natural gas distribution and nonregulated segments. We currently
do not manage commodity price risk with financial instruments in
our regulated transmission and storage segment.
Our financial instruments do not contain any credit-risk-related
or other contingent features that could cause accelerated
payments when our financial instruments are in net liability
positions.
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 underlying financial instrument. The
following table shows the fair values of our risk management
assets and liabilities by segment at September 30, 2011 and
2010:
|
Natural Gas
|
||||||||||||
| Distribution | Nonregulated | Total | ||||||||||
| (In thousands) | ||||||||||||
|
September 30,
2011
(3)
|
||||||||||||
|
Assets from risk management activities,
current
(1)
|
$ | 843 | $ | 17,501 | $ | 18,344 | ||||||
|
Assets from risk management activities, noncurrent
|
998 | — | 998 | |||||||||
|
Liabilities from risk management activities,
current
(1)
|
(11,916 | ) | (3,537 | ) | (15,453 | ) | ||||||
|
Liabilities from risk management activities, noncurrent
|
(67,862 | ) | (10,227 | ) | (78,089 | ) | ||||||
|
Net assets (liabilities)
|
$ | (77,937 | ) | $ | 3,737 | $ | (74,200 | ) | ||||
|
September 30, 2010
|
||||||||||||
|
Assets from risk management activities,
current
(2)
|
$ | 2,219 | $ | 18,356 | $ | 20,575 | ||||||
|
Assets from risk management activities, noncurrent
|
47 | 890 | 937 | |||||||||
|
Liabilities from risk management activities,
current
(2)
|
(48,942 | ) | (731 | ) | (49,673 | ) | ||||||
|
Liabilities from risk management activities, noncurrent
|
(2,924 | ) | (6,000 | ) | (8,924 | ) | ||||||
|
Net assets (liabilities)
|
$ | (49,600 | ) | $ | 12,515 | $ | (37,085 | ) | ||||
| (1) | Includes $28.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $12.4 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.4 million is classified as current risk management assets. | |
| (2) | Includes $24.9 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $12.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $12.3 million is classified as current risk management assets. | |
| (3) | The September 30, 2011 amounts are presented net of assets and liabilities held for sale in conjunction with the sale of our Iowa, Illinois and Missouri operations. At September 30, 2011, assets and liabilities held for sale included $1.3 million of current liabilities from risk management activities. |
Regulated
Commodity Risk Management Activities
Although our purchased gas cost adjustment mechanisms
essentially insulate our natural gas distribution segment from
commodity price risk, our customers are exposed to the effects
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 segment’s 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
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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
2010-2011
heating season (generally October through March), in the
jurisdictions where we are permitted to utilize financial
instruments, we hedged approximately 35 percent, or
31.7 Bcf of the winter flowing gas requirements at a
weighted average cost of approximately $5.81 per Mcf. We have
not designated these financial instruments as hedges.
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 applicable authoritative accounting guidance.
Accordingly, there is no earnings impact on our natural gas
distribution segment as a result of the use of financial
instruments.
Nonregulated
Commodity Risk Management Activities
In our nonregulated operations, we aggregate and purchase gas
supply, arrange transportation
and/or
storage logistics and ultimately deliver gas to our customers at
competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers’ request.
We also perform asset optimization activities in our
nonregulated 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 should 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 segment is
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 nonregulated operations associated
with deliveries under fixed-priced forward contracts to deliver
gas to customers. These financial instruments have maturity
dates ranging from one to 62 months. We use financial
instruments, designated as fair value hedges, to hedge our
natural gas inventory used in our asset optimization activities
in our nonregulated segment.
Also, in nonregulated operations, 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.
83
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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. A risk
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 in order 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. Our operations 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, 2011,
our nonregulated segment had net open positions (including
existing storage and related financial contracts) of
0.1 Bcf.
Interest
Rate Risk Management Activities
We periodically manage interest rate risk by entering into
Treasury lock agreements to fix the Treasury yield component of
the interest cost associated with anticipated financings.
We intend to refinance our $250 million unsecured
5.125% Senior Notes that mature in January 2013 through the
issuance of $350 million
30-year
unsecured notes. In August 2011, we entered into three Treasury
lock agreements to fix the Treasury yield component of the
interest cost associated with the anticipated issuances of these
senior notes. We designated all of these Treasury locks as cash
flow hedges.
In September 2010, we entered into three Treasury lock
agreements to fix the Treasury yield component of the interest
cost associated with $300 million of a total
$400 million of senior notes that were issued in June 2011.
This offering is discussed in Note 7. We designated these
Treasury locks as cash flow hedges. The Treasury locks were
settled on June 7, 2011 with the receipt of
$20.1 million from the counterparties due to an increase in
the
30-year
Treasury lock rates between inception of the Treasury locks and
settlement. Because the Treasury locks were effective, the net
$12.6 million unrealized gain was recorded as a component
of accumulated other comprehensive income and will be recognized
as a component of interest expense over the
30-year
life
of the senior notes.
Additionally, our original fiscal 2011 financing plans included
the issuance of $250 million of
30-year
unsecured notes in November 2011 to fund our capital expenditure
program. In September 2010, we entered into two Treasury lock
agreements to fix the Treasury yield component of the interest
cost associated with the anticipated issuance of these senior
notes, which were designated as cash flow hedges. Due primarily
to stronger than anticipated cash flows primarily resulting from
the extension of the Bush tax cuts that allow the continued use
of bonus depreciation on qualifying expenditures through
December 31, 2011, the need to issue $250 million of
debt in November was eliminated and the related Treasury lock
agreements were unwound in March 2011. As a result of unwinding
these Treasury locks, we recognized a pre-tax cash gain of
$27.8 million during the second quarter of fiscal 2011.
In prior years, we entered into several Treasury lock agreements
to fix the Treasury yield component of the interest cost of
financing for various issuances of long-term debt and senior
notes. The gains and losses realized upon settlement of these
Treasury locks were recorded as a component of accumulated other
comprehensive income (loss) when they were settled and are being
recognized as a component of interest
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
expense over the life of the associated notes from the date of
settlement. The remaining amortization periods for the settled
Treasury locks extends through fiscal 2041.
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, 2011, 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, 2011, we had net long/(short) commodity
contracts outstanding in the following quantities:
|
Hedge
|
Natural Gas
|
|||||||||
| Contract Type | Designation | Distribution | Nonregulated | |||||||
| Quantity (MMcf) | ||||||||||
|
Commodity contracts
|
Fair Value | — | (13,950 | ) | ||||||
| Cash Flow | — | 38,713 | ||||||||
| Not designated | 26,977 | 31,648 | ||||||||
| 26,977 | 56,411 | |||||||||
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, 2011 and 2010. 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 $28.8 million and $24.9 million
of cash held on deposit in margin accounts as of
September 30, 2011 and 2010 to collateralize certain
financial instruments. Therefore, these gross balances are not
indicative of either our actual credit exposure or net economic
exposure. Additionally, the amounts below will not be equal
85
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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
|
||||||||||||||
|
Gas
|
||||||||||||||
|
Balance Sheet Location
|
Distribution | Nonregulated | Total | |||||||||||
| (In thousands) | ||||||||||||||
|
September 30, 2011
|
||||||||||||||
|
Designated As Hedges:
|
||||||||||||||
|
Asset Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current assets | $ | — | $ | 22,396 | $ | 22,396 | |||||||
|
Noncurrent commodity contracts
|
Deferred charges and other assets | — | 174 | 174 | ||||||||||
|
Liability Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current liabilities | — | (31,064 | ) | (31,064 | ) | ||||||||
|
Noncurrent commodity contracts
|
Deferred credits and other liabilities | (67,527 | ) | (7,709 | ) | (75,236 | ) | |||||||
|
Total
|
(67,527 | ) | (16,203 | ) | (83,730 | ) | ||||||||
|
Not Designated As Hedges:
|
||||||||||||||
|
Asset Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current assets | 843 | 67,710 | 68,553 | ||||||||||
|
Noncurrent commodity contracts
|
Deferred charges and other assets | 998 | 22,379 | 23,377 | ||||||||||
|
Liability Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current liabilities (1) | (13,256 | ) | (73,865 | ) | (87,121 | ) | |||||||
|
Noncurrent commodity contracts
|
Deferred credits and other liabilities | (335 | ) | (25,071 | ) | (25,406 | ) | |||||||
|
Total
|
(11,750 | ) | (8,847 | ) | (20,597 | ) | ||||||||
|
Total Financial Instruments
|
$ | (79,277 | ) | $ | (25,050 | ) | $ | (104,327 | ) | |||||
| (1) | Other current liabilities not designated as hedges in our natural gas distribution segment include $1.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2011. |
86
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ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
|
Natural
|
||||||||||||||
|
Gas
|
||||||||||||||
|
Balance Sheet Location
|
Distribution | Nonregulated | Total | |||||||||||
| (In thousands) | ||||||||||||||
|
September 30, 2010
|
||||||||||||||
|
Designated As Hedges:
|
||||||||||||||
|
Asset Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current assets | $ | — | $ | 40,030 | $ | 40,030 | |||||||
|
Noncurrent commodity contracts
|
Deferred charges and other assets | — | 2,461 | 2,461 | ||||||||||
|
Liability Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current liabilities | — | (56,575 | ) | (56,575 | ) | ||||||||
|
Noncurrent commodity contracts
|
Deferred credits and other liabilities | — | (9,222 | ) | (9,222 | ) | ||||||||
|
Total
|
— | (23,306 | ) | (23,306 | ) | |||||||||
|
Not Designated As Hedges:
|
||||||||||||||
|
Asset Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current assets | 2,219 | 16,459 | 18,678 | ||||||||||
|
Noncurrent commodity contracts
|
Deferred charges and other assets | 47 | 2,056 | 2,103 | ||||||||||
|
Liability Financial Instruments
|
||||||||||||||
|
Current commodity contracts
|
Other current liabilities | (48,942 | ) | (7,178 | ) | (56,120 | ) | |||||||
|
Noncurrent commodity contracts
|
Deferred credits and other liabilities | (2,924 | ) | (405 | ) | (3,329 | ) | |||||||
|
Total
|
(49,600 | ) | 10,932 | (38,668 | ) | |||||||||
|
Total Financial Instruments
|
$ | (49,600 | ) | $ | (12,374 | ) | $ | (61,974 | ) | |||||
Impact of
Financial Instruments on the Income Statement
Hedge ineffectiveness for our nonregulated segment 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, 2011, 2010 and
2009 we recognized a gain arising from fair value and cash flow
hedge ineffectiveness of $24.8 million, $51.8 million
and $6.4 million. Additional information regarding
ineffectiveness recognized in the income statement is included
in the tables below.
87
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Fair
Value Hedges
The impact of our nonregulated commodity contracts designated as
fair value hedges and the related hedged item on our
consolidated income statement for the years ended
September 30, 2011, 2010 and 2009 is presented below.
| Fiscal Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Commodity contracts
|
$ | 16,552 | $ | 34,650 | $ | 45,120 | ||||||
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
9,824 | 19,867 | (28,831 | ) | ||||||||
|
Total impact on revenue
|
$ | 26,376 | $ | 54,517 | $ | 16,289 | ||||||
|
The impact on revenue is comprised of the following:
|
||||||||||||
|
Basis ineffectiveness
|
$ | 803 | $ | (1,272 | ) | $ | 5,958 | |||||
|
Timing ineffectiveness
|
25,573 | 55,789 | 10,331 | |||||||||
| $ | 26,376 | $ | 54,517 | $ | 16,289 | |||||||
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.
Cash
Flow Hedges
The impact of cash flow hedges on our consolidated income
statements for the years ended September 30, 2011, 2010 and
2009 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, 2011 | ||||||||||||||||
|
Natural
|
Regulated
|
|||||||||||||||
|
Gas
|
Transmission
|
|||||||||||||||
| Distribution | and Storage | Nonregulated | Consolidated | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Loss reclassified from AOCI into revenue for effective portion
of commodity contracts
|
$ | — | $ | — | $ | (28,430 | ) | $ | (28,430 | ) | ||||||
|
Loss arising from ineffective portion of commodity contracts
|
— | — | (1,585 | ) | (1,585 | ) | ||||||||||
|
Total impact on revenue
|
— | — | (30,015 | ) | (30,015 | ) | ||||||||||
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
(2,455 | ) | — | — | (2,455 | ) | ||||||||||
|
Gain on unwinding of Treasury lock reclassified from AOCI into
miscellaneous income
|
21,803 | 6,000 | — | 27,803 | ||||||||||||
|
Total impact from cash flow hedges
|
$ | 19,348 | $ | 6,000 | $ | (30,015 | ) | $ | (4,667 | ) | ||||||
88
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Fiscal Year Ended September 30, 2010 | ||||||||||||||||
|
Natural
|
Regulated
|
|||||||||||||||
|
Gas
|
Transmission
|
|||||||||||||||
| Distribution | and Storage | Nonregulated | Consolidated | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Loss reclassified from AOCI into revenue for effective portion
of commodity contracts
|
$ | — | $ | — | $ | (44,809 | ) | $ | (44,809 | ) | ||||||
|
Loss arising from ineffective portion of commodity contracts
|
— | — | (2,717 | ) | (2,717 | ) | ||||||||||
|
Total impact on revenue
|
— | — | (47,526 | ) | (47,526 | ) | ||||||||||
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
(2,678 | ) | — | — | (2,678 | ) | ||||||||||
|
Total impact from cash flow hedges
|
$ | (2,678 | ) | $ | — | $ | (47,526 | ) | $ | (50,204 | ) | |||||
| Fiscal Year Ended September 30, 2009 | ||||||||||||||||
|
Natural
|
Regulated
|
|||||||||||||||
|
Gas
|
Transmission
|
|||||||||||||||
| Distribution | and Storage | Nonregulated | Consolidated | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Loss reclassified from AOCI into revenue for effective portion
of commodity contracts
|
$ | — | $ | — | $ | (136,540 | ) | $ | (136,540 | ) | ||||||
|
Loss arising from ineffective portion of commodity contracts
|
— | — | (9,888 | ) | (9,888 | ) | ||||||||||
|
Total impact on revenue
|
— | — | (146,428 | ) | (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 | ) | $ | — | $ | (146,428 | ) | $ | (150,498 | ) | |||||
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 years
ended September 30, 2011 and 2010. 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 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Increase (decrease) in fair value:
|
||||||||
|
Treasury lock agreements
|
$ | (12,720 | ) | $ | 343 | |||
|
Forward commodity contracts
|
(12,096 | ) | (34,296 | ) | ||||
|
Recognition of (gains) losses in earnings due to
settlements:
|
||||||||
|
Treasury lock agreements
|
(15,969 | ) | 1,687 | |||||
|
Forward commodity contracts
|
17,344 | 27,333 | ||||||
|
Total other comprehensive loss from hedging, net of
tax
(1)
|
$ | (23,441 | ) | $ | (4,933 | ) | ||
| (1) | Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction. |
89
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Deferred gains (losses) recorded in AOCI associated with our
Treasury lock agreements are recognized in earnings as they are
amortized, while deferred losses associated with commodity
contracts are recognized in earnings upon settlement. The
following amounts, net of deferred taxes, represent the expected
recognition in earnings of the deferred gains (losses) recorded
in AOCI associated with our financial instruments, based upon
the fair values of these financial instruments as of
September 30, 2011. However, the table below does not
include the expected recognition in earnings of the Treasury
lock agreements entered into in August 2011 as those financial
instruments have not yet settled.
|
Treasury
|
||||||||||||
|
Lock
|
Commodity
|
|||||||||||
| Agreements | Contracts | Total | ||||||||||
| (In thousands) | ||||||||||||
|
2012
|
$ | (1,266 | ) | $ | (12,160 | ) | $ | (13,426 | ) | |||
|
2013
|
(1,266 | ) | (3,214 | ) | (4,480 | ) | ||||||
|
2014
|
(1,266 | ) | (1,461 | ) | (2,727 | ) | ||||||
|
2015
|
601 | (29 | ) | 572 | ||||||||
|
2016
|
770 | 3 | 773 | |||||||||
|
Thereafter
|
10,812 | — | 10,812 | |||||||||
|
Total
(1)
|
$ | 8,385 | $ | (16,861 | ) | $ | (8,476 | ) | ||||
| (1) | Utilizing an income tax rate ranging from 37 percent to 39 percent based on 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 years ended September 30, 2011, 2010 and 2009 was an
increase (decrease) in revenue of $(1.4) million,
$15.4 million and $36.9 million. 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 on 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 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.
| 5. | 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
record cash and cash equivalents, accounts receivable and
accounts payable at carrying value, which substantially
approximates fair value due to the short-term nature of these
assets and liabilities. For other financial assets and
liabilities, we primarily use quoted market prices and other
observable market pricing information to minimize the use of
unobservable pricing inputs in our measurements when determining
fair value. The methods used to determine fair value for our
assets and liabilities are fully described in Note 2.
90
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Fair value measurements also apply to the valuation of our
pension and post-retirement plan assets. The fair value of these
assets is presented in Note 9 below.
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 tables summarize, by level within the fair value
hierarchy, our assets and liabilities that were accounted for at
fair value on a recurring basis as of September 30, 2011
and 2010. 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) (1) | (Level 3) | Collateral (2) | 2011 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||
|
Financial instruments
|
||||||||||||||||||||
|
Natural gas distribution segment
|
$ | — | $ | 1,841 | $ | — | $ | — | $ | 1,841 | ||||||||||
|
Nonregulated segment
|
15,262 | 97,396 | — | (95,156 | ) | 17,502 | ||||||||||||||
|
Total financial instruments
|
15,262 | 99,237 | — | (95,156 | ) | 19,343 | ||||||||||||||
|
Hedged portion of gas stored underground
|
47,940 | — | — | — | 47,940 | |||||||||||||||
|
Available-for-sale
securities
|
||||||||||||||||||||
|
Money market funds
|
— | 1,823 | — | — | 1,823 | |||||||||||||||
|
Registered investment companies
|
36,444 | — | — | — | 36,444 | |||||||||||||||
|
Bonds
|
— | 14,366 | — | — | 14,366 | |||||||||||||||
|
Total
available-for-sale
securities
|
36,444 | 16,189 | — | — | 52,633 | |||||||||||||||
|
Total assets
|
$ | 99,646 | $ | 115,426 | $ | — | $ | (95,156 | ) | $ | 119,916 | |||||||||
|
Liabilities:
|
||||||||||||||||||||
|
Financial instruments
|
||||||||||||||||||||
|
Natural gas distribution segment
|
$ | — | $ | 81,118 | $ | — | $ | — | $ | 81,118 | ||||||||||
|
Nonregulated segment
|
22,091 | 115,617 | — | (123,943 | ) | 13,765 | ||||||||||||||
|
Total liabilities
|
$ | 22,091 | $ | 196,735 | $ | — | $ | (123,943 | ) | $ | 94,883 | |||||||||
91
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
|
Quoted
|
Significant
|
Significant
|
||||||||||||||||||
|
Prices in
|
Other
|
Other
|
Netting
|
|||||||||||||||||
|
Active
|
Observable
|
Unobservable
|
and
|
|||||||||||||||||
|
Markets
|
Inputs
|
Inputs
|
Cash
|
September 30,
|
||||||||||||||||
| (Level 1) | (Level 2) (1) | (Level 3) | Collateral (3) | 2010 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||
|
Financial instruments
|
||||||||||||||||||||
|
Natural gas distribution segment
|
$ | — | $ | 2,266 | $ | — | $ | — | $ | 2,266 | ||||||||||
|
Nonregulated segment
|
18,544 | 42,462 | — | (41,760 | ) | 19,246 | ||||||||||||||
|
Total financial instruments
|
18,544 | 44,728 | — | (41,760 | ) | 21,512 | ||||||||||||||
|
Hedged portion of gas stored underground
|
57,507 | — | — | — | 57,507 | |||||||||||||||
|
Available-for-sale
securities
|
||||||||||||||||||||
|
Money market funds
|
— | 499 | — | — | 499 | |||||||||||||||
|
Registered investment companies
|
40,967 | — | — | — | 40,967 | |||||||||||||||
|
Total
available-for-sale
securities
|
40,967 | 499 | — | — | 41,466 | |||||||||||||||
|
Total assets
|
$ | 117,018 | $ | 45,227 | $ | — | $ | (41,760 | ) | $ | 120,485 | |||||||||
|
Liabilities:
|
||||||||||||||||||||
|
Financial instruments
|
||||||||||||||||||||
|
Natural gas distribution segment
|
$ | — | $ | 51,866 | $ | — | $ | — | $ | 51,866 | ||||||||||
|
Nonregulated segment
|
41,430 | 31,950 | — | (66,649 | ) | 6,731 | ||||||||||||||
|
Total liabilities
|
$ | 41,430 | $ | 83,816 | $ | — | $ | (66,649 | ) | $ | 58,597 | |||||||||
| (1) | 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. The fair values for these assets and liabilities are determined using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences. This level also includes municipal and corporate bonds where market data for pricing is observable. | |
| (2) | 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, 2011 we had $28.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.4 million was used to offset current risk management liabilities under master netting agreements and the remaining $16.4 million is classified as current risk management assets. | |
| (3) | 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, 2010 we had $24.9 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.6 million was used to offset current risk management liabilities under master netting agreements and the remaining $12.3 million is classified as current risk management assets. |
92
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Available-for-sale
securities are comprised of the following:
|
Gross
|
Gross
|
|||||||||||||||
|
Amortized
|
Unrealized
|
Unrealized
|
Fair
|
|||||||||||||
| Cost | Gain | Loss | Value | |||||||||||||
| (In thousands) | ||||||||||||||||
|
As of September 30, 2011:
|
||||||||||||||||
|
Domestic equity mutual funds
|
$ | 27,748 | $ | 4,074 | $ | — | $ | 31,822 | ||||||||
|
Foreign equity mutual funds
|
4,597 | 267 | (242 | ) | 4,622 | |||||||||||
|
Bonds
|
14,390 | 10 | (34 | ) | 14,366 | |||||||||||
|
Money market funds
|
1,823 | — | — | 1,823 | ||||||||||||
| $ | 48,558 | $ | 4,351 | $ | (276 | ) | $ | 52,633 | ||||||||
|
As of September 30, 2010:
|
||||||||||||||||
|
Domestic equity mutual funds
|
$ | 29,540 | $ | 5,698 | $ | — | $ | 35,238 | ||||||||
|
Foreign equity mutual funds
|
4,753 | 976 | — | 5,729 | ||||||||||||
|
Money market funds
|
499 | — | — | 499 | ||||||||||||
| $ | 34,792 | $ | 6,674 | $ | — | $ | 41,466 | |||||||||
At September 30, 2011 and 2010, our
available-for-sale
securities included $38.3 million and $41.5 million
related to assets held in separate rabbi trusts for our
supplemental executive benefit plans as discussed in
Note 9. At September 30, 2011 we maintained
investments in bonds that have contractual maturity dates
ranging from January 2012 through January 2016.
We maintained an investment in one foreign equity mutual fund
with a fair value of $2.3 million in an unrealized loss
position of $0.2 million as of September 30, 2011.
This fund has been in an unrealized loss position for less than
twelve months. Because this fund is only used to fund the
supplemental plans, we evaluate investment performance over a
long-term horizon. Based upon our intent and ability to hold
this investment, our ability to direct the source of the
payments in order to maximize the life of the portfolio, the
short-term nature of the decline in fair value and the fact that
this fund continues to receive good ratings from mutual fund
rating companies, we do not consider this impairment to be
other-than-temporary
as of September 30, 2011. We also maintained several bonds
with a cumulative fair value of $9.9 million in an
unrealized loss position of less than $0.1 million as of
September 30, 2011. These bonds have been in an unrealized
loss position for less than twelve months. Based upon our intent
and ability to hold these investments, our ability to direct the
source of the payments in order to maximize the life of the
portfolio, the short-term nature of the decline in fair value
and the fact that these bonds are investment-grade, we do not
consider this impairment to be
other-than-temporary
as of September 30, 2011.
At September 30, 2010, we did not maintain any investments
that were in an unrealized loss position. In fiscal 2009, we
recorded a $5.4 million noncash charge to impair certain
available-for sale investments during the year ended
September 30, 2009 due to the conditions of the financial
markets at that time.
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. 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.
93
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Atmos Gathering Company (AGC) owns and operates the Park City
and Shrewsbury gathering systems in Kentucky. The Park City
gathering system consists of a
23-mile
low
pressure pipeline and a nitrogen removal unit that was
constructed in 2008. The Shrewsbury production, gathering and
processing assets were acquired in 2008 at which time we sold
the production assets to a third party. As a result of the sale
of the production assets, we obtained a
10-year
production payment note under which we were to be paid from
future production generated from the assets.
As discussed in Note 13, AGC is involved in an ongoing
lawsuit with the Park City gathering system. Due to the lawsuit
and a low natural gas price environment, the assets have
generated operating losses. As a result of these developments,
we performed an impairment assessment of these assets during the
third fiscal quarter and determined the assets to be impaired.
We reduced the carrying value of the assets to their estimated
fair value of approximately $6 million and recorded a
pre-tax noncash impairment loss of approximately
$11 million. We used a combination of a market and income
approach in a weighted average discounted cash flow analysis
that included significant inputs such as our weighted average
cost of capital and assumptions regarding future natural gas
prices. This is a Level 3 fair value measurement because
the inputs used are unobservable. Based on this analysis, we
determined the assets to be impaired.
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. In March 2010, we
entered into an option and acquisition agreement with a third
party, which provided the third party with the exclusive option
to develop the proposed Fort Necessity salt-dome natural
gas storage project. In July 2010, we agreed with the third
party to extend the option period to March 2011. In January
2011, the third party developer notified us that it did not plan
to commence the activities required to allow it to exercise the
option by March 2011; accordingly, the option was terminated. We
evaluated our strategic alternatives and concluded the
project’s returns did not meet our investment objectives.
Accordingly, in March 2011, we recorded a $19.3 million
pretax noncash impairment loss to write off substantially all of
our investment in the project.
Our debt is recorded at carrying value. 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, 2011:
| September 30, 2011 | ||||
| (In thousands) | ||||
|
Carrying Amount
|
$ | 2,212,565 | ||
|
Fair Value
|
$ | 2,560,945 | ||
| 6. | Discontinued Operations |
On May 12, 2011, we entered into a definitive agreement to
sell all of our natural gas distribution assets located in
Missouri, Illinois and Iowa to Liberty Energy (Midstates)
Corporation, an affiliate of Algonquin Power &
Utilities Corp. for a cash price of approximately
$124 million. The agreement contains terms and conditions
customary for transactions of this type, including typical
adjustments to the purchase price at closing, if applicable. The
closing of the transaction is subject to the satisfaction of
customary conditions including the receipt of applicable
regulatory approvals.
As required under generally accepted accounting principles, the
operating results of our Missouri, Illinois and Iowa operations
have been aggregated and reported on the consolidated statements
of income as income from discontinued operations, net of income
tax. Expenses related to general corporate overhead and interest
expense allocated to their operations are not included in
discontinued operations.
The tables below set forth selected financial and operational
information related to net assets and operating results related
to discontinued operations. Additionally, assets and liabilities
related to our Missouri, Illinois and Iowa operations are
classified as “held for sale” in other current assets
and liabilities in our
94
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
consolidated balance sheets at September 30, 2011. Prior
period revenues and expenses associated with these assets have
been reclassified into discontinued operations. This
reclassification had no impact on previously reported net income.
The following table presents statement of income data related to
discontinued operations.
| Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Operating revenues
|
$ | 80,028 | $ | 69,855 | $ | 99,969 | ||||||
|
Purchased gas cost
|
48,759 | 42,419 | 72,945 | |||||||||
|
Gross profit
|
31,269 | 27,436 | 27,024 | |||||||||
|
Operating expenses
|
16,854 | 15,151 | 15,988 | |||||||||
|
Operating income
|
14,415 | 12,285 | 11,036 | |||||||||
|
Other nonoperating expense
|
(196 | ) | (294 | ) | (428 | ) | ||||||
|
Income from discontinued operations before income taxes
|
14,219 | 11,991 | 10,608 | |||||||||
|
Income tax expense
|
5,502 | 4,425 | 2,929 | |||||||||
|
Net income
|
$ | 8,717 | $ | 7,566 | $ | 7,679 | ||||||
The following table presents balance sheet data related to
assets held for sale.
| September 30, 2011 | ||||
| (In thousands) | ||||
|
Net plant, property & equipment
|
$ | 127,577 | ||
|
Gas stored underground
|
11,931 | |||
|
Other current assets
|
786 | |||
|
Deferred charges and other assets
|
277 | |||
|
Assets held for sale
|
$ | 140,571 | ||
|
Accounts payable and accrued liabilities
|
$ | 1,917 | ||
|
Other current liabilities
|
4,877 | |||
|
Regulatory cost of removal
|
10,498 | |||
|
Deferred credits and other liabilities
|
1,153 | |||
|
Liabilities held for sale
|
$ | 18,445 | ||
95
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 7. | Debt |
Long-term debt at September 30, 2011 and 2010 consisted of
the following:
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Unsecured 7.375% Senior Notes, redeemed May 2011
|
$ | — | $ | 350,000 | ||||
|
Unsecured 10% Notes, due December 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 | 450,000 | ||||||
|
Unsecured 5.95% Senior Notes, due 2034
|
200,000 | 200,000 | ||||||
|
Unsecured 5.50% Senior Notes, due 2041
|
400,000 | — | ||||||
|
Medium term notes
|
||||||||
|
Series A,
1995-2,
6.27%, redeemed December 2010
|
— | 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 term notes due in installments through 2013
|
262 | 393 | ||||||
|
Total long-term debt
|
2,212,565 | 2,172,696 | ||||||
|
Less:
|
||||||||
|
Original issue discount on unsecured senior notes and debentures
|
(4,014 | ) | (3,014 | ) | ||||
|
Current maturities
|
(2,434 | ) | (360,131 | ) | ||||
| $ | 2,206,117 | $ | 1,809,551 | |||||
As noted above, our unsecured 10% notes will mature in
December 2011; accordingly, these have been classified within
the current maturities of long-term debt.
Our $350 million 7.375% senior notes were paid on
their maturity date on May 15, 2011, using commercial paper
borrowings. We replaced these senior notes on June 10, 2011
with $400 million 5.50% senior notes. The effective
interest rate on these notes is 5.381 percent, after giving
effect to offering costs and the settlement of the
$300 million Treasury locks discussed in Note 4.
Substantially all of the net proceeds of approximately
$394 million was used to repay $350 million of
outstanding commercial paper. The remainder of the net proceeds
was 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 could significantly affect our
borrowing requirements. Our short-term borrowings typically
reach their highest levels in the winter months.
Prior to the third quarter of fiscal 2011, we financed 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
provided approximately $1.0 billion of working capital
funding. On April 13, 2011, our $200 million
180-day
unsecured credit facility expired and was not replaced. On
May 2, 2011, we replaced our $566.7 million unsecured
credit facility with a new five-year $750 million unsecured
credit
96
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
facility with an accordion feature that could increase our
borrowing capacity to $1.0 billion. On September 30,
2011, we renewed our
364-day
revolving line of credit facility used to backstop letters of
credit for our regulated operations and increased the borrowing
capacity from $6.25 million to $10 million. As a
result of these changes, we have $985 million of working
capital funding from our commercial paper program and four
committed revolving credit facilities with third-party lenders.
At September 30, 2011 and 2010, there was
$206.4 million and $126.1 million outstanding under
our commercial paper program. As of September 30, 2011 our
commercial paper had maturities of less than one week with
interest rates of 0.29 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
our commercial paper program and three committed revolving
credit facilities with third-party lenders that provide
approximately $785 million of working capital funding. The
first facility is a five-year $750 million unsecured
facility, expiring May 2016, that bears interest at a base rate
or at a LIBOR-based rate for the applicable interest period,
plus a spread ranging from zero percent to 2 percent, based
on the Company’s credit ratings. This credit facility
serves as a backup liquidity facility for our commercial paper
program. At September 30, 2011, there were no borrowings
under this facility, but we had $206.4 million of
commercial paper outstanding leaving $543.6 million
available.
The second facility is a $25 million unsecured facility
that bears interest at a daily negotiated rate, generally based
on the Federal Funds rate plus a variable margin. At
September 30, 2011, there were no borrowings outstanding
under this facility.
The third facility is a $10 million revolving credit
facility used primarily to issue letters of credit that bears
interest at a LIBOR-based rate. At September 30, 2011,
there were no borrowings outstanding under this credit facility;
however, letters of credit totaling $5.9 million had been
issued under the facility at September 30, 2011, which
reduced the amount available by a corresponding amount.
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, 2011, our
total-debt-to-total-capitalization ratio, as defined, was
54 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 $350 million intercompany revolving
credit facility with AEH. This facility 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 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 our use of this
facility through December 31, 2011. There was
$181.3 million outstanding under this facility at
September 30, 2011.
Nonregulated
Operations
Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH,
has a three-year $200 million committed revolving credit
facility with a syndicate of third-party lenders with an
accordion feature that could
97
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
increase AEM’s borrowing capacity to $500 million. The
credit facility is primarily used to issue letters of credit
and, on a less frequent basis, to borrow funds for gas purchases
and other working capital needs.
At AEM’s 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 three-month interest period) as in effect from time
to time; or (d) the “cost of funds” rate which is
the cost of funds as reasonably determined by 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; or (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 1.875 percent
to 2.25 percent per annum, depending on the excess tangible
net worth of AEM, as defined in the credit facility. This
facility has swing line loan features, which allow AEM to
borrow, on a same day basis, an amount ranging from
$6 million to $30 million based on the terms of an
election within the agreement. This facility is collateralized
by substantially all of the assets of AEM and is guaranteed by
AEH.
At September 30, 2011, there were no borrowings outstanding
under this credit facility. However, at September 30, 2011,
AEM letters of credit totaling $20.2 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 $129.8 million at September 30, 2011.
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, 2011,
AEM’s ratio of total liabilities to tangible net worth, as
defined, was 1.33 to 1. Additionally, AEM must maintain minimum
levels of net working capital and net worth ranging from
$20 million to $40 million. As defined in the
financial covenants, at September 30, 2011, AEM’s net
working capital was $131.8 million and its tangible net
worth was $144.5 million.
To supplement borrowings under this facility, AEH has a
$350 million intercompany demand credit facility with AEC,
which bears interest at a rate equal to the greater of
(i) the one-month LIBOR rate plus 3.00 percent or
(ii) the rate for AEM’s offshore borrowings under its
committed credit facility plus 0.75 percent. Applicable
state regulatory commissions have approved our use of this
facility through December 31, 2011. There were no
borrowings outstanding under this facility at September 30,
2011.
Shelf
Registration
We have an effective shelf registration statement with the
Securities and Exchange Commission (SEC) that permits us to
issue a total of $1.3 billion in common stock
and/or
debt
securities. The shelf registration statement has been approved
by all requisite state regulatory commissions. Due to certain
restrictions imposed by one state regulatory commission on our
ability to issue securities under the new registration
statement, we were able to issue a total of $950 million in
debt securities and $350 million in equity securities prior
to our $400 million senior notes offering in June 2011. At
September 30, 2011, $900 million remains available for
issuance. Of this amount, $550 million is available for the
issuance of debt securities and $350 million remains
available for the issuance of equity securities under the shelf
until March 2013.
Debt
Covenants
In addition to the financial covenants described above, our
credit facilities and public indentures contain usual and
customary covenants for our business, including covenants
substantially limiting liens, substantial asset sales and
mergers.
98
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, AEM’s 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, AEM’s 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 Moody’s
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, 2011. 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.
Maturities of long-term debt at September 30, 2011 were as
follows (in thousands):
|
2012
|
$ | 2,434 | ||
|
2013
|
250,131 | |||
|
2014
|
— | |||
|
2015
|
500,000 | |||
|
2016
|
— | |||
|
Thereafter
|
1,460,000 | |||
| $ | 2,212,565 | |||
| 8. | Stock and Other Compensation Plans |
Share
Repurchase Agreement
On, July 1, 2010, we entered into an accelerated share
repurchase agreement with Goldman Sachs & Co. under
which we repurchased $100 million of our outstanding common
stock in order to offset stock grants made under our various
employee and director incentive compensation plans. We paid
$100 million to Goldman Sachs & Co. on
July 7, 2010 in a share forward transaction and received
2,958,580 shares of Atmos Energy common stock. On
March 4, 2011, we received and retired an additional
375,468 common shares which concluded our share repurchase
agreement. In total, we received and retired 3,334,048 common
shares under the repurchase agreement. The final number of
shares we ultimately repurchased in the transaction was based
generally on the average of the effective share repurchase price
of our common stock over the duration of the agreement, which
was $29.99. As a result of this transaction, beginning in our
fourth quarter of fiscal 2010, the number of outstanding shares
used to calculate our earnings per share was reduced by the
number of shares received and the $100 million purchase
price was recorded as a reduction in shareholders’ equity.
Share
Repurchase Program
On September 28, 2011 our Board of Directors approved a new
program authorizing the repurchase of up to five million shares
of common stock over a five-year period. Although the program is
authorized for a five-year period, it may be terminated or
limited at any time. Shares may be repurchased in the open
market or in privately negotiated transactions in amounts the
company deems appropriate. The program is primarily intended to
minimize the dilutive effect of equity grants under various
benefit related incentive compensation plans of the company.
99
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Stock-Based
Compensation Plans
Total stock-based compensation expense was $11.6 million,
$12.7 million and $14.5 million for the fiscal years
ended September 30, 2011, 2010 and 2009, 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.
As of September 30, 2011, 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. In
February 2011, shareholders voted to increase the number of
authorized LTIP shares by 2.2 million shares. On
October 19, 2011, we received all required state regulatory
approvals to increase the maximum number of authorized LTIP
shares to 8.7 million shares, subject to certain adjustment
provisions. On October 28, 2011, we filed with the SEC a
registration statement on
Form S-8
to register an additional 2.2 million shares; we also
listed such shares with the New York Stock Exchange. As of
September 30, 2011, 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 319,700 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 units 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 fair value of the awards granted is
based on the market price of our stock at the date of grant. The
associated expense is recognized ratably over the vesting period.
Employees who are granted shares of time-lapse restricted stock
under our LTIP have a nonforfeitable right to dividends that are
paid at the same rate at which they are paid on shares of stock
without restrictions. In addition, employees who are granted
shares of time-lapse restricted stock units under our LTIP have
a nonforfeitable right to dividend equivalents that are paid at
the same rate at which they are paid on shares of stock without
restrictions. Both time-lapse restricted stock and time-lapse
restricted stock units contain only a service condition that the
employee recipients render continuous services to the Company
for a period of three years from the date of grant, except for
accelerated vesting in the event of death, disability, change of
control of the Company or termination without cause (with
certain exceptions). There are no performance conditions
required to be met for employees to be vested in either the
time-lapse restricted stock or time-lapse restricted stock units.
Employees who are granted shares of performance-based restricted
stock units under our LTIP have a forfeitable right to dividends
that accrue at the same rate at which they are paid on shares of
stock without
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
restrictions. Dividends on the performance-based restricted
stock units are paid in the form of shares upon the vesting of
the award. Performance-based restricted stock units contain a
service condition that the employee recipients render continuous
services to the Company for a period of three years from the
date of grant, except for accelerated vesting in the event of
death, disability, change of control of the Company or
termination without cause (with certain exceptions) and a
performance condition based on a cumulative earnings per share
target amount.
The following summarizes information regarding the restricted
stock issued under the plan during the fiscal years ended
September 30, 2011, 2010 and 2009:
| 2011 | 2010 | 2009 | ||||||||||||||||||||||
|
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
|
1,293,960 | $ | 27.28 | 1,295,841 | $ | 27.23 | 1,096,770 | $ | 29.04 | |||||||||||||||
|
Granted
|
491,345 | 33.10 | 551,278 | 29.07 | 711,909 | 25.76 | ||||||||||||||||||
|
Vested
|
(464,321 | ) | 27.21 | (493,957 | ) | 29.24 | (499,267 | ) | 29.05 | |||||||||||||||
|
Forfeited
|
(56,842 | ) | 27.56 | (59,202 | ) | 26.54 | (13,571 | ) | 28.92 | |||||||||||||||
|
Nonvested at end of year
|
1,264,142 | $ | 29.56 | 1,293,960 | $ | 27.28 | 1,295,841 | $ | 27.23 | |||||||||||||||
As of September 30, 2011, there was $18.0 million of
total unrecognized compensation cost related to nonvested
time-lapse restricted shares and restricted stock units 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, 2011, 2010 and 2009 was $12.6 million,
$14.4 million and $14.5 million.
Stock
Option Plan
A summary of stock option activity under the LTIP follows:
| 2011 | 2010 | 2009 | ||||||||||||||||||||||
|
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
|
434,962 | $ | 22.46 | 611,227 | $ | 21.88 | 913,841 | $ | 22.54 | |||||||||||||||
|
Granted
|
— | — | — | — | — | — | ||||||||||||||||||
|
Exercised
|
(348,196 | ) | 22.54 | (176,265 | ) | 20.44 | (130,965 | ) | 21.99 | |||||||||||||||
|
Forfeited
|
— | — | — | — | — | — | ||||||||||||||||||
|
Expired
|
— | — | — | — | (171,649 | ) | 25.31 | |||||||||||||||||
|
Outstanding at end of
year
(1)
|
86,766 | $ | 22.16 | 434,962 | $ | 22.46 | 611,227 | $ | 21.88 | |||||||||||||||
|
Exercisable at end of
year
(2)
|
86,766 | $ | 22.16 | 434,962 | $ | 22.46 | 611,227 | $ | 21.88 | |||||||||||||||
| (1) | The weighted-average remaining contractual life for outstanding options was 1.7 years, 1.6 years, and 2.4 years for fiscal years 2011, 2010 and 2009. The aggregate intrinsic value of outstanding options was $0.3 million, $1.6 million and $2.1 million for fiscal years 2011, 2010 and 2009. | |
| (2) | The weighted-average remaining contractual life for exercisable options was 1.7 years, 1.6 years and 2.4 years for fiscal years 2011, 2010 and 2009. The aggregate intrinsic value of exercisable options was $0.3 million, $1.6 million and $2.1 million for the fiscal years 2011, 2010 and 2009. |
101
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Information about outstanding and exercisable options under the
LTIP, as of September 30, 2011, 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 | |||||||||
|
$21.23 to $22.99
|
71,064 | 1.4 | $ | 21.31 | ||||||||
|
$23.00 to $26.19
|
15,702 | 3.3 | $ | 26.00 | ||||||||
|
$21.23 to $26.19
|
86,766 | 1.7 | $ | 22.16 | ||||||||
| Fiscal Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands, except per share data) | ||||||||||||
|
Grant date weighted average fair value per share
|
$ | — | $ | — | $ | — | ||||||
|
Net cash proceeds from stock option exercises
|
$ | 7,848 | $ | 3,604 | $ | 2,880 | ||||||
|
Income tax benefit from stock option exercises
|
$ | 1,010 | $ | 547 | $ | 177 | ||||||
|
Total intrinsic value of options exercised
|
$ | 1,263 | $ | 239 | $ | 262 | ||||||
As of September 30, 2011, 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 of Directors adopted the Outside
Directors
Stock-for-Fee
Plan which was approved by our shareholders in February 1995.
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.
102
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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.
In addition, we adopted an incentive plan in October 2001 to
give the employees in our nonregulated segment an opportunity to
share in the success of the nonregulated operations. In fiscal
2010, we modified the award structure of the plan to reflect the
different performance goals of the front and back office
employees of our nonregulated operations. The front office award
structure is based on a fixed percentage of the net income of
our nonregulated operations that represents the available award
pool for eligible employees. There is no minimum or maximum
threshold for the available award pool. The back office award
structure 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.
| 9. | Retirement and Post-Retirement Employee Benefit Plans |
We have both funded and unfunded noncontributory defined benefit
plans that together cover substantially all of our employees. We
also maintain post-retirement plans that provide health care
benefits to retired employees. Finally, we sponsor defined
contribution plans which cover substantially all employees.
These plans are discussed in further detail below.
As a rate regulated entity, we generally recover our pension
costs in our rates over a period of up to 15 years. 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, 2011
|
||||||||||||||||
|
Unrecognized transition obligation
|
$ | — | $ | — | $ | 3,220 | $ | 3,220 | ||||||||
|
Unrecognized prior service cost
|
(373 | ) | — | (8,861 | ) | (9,234 | ) | |||||||||
|
Unrecognized actuarial loss
|
182,486 | 30,654 | 47,540 | 260,680 | ||||||||||||
| $ | 182,113 | $ | 30,654 | $ | 41,899 | $ | 254,666 | |||||||||
|
September 30, 2010
|
||||||||||||||||
|
Unrecognized transition obligation
|
$ | — | $ | — | $ | 4,731 | $ | 4,731 | ||||||||
|
Unrecognized prior service cost
|
(842 | ) | — | (10,311 | ) | (11,153 | ) | |||||||||
|
Unrecognized actuarial loss
|
159,539 | 30,753 | 25,694 | 215,986 | ||||||||||||
| $ | 158,697 | $ | 30,753 | $ | 20,114 | $ | 209,564 | |||||||||
103
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Defined
Benefit Plans
Employee
Pension Plans
As of September 30, 2011, 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 Energy’s 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
participant’s account at the end of each year according to
a formula based on the participant’s age, service and total
pay (excluding incentive pay).
The Plan also provides for an additional annual allocation based
upon a participant’s age as of January 1, 1999 for
those participants who were participants in the prior pension
plans. The Plan credited this additional allocation each year
through December 31, 2008. In addition, at the end of each
year, a participant’s account will be credited with
interest on the employee’s prior year account balance. A
special grandfather benefit also 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. In August 2010,
the Board of Directors of Atmos Energy approved a proposal to
close the Plan to new participants effective October 1,
2010. Additionally, employees participating in the Plan as of
October 1, 2010 were allowed to make a one-time election to
migrate from the Plan into our defined contribution plan which
was enhanced, effective January 1, 2011.
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 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 2011 and 2009, we contributed $0.9 million
and $21.0 million in cash to the Plans to achieve a desired
level of funding while maximizing the tax deductibility of this
payment. In fiscal 2010, we did not make any contributions to
our pension plans. Based upon market conditions subsequent to
September 30, 2011, the current funded position of the
plans and the new funding requirements under the PPA, we
anticipate contributing between $25 million and
$30 million to the Plans in fiscal 2012. Further, we will
consider whether an additional voluntary contribution is prudent
to maintain certain PPA funding thresholds.
We manage the Master Trust’s 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 Trust’s
assets. Finally, we strive to ensure the Master Trust’s
assets are appropriately invested to maintain an acceptable
level of risk and meet the Master Trust’s long-term asset
investment policy adopted by the Board of Directors.
104
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
To achieve these objectives, we invest the Master Trust’s
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 market’s 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, 2011 and 2010.
|
Actual Allocation
|
||||||||||
|
Targeted
|
September 30 | |||||||||
|
Security Class
|
Allocation Range | 2011 | 2010 | |||||||
|
Domestic equities
|
35%-55% | 40.4 | % | 44.1 | % | |||||
|
International equities
|
10% - 20% | 13.6 | % | 14.4 | % | |||||
|
Fixed income
|
10%-30% | 21.3 | % | 19.0 | % | |||||
|
Company stock
|
5%-15% | 13.5 | % | 11.3 | % | |||||
|
Other assets
|
5%-15% | 11.2 | % | 11.2 | % | |||||
At September 30, 2011 and 2010, the Plan held
1,169,700 shares of our common stock, which represented
13.5 percent and 11.3 percent of total Master Trust
assets. These shares generated dividend income for the Plan of
approximately $1.6 million and $1.6 million during
fiscal 2011 and 2010.
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. 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, 2011 and 2010 and
the actuarial assumptions used to determine the net periodic
pension cost for the Plans were determined as of
September 30, 2010, 2009 and 2008. These assumptions are
presented in the following table:
| Pension Liability | Pension Cost | |||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | 2009 | ||||||||||||||||
|
Discount rate
|
5.05 | % | 5.39 | % | 5.39 | % (1) | 5.52 | % | 7.57 | % | ||||||||||
|
Rate of compensation increase
|
3.50 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | ||||||||||
|
Expected return on plan assets
|
7.75 | % | 8.25 | % | 8.25 | % | 8.25 | % | 8.25 | % | ||||||||||
| (1) | The discount rate for the Pension Account Plan increased from 5.39% to 5.68% effective January 1, 2011 due to a curtailment gain recorded in the current fiscal year. |
105
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table presents the Plans’ accumulated benefit
obligation, projected benefit obligation and funded status as of
September 30, 2011 and 2010:
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Accumulated benefit obligation
|
$ | 414,489 | $ | 391,915 | ||||
|
Change in projected benefit obligation:
|
||||||||
|
Benefit obligation at beginning of year
|
$ | 407,536 | $ | 380,045 | ||||
|
Service cost
|
14,384 | 13,499 | ||||||
|
Interest cost
|
22,264 | 20,870 | ||||||
|
Actuarial loss
|
12,944 | 19,809 | ||||||
|
Benefits paid
|
(27,534 | ) | (26,687 | ) | ||||
|
Curtailments
|
(162 | ) | — | |||||
|
Benefit obligation at end of year
|
429,432 | 407,536 | ||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of year
|
301,708 | 301,146 | ||||||
|
Actual return on plan assets
|
5,154 | 27,249 | ||||||
|
Employer contributions
|
876 | — | ||||||
|
Benefits paid
|
(27,534 | ) | (26,687 | ) | ||||
|
Fair value of plan assets at end of year
|
280,204 | 301,708 | ||||||
|
Reconciliation:
|
||||||||
|
Funded status
|
(149,228 | ) | (105,828 | ) | ||||
|
Unrecognized prior service cost
|
— | — | ||||||
|
Unrecognized net loss
|
— | — | ||||||
|
Net amount recognized
|
$ | (149,228 | ) | $ | (105,828 | ) | ||
Net periodic pension cost for the Plans for fiscal 2011, 2010
and 2009 is recorded as operating expense and included the
following components:
| Fiscal Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Components of net periodic pension cost:
|
||||||||||||
|
Service cost
|
$ | 14,384 | $ | 13,499 | $ | 12,951 | ||||||
|
Interest cost
|
22,264 | 20,870 | 24,060 | |||||||||
|
Expected return on assets
|
(24,817 | ) | (25,280 | ) | (24,950 | ) | ||||||
|
Amortization of prior service cost
|
(429 | ) | (960 | ) | (946 | ) | ||||||
|
Recognized actuarial loss
|
9,498 | 9,290 | 3,742 | |||||||||
|
Curtailment gain
|
(40 | ) | — | — | ||||||||
|
Net periodic pension cost
|
$ | 20,860 | $ | 17,419 | $ | 14,857 | ||||||
The following table sets forth by level, within the fair value
hierarchy, the Master Trust’s assets at fair value as of
September 30, 2011 and 2010. As required by authoritative
accounting literature, assets are categorized in their entirety
based on the lowest level of input that is significant to the
fair value measurement. The methods used to determine fair value
for the assets held by the Master Trust are fully described in
Note 2.
106
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In addition to the assets shown below, the Master Trust had net
accounts receivable of $0.4 million and $0.1 million
at September 30, 2011 and 2010 which materially
approximates fair value due to the short-term nature of these
assets.
| Assets at Fair Value as of September 30, 2011 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Investments:
|
||||||||||||||||
|
Common stocks
|
$ | 94,336 | $ | — | $ | — | $ | 94,336 | ||||||||
|
Money market funds
|
— | 9,383 | — | 9,383 | ||||||||||||
|
Registered investment companies
|
27,236 | — | — | 27,236 | ||||||||||||
|
Common/collective trusts
|
53,309 | — | — | 53,309 | ||||||||||||
|
Government securities
|
4,946 | 18,907 | — | 23,853 | ||||||||||||
|
Corporate bonds
|
— | 33,636 | — | 33,636 | ||||||||||||
|
Limited partnerships
|
— | 37,806 | — | 37,806 | ||||||||||||
|
Real estate
|
— | — | 200 | 200 | ||||||||||||
|
Total investments at fair value
|
$ | 179,827 | $ | 99,732 | $ | 200 | $ | 279,759 | ||||||||
| Assets at Fair Value as of September 30, 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Investments:
|
||||||||||||||||
|
Common stocks
|
$ | 116,315 | $ | — | $ | — | $ | 116,315 | ||||||||
|
Money market funds
|
— | 10,013 | — | 10,013 | ||||||||||||
|
Registered investment companies
|
32,601 | — | — | 32,601 | ||||||||||||
|
Common/collective trusts
|
— | 48,920 | — | 48,920 | ||||||||||||
|
Government securities
|
5,548 | 16,296 | — | 21,844 | ||||||||||||
|
Corporate bonds
|
— | 33,987 | — | 33,987 | ||||||||||||
|
Limited partnerships
|
— | 37,691 | — | 37,691 | ||||||||||||
|
Real estate
|
— | — | 200 | 200 | ||||||||||||
|
Total investments at fair value
|
$ | 154,464 | $ | 146,907 | $ | 200 | $ | 301,571 | ||||||||
The fair value of our Level 3 real estate assets was
determined based on independent third party appraisals. There
were no changes in the fair value of the Level 3 assets
during the year ended September 30, 2011.
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 (SERP) (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.
In August 2009, the Board of Directors determined that there
would be no new participants in the SERP subsequent to
August 5, 2009, except for any corporate officers who may
be appointed to the Management Committee. The SERP is a defined
benefit arrangement which provides a benefit equal to
60 percent of
107
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
covered compensation under which benefits paid from the
underlying qualified defined benefit plan are an offset to the
benefits under the SERP. However, the Board also established a
new defined benefit supplemental executive retirement plan (the
2009 SERP), effective August 5, 2009, with each participant
being selected by the Board, with each such participant being
either (i) a corporate officer (other than such officer who
is appointed as a member of the Company’s Management
Committee), (ii) a division president or (iii) an
employee selected in the discretion of the Board. Under the 2009
SERP, a nominal account has been established for each
participant, to which the Company contributes at the end of each
calendar year an amount equal to ten percent of the total of
each participant’s base salary and cash incentive
compensation earned during each prior calendar year, beginning
December 31, 2009. The benefits vest after three years of
service and attainment of age 55 and earn interest credits
at the same annual rate as the Company’s Pension Account
Plan (currently 4.69%).
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, 2011
and 2010 and the actuarial assumptions used to determine the net
periodic pension cost for the supplemental plans were determined
as of September 30, 2010, 2009 and 2008. These assumptions
are presented in the following table:
| Pension Liability | Pension Cost | |||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | 2009 | ||||||||||||||||
|
Discount rate
|
5.05 | % | 5.39 | % | 5.39 | % | 5.52 | % | 7.57 | % | ||||||||||
|
Rate of compensation increase
|
3.50 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | ||||||||||
The following table presents the supplemental plans’
accumulated benefit obligation, projected benefit obligation and
funded status as of September 30, 2011 and 2010:
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Accumulated benefit obligation
|
$ | 104,363 | $ | 99,673 | ||||
|
Change in projected benefit obligation:
|
||||||||
|
Benefit obligation at beginning of year
|
$ | 108,919 | $ | 102,747 | ||||
|
Service cost
|
2,768 | 2,476 | ||||||
|
Interest cost
|
5,825 | 5,224 | ||||||
|
Actuarial loss
|
2,140 | 3,043 | ||||||
|
Benefits paid
|
(7,537 | ) | (4,571 | ) | ||||
|
Benefit obligation at end of year
|
112,115 | 108,919 | ||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of year
|
— | — | ||||||
|
Employer contribution
|
7,537 | 4,571 | ||||||
|
Benefits paid
|
(7,537 | ) | (4,571 | ) | ||||
|
Fair value of plan assets at end of year
|
— | — | ||||||
|
Reconciliation:
|
||||||||
|
Funded status
|
(112,115 | ) | (108,919 | ) | ||||
|
Unrecognized prior service cost
|
— | — | ||||||
|
Unrecognized net loss
|
— | — | ||||||
|
Accrued pension cost
|
$ | (112,115 | ) | $ | (108,919 | ) | ||
108
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Assets for the supplemental plans are held in separate rabbi
trusts. At September 30, 2011 and 2010, assets held in the
rabbi trusts consisted of
available-for-sale
securities of $38.3 million and $41.5 million, which
are included in our fair value disclosures in Note 5.
Net periodic pension cost for the supplemental plans for fiscal
2011, 2010 and 2009 is recorded as operating expense and
included the following components:
| Fiscal Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Components of net periodic pension cost:
|
||||||||||||
|
Service cost
|
$ | 2,768 | $ | 2,476 | $ | 1,985 | ||||||
|
Interest cost
|
5,825 | 5,224 | 6,056 | |||||||||
|
Amortization of transition asset
|
— | — | — | |||||||||
|
Amortization of prior service cost
|
— | 187 | 212 | |||||||||
|
Recognized actuarial loss
|
2,239 | 1,999 | 324 | |||||||||
|
Curtailment
|
— | — | 1,645 | |||||||||
|
Net periodic pension cost
|
$ | 10,832 | $ | 9,886 | $ | 10,222 | ||||||
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 2011 and 2010 the accumulated benefit
obligation for our supplemental plans exceeded the fair value of
plan assets.
| Supplemental Plans | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Projected Benefit Obligation
|
$ | 112,115 | $ | 108,919 | ||||
|
Accumulated Benefit Obligation
|
104,363 | 99,673 | ||||||
|
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) | ||||||||
|
2012
|
$ | 35,286 | $ | 25,116 | ||||
|
2013
|
33,109 | 6,910 | ||||||
|
2014
|
31,753 | 4,738 | ||||||
|
2015
|
30,633 | 6,862 | ||||||
|
2016
|
30,648 | 4,622 | ||||||
|
2017-2021
|
146,923 | 43,625 | ||||||
109
Table of Contents
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 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
$31.5 million to our postretirement benefits plan during
fiscal 2012.
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, 2011
and 2010.
|
Actual Allocation
|
||||||||
| September 30 | ||||||||
|
Security Class
|
2011 | 2010 | ||||||
|
Diversified investment funds
|
96.8 | % | 97.5 | % | ||||
|
Cash and cash equivalents
|
3.2 | % | 2.5 | % | ||||
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, 2011 and 2010 and the actuarial
110
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
assumptions used to determine the net periodic pension cost for
the postretirement plan were determined as of September 30,
2010, 2009 and 2008. The assumptions are presented in the
following table:
|
Postretirement
|
||||||||||||||||||||
| Liability | Postretirement Cost | |||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | 2009 | ||||||||||||||||
|
Discount rate
|
5.05 | % | 5.39 | % | 5.39 | % | 5.52 | % | 7.57 | % | ||||||||||
|
Expected return on plan assets
|
5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | ||||||||||
|
Initial trend rate
|
8.00 | % | 8.00 | % | 8.00 | % | 7.50 | % | 8.00 | % | ||||||||||
|
Ultimate trend rate
|
5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | ||||||||||
|
Ultimate trend reached in
|
2018 | 2016 | 2016 | 2015 | 2015 | |||||||||||||||
The following table presents the postretirement plan’s
benefit obligation and funded status as of September 30,
2011 and 2010:
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Change in benefit obligation:
|
||||||||
|
Benefit obligation at beginning of year
|
$ | 228,234 | $ | 209,732 | ||||
|
Service cost
|
14,403 | 13,439 | ||||||
|
Interest cost
|
12,813 | 12,071 | ||||||
|
Plan participants’ contributions
|
2,892 | 2,734 | ||||||
|
Actuarial loss
|
17,966 | 2,980 | ||||||
|
Benefits paid
|
(13,046 | ) | (12,722 | ) | ||||
|
Subsidy payments
|
432 | — | ||||||
|
Benefit obligation at end of year
|
263,694 | 228,234 | ||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of year
|
53,033 | 47,646 | ||||||
|
Actual return on plan assets
|
(1,500 | ) | 3,551 | |||||
|
Employer contributions
|
11,254 | 11,824 | ||||||
|
Plan participants’ contributions
|
2,892 | 2,734 | ||||||
|
Benefits paid
|
(13,046 | ) | (12,722 | ) | ||||
|
Subsidy payments
|
432 | — | ||||||
|
Fair value of plan assets at end of year
|
53,065 | 53,033 | ||||||
|
Reconciliation:
|
||||||||
|
Funded status
|
(210,629 | ) | (175,201 | ) | ||||
|
Unrecognized transition obligation
|
— | — | ||||||
|
Unrecognized prior service cost
|
— | — | ||||||
|
Unrecognized net loss
|
— | — | ||||||
|
Accrued postretirement cost
|
$ | (210,629 | ) | $ | (175,201 | ) | ||
111
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Net periodic postretirement cost for fiscal 2011, 2010 and 2009
is recorded as operating expense and included the components
presented below.
| Fiscal Year Ended September 30 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Components of net periodic postretirement cost:
|
||||||||||||
|
Service cost
|
$ | 14,403 | $ | 13,439 | $ | 11,786 | ||||||
|
Interest cost
|
12,813 | 12,071 | 14,080 | |||||||||
|
Expected return on assets
|
(2,727 | ) | (2,460 | ) | (2,292 | ) | ||||||
|
Amortization of transition obligation
|
1,511 | 1,511 | 1,511 | |||||||||
|
Amortization of prior service cost
|
(1,450 | ) | (1,450 | ) | — | |||||||
|
Recognized actuarial loss
|
347 | 374 | — | |||||||||
|
Net periodic postretirement cost
|
$ | 24,897 | $ | 23,485 | $ | 25,085 | ||||||
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:
|
One-Percentage
|
One-Percentage
|
|||||||
| Point Increase | Point Decrease | |||||||
| (In thousands) | ||||||||
|
Effect on total service and interest cost components
|
$ | 4,155 | $ | (3,479 | ) | |||
|
Effect on postretirement benefit obligation
|
$ | 30,159 | $ | (25,578 | ) | |||
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.
The following table sets forth by level, within the fair value
hierarchy, the Retiree Medical Plan’s assets at fair value
as of September 30, 2011 and 2010. The methods used to
determine fair value for the assets held by the Retiree Medical
Plan are fully described in Note 2.
| Assets at Fair Value as of September 30, 2011 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Investments:
|
||||||||||||||||
|
Money market funds
|
$ | — | $ | 1,707 | $ | — | $ | 1,707 | ||||||||
|
Registered investment companies
|
51,358 | — | — | 51,358 | ||||||||||||
|
Total investments at fair value
|
$ | 51,358 | $ | 1,707 | $ | — | $ | 53,065 | ||||||||
112
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Assets at Fair Value as of September 30, 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Investments:
|
||||||||||||||||
|
Money market funds
|
$ | — | $ | 1,307 | $ | — | $ | 1,307 | ||||||||
|
Registered investment companies
|
51,726 | — | — | 51,726 | ||||||||||||
|
Total investments at fair value
|
$ | 51,726 | $ | 1,307 | $ | — | $ | 53,033 | ||||||||
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) | ||||||||||||||||
|
2012
|
$ | 31,519 | $ | 3,293 | $ | — | $ | 34,812 | ||||||||
|
2013
|
13,272 | 3,895 | — | 17,167 | ||||||||||||
|
2014
|
15,271 | 4,491 | — | 19,762 | ||||||||||||
|
2015
|
16,789 | 5,026 | — | 21,815 | ||||||||||||
|
2016
|
18,333 | 5,672 | — | 24,005 | ||||||||||||
|
2017-2021
|
99,139 | 38,238 | — | 137,377 | ||||||||||||
Defined
Contribution Plans
As of September 30, 2011, 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 Holdings,
LLC 401K Profit-Sharing Plan (the AEH 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
participant’s contributions, limited to four percent of the
participant’s 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. In August 2010, the Board of Directors of
Atmos Energy approved a proposal to close the Pension Account
Plan to new participants effective October 1, 2010. New
employees participate in our defined contribution plan, which
was enhanced, effective January 1, 2011. Employees
participating in the Pension Account Plan as of October 1,
2010 were allowed to make a one-time election to migrate from
the Plan into our defined contribution plan, effective
January 1, 2011. Under the enhanced plan, participants will
receive a fixed annual contribution of four percent of eligible
earnings to their Retirement Savings Plan account. Participants
will continue to be eligible for company
113
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
matching contributions of up to four percent of their eligible
earnings and will be fully vested in the fixed annual
contribution after three years of service.
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 participant’s contribution in cash, limited to six
percent of the participant’s 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
$10.2 million, $9.8 million, and $9.3 million for
fiscal years 2011, 2010 and 2009. 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 2011, 2010 or 2009. At
September 30, 2011 and 2010, the Retirement Savings Plan
held 4.5 percent and 4.3 percent of our outstanding
common stock.
The AEH 401K Profit-Sharing Plan covers substantially all AEH
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 75 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 four percent of the
employee’s salary which vest immediately. The Company may
also make discretionary profit sharing contributions to the AEH
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 AEH 401K Profit-Sharing Plan
are expensed as incurred and amounted to $1.3 million,
$1.3 million and $1.2 million for fiscal years 2011,
2010 and 2009.
| 10. | Details of Selected Consolidated Balance Sheet Captions |
The following tables provide additional information regarding
the composition of certain of our balance sheet captions.
Accounts
receivable
Accounts receivable was comprised of the following at
September 30, 2011 and 2010:
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Billed accounts receivable
|
$ | 216,145 | $ | 223,129 | ||||
|
Unbilled revenue
|
48,006 | 47,423 | ||||||
|
Other accounts receivable
|
16,592 | 15,356 | ||||||
|
Total accounts receivable
|
280,743 | 285,908 | ||||||
|
Less: allowance for doubtful accounts
|
(7,440 | ) | (12,701 | ) | ||||
|
Net accounts receivable
|
$ | 273,303 | $ | 273,207 | ||||
114
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Other
current assets
Other current assets as of September 30, 2011 and 2010 were
comprised of the following accounts.
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Assets from risk management activities
|
$ | 18,344 | $ | 20,575 | ||||
|
Deferred gas costs
|
33,976 | 22,701 | ||||||
|
Taxes receivable
|
9,215 | 19,382 | ||||||
|
Current deferred tax asset
|
76,725 | 53,926 | ||||||
|
Prepaid expenses
|
22,499 | 24,754 | ||||||
|
Current portion of leased assets receivable
|
2,013 | 2,973 | ||||||
|
Materials and supplies
|
4,113 | 3,940 | ||||||
|
Assets held for sale
|
140,571 | — | ||||||
|
Other
|
9,015 | 2,744 | ||||||
|
Total
|
$ | 316,471 | $ | 150,995 | ||||
As discussed in Note 6, assets and liabilities related to
our Missouri, Illinois and Iowa operations are classified as
“assets held for sale” in other current assets and
liabilities in our consolidated balance sheets at
September 30, 2011.
Property,
plant and equipment
Property, plant and equipment was comprised of the following as
of September 30, 2011 and 2010:
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Production plant
|
$ | 7,412 | $ | 17,360 | ||||
|
Storage plant
|
198,422 | 193,155 | ||||||
|
Transmission plant
|
1,126,509 | 1,108,398 | ||||||
|
Distribution plant
|
4,496,263 | 4,339,277 | ||||||
|
General plant
|
737,850 | 671,953 | ||||||
|
Intangible plant
|
41,096 | 54,253 | ||||||
| 6,607,552 | 6,384,396 | |||||||
|
Construction in progress
|
209,242 | 157,922 | ||||||
| 6,816,794 | 6,542,318 | |||||||
|
Less: accumulated depreciation and amortization
|
(1,668,876 | ) | (1,749,243 | ) | ||||
|
Net property, plant and equipment
|
$ | 5,147,918 | $ | 4,793,075 | ||||
115
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Deferred
charges and other assets
Deferred charges and other assets as of September 30, 2011
and 2010 were comprised of the following accounts.
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Marketable securities
|
$ | 52,633 | $ | 41,466 | ||||
|
Regulatory assets
|
278,920 | 254,809 | ||||||
|
Deferred financing costs
|
35,149 | 35,761 | ||||||
|
Assets from risk management activities
|
998 | 937 | ||||||
|
Other
|
16,093 | 22,403 | ||||||
|
Total
|
$ | 383,793 | $ | 355,376 | ||||
Other
current liabilities
Other current liabilities as of September 30, 2011 and 2010
were comprised of the following accounts.
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Customer credit balances and deposits
|
$ | 106,743 | $ | 114,215 | ||||
|
Accrued employee costs
|
38,558 | 40,642 | ||||||
|
Deferred gas costs
|
8,130 | 43,333 | ||||||
|
Accrued interest
|
37,557 | 42,901 | ||||||
|
Liabilities from risk management activities
|
15,453 | 49,673 | ||||||
|
Taxes payable
|
57,853 | 56,616 | ||||||
|
Pension and postretirement obligations
|
33,036 | 14,815 | ||||||
|
Regulatory cost of removal accrual
|
35,078 | 30,953 | ||||||
|
Liabilities held for sale
|
18,445 | — | ||||||
|
Other
|
16,710 | 20,492 | ||||||
|
Total
|
$ | 367,563 | $ | 413,640 | ||||
Deferred
credits and other liabilities
Deferred credits and other liabilities as of September 30,
2011 and 2010 were comprised of the following accounts.
| September 30 | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Postretirement obligations
|
$ | 202,709 | $ | 167,899 | ||||
|
Retirement plan obligations
|
236,227 | 207,234 | ||||||
|
Customer advances for construction
|
13,967 | 15,466 | ||||||
|
Regulatory liabilities
|
13,823 | 6,112 | ||||||
|
Asset retirement obligation
|
13,574 | 11,432 | ||||||
|
Uncertain tax positions
|
— | 6,731 | ||||||
|
Liabilities from risk management activities
|
78,089 | 8,924 | ||||||
|
Other
|
6,306 | 6,366 | ||||||
|
Total
|
$ | 564,695 | $ | 430,164 | ||||
116
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 11. | Earnings Per Share |
Since we have non-vested share-based payments with a
nonforfeitable right to dividends or dividend equivalents
(referred to as participating securities) we are required to use
the two-class method of computing earnings per share. The
Company’s non-vested restricted stock and restricted stock
units, granted under the LTIP, for which vesting is predicated
solely on the passage of time, are considered to be
participating securities. The calculation of earnings per share
using the two-class method excludes income attributable to these
participating securities from the numerator and excludes the
dilutive impact of those shares from the denominator.
Basic and diluted earnings per share for the fiscal years ended
September 30 are calculated as follows:
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands, except per share data) | ||||||||||||
|
Basic Earnings Per Share from continuing operations
|
||||||||||||
|
Income from continuing operations
|
$ | 198,884 | $ | 198,273 | $ | 183,299 | ||||||
|
Less: Income from continuing operations allocated to
participating securities
|
2,077 | 2,029 | 1,712 | |||||||||
|
Income from continuing operations available to common
shareholders
|
$ | 196,807 | $ | 196,244 | $ | 181,587 | ||||||
|
Basic weighted average shares outstanding
|
90,201 | 91,852 | 91,117 | |||||||||
|
Income from continuing operations per share — Basic
|
$ | 2.18 | $ | 2.14 | $ | 1.99 | ||||||
|
Basic Earnings Per Share from discontinued operations
|
||||||||||||
|
Income from discontinued operations
|
$ | 8,717 | $ | 7,566 | $ | 7,679 | ||||||
|
Less: Income from discontinued operations allocated to
participating securities
|
91 | 77 | 72 | |||||||||
|
Income from discontinued operations available to common
shareholders
|
$ | 8,626 | $ | 7,489 | $ | 7,607 | ||||||
|
Basic weighted average shares outstanding
|
90,201 | 91,852 | 91,117 | |||||||||
|
Income from discontinued operations per share — Basic
|
$ | 0.10 | $ | 0.08 | $ | 0.09 | ||||||
|
Net income per share — Basic
|
$ | 2.28 | $ | 2.22 | $ | 2.08 | ||||||
117
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
|
Diluted Earnings Per Share from continuing operations
|
||||||||||||
|
Income from continuing operations available to common
shareholders
|
$ | 196,807 | $ | 196,244 | $ | 181,587 | ||||||
|
Effect of dilutive stock options and other shares
|
4 | 5 | 4 | |||||||||
|
Income from continuing operations available to common
shareholders
|
$ | 196,811 | $ | 196,249 | $ | 181,591 | ||||||
|
Basic weighted average shares outstanding
|
90,201 | 91,852 | 91,117 | |||||||||
|
Additional dilutive stock options and other shares
|
451 | 570 | 503 | |||||||||
|
Diluted weighted average shares outstanding
|
90,652 | 92,422 | 91,620 | |||||||||
|
Income from continuing operations per share — Diluted
|
$ | 2.17 | $ | 2.12 | $ | 1.98 | ||||||
|
Diluted Earnings Per Share from discontinued operations
|
||||||||||||
|
Income from discontinued operations available to common
shareholders
|
$ | 8,626 | $ | 7,489 | $ | 7,607 | ||||||
|
Effect of dilutive stock options and other shares
|
— | — | — | |||||||||
|
Income from discontinued operations available to common
shareholders
|
$ | 8,626 | $ | 7,489 | $ | 7,607 | ||||||
|
Basic weighted average shares outstanding
|
90,201 | 91,852 | 91,117 | |||||||||
|
Additional dilutive stock options and other shares
|
451 | 570 | 503 | |||||||||
|
Diluted weighted average shares outstanding
|
90,652 | 92,422 | 91,620 | |||||||||
|
Income from discontinued operations per share — Diluted
|
$ | 0.10 | $ | 0.08 | $ | 0.09 | ||||||
|
Net income per share — Diluted
|
$ | 2.27 | $ | 2.20 | $ | 2.07 | ||||||
There were no
out-of-the-money
options excluded from the computation of diluted earnings per
share for the fiscal years ended September 30, 2011 and
2010. 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.
| 12. | Income Taxes |
The components of income tax expense from continuing operations
for 2011, 2010 and 2009 were as follows:
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Current
|
||||||||||||
|
Federal
|
$ | (11,204 | ) | $ | (72,234 | ) | $ | (37,141 | ) | |||
|
State
|
6,533 | 6,179 | 8,720 | |||||||||
|
Deferred
|
||||||||||||
|
Federal
|
112,612 | 179,271 | 134,912 | |||||||||
|
State
|
5,920 | 11,429 | (8,739 | ) | ||||||||
|
Investment tax credits
|
(172 | ) | (283 | ) | (390 | ) | ||||||
| $ | 113,689 | $ | 124,362 | $ | 97,362 | |||||||
118
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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 2011, 2010 and 2009 are set forth
below:
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Tax at statutory rate of 35%
|
$ | 109,401 | $ | 112,922 | $ | 98,231 | ||||||
|
Common stock dividends deductible for tax reporting
|
(1,930 | ) | (1,785 | ) | (1,591 | ) | ||||||
|
Penalties
|
2,294 | 107 | 72 | |||||||||
|
Settlement of uncertain tax positions
|
(4,950 | ) | — | — | ||||||||
|
State taxes (net of federal benefit)
|
8,184 | 11,445 | (13 | ) | ||||||||
|
Other, net
|
690 | 1,673 | 663 | |||||||||
|
Income tax expense
|
$ | 113,689 | $ | 124,362 | $ | 97,362 | ||||||
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, 2011 and 2010 are
presented below:
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Deferred tax assets:
|
||||||||
|
Accruals not currently deductible for tax purposes
|
$ | 10,327 | $ | 9,182 | ||||
|
Customer advances
|
5,271 | 5,723 | ||||||
|
Nonqualified benefit plans
|
43,924 | 43,427 | ||||||
|
Postretirement benefits
|
62,274 | 57,386 | ||||||
|
Treasury lock agreements
|
20,060 | 3,211 | ||||||
|
Unamortized investment tax credit
|
120 | 183 | ||||||
|
Tax net operating loss and credit carryforwards
|
95,293 | 63,621 | ||||||
|
Difference between book and tax on mark to market accounting
|
8,039 | 2,159 | ||||||
|
Other, net
|
3,529 | 4,559 | ||||||
|
Total deferred tax assets
|
248,837 | 189,451 | ||||||
|
Deferred tax liabilities:
|
||||||||
|
Difference in net book value and net tax value of assets
|
(1,108,063 | ) | (940,914 | ) | ||||
|
Pension funding
|
(7,533 | ) | (14,936 | ) | ||||
|
Gas cost adjustments
|
(13,570 | ) | (6,473 | ) | ||||
|
Cost expensed for tax purposes and capitalized for book purposes
|
(3,039 | ) | (2,330 | ) | ||||
|
Total deferred tax liabilities
|
(1,132,205 | ) | (964,653 | ) | ||||
|
Net deferred tax liabilities
|
$ | (883,368 | ) | $ | (775,202 | ) | ||
|
Deferred credits for rate regulated entities
|
$ | 325 | $ | 587 | ||||
At September 30, 2011, we had $10.1 million of federal
alternative minimum tax credit carryforwards, $75.2 million
of federal net operating loss carryforwards and
$9.9 million of state net operating loss carryforwards. The
alternative minimum tax credit carryforwards do not expire. The
federal net operating loss carryforwards are available to offset
taxable income and will begin to expire in 2029. Depending on
the jurisdiction in which the state net operating loss was
generated, the state net operating loss carryforwards will begin
to expire between 2016 and 2029.
119
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At September 30, 2010, we had accrued liabilities
associated with uncertain tax positions totaling
$6.7 million. During the fiscal year ended
September 30, 2011, the IRS completed its audit of fiscal
years
2005-2007.
All uncertain tax positions were effectively settled upon
completion of the audit. As a result of the settlement, we
reduced our unrecognized tax benefits by $6.7 million in
the second quarter of fiscal 2011. Income tax expense was
reduced by $5.0 million in the second quarter due to the
realization of the tax positions which were previously
uncertain. As of September 30, 2011, we had no liabilities
associated with uncertain tax positions.
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. We recognized a tax expense of $0.01 million,
$0.5 million and $0.1 million related to penalty and
interest expenses during the fiscal years ended
September 30, 2011, 2010 and 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 2007.
| 13. | Commitments and Contingencies |
Litigation
Since April 2009, Atmos Energy and two subsidiaries of AEH, AEM
and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos
Entities), have been involved in a lawsuit filed in the Circuit
Court of Edmonson County, Kentucky related to our Park City
Gathering Project. The dispute which gave rise to the litigation
involves the amount of royalties due from a third party producer
to landowners (who own the mineral rights) for natural gas
produced from the landowners’ properties. The third party
producer was operating pursuant to leases between the landowners
and certain investors/working interest owners. The third party
producer filed a petition in bankruptcy, which was subsequently
dismissed due to the lack of meaningful assets to reorganize or
liquidate.
Although certain Atmos Energy companies entered into contracts
with the third party producer to gather, treat and ultimately
sell natural gas produced from the landowners’ properties,
no Atmos Energy company had a contractual relationship with the
landowners or the investors/working interest owners. After the
lawsuit was filed, the landowners were successful in terminating
for non-payment of royalties the leases related to the
production of natural gas from their properties. Subsequent to
termination, the investors/working interest owners under such
leases filed additional claims against us for the termination of
the leases.
During the trial, the landowners and the investors/working
interest owners requested an award of compensatory damages plus
punitive damages against us. On December 17, 2010, the jury
returned a verdict in favor of the landowners and
investor/working interest owners and awarded compensatory
damages of $3.8 million and punitive damages of
$27.5 million payable by Atmos Energy and the two AEH
subsidiaries.
A hearing was held on February 28, 2011 to hear a number of
motions, including a motion to dismiss the jury verdict and a
motion for a new trial. The motions to dismiss the jury verdict
and for a new trial were denied. However, the total punitive
damages award was reduced from $27.5 million to
$24.7 million. On March 30, 2011, we filed a notice of
appeal of this ruling. We strongly believe that the trial court
erred in not granting our motion to dismiss the lawsuit prior to
trial and that the verdict is unsupported by law. After
consultation with counsel, we believe that it is probable that
any judgment based on this verdict will be overturned on appeal.
In addition, in a related development, on July 12, 2011,
the Atmos Entities filed a lawsuit in the United States District
Court, Western District of Kentucky against the third party
producer and its affiliates to recover all costs, including
attorneys’ fees, incurred by the Atmos Entities, which are
associated with the defense and
120
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
appeal of the case discussed above as well as for all damages
awarded to the plaintiffs in such case against the Atmos
Entities. The total amount of damages being claimed in the
lawsuit is “open-ended” since the appellate process
and related costs are ongoing. This lawsuit is based upon the
indemnification provisions agreed to by the third party producer
in favor of Atmos Gathering that are contained in an agreement
entered into between Atmos Gathering and the third party
producer in May 2009.
We have accrued what we believe is an adequate amount for the
anticipated resolution of this matter; however, the amount
accrued is less than the amount of the verdict. The Company does
not have insurance coverage that could mitigate any losses that
may arise from the resolution of this matter; however, we
believe that the final outcome will not have a material adverse
effect on our financial condition, results of operations or cash
flows.
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, Tennessee, Keokuk, Iowa 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. We have taken removal actions
with respect to the sites that have been approved by the
applicable regulatory authorities in Tennessee, Iowa, 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
AEH has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At September 30, 2011, AEH was committed
to purchase 103.3 Bcf within one year, 46.4 Bcf within
one to three years and 0.9 Bcf after three years under
indexed contracts. AEH is committed to purchase 4.2 Bcf
within one year and 0.3 Bcf within one to three years under
fixed price contracts with prices ranging from $3.49 to $6.36
per Mcf. Purchases under these contracts totaled
$1,498.6 million, $1,562.8 million and
$1,484.5 million for 2011, 2010 and 2009.
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.
121
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, 2011 are as follows (in
thousands):
|
2012
|
$ | 274,985 | ||
|
2013
|
102,959 | |||
|
2014
|
82,235 | |||
|
2015
|
— | |||
|
2016
|
— | |||
|
Thereafter
|
— | |||
| $ | 460,179 | |||
Our nonregulated segment maintains 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, 2011 are as follows (in
thousands):
|
2012
|
$ | 25,362 | ||
|
2013
|
16,711 | |||
|
2014
|
9,988 | |||
|
2015
|
4,130 | |||
|
2016
|
278 | |||
|
Thereafter
|
165 | |||
| $ | 56,634 | |||
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 Commission’s posting and
competitive bidding regulations for pre-arranged released firm
capacity on natural gas pipelines.
Since that time, we have fully cooperated with FERC during this
investigation. In August 2011, the FERC issued a Notice of
Alleged Violations stating that it preliminarily determined that
Atmos Energy Corporation and its subsidiaries, Atmos Energy
Marketing, LLC (AEM) and Trans Louisiana Gas Pipeline, Inc.
(TLGP) violated Sections 284.8(h)(2) and 1c.1 of the
Commission’s regulations through flipping and AEM violated
the Commission’s shipper-must-have-title requirement and
the associated FERC gas tariffs of various pipelines.
The Company and FERC are currently involved in settlement
discussions. We have accrued what we believe is an adequate
amount for the anticipated resolution of this matter.
We have been replacing certain steel service lines in our
Mid-Tex Division since our acquisition of the natural gas
distribution system in 2004. Since early 2010, we have been
discussing the financial and operational details of an
accelerated steel service line replacement program with
representatives of 440 municipalities served by our Mid-Tex
Division. As previously discussed in Note 12 to the
consolidated financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2010, all of the
cities in our Mid-Tex Division have agreed to a program of
installing 100,000 replacements during the next fiscal year,
with approved recovery of the associated return, depreciation
and taxes. Under the terms of the agreement, the accelerated
replacement program commenced in the first quarter of fiscal
2011, replacing
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
35,852 lines for a cost of $49.7 million as of
September 30, 2011. The program is progressing on schedule
for completion in September 2012.
In July 2010, the Dodd-Frank Act was enacted, representing an
extensive overhaul of the framework for regulation of
U.S. financial markets. The Dodd-Frank Act calls for
various regulatory agencies, including the SEC and the
Commodities Futures Trading Commission, to establish regulations
for implementation of many of the provisions of the Dodd-Frank
Act, which we expect will provide additional clarity regarding
the extent of the impact of this legislation on us. The costs of
participating in financial markets for hedging certain risks
inherent in our business may be increased as a result of the new
legislation. We may also incur additional costs associated with
compliance with new regulations and anticipate additional
reporting and disclosure obligations.
| 14. | Leases |
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, 2011 and 2010, we had
receivables of $2.0 million and $7.8 million and
recognized income of $0.5 million, $0.9 million and
$1.2 million for fiscal years 2011, 2010 and 2009. The
future minimum lease payments to be received for each of the
five succeeding fiscal years are as follows:
|
Minimum
|
||||
|
Lease
|
||||
| Receipts | ||||
| (In thousands) | ||||
|
2012
|
$ | 2,013 | ||
|
Thereafter
|
— | |||
|
Total minimum lease receipts
|
$ | 2,013 | ||
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 21 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 and $1.3 million at
September 30, 2011 and 2010. Accumulated depreciation for
these capital leases totaled $0.9 and $0.8 million at
September 30, 2011 and 2010. Depreciation expense for these
assets is included in consolidated depreciation expense on the
consolidated statement of income.
123
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The related future minimum lease payments at September 30,
2011 were as follows:
|
Capital
|
Operating
|
|||||||
| Leases | Leases | |||||||
| (In thousands) | ||||||||
|
2012
|
$ | 186 | $ | 17,718 | ||||
|
2013
|
186 | 16,846 | ||||||
|
2014
|
186 | 16,519 | ||||||
|
2015
|
186 | 15,455 | ||||||
|
2016
|
186 | 14,921 | ||||||
|
Thereafter
|
264 | 118,108 | ||||||
|
Total minimum lease payments
|
1,194 | $ | 199,567 | |||||
|
Less amount representing interest
|
406 | |||||||
|
Present value of net minimum lease payments
|
$ | 788 | ||||||
Consolidated lease and rental expense amounted to
$19.1 million, $16.0 million and $13.6 million
for fiscal 2011, 2010 and 2009.
| 15. | Concentration of Credit Risk |
Credit risk is the risk of financial loss to us if a customer
fails to perform its contractual obligations. We engage in
transactions for the purchase and sale of products and services
with major companies in the energy industry and with industrial,
commercial, residential and municipal energy consumers. These
transactions principally occur in the southern and midwestern
regions of the United States. We believe that this geographic
concentration does not contribute significantly to our overall
exposure to credit risk. Credit risk associated with trade
accounts receivable for the 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 AEM’s 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 counterparty’s 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, 2011, that
our financial position, results of operations and cash flows
will not be materially affected as a result of nonperformance by
any single counterparty.
AEM’s 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 AEM’s credit
department, but are primarily based on external ratings provided
by Moody’s Investors Service Inc. (Moody’s)
and/or
Standard & Poor’s 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
124
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ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
grade. Customers who have a non-investment grade but provide
either a letter of credit or prepay their monthly invoice have
been included as investment grade. The following table shows the
percentages related to the investment ratings as of
September 30, 2011 and 2010.
| September 30, 2011 | September 30, 2010 | |||||||
|
Investment grade
|
54 | % | 58 | % | ||||
|
Non-investment grade
|
46 | % | 42 | % | ||||
|
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, 2011. Investment grade
counterparties have minimum credit ratings of BBB-, assigned by
S&P; or Baa3, assigned by Moody’s. 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
|
||||||||||||
|
Distribution
|
Nonregulated
|
|||||||||||
| Segment (1) | Segment | Consolidated | ||||||||||
| (In thousands) | ||||||||||||
|
Investment grade counterparties
|
$ | — | $ | 16 | $ | 16 | ||||||
|
Non-investment grade counterparties
|
— | 1,081 | 1,081 | |||||||||
| $ | — | $ | 1,097 | $ | 1,097 | |||||||
| (1) | Counterparty risk for our natural gas distribution segment is minimized because hedging gains and losses are passed through to our customers. |
| 16. | Supplemental Cash Flow Disclosures |
Supplemental disclosures of cash flow information for fiscal
2011, 2010 and 2009 are presented below.
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Cash paid for interest
|
$ | 157,976 | $ | 161,925 | $ | 163,554 | ||||||
|
Cash received for income taxes
|
$ | (8,329 | ) | $ | (63,677 | ) | $ | (36,405 | ) | |||
There were no significant noncash investing and financing
transactions during fiscal 2011, 2010 and 2009. All cash flows
and noncash activities related to our commodity financial
instruments are considered as operating activities.
| 17. | Segment Information |
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 three 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
125
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
and Southeast. Additionally, we provide natural gas
transportation and storage services to certain of our natural
gas distribution operations and to third parties.
Through November 30, 2010, our operations were divided into
four segments:
| • | The natural gas distribution segment , which included our regulated natural gas distribution and related sales operations. | |
| • | The regulated transmission and storage segment , which included the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division. | |
| • | The natural gas marketing segment , which included a variety of nonregulated natural gas management services. | |
| • | The pipeline, storage and other segment , which included our nonregulated natural gas gathering transmission and storage services. |
As a result of the appointment of a new CEO effective
October 1, 2010, during the first quarter of fiscal 2011,
we revised the information used by the chief operating decision
maker to manage the Company. As a result of this change,
effective December 1, 2010, we began dividing our
operations into the following three segments:
| • | The natural gas distribution segment , remains unchanged and includes our regulated natural gas distribution and related sales operations. | |
| • | The regulated transmission and storage segment , remains unchanged and includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division. | |
| • | The nonregulated segment , is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services which were previously reported in the natural gas marketing and pipeline, storage and other segments. |
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
segment’s taxes were calculated on a separate return basis.
126
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Summarized income statements and capital expenditures by segment
are shown in the following tables. Prior-year amounts have been
restated to reflect the new operating segments.
| Year Ended September 30, 2011 | ||||||||||||||||||||
|
Regulated
|
||||||||||||||||||||
|
Natural Gas
|
Transmission
|
|||||||||||||||||||
| Distribution | and Storage | Nonregulated | Eliminations | Consolidated | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Operating revenues from external parties
|
$ | 2,530,980 | $ | 87,141 | $ | 1,729,513 | $ | — | $ | 4,347,634 | ||||||||||
|
Intersegment revenues
|
883 | 132,232 | 295,380 | (428,495 | ) | — | ||||||||||||||
| 2,531,863 | 219,373 | 2,024,893 | (428,495 | ) | 4,347,634 | |||||||||||||||
|
Purchased gas cost
|
1,487,499 | — | 1,959,893 | (426,999 | ) | 3,020,393 | ||||||||||||||
|
Gross profit
|
1,044,364 | 219,373 | 65,000 | (1,496 | ) | 1,327,241 | ||||||||||||||
|
Operating expenses
|
||||||||||||||||||||
|
Operation and maintenance
|
348,083 | 70,401 | 32,308 | (1,502 | ) | 449,290 | ||||||||||||||
|
Depreciation and amortization
|
196,909 | 25,997 | 4,193 | — | 227,099 | |||||||||||||||
|
Taxes, other than income
|
161,371 | 14,700 | 2,612 | — | 178,683 | |||||||||||||||
|
Asset impairments
|
— | — | 30,270 | — | 30,270 | |||||||||||||||
|
Total operating expenses
|
706,363 | 111,098 | 69,383 | (1,502 | ) | 885,342 | ||||||||||||||
|
Operating income (loss)
|
338,001 | 108,275 | (4,383 | ) | 6 | 441,899 | ||||||||||||||
|
Miscellaneous income
|
16,557 | 4,715 | 657 | (430 | ) | 21,499 | ||||||||||||||
|
Interest charges
|
115,802 | 31,432 | 4,015 | (424 | ) | 150,825 | ||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
238,756 | 81,558 | (7,741 | ) | — | 312,573 | ||||||||||||||
|
Income tax expense (benefit)
|
84,755 | 29,143 | (209 | ) | — | 113,689 | ||||||||||||||
|
Income (loss) from continuing operations
|
154,001 | 52,415 | (7,532 | ) | — | 198,884 | ||||||||||||||
|
Income from discontinued operations, net of tax
|
8,717 | — | — | — | 8,717 | |||||||||||||||
|
Net income (loss)
|
$ | 162,718 | $ | 52,415 | $ | (7,532 | ) | $ | — | $ | 207,601 | |||||||||
|
Capital expenditures
|
$ | 496,899 | $ | 118,452 | $ | 7,614 | $ | — | $ | 622,965 | ||||||||||
127
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended September 30, 2010 | ||||||||||||||||||||
|
Regulated
|
||||||||||||||||||||
|
Natural Gas
|
Transmission
|
|||||||||||||||||||
| Distribution | and Storage | Nonregulated | Eliminations | Consolidated | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Operating revenues from external parties
|
$ | 2,841,768 | $ | 97,023 | $ | 1,781,044 | $ | — | $ | 4,719,835 | ||||||||||
|
Intersegment revenues
|
870 | 105,990 | 365,614 | (472,474 | ) | — | ||||||||||||||
| 2,842,638 | 203,013 | 2,146,658 | (472,474 | ) | 4,719,835 | |||||||||||||||
|
Purchased gas cost
|
1,820,627 | — | 2,032,567 | (470,864 | ) | 3,382,330 | ||||||||||||||
|
Gross profit
|
1,022,011 | 203,013 | 114,091 | (1,610 | ) | 1,337,505 | ||||||||||||||
|
Operating expenses
|
||||||||||||||||||||
|
Operation and maintenance
|
355,357 | 72,249 | 34,517 | (1,610 | ) | 460,513 | ||||||||||||||
|
Depreciation and amortization
|
185,147 | 21,368 | 5,074 | — | 211,589 | |||||||||||||||
|
Taxes, other than income
|
171,338 | 12,358 | 4,556 | — | 188,252 | |||||||||||||||
|
Total operating expenses
|
711,842 | 105,975 | 44,147 | (1,610 | ) | 860,354 | ||||||||||||||
|
Operating income
|
310,169 | 97,038 | 69,944 | — | 477,151 | |||||||||||||||
|
Miscellaneous income (expense)
|
1,567 | 135 | 3,859 | (5,717 | ) | (156 | ) | |||||||||||||
|
Interest charges
|
118,319 | 31,174 | 10,584 | (5,717 | ) | 154,360 | ||||||||||||||
|
Income from continuing operations before income taxes
|
193,417 | 65,999 | 63,219 | — | 322,635 | |||||||||||||||
|
Income tax expense
|
75,034 | 24,513 | 24,815 | — | 124,362 | |||||||||||||||
|
Income from continuing operations
|
118,383 | 41,486 | 38,404 | — | 198,273 | |||||||||||||||
|
Income from discontinued operations, net of tax
|
7,566 | — | — | — | 7,566 | |||||||||||||||
|
Net income
|
$ | 125,949 | $ | 41,486 | $ | 38,404 | $ | — | $ | 205,839 | ||||||||||
|
Capital expenditures
|
$ | 437,815 | $ | 95,835 | $ | 8,986 | $ | — | $ | 542,636 | ||||||||||
128
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended September 30, 2009 | ||||||||||||||||||||
|
Regulated
|
||||||||||||||||||||
|
Natural Gas
|
Transmission
|
|||||||||||||||||||
| Distribution | and Storage | Nonregulated | Eliminations | Consolidated | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Operating revenues from external parties
|
$ | 2,883,997 | $ | 119,427 | $ | 1,865,687 | $ | — | $ | 4,869,111 | ||||||||||
|
Intersegment revenues
|
799 | 90,231 | 418,301 | (509,331 | ) | — | ||||||||||||||
| 2,884,796 | 209,658 | 2,283,988 | (509,331 | ) | 4,869,111 | |||||||||||||||
|
Purchased gas cost
|
1,887,192 | — | 2,169,880 | (507,639 | ) | 3,549,433 | ||||||||||||||
|
Gross profit
|
997,604 | 209,658 | 114,108 | (1,692 | ) | 1,319,678 | ||||||||||||||
|
Operating expenses
|
||||||||||||||||||||
|
Operation and maintenance
|
361,123 | 85,249 | 41,368 | (2,036 | ) | 485,704 | ||||||||||||||
|
Depreciation and amortization
|
187,050 | 20,413 | 4,521 | — | 211,984 | |||||||||||||||
|
Taxes, other than income
|
166,854 | 10,231 | 3,157 | — | 180,242 | |||||||||||||||
|
Asset impairments
|
4,599 | 602 | 181 | — | 5,382 | |||||||||||||||
|
Total operating expenses
|
719,626 | 116,495 | 49,227 | (2,036 | ) | 883,312 | ||||||||||||||
|
Operating income
|
277,978 | 93,163 | 64,881 | 344 | 436,366 | |||||||||||||||
|
Miscellaneous income (expense)
|
6,002 | 1,433 | 6,399 | (16,901 | ) | (3,067 | ) | |||||||||||||
|
Interest charges
|
123,863 | 30,982 | 14,350 | (16,557 | ) | 152,638 | ||||||||||||||
|
Income from continuing operations before income taxes
|
160,117 | 63,614 | 56,930 | — | 280,661 | |||||||||||||||
|
Income tax expense
|
50,989 | 22,558 | 23,815 | — | 97,362 | |||||||||||||||
|
Income from continuing operations
|
109,128 | 41,056 | 33,115 | — | 183,299 | |||||||||||||||
|
Income from discontinued operations, net of tax
|
7,679 | — | — | — | 7,679 | |||||||||||||||
|
Net income
|
$ | 116,807 | $ | 41,056 | $ | 33,115 | $ | — | $ | 190,978 | ||||||||||
|
Capital expenditures
|
$ | 379,500 | $ | 108,332 | $ | 21,662 | $ | — | $ | 509,494 | ||||||||||
The following table summarizes our revenues by products and
services for the fiscal year ended September 30. Prior-year
amounts have been restated to reflect the new operating segments.
| 2011 | 2010 | 2009 | ||||||||||
| (In thousands) | ||||||||||||
|
Natural gas distribution revenues:
|
||||||||||||
|
Gas sales revenues:
|
||||||||||||
|
Residential
|
$ | 1,570,723 | $ | 1,784,051 | $ | 1,768,082 | ||||||
|
Commercial
|
698,366 | 787,433 | 807,109 | |||||||||
|
Industrial
|
106,569 | 110,280 | 132,487 | |||||||||
|
Public authority and other
|
69,176 | 70,402 | 88,972 | |||||||||
|
Total gas sales revenues
|
2,444,834 | 2,752,166 | 2,796,650 | |||||||||
|
Transportation revenues
|
59,547 | 58,511 | 56,162 | |||||||||
|
Other gas revenues
|
26,599 | 31,091 | 31,185 | |||||||||
|
Total natural gas distribution revenues
|
2,530,980 | 2,841,768 | 2,883,997 | |||||||||
|
Regulated transmission and storage revenues
|
87,141 | 97,023 | 119,427 | |||||||||
|
Nonregulated revenues
|
1,729,513 | 1,781,044 | 1,865,687 | |||||||||
|
Total operating revenues
|
$ | 4,347,634 | $ | 4,719,835 | $ | 4,869,111 | ||||||
129
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Balance sheet information at September 30, 2011 and 2010 by
segment is presented in the following tables. Prior-year amounts
have been restated to reflect the new operating segments.
| September 30, 2011 | ||||||||||||||||||||
|
Regulated
|
||||||||||||||||||||
|
Natural Gas
|
Transmission
|
|||||||||||||||||||
| Distribution | and Storage | Nonregulated | Eliminations | Consolidated | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
Property, plant and equipment, net
|
$ | 4,248,198 | $ | 838,302 | $ | 61,418 | $ | — | $ | 5,147,918 | ||||||||||
|
Investment in subsidiaries
|
670,993 | — | (2,096 | ) | (668,897 | ) | — | |||||||||||||
|
Current assets
|
||||||||||||||||||||
|
Cash and cash equivalents
|
24,646 | — | 106,773 | — | 131,419 | |||||||||||||||
|
Assets from risk management activities
|
843 | — | 17,501 | — | 18,344 | |||||||||||||||
|
Other current assets
|
655,716 | 15,413 | 386,215 | (196,154 | ) | 861,190 | ||||||||||||||
|
Intercompany receivables
|
569,898 | — | — | (569,898 | ) | — | ||||||||||||||
|
Total current assets
|
1,251,103 | 15,413 | 510,489 | (766,052 | ) | 1,010,953 | ||||||||||||||
|
Intangible assets
|
— | — | 207 | — | 207 | |||||||||||||||
|
Goodwill
|
572,908 | 132,381 | 34,711 | — | 740,000 | |||||||||||||||
|
Noncurrent assets from risk management activities
|
998 | — | — | — | 998 | |||||||||||||||
|
Deferred charges and other assets
|
353,960 | 18,028 | 10,807 | — | 382,795 | |||||||||||||||
| $ | 7,098,160 | $ | 1,004,124 | $ | 615,536 | $ | (1,434,949 | ) | $ | 7,282,871 | ||||||||||
|
CAPITALIZATION AND LIABILITIES
|
||||||||||||||||||||
|
Shareholders’ equity
|
$ | 2,255,421 | $ | 265,102 | $ | 405,891 | $ | (670,993 | ) | $ | 2,255,421 | |||||||||
|
Long-term debt
|
2,205,986 | — | 131 | — | 2,206,117 | |||||||||||||||
|
Total capitalization
|
4,461,407 | 265,102 | 406,022 | (670,993 | ) | 4,461,538 | ||||||||||||||
|
Current liabilities
|
||||||||||||||||||||
|
Current maturities of long-term debt
|
2,303 | — | 131 | — | 2,434 | |||||||||||||||
|
Short-term debt
|
387,691 | — | — | (181,295 | ) | 206,396 | ||||||||||||||
|
Liabilities from risk management activities
|
11,916 | — | 3,537 | — | 15,453 | |||||||||||||||
|
Other current liabilities
|
474,783 | 10,369 | 170,926 | (12,763 | ) | 643,315 | ||||||||||||||
|
Intercompany payables
|
— | 543,084 | 26,814 | (569,898 | ) | — | ||||||||||||||
|
Total current liabilities
|
876,693 | 553,453 | 201,408 | (763,956 | ) | 867,598 | ||||||||||||||
|
Deferred income taxes
|
789,649 | 173,351 | (2,907 | ) | — | 960,093 | ||||||||||||||
|
Noncurrent liabilities from risk management activities
|
67,862 | — | 10,227 | — | 78,089 | |||||||||||||||
|
Regulatory cost of removal obligation
|
428,947 | — | — | — | 428,947 | |||||||||||||||
|
Deferred credits and other liabilities
|
473,602 | 12,218 | 786 | — | 486,606 | |||||||||||||||
| $ | 7,098,160 | $ | 1,004,124 | $ | 615,536 | $ | (1,434,949 | ) | $ | 7,282,871 | ||||||||||
130
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ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| September 30, 2010 | ||||||||||||||||||||
|
Regulated
|
||||||||||||||||||||
|
Natural Gas
|
Transmission
|
|||||||||||||||||||
| Distribution | and Storage | Nonregulated | Eliminations | Consolidated | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
Property, plant and equipment, net
|
$ | 3,959,112 | $ | 748,947 | $ | 85,016 | $ | — | $ | 4,793,075 | ||||||||||
|
Investment in subsidiaries
|
620,863 | — | (2,096 | ) | (618,767 | ) | — | |||||||||||||
|
Current assets
|
||||||||||||||||||||
|
Cash and cash equivalents
|
31,952 | — | 100,000 | — | 131,952 | |||||||||||||||
|
Assets from risk management activities
|
2,219 | — | 18,356 | — | 20,575 | |||||||||||||||
|
Other current assets
|
528,655 | 19,504 | 325,348 | (150,842 | ) | 722,665 | ||||||||||||||
|
Intercompany receivables
|
546,313 | — | — | (546,313 | ) | — | ||||||||||||||
|
Total current assets
|
1,109,139 | 19,504 | 443,704 | (697,155 | ) | 875,192 | ||||||||||||||
|
Intangible assets
|
— | — | 834 | — | 834 | |||||||||||||||
|
Goodwill
|
572,262 | 132,341 | 34,711 | — | 739,314 | |||||||||||||||
|
Noncurrent assets from risk management activities
|
47 | — | 890 | — | 937 | |||||||||||||||
|
Deferred charges and other assets
|
324,707 | 13,037 | 16,695 | — | 354,439 | |||||||||||||||
| $ | 6,586,130 | $ | 913,829 | $ | 579,754 | $ | (1,315,922 | ) | $ | 6,763,791 | ||||||||||
|
CAPITALIZATION AND LIABILITIES
|
||||||||||||||||||||
|
Shareholders’ equity
|
$ | 2,178,348 | $ | 212,687 | $ | 408,176 | $ | (620,863 | ) | $ | 2,178,348 | |||||||||
|
Long-term debt
|
1,809,289 | — | 262 | — | 1,809,551 | |||||||||||||||
|
Total capitalization
|
3,987,637 | 212,687 | 408,438 | (620,863 | ) | 3,987,899 | ||||||||||||||
|
Current liabilities
|
||||||||||||||||||||
|
Current maturities of long-term debt
|
360,000 | — | 131 | — | 360,131 | |||||||||||||||
|
Short-term debt
|
258,488 | — | — | (132,388 | ) | 126,100 | ||||||||||||||
|
Liabilities from risk management activities
|
48,942 | — | 731 | — | 49,673 | |||||||||||||||
|
Other current liabilities
|
473,076 | 10,949 | 162,508 | (16,358 | ) | 630,175 | ||||||||||||||
|
Intercompany payables
|
— | 543,007 | 3,306 | (546,313 | ) | — | ||||||||||||||
|
Total current liabilities
|
1,140,506 | 553,956 | 166,676 | (695,059 | ) | 1,166,079 | ||||||||||||||
|
Deferred income taxes
|
691,126 | 142,337 | (4,335 | ) | — | 829,128 | ||||||||||||||
|
Noncurrent liabilities from risk management activities
|
2,924 | — | 6,000 | — | 8,924 | |||||||||||||||
|
Regulatory cost of removal obligation
|
350,521 | — | — | — | 350,521 | |||||||||||||||
|
Deferred credits and other liabilities
|
413,416 | 4,849 | 2,975 | — | 421,240 | |||||||||||||||
| $ | 6,586,130 | $ | 913,829 | $ | 579,754 | $ | (1,315,922 | ) | $ | 6,763,791 | ||||||||||
131
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 18. | Selected Quarterly Financial Data (Unaudited) |
Summarized unaudited quarterly financial data is presented
below. Prior-period amounts have been restated to reflect
continuing operations. 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
“Management’s 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 2011:
|
||||||||||||||||
|
Operating revenues
|
||||||||||||||||
|
Natural gas distribution
|
$ | 703,462 | (1) | $ | 1,077,414 | (2) | $ | 407,031 | $ | 343,956 | ||||||
|
Regulated transmission and storage
|
49,007 | 54,976 | 53,570 | 61,820 | ||||||||||||
|
Nonregulated
|
475,640 | 583,531 | 491,285 | 474,437 | ||||||||||||
|
Intersegment eliminations
|
(94,847 | ) | (134,424 | ) | (108,271 | ) | (90,953 | ) | ||||||||
| 1,133,262 | 1,581,497 | 843,615 | 789,260 | |||||||||||||
|
Gross profit
|
364,724 | (1) | 453,668 | (2) | 266,805 | 242,044 | ||||||||||
|
Operating income
|
155,289 | (1) | 211,199 | (2) | 34,078 | 41,333 | ||||||||||
|
Income (loss) from continuing operations
|
71,100 | 128,160 | (1,474 | ) | 1,098 | |||||||||||
|
Income from discontinued operations
|
2,897 | 4,049 | 908 | 863 | ||||||||||||
|
Net income (loss)
|
73,997 | 132,209 | (566 | ) | 1,961 | |||||||||||
|
Basic earnings per share
|
||||||||||||||||
|
Income (loss) per share from continuing operations
|
$ | 0.78 | $ | 1.41 | $ | (0.02 | ) | $ | 0.01 | |||||||
|
Income per share from discontinued operations
|
$ | 0.03 | $ | 0.04 | $ | 0.01 | $ | 0.01 | ||||||||
|
Net income (loss) per share — basic
|
$ | 0.81 | $ | 1.45 | $ | (0.01 | ) | $ | 0.02 | |||||||
|
Diluted earnings per share
|
||||||||||||||||
|
Income (loss) per share from continuing operations
|
$ | 0.78 | $ | 1.41 | $ | (0.02 | ) | $ | 0.01 | |||||||
|
Income per share from discontinued operations
|
$ | 0.03 | $ | 0.04 | $ | 0.01 | $ | 0.01 | ||||||||
|
Net income (loss) per share — diluted
|
$ | 0.81 | $ | 1.45 | $ | (0.01 | ) | $ | 0.02 | |||||||
132
Table of Contents
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Quarter Ended | ||||||||||||||||
| December 31 | March 31 | June 30 | September 30 | |||||||||||||
| (In thousands, except per share data) | ||||||||||||||||
|
Fiscal year 2010:
|
||||||||||||||||
|
Operating revenues
|
||||||||||||||||
|
Natural gas distribution
|
$ | 781,841 | (3) | $ | 1,333,872 | (4) | $ | 396,319 | $ | 330,606 | (5) | |||||
|
Regulated transmission and storage
|
46,860 | 55,181 | 44,957 | 56,015 | ||||||||||||
|
Nonregulated
|
548,016 | 677,032 | 427,405 | 494,205 | ||||||||||||
|
Intersegment eliminations
|
(104,918 | ) | (157,935 | ) | (107,376 | ) | (102,245 | ) | ||||||||
| 1,271,799 | 1,908,150 | 761,305 | 778,581 | |||||||||||||
|
Gross profit
|
403,003 | (3) | 445,444 | (4) | 247,666 | 241,392 | (5) | |||||||||
|
Operating income
|
186,598 | (3) | 219,757 | (4) | 32,259 | 38,537 | (5) | |||||||||
|
Income (loss) from continuing operations
|
90,975 | 111,283 | (4,229 | ) | 244 | |||||||||||
|
Income from discontinued operations
|
2,355 | 2,843 | 1,075 | 1,293 | ||||||||||||
|
Net income (loss)
|
93,330 | 114,126 | (3,154 | ) | 1,537 | |||||||||||
|
Basic earnings per share
|
||||||||||||||||
|
Income (loss) per share from continuing operations
|
$ | 0.97 | $ | 1.19 | $ | (0.04 | ) | $ | — | |||||||
|
Income per share from discontinued operations
|
$ | 0.03 | 0.03 | $ | 0.01 | $ | 0.02 | |||||||||
|
Net income (loss) per share — basic
|
$ | 1.00 | $ | 1.22 | $ | (0.03 | ) | $ | 0.02 | |||||||
|
Diluted earnings per share
|
||||||||||||||||
|
Income (loss) per share from continuing operations
|
$ | 0.97 | $ | 1.19 | $ | (0.04 | ) | $ | — | |||||||
|
Income per share from discontinued operations
|
$ | 0.03 | $ | 0.03 | $ | 0.01 | $ | 0.02 | ||||||||
|
Net income (loss) per share — diluted
|
$ | 1.00 | $ | 1.22 | $ | (0.03 | ) | $ | 0.02 | |||||||
| (1) | Operating revenues for natural gas distribution, gross profit and operating income are shown net of discontinued operations of $23.7 million, $8.8 million and $4.8 million. | |
| (2) | Operating revenues for natural gas distribution, gross profit and operating income are shown net of discontinued operations of $35.8 million, $11.2 million and $6.7 million. | |
| (3) | Operating revenues for natural gas distribution, gross profit and operating income are shown net of discontinued operations of $21.1 million, $7.8 million and $4.0 million. | |
| (4) | Operating revenues for natural gas distribution, gross profit and operating income are shown net of discontinued operations of $32.1 million, $8.9 million and $4.8 million. | |
| (5) | Operating revenues for natural gas distribution, gross profit and operating income are shown net of discontinued operations of $7.7 million, $5.2 million and $1.7 million. |
133
Table of Contents
| ITEM 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. |
None.
| ITEM 9A. | Controls and Procedures. |
Management’s
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 Company’s 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 Company’s principal
executive officer and principal financial officer have concluded
that the Company’s disclosure controls and procedures were
effective as of September 30, 2011 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 SEC’s 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.
Management’s
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, 2011, 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 Company’s internal control over
financial reporting. That report appears below.
|
/s/
KIM
R. COCKLIN
|
/s/
FRED
E.
MEISENHEIMER
|
|
| Kim R. Cocklin | Fred E. Meisenheimer | |
| President and Chief Executive Officer | Senior Vice President and | |
| Chief Financial Officer |
November 22, 2011
134
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have audited Atmos Energy Corporation’s internal control
over financial reporting as of September 30, 2011, 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
Corporation’s 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
Management’s Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the
company’s 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 company’s 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 company’s
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
company’s 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, 2011, 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, 2011 and
2010, and the related statements of income, shareholders’
equity, and cash flows for each of the three years in the period
ended September 30, 2011 of Atmos Energy Corporation and
our report dated November 22, 2011 expressed an unqualified
opinion thereon.
/s/
ERNST &
YOUNG LLP
Dallas, Texas
November 22, 2011
135
Table of Contents
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, 2011 that have materially affected, or
are reasonably likely to materially affect, our internal control
over financial reporting.
| ITEM 9B. | Other Information. |
Not applicable.
| 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 Company’s
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 8, 2012. Information regarding
executive officers is reported below:
EXECUTIVE
OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of
September 30, 2011, 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
|
64 | 14 | Executive Chairman of the Board | |||||||
|
Kim R. Cocklin
|
60 | 5 | President and Chief Executive Officer | |||||||
|
Louis P. Gregory
|
56 | 11 | Senior Vice President and General Counsel | |||||||
|
Michael E. Haefner
|
51 | 3 | Senior Vice President, Human Resources | |||||||
|
Fred E. Meisenheimer
|
67 | 11 | Senior Vice President and Chief Financial Officer | |||||||
Robert W. Best was named Executive Chairman of the Board on
October 1, 2010. From March 1997 through September 2008,
Mr. Best served the Company as Chairman of the Board,
President and Chief Executive Officer. From October 1, 2008
through September 30, 2010, Mr. Best continued to
serve the Company as Chairman of the Board and Chief Executive
Officer.
Kim R. Cocklin was named President and Chief Executive Officer
effective October 1, 2010. Mr. Cocklin joined the
Company in June 2006 and served as President and Chief Operating
Officer of the Company from October 1, 2008 through
September 30, 2010, after having served as Senior Vice
President, Regulated Operations from October 2006 through
September 2008. Mr. Cocklin was Senior Vice President,
General Counsel and Chief Compliance Officer of Piedmont Natural
Gas Company from February 2003 through May 2006.
Mr. Cocklin was appointed to the Board of Directors on
November 10, 2009.
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.
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
136
Table of Contents
May 2009, interim Chief Financial Officer in January 2009 and
Treasurer from November 2009 through February 2011.
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
Company’s Definitive Proxy Statement for the Annual Meeting
of Shareholders on February 8, 2012.
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
Company’s Code of Conduct, which is applicable to all
directors, officers and employees of the Company, including the
Company’s principal executive officer, principal financial
officer and principal accounting officer. A copy of the
Company’s Code of Conduct is posted on the Company’s
website at
www.atmosenergy.com
under “Corporate
Governance.” In addition, any amendment to or waiver
granted from a provision of the Company’s Code of Conduct
will be posted on the Company’s website under
“Corporate Governance.”
| ITEM 11. | Executive Compensation. |
Information on executive compensation is incorporated herein by
reference to the Company’s Definitive Proxy Statement for
the Annual Meeting of Shareholders on February 8, 2012.
| 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
Company’s Definitive Proxy Statement for the Annual Meeting
of Shareholders on February 8, 2012. Information concerning
our equity compensation plans is provided in Part II,
Item 5, “Market for Registrant’s 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 Company’s Definitive Proxy Statement for
the Annual Meeting of Shareholders on February 8, 2012.
| ITEM 14. | Principal Accountant Fees and Services. |
Information on our principal accountant’s fees and services
is incorporated herein by reference to the Company’s
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 8, 2012.
| ITEM 15. | Exhibits and Financial Statement Schedules. |
(a) 1.
and 2.
Financial statements and financial statement
schedules.
The financial statements and financial statement schedule listed
in the Index to Financial Statements in Item 8 are filed as
part of this
Form 10-K.
| 3. | Exhibits |
The exhibits listed in the accompanying Exhibits Index are
filed as part of this
Form 10-K.
The exhibits numbered 10.6(a) through 10.14 are management
contracts or compensatory plans or arrangements.
137
Table of Contents
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 22, 2011
138
Table of Contents
POWER OF
ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below hereby constitutes and appoints Kim R. Cocklin 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/
KIM
R. COCKLIN
|
President, Chief Executive Officer and Director | November 22, 2011 | ||||
|
/s/
FRED
E. MEISENHEIMER
|
Senior Vice President and Chief Financial Officer | November 22, 2011 | ||||
|
/s/
CHRISTOPHER
T. FORSYTHE
|
Vice President and Controller (Principal Accounting Officer) | November 22, 2011 | ||||
|
/s/
ROBERT
W. BEST
|
Executive Chairman of the Board | November 22, 2011 | ||||
|
/s/
RICHARD
W. DOUGLAS
|
Director | November 22, 2011 | ||||
|
/s/
RUBEN
E. ESQUIVEL
|
Director | November 22, 2011 | ||||
|
/s/
RICHARD
K. GORDON
|
Director | November 22, 2011 | ||||
|
/s/
ROBERT
C. GRABLE
|
Director | November 22, 2011 | ||||
|
/s/
THOMAS
C. MEREDITH
|
Director | November 22, 2011 | ||||
|
/s/
NANCY
K. QUINN
|
Director | November 22, 2011 | ||||
|
/s/
STEPHEN
R. SPRINGER
|
Director | November 22, 2011 | ||||
|
/s/
CHARLES
K. VAUGHAN
|
Director | November 22, 2011 | ||||
|
/s/
RICHARD
WARE II
|
Director | November 22, 2011 | ||||
139
Table of Contents
Schedule II
ATMOS
ENERGY CORPORATION
Three
Years Ended September 30, 2011
| Additions | ||||||||||||||||||||
|
Balance at
|
Charged to
|
Charged to
|
Balance
|
|||||||||||||||||
|
beginning
|
Cost &
|
Other
|
at End
|
|||||||||||||||||
| of period | Expenses | Accounts | Deductions | of Period | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
2011
|
||||||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 12,701 | $ | 2,201 | $ | — | $ | 7,462 | (1) | $ | 7,440 | |||||||||
|
2010
|
||||||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 11,478 | $ | 7,694 | $ | — | $ | 6,471 | (1) | $ | 12,701 | |||||||||
|
2009
|
||||||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 15,301 | $ | 7,769 | $ | — | $ | 11,592 (1 | ) | $ | 11,478 | |||||||||
| (1) | Uncollectible accounts written off. |
140
Table of Contents
EXHIBITS INDEX
Item 14.(a)(3)
Item 14.(a)(3)
|
Page Number or
|
||||||
|
Exhibit
|
Incorporation by
|
|||||
|
Number
|
Description
|
Reference to
|
||||
| Plan of Acquisition | ||||||
| 2 | .1 | Asset Purchase Agreement by and between Atmos Energy Corporation as Seller and Liberty Energy (Midstates) Corp. as Buyer, dated as of May 12, 2011 | Exhibit 2.1 to Form 8-K dated May 12, 2011 (File No. 1-10042) | |||
| Articles of Incorporation and Bylaws | ||||||
| 3 | .1 | Restated Articles of Incorporation of Atmos Energy Corporation — Texas (As Amended Effective February 3, 2010) | Exhibit 3.1 to Form 10-Q dated March 31, 2010 (File No. 1-10042) | |||
| 3 | .2 | Restated Articles of Incorporation of Atmos Energy Corporation — Virginia (As Amended Effective February 3, 2010) | Exhibit 3.2 to Form 10-Q dated March 31, 2010 (File No. 1-10042) | |||
| 3 | .3 | Amended and Restated Bylaws of Atmos Energy Corporation (as of February 3, 2010) | Exhibit 3.2 of Form 8-K dated February 3, 2010 (File No. 1-10042) | |||
| Instruments Defining Rights of Security Holders | ||||||
| 4 | .1 | Specimen Common Stock Certificate (Atmos Energy Corporation) | Exhibit 4.1 to Form 10-K for fiscal year ended September 30, 2010 (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 6 3 / 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 5 1 / 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(c) | 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(d) | 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(e) | 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(f) | 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) | |||
| 4 | .7(g) | Global Security for the 5.5% Senior Notes due 2041 | Exhibit 4.2 to Form 8-K dated June 10, 2011 (File No. 1-10042) | |||
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| 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) | |||
| 10 | .2 | Revolving Credit Agreement, dated as of May 2, 2011 among Atmos Energy Corporation, the Lenders from time to time parties thereto, The Royal Bank of Scotland plc as Administrative Agent, Crédit Agricole Corporate and Investment Bank as Syndication Agent, Bank of America, N.A., U.S. Bank National Association and Wells Fargo Bank, N.A. as Co-Documentation Agents | Exhibit 10.1 to Form 8-K dated May 2, 2011 (File No. 1-10042) | |||
| 10 | .3(a) | Fifth Amended and Restated Credit Agreement, dated as of December 8, 2010, among Atmos Energy Marketing, LLC, a Delaware limited liability company, BNP Paribas, a bank organized under the laws of France, as administrative agent, collateral agent, as an issuing bank, a swing line bank and a bank; Société Générale as co-syndication agent, an issuing bank and a bank and The Royal Bank of Scotland plc, as co-syndication agent and a bank; and Natixis, New York Branch, Crédit Agricole Corporate and Investment Bank, and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A. as co-documentation agents and the other financial institutions that become parties thereto | Exhibit 10.1 to Form 8-K dated December 8, 2010 (File No. 1-10042) | |||
| 10 | .3(b) | Third Amended and Restated Intercreditor Agreement, dated as of December 8, 2010, (as amended, supplemented and otherwise modified from time to time, the “Agreement”), among BNP Paribas, a bank organized under the laws of France, in its capacity as Collateral Agent (together with its successors and assigns in such capacity, the “Agent”) for the Banks thereinafter referred to, and each bank and other financial institution which is now or hereafter a party to the Agreement in its capacity as a Bank and, as applicable, as a Swap Bank (collectively, the “Swap Banks”) and/or a Physical Trade Bank (collectively, the “Physical Trade Banks”) | Exhibit 10.2 to Form 8-K dated December 8, 2010 (File No. 1-10042) | |||
| 10 | .4(a) | Accelerated Share Buyback Agreement with Goldman, Sachs & Co. — Master Confirmation dated July 1, 2010 | Exhibit 10.6(a) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
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| 10 | .4(b) | Accelerated Share Buyback Agreement with Goldman, Sachs & Co. — Supplemental Confirmation dated July 1, 2010 | Exhibit 10.6(b) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
| 10 | .5 | Guaranty of Algonquin Power & Utilities Corp. dated May 12, 2011 | Exhibit 10.1 to Form 8-K dated May 12, 2011 (File No. 1-10042) | |||
| Executive Compensation Plans and Arrangements | ||||||
| 10 | .6(a)* | Form of Atmos Energy Corporation Change in Control Severance Agreement — Tier I | Exhibit 10.7(a) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
| 10 | .6(b)* | Form of Atmos Energy Corporation Change in Control Severance Agreement — Tier II | Exhibit 10.7(b) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
| 10 | .7(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 | .7(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 | .8(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 | .8(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 | .9(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) | |||
| 10 | .9(b)* | Atmos Energy Corporation Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of November 12, 2009) | Exhibit 10.10(b) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
| 10 | .9(c)* | Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan, Effective Date August 5, 2009 | Exhibit 10.10(c) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
| 10 | .9(d)* | Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan Trust Agreement, Effective Date December 1, 2000 | Exhibit 10.1 to Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042) | |||
| 10 | .9(e)* | Form of Individual Trust Agreement for the Supplemental Executive Benefits Plan | Exhibit 10.3 to Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042) | |||
| 10 | .10(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 | .10(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 | .10(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 | .11* | Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, Amended and Restated as of January 1, 2010 | Exhibit 10.12 to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
| 10 | .12* | Atmos Energy Corporation Outside Directors Stock-for-Fee Plan, Amended and Restated as of October 1, 2009 | Exhibit 10.13 to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042) | |||
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| 10 | .13(a)* | Atmos Energy Corporation 1998 Long-Term Incentive Plan (as amended and restated February 10, 2011) | Exhibit 99.1 to Form S-8 dated October 28, 2011 (File No. 333-177593) | |||
| 10 | .13(b)* | Form of Non-Qualified Stock Option Agreement under the Atmos Energy Corporation 1998 Long-Term Incentive Plan | Exhibit 10.16(b) to Form 10-K for fiscal year ended September 30, 2005 (File No. 1-10042) | |||
| 10 | .13(c)* | 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 | .13(d)* | Form of Award Agreement of Time-Lapse Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan | Exhibit 99.4 to Form S-8 dated October 28, 2011 (File No. 333-177593) | |||
| 10 | .13(e)* | Form of Award Agreement of Performance-Based Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan | Exhibit 99.5 to Form S-8 dated October 28, 2011 (File No. 333-177593) | |||
| 10 | .14* | Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated February 10, 2011) | ||||
| 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, 2011 | ||||
| 31 | Rule 13a-14(a)/15d-14(a) Certifications | |||||
| 32 | Section 1350 Certifications** | |||||
| 101 | .INS | XBRL Instance Document*** | ||||
| 101 | .SCH | XBRL Taxonomy Extension Schema*** | ||||
| 101 | .CAL | XBRL Taxonomy Extension Calculation Linkbase*** | ||||
| 101 | .DEF | XBRL Taxonomy Extension Definition Linkbase*** | ||||
| 101 | .LAB | XBRL Taxonomy Extension Labels Linkbase*** | ||||
| 101 | .PRE | XBRL Taxonomy Extension Presentation Linkbase*** | ||||
| * | This exhibit constitutes a “management contract or compensatory plan, contract, or arrangement.” | |
| ** | These certifications pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as 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. | |
| *** | Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. |
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Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accountant Fees and ServicesPart IVItem 15. Exhibits and Financial Statement Schedules