10-K 1 ato0930201310-k.htm FORM 10-K ATO 09.30.2013 10-K
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, 2013
OR
¨    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    (IRS employer
incorporation or organization)    identification no.)
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas    75240
(Address of principal executive offices)    (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
Title of Each Class     on Which Registered
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  ¨
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  ¨        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  ¨
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  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.45) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨
Indicate by check 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    ¨    Non-accelerated filer    ¨    Smaller reporting company    ¨
(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  ¨        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, 2013, was $3,816,801,052.
As of November 8, 2013, the registrant had 90,912,251 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 5, 2014 are incorporated by reference into Part III of this report.



TABLE OF CONTENTS
 
 
 
 
 
 
Page
 
 
 
 
Part I
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Part II
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
Part III
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
Part IV
 
Item 15.



GLOSSARY OF KEY TERMS
 
 
AEC
Atmos Energy Corporation
AEH
Atmos Energy Holdings, Inc.
AEM
Atmos Energy Marketing, LLC
AOCI
Accumulated Other Comprehensive Income
APS
Atmos Pipeline and Storage, LLC
ATO
Trading symbol for Atmos Energy Corporation common stock on the New York Stock Exchange
Bcf
Billion cubic feet
CFTC
Commodity Futures Trading Commission
COSO
Committee of Sponsoring Organizations of the Treadway Commission
ERISA
Employee Retirement Income Security Act of 1974
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings, Ltd.
GAAP
Generally Accepted Accounting Principles
GRIP
Gas Reliability Infrastructure Program
GSRS
Gas System Reliability Surcharge
ISRS
Infrastructure System Replacement Surcharge
KPSC
Kentucky Public Service Commission
LTIP
1998 Long-Term Incentive Plan
Mcf
Thousand cubic feet
MDWQ
Maximum daily withdrawal quantity
Mid-Tex Cities
Represents 440 of the 441 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.
MMcf
Million cubic feet
Moody’s
Moody’s Investor Services, Inc.
NYMEX
New York Mercantile Exchange, Inc.
NYSE
New York Stock Exchange
PAP
Pension Account Plan
PPA
Pension Protection Act of 2006
RRC
Railroad Commission of Texas
RRM
Rate Review Mechanism
RSC
Rate Stabilization Clause
S&P
Standard & Poor’s Corporation
SEC
United States Securities and Exchange Commission
SRF
Stable Rate Filing
WNA
Weather Normalization Adjustment

3


PART I
The terms “we,” “our,” “us”, “Atmos Energy” and the “Company” refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise.
 
ITEM 1.
Business.
Overview and Strategy
Atmos Energy Corporation, headquartered in Dallas, Texas, and incorporated in Texas and Virginia, is engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as other nonregulated natural gas businesses. We deliver natural gas through regulated sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers in eight states located primarily in the South, which makes us one of the country’s largest natural-gas-only distributors based on number of customers. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.
Over the last two fiscal years, we have sold our natural gas distribution operations in four states to streamline our regulated operations. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers, and in August 2012, we completed the sale of our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers.
Through our nonregulated businesses, we provide natural gas management, marketing, transportation and storage services to municipalities, local gas distribution companies, including certain of our natural gas distribution divisions and industrial customers principally in the Midwest and Southeast.
Our overall strategy is to:
deliver superior shareholder value,
improve the quality and consistency of earnings growth, while operating our business exceptionally well
invest in our people and infrastructure
enhance our culture.
We have delivered excellent shareholder value by growing our earnings and increasing our dividends for over 25 consecutive years. Over the last five years, we have 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
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.

4


Natural Gas Distribution Segment Overview
Our natural gas distribution segment is comprised of our six regulated natural gas distribution divisions. This segment represents approximately 65 percent of our consolidated net income. The following table summarizes key information about these divisions, presented in order of total rate base. See Note 16 in the consolidated financial statements for a description of the completed sales of our Missouri, Illinois, Iowa and Georgia service areas. 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, 2013, we held 998 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.
Division
 
Service Areas
 
Communities Served
 
Customer Meters
Mid-Tex
 
Texas, including the Dallas/Fort Worth Metroplex
 
550
 
1,560,409
Kentucky/Mid-States
 
Kentucky
 
230
 
179,708
 
 
Tennessee
 
 
 
123,590
 
 
Virginia
 
 
 
20,358
Louisiana
 
Louisiana
 
300
 
342,187
West Texas
 
Amarillo, Lubbock, Midland
 
80
 
293,802
Mississippi
 
Mississippi
 
110
 
255,730
Colorado-Kansas
 
Colorado
 
170
 
99,654
 
 
Kansas
 
 
 
136,542
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. Historically, this generally has resulted 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. However, rate design changes implemented during the first quarter of fiscal 2013 in our Mid-Tex and West Texas Divisions should change this trend. The rate design approved in these regulatory proceedings includes an increase to the customer base charge and a decrease in the consumption charge applied to customer usage. The effect of this change in rate design allows our rates to be more closely aligned with the natural gas distribution industry standard rate design. In addition, we anticipate these divisions, which represent approximately 50 percent of the operating income for our natural gas distribution segment, will earn their operating income more ratably over the fiscal year as they are now less dependent on customer consumption.
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. 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 distribution 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 distribution companies 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.


5


Regulatory authorities have approved weather normalization adjustments (WNA) for approximately 97 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 the effect of lower gas usage when weather is warmer than normal and decrease customers’ bills to offset the effect of higher gas usage when weather is colder than normal.
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.
Division
 
Jurisdiction
 
Effective
Date of Last
Rate/GRIP Action
 
Rate Base
(thousands)(1)
 
Authorized
Rate of
Return(1)
 
Authorized Debt/
Equity Ratio
Authorized
Return
on Equity(1)
Atmos Pipeline — Texas
 
Texas
 
05/01/2011
 
$807,733
 
9.36%
 
50/50
11.80%
Atmos Pipeline — Texas — GRIP
 
Texas
 
05/07/2013
 
979,324
 
9.36%
 
N/A
11.80%
Colorado-Kansas
 
Colorado
 
01/04/2010
 
86,189
 
8.57%
 
50/50
10.25%
 
 
Kansas
 
09/01/2012
 
160,075
 
(2)
 
(2)
(2)
Kentucky/Mid-States
 
Kentucky
 
06/01/2010
 
221,340(3)
 
(2)
 
(2)
(2)
 
 
Tennessee
 
11/08/2012
 
201,359
 
8.28%
 
49/51
10.10%
 
 
Virginia
 
11/23/2009
 
36,861
 
8.48%
 
51/49
9.50% - 10.50%
Louisiana
 
Trans LA
 
04/01/2013
 
105,527
 
7.94%
 
52/48
10.00% - 10.80%
 
 
LGS
 
07/01/2013
 
298,642
 
8.08%
 
52/48
10.40%
Mid-Tex Cities
 
Texas
 
12/04/2012
 
1,512,986(4)
 
8.57%
 
48/52
10.50%
Mid-Tex — Dallas
 
Texas
 
06/01/2013
 
1,619,429(4)
 
8.35%
 
48/52
10.10%
Mississippi
 
Mississippi
 
11/01/2012
 
287,646
 
8.04%
 
49/51
9.64%
West Texas(5)
 
Texas
 
10/01/2012
 
271,590
 
(2)
 
(2)
(2)
 
Division
 
Jurisdiction
 
Bad  Debt
Rider(6)
 
Annual Rate Mechanism
 
Infrastructure Mechanism
Performance- Based
Rate  Program(7)
 
WNA Period
Atmos Pipeline —  Texas
 
Texas
 
No
 
No
 
Yes
N/A
 
N/A
Colorado-Kansas
 
Colorado
 
   Yes(8)
 
No
 
Yes
No
 
N/A
 
 
Kansas
 
Yes
 
No
 
Yes
No
 
October-May
Kentucky/Mid-States
 
Kentucky
 
Yes
 
No
 
Yes
Yes
 
November-April
 
 
Tennessee
 
Yes
 
No
 
No
Yes
 
October-April
 
 
Virginia
 
Yes
 
No
 
Yes
No
 
January-December
Louisiana
 
Trans LA
 
No
 
Yes
 
No
No
 
December-March
 
 
LGS
 
No
 
Yes
 
No
No
 
December-March
Mid-Tex Cities
 
Texas
 
Yes
 
Yes
 
Yes
No
 
November-April
Mid-Tex — Dallas
 
Texas
 
Yes
 
Yes
 
Yes
No
 
November-April
Mississippi
 
Mississippi
 
No
 
Yes
 
No
Yes
 
November-April
West Texas(5)
 
Texas
 
Yes
 
No
 
Yes
No
 
October-May
 
(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) 
Kentucky rate base consists of $184.7 million included in the June 2010 rate case and $36.6 million included in the October 2012 PRP surcharge. A total of $36.6 million of the Kentucky rate base amount was granted in the annual PRP filing with an effective date of October 1, 2012, an authorized rate of return of 8.74 percent and an authorized return on equity of 10.50 percent.
(4) 
The Mid-Tex Rate Base amounts for the Mid-Tex Cities and Dallas areas represent “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base.

6


(5) 
On October 2, 2012, a rate case settlement was approved by the Texas Railroad Commission (RRC) that combined the former Amarillo, Lubbock and West Texas jurisdictions into a single “West Texas” jurisdiction.
(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 distribution companies to minimize purchased gas costs by allowing the companies and its customers to share the purchased gas costs savings.
(8) 
The Company and Commission Staff have agreed to roll the recovery of the gas portion of uncollectible accounts back into base rates as part of the current rate proceeding.
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 reasonable cost. Major suppliers during fiscal 2013 were Anadarko Energy Services Company, BP Energy Company, ConocoPhillips Company, Devon Gas Services, L.P., Enterprise Products Operating LLC, Iberdrola Energy Services, LLC, Sequent Energy Management, L.P., Targa Gas Marketing LLC, Tenaska Marketing Ventures, Texla Energy Management, Inc. 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 2013 was on January 15, 2013, when sales to customers reached approximately 3.1 Bcf.
Currently, our natural gas distribution divisions, except for our Mid-Tex Division, utilize 35 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.
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 (APT). APT is 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. It 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 excess gas. This segment represents approximately 30 percent of our consolidated operations.
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.

7



Nonregulated Segment Overview
Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation, and represent approximately five percent of our consolidated net income.
AEH's primary business is to buy, sell and deliver natural gas at competitive prices to approximately 1,000 customers located primarily in the Midwest and Southeast areas of the United States. AEH accomplishes this objective by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.
AEH also earns storage and transportation demand fees primarily from our regulated natural gas distribution operations in Louisiana and Kentucky. These demand fees are subject to regulatory oversight and are renewed periodically.
Ratemaking Activity
Overview
The method of determining regulated rates varies among the states in which our regulated businesses 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, which benefit both our customers and the Company. As a result of our ratemaking efforts in recent years, Atmos Energy has:
Annual ratemaking mechanisms in place in four states that provide for an annual rate review and adjustment to rates for approximately 69 percent of our natural gas distribution gross margin.
Accelerated recovery of capital for approximately 74 percent of our natural gas distribution gross margin.
Enhanced rate design that allows us to defer certain elements of our cost of service until they are included in rates, such as depreciation, ad valorem taxes and pension costs.
WNA mechanisms in seven states that serve to minimize the effects of weather on approximately 97 percent of our natural gas distribution gross margin.
The ability to recover the gas cost portion of bad debts for approximately 75 percent of our natural gas distribution gross margin.
Although substantial progress has been made in recent years by improving rate design across Atmos Energy’s operating areas, we will continue to seek improvements in rate design to address cost variations that are related to pass-through energy costs beyond our control. Further, 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.
Recent Ratemaking Activity
Substantially all of our regulated revenues in the fiscal years ended September 30, 2013, 2012 and 2011 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 $98.1 million, $30.7 million and $72.4 million, became effective in fiscal 2013, 2012 and 2011, as summarized below:

 
 
Annual Increase to Operating
Income For the Fiscal Year Ended September 30
Rate Action
 
2013
 
2012
 
2011
 
 
(In thousands)
Infrastructure programs
 
$
30,936

 
$
19,172

 
$
15,033

Annual rate filing mechanisms
 
9,152

 
7,044

 
35,216

Rate case filings
 
56,700

 
4,309

 
20,502

Other ratemaking activity
 
1,322

 
167

 
1,675

 
 
$
98,110

 
$
30,692

 
$
72,426





8


Additionally, the following ratemaking efforts were initiated during fiscal 2013 but had not been completed as of September 30, 2013:
 
 
 
 
Division
Rate Action
Jurisdiction
Operating Income
Requested
 
 
 
(In thousands)
 
 
 
 
Colorado-Kansas
Rate Case(1)
Colorado
$
10,891

Kentucky/Mid-States
Rate Case
Kentucky
13,133

 
PRP(2)
Kentucky
2,493

 
PRP(2)
Virginia
213

Mid-Tex Division
GRIP(3)
Railroad Commission - Environs
768

 
RRM(4)
Mid-Tex Cities
17,077

Mississippi
Stable Rate Filing(5)
Mississippi

 
 
 
$
44,575

 
(1) 
This rate case seeks a multi-year step increase in annual operating income of $4.5 million on January 1, 2014, $2.9 million on July 1, 2014 and $3.5 million on July 1, 2015.
(2) 
The Pipeline Replacement Program (PRP) surcharge relates to a long-term program to replace aging infrastructure. The Kentucky and Virginia PRPs were implemented on October 1, 2013.
(3) 
The Gas Reliability Infrastructure Program (GRIP) surcharge relates to replacing aging infrastructure as well as other changes in net plant. The surcharge is calculated on a system-wide basis, but is only filed with the Railroad Commission for unincorporated areas served by the Mid-Tex Division.
(4) 
The Rate Review Mechanism (RRM) is an annual rate filing mechanism that allows us to refresh our rates on a periodic basis without filing a formal rate case. The current RRM program was approved by the Mid-Tex Cities in the summer of 2013. The first filing under the mechanism was made in July of 2013 and has been settled for $12.5 million to be implemented on November 1, 2013.
(5) 
The Stable Rate Filing shows no deficiency, thus no change in operating income is anticipated from the current year filing.


    

9


Our recent ratemaking activity is discussed in greater detail below.

Infrastructure Programs
As discussed above in “Natural Gas Distribution Segment Overview” and “Regulated Transmission and Storage Segment Overview,” infrastructure programs such as GRIP allow our regulated divisions 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, Kansas, Kentucky and Virginia. The following table summarizes our infrastructure program filings with effective dates during the fiscal years ended September 30, 2013, 2012 and 2011:
Division
 
Period
End
 
Incremental Net
Utility Plant
Investment
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
 
(In thousands)
 
 
2013 Infrastructure Programs:
 
 
 
 
 
 
 
 
Atmos Pipeline — Texas
 
12/2012
 
$
156,440

 
$
26,730

 
05/07/2013
Colorado-Kansas — Kansas
 
09/2012
 
5,376

 
601

 
01/09/2013
Kentucky/Mid-States — Georgia(1)(2)
 
09/2011
 
6,519

 
1,079

 
10/01/2012
Kentucky/Mid-States — Kentucky(2)
 
09/2013
 
19,296

 
2,425

 
10/01/2012
Kentucky/Mid-States — Virginia
 
09/2013
 
756

 
101

 
10/01/2012
Total 2013 Infrastructure Programs
 
 
 
$
188,387

 
$
30,936

 
 
2012 Infrastructure Programs:
 
 
 
 
 
 
 
 
Mid-Tex Unincorporated (Environs)(3)
 
12/2011
 
$
145,671

 
$
744

 
06/26/2012
Atmos Pipeline — Texas
 
12/2011
 
87,210

 
14,684

 
04/10/2012
Kentucky/Mid-States — Georgia(1)(2)
 
09/2010
 
7,160

 
1,215

 
10/01/2011
Kentucky/Mid-States — Kentucky(2)
 
09/2012
 
17,347

 
2,529

 
10/01/2011
Total 2012 Infrastructure Programs
 
 
 
$
257,388

 
$
19,172

 
 
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 (2)
 
09/2011
 
3,329

 
468

 
06/01/2011
Kentucky/Mid-States — Missouri(4)
 
09/2010
 
2,367

 
277

 
02/14/2011
Kentucky/Mid-States — Georgia(1)(2)
 
09/2009
 
5,359

 
764

 
10/01/2010
Total 2011 Infrastructure Programs
 
 
 
$
209,552

 
$
15,033

 
 
 
(1)
On April 1, 2013, we completed the sale of our Georgia operations to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. The increase in operating income arising from the implementation of new rates is included as a component of discontinued operations through March 31, 2013.
(2) 
The Pipeline Replacement Program (PRP) surcharge relates to a long-term program to replace aging infrastructure.
(3) 
Incremental net utility plant investment represents the system-wide incremental investment for the Mid-Tex Division. The increase in annual operating income is for the unincorporated areas of the Mid-Tex Division only.
(4) 
Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.



10


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. We currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and in a portion of our Texas divisions. These mechanisms are referred to as Dallas annual rate review (DARR) and rate review mechanisms (RRM) in our Mid-Tex Division, 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:
Division
 
Jurisdiction
 
Test Year Ended
 
Increase
(Decrease) in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
 
 
(In thousands)
 
 
2013 Filings:
 
 
 
 
 
 
 
 
Louisiana
 
LGS
 
12/31/2012
 
$
908

 
07/01/2013
Mid-Tex
 
City of Dallas
 
9/30/2012
 
1,800

 
06/01/2013
Louisiana
 
TransLa
 
9/30/2012
 
2,260

 
04/01/2013
Kentucky/Mid-States
 
Georgia(1)
 
9/30/2013
 
743

 
02/01/2013
Mississippi
 
Mississippi
 
6/30/2012
 
3,441

 
11/01/2012
Total 2013 Filings
 
 
 
 
 
$
9,152

 
 
2012 Filings:
 
 
 
 
 
 
 
 
Louisiana
 
LGS
 
12/31/2011
 
$
2,324

 
07/01/2012
Mid-Tex
 
Dallas
 
9/30/2011
 
1,204

 
06/01/2012
Louisiana
 
Trans La
 
9/30/2011
 
11

 
04/01/2012
Kentucky/Mid-States
 
Georgia(1)
 
9/30/2011
 
(818
)
 
02/01/2012
Mississippi
 
Mississippi
 
6/30/2011
 
4,323

 
01/11/2012
Total 2012 Filings
 
 
 
 
 
$
7,044

 
 
2011 Filings:
 
 
 
 
 
 
 
 
Mid-Tex
 
Mid-Tex 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
 
9/30/2010
 
350

 
04/01/2011
Mid-Tex
 
Mid-Tex Cities
 
12/31/2009
 
23,122

 
10/01/2010
Total 2011 Filings
 
 
 
 
 
$
35,216

 
 
(1)
On April 1, 2013, we completed the sale of our Georgia operations to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. The increase in operating income arising from the implementation of new rates is included as a component of discontinued operations through March 31, 2013.

From 2008 through fiscal 2011, the Mid-Tex Division had an annual rate review mechanism (RRM) for approximately 80 percent of its customers, which allowed it to update rates annually without the necessity of filing a general rate case. In fiscal 2013, a new RRM was approved for these customers.
Since June 2011, the Mid-Tex Division has operated under a Dallas Annual Rate Review Mechanism (DARR) that provides the ability for it to annually update rates for its City of Dallas customers without the necessity of filing a general rate case. The first rates were implemented under the DARR in June 2012.
During fiscal 2011, the RRC’s Division of Public Safety issued a new rule requiring natural gas distribution companies with operations in Texas 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 expenses associated with capital expenditures incurred pursuant to this rule until the expenses are included in rates, including the recording of interest on the deferred expenses.

11



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 safely deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes our recent rate cases:
Division
 
State
 
Increase in Annual
Operating Income
 
Effective Date
 
 
 
 
(In thousands)
 
 
2013 Rate Case Filings:
 
 
 
 
 
 
Mid-Tex
 
Texas
 
$
42,601

 
12/04/2012
Kentucky/Mid-States
 
Tennessee
 
7,530

 
11/08/2012
West Texas
 
Texas
 
6,569

 
10/01/2012
Total 2013 Rate Case Filings
 
 
 
$
56,700

 
 
2012 Rate Case Filings:
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
$
3,764

 
09/01/2012
West Texas — Environs
 
Texas
 
545

 
11/08/2011
Total 2012 Rate Case Filings
 
 
 
$
4,309

 
 
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

 
 
 
Other Ratemaking Activity
The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2013, 2012 and 2011:
Division
 
Jurisdiction
 
Rate Activity
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
 
 
(In thousands)
 
 
2013 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad Valorem(1)
 
$
1,322

 
02/01/2013
Total 2013 Other Rate Activity
 
 
 
 
 
$
1,322

 
 
2012 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad Valorem(1)
 
$
167

 
01/14/2012
Total 2012 Other Rate Activity
 
 
 
 
 
$
167

 
 
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

 
 
 
(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.
Other Regulation
Each of our natural gas distribution divisions and our regulated transmission and storage division 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 transmission and distribution facilities. In addition, our distribution operations are also subject to various state and federal laws regulating environmental matters. From time to time

12


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.
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. The FERC also has 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, 2013, we had 4,720 employees, consisting of 4,611 employees in our regulated operations and 109 employees in our nonregulated operations.
Available Information
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports, and amendments to those reports, and other forms that we file with or furnish to the Securities and Exchange Commission (SEC) are available free of charge at our website, www.atmosenergy.com, under “Publications and Filings” under the “Investors” tab, as soon as reasonably practicable, after we electronically file these reports with, or furnish these reports to, the SEC. We will also provide copies of these reports free of charge upon request to Shareholder Relations at the address and telephone number appearing below:
Shareholder Relations
Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas 75265-0205
972-855-3729
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 2013, Kim R. Cocklin, certified to the New York Stock Exchange that he was not aware of any

13


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:

The Company is dependent on continued access to the credit and capital markets to execute our business strategy.
Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation, Moody’s Investors Services, Inc. and Fitch Ratings, Ltd. Similar to most companies, we rely upon access to both short-term and long-term credit and capital markets to satisfy our liquidity requirements. If adverse credit conditions were to cause a significant limitation on our access to the private and public capital 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 private credit and/or public capital markets and increase our costs of borrowing.

Further, if our credit ratings were downgraded, we could be required to provide additional liquidity to our nonregulated segment because the commodity financial instrument markets could become unavailable to us. Our nonregulated segment depends primarily upon an intercompany lending facility between AEH and Atmos Energy to finance its working capital needs, supplemented by two small credit facilities with outside lenders. Our ability to provide this liquidity to AEH for our nonregulated operations is limited by the terms of the lending arrangement with AEH, which is subject to annual approval by one state regulatory commission.

While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly in the near term. The future effects on our business, liquidity and financial results of a deterioration of current conditions in the credit and capital markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.

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 regulatory oversight from various state and local regulatory authorities in the eight states that we serve. Therefore, our returns are continuously monitored and are subject to challenge for their reasonableness by the appropriate regulatory authorities or other third-party intervenors. In the normal course of business, a regulated entity often needs to place assets in service and establish historical test periods before rate cases that seek to adjust our allowed returns to recover that investment can be filed. Further, the regulatory review process can be lengthy. Because of this process, we 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.” The regulatory process also involves the risk that regulatory authorities may (i) review our purchases of natural gas and adjust the amount of our gas costs that we pass through to our customers or (ii) limit the costs we may have incurred from our cost of service that can be recovered from customers.

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 several 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 continuing to improve economic conditions, including the continued 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.

14



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.

We are exposed to market risks that are beyond our control, which could adversely affect our financial results and capital requirements.
We are subject to market risks beyond our control, including market liquidity, commodity price volatility caused by market supply and demand dynamics and counterparty creditworthiness and interest rate risk. Our regulated operations are generally insulated from commodity price risk through its purchased gas cost mechanisms. With respect to interest rate risk, we have been operating in a relatively low interest-rate environment in recent years compared to historical norms for both short and long-term interest rates. However, increases in interest rates could adversely affect our future financial results.

Although our nonregulated operations represent approximately five percent of our consolidated results, commodity price volatility experienced in this business segment could lead to some volatility in our earnings. 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.

Although we manage our business to maintain no open positions related to our physical storage, there are times when limited net open positions 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. 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. Further, if the local physical markets 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.

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.


15


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.

Finally, 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 from competitors who offer lower cost, basic services.

Adverse weather conditions could affect our operations or financial results.
We have weather-normalized rates for over 95 percent of our residential and commercial meters in our natural gas distribution business, which substantially mitigates 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.

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 to comply with rules issued by the RRC’s Division of Public Safety that require natural gas distribution companies to develop and implement risk-based programs for the renewal or replacement of distribution facilities, including steel service lines. Our cash flows from operations generally are sufficient to supply funding for all our capital expenditures, including the financing of the costs of new construction along with capital expenditures necessary to maintain our existing natural gas system. Due to the timing of these cash flows and capital expenditures, we often must fund at least a portion of these costs through borrowing funds from third-party lenders, the cost and availability of which is dependent on the liquidity of the credit markets, interest rates and other market conditions. This in turn may limit our ability to connect new customers to our system due to constraints on the amount of funds we can invest in our infrastructure.

The costs of providing health care benefits, pension and postretirement health care benefits and related funding requirements may increase substantially.
We provide health care benefits and a cash-balance pension plan and postretirement health care benefits to eligible full-time employees. The costs of providing health care benefits to our employees could significantly increase over time due to rapidly increasing health care inflation, the impact of the Health Care Reform Act of 2010 (HCR) and any future legislative changes related to the provision of health care benefits. Although the HCR is not expected to have a direct material impact when a number of its more significant provisions become effective in 2014, the impact of costs incurred by the insurance industry arising from the implementation of HCR on the Company are difficult to measure at this time.

The costs of providing a cash-balance pension plan and postretirement health care benefits to eligible full-time employees and related funding requirements could be influenced by changes in the market value of the assets funding our pension and postretirement health care plans. Any significant declines in the value of these investments could increase the costs of our

16


pension and postretirement health care plans and related funding requirements in the future. Further, our costs of providing such benefits and related funding requirements are also subject to a number of factors, including (i) changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five to ten years; and (ii) various actuarial calculations and assumptions, which may differ materially from actual results due primarily to changing market and economic conditions and higher or lower withdrawal rates.

The costs to the Company of providing these benefits and related funding requirements could also increase materially in the future, depending on the timing of the recovery, if any, of such costs through our rates.

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 72,000 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 eight 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 unfortunate pipeline incident in California in 2010, natural gas distribution and pipeline companies are facing increasing federal, state and local oversight of the safety of their operations. Although we believe these costs should be ultimately recoverable through our rates, the 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 over 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. 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. 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 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 federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. 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 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.

Distributing, transporting and storing natural gas involve risks that may result in accidents and additional operating costs.
Our natural gas distribution and pipeline and storage businesses involve 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

17


as substantial financial losses resulting from property damage, damage to the environment and to our operations. We maintain liability and property insurance coverage in place for many of these hazards and risks. However, because some of 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.
Cyber-attacks or acts of cyber-terrorism could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information.
Our business operations and information technology systems may be vulnerable to an attack by individuals or organizations intending to disrupt our business operations and information technology systems. We use such systems to manage our natural gas distribution and intrastate pipeline operations and other business processes. Disruption of those systems could adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline systems or serve our customers timely. Accordingly, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected. In addition, we use our information technology systems to protect confidential or sensitive customer, employee and Company information developed and maintained in the normal course of our business. Any attack on such systems that would result in the unauthorized release of customer, employee or other confidential or sensitive data could have a material adverse effect on our business reputation, increase our costs and expose us to additional material legal claims and liability. Even though we have insurance coverage in place for many of these cyber-related risks, if such an attack or act of terrorism were to occur, our operations and 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.
ITEM 2.
Properties.
Distribution, transmission and related assets
At September 30, 2013, in our natural gas distribution segment, we owned an aggregate of 67,146 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. Through our regulated transmission and storage segment we owned 5,628 miles of gas transmission and gathering lines as well as 110 miles of gas transmission and gathering lines through our nonregulated segment.
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, 2013:

18


State
 
Usable Capacity
(Mcf)
 
Cushion
Gas
(Mcf)(1)
 
Total
Capacity
(Mcf)
 
Maximum
Daily Delivery
Capability
(Mcf)
Natural Gas Distribution Segment
 
 
 
 
 
 
 
 
Kentucky
 
4,442,696

 
6,322,283

 
10,764,979

 
105,100

Kansas
 
3,239,000

 
2,300,000

 
5,539,000

 
45,000

Mississippi
 
2,211,894

 
2,442,917

 
4,654,811

 
48,000

Total
 
9,893,590

 
11,065,200

 
20,958,790

 
198,100

Regulated Transmission and Storage Segment — Texas
 
46,143,226

 
15,878,025

 
62,021,251

 
1,235,000

Nonregulated Segment
 
 
 
 
 
 
 
 
Kentucky
 
3,438,900

 
3,240,000

 
6,678,900

 
67,500

Louisiana
 
438,583

 
300,973

 
739,556

 
56,000

Total
 
3,877,483

 
3,540,973

 
7,418,456

 
123,500

Total
 
59,914,299

 
30,484,198

 
90,398,497

 
1,556,600

 
(1) 
Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.




19


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, 2013:
Segment
 
Division/Company
 
Maximum
Storage
Quantity
(MMBtu)
 
Maximum
Daily
Withdrawal
Quantity
(MDWQ)(1)
Natural Gas Distribution Segment
 
 
 
 
 
 
 
 
Colorado-Kansas Division
 
4,261,909

 
108,489

 
 
Kentucky/Mid-States Division
 
11,081,603

 
344,706

 
 
Louisiana Division
 
2,736,539

 
161,393

 
 
Mid-Tex Division
 
1,000,000

 
75,000

 
 
Mississippi Division
 
3,695,429

 
162,402

 
 
West Texas Division
 
3,375,000

 
106,000

Total
 
26,150,480

 
957,990

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
 
35,851,349

 
1,276,434

 
(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.
Offices
Our administrative offices and corporate headquarters are consolidated in a leased facility in Dallas, Texas. We also maintain field offices throughout our service territory, 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 10 to the consolidated financial statements.

ITEM 4.
Mine Safety Disclosures.

Not applicable.
PART II
 
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 2013 and 2012 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:

20


 
Fiscal 2013
 
Fiscal 2012
 
High
 
Low
 
Dividends
Paid
 
High
 
Low
 
Dividends
Paid
Quarter ended:
 
 
 
 
 
 
 
 
 
 
 
December 31
$
36.86

 
$
33.20

 
$
0.35

 
$
35.40

 
$
30.97

 
$
0.345

March 31
42.69

 
35.11

 
0.35

 
33.15

 
30.60

 
0.345

June 30
44.87

 
38.59

 
0.35

 
35.07

 
30.91

 
0.345

September 30
45.19

 
39.40

 
0.35

 
36.94

 
34.94

 
0.345

 
 
 
 
 
$
1.40

 
 
 
 
 
$
1.38

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, 2013 was 16,746. 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 2013 that were not registered under the Securities Act of 1933, as amended.
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 S&P 500 Stock Index and the cumulative total return of a customized peer company group, the Comparison Company Index. The Comparison Company Index 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, 2008 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 Index

21


 
Cumulative Total Return
 
9/30/2008
 
9/30/2009
 
9/30/2010
 
9/30/2011
 
9/30/2012
 
9/30/2013
Atmos Energy Corporation
100.00

 
111.68

 
121.63

 
140.75

 
161.81

 
199.54

S&P 500
100.00

 
93.09

 
102.55

 
103.72

 
135.05

 
161.17

Peer Group
100.00

 
98.11

 
130.03

 
153.00

 
184.92

 
217.15

The Comparison Company Index contains a hybrid group of utility companies, primarily natural gas distribution companies, recommended by our independent executive compensation 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, Integrys Energy Group, Inc., National Fuel Gas, NiSource Inc., ONEOK Inc., Piedmont Natural Gas Company, Inc., Questar Corporation, Vectren Corporation and WGL Holdings, Inc.
The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2013.
 
Number of
securities to be issued
upon exercise of
outstanding options,
warrants and rights
 
Weighted-average
exercise price of
outstanding options,
warrants and rights
 
Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))
 
(a)
 
(b)
 
(c)
Equity compensation plans approved by security holders:
 
 
 
 
 
1998 Long-Term Incentive Plan
7,930

 
$
25.96

 
1,403,439

Total equity compensation plans approved by security holders
7,930

 
25.96

 
1,403,439

Equity compensation plans not approved by security holders

 

 

Total
7,930

 
$
25.96

 
1,403,439

On September 28, 2011, the Board of Directors approved a program authorizing the repurchase of up to five million shares of common stock over a five-year period. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the Company. 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. We did not repurchase any shares during fiscal 2013. At September 30, 2013, there were 4,612,009 shares of repurchase authority remaining under the program.

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
 
2013
 
2012(1)
 
2011(1)
 
2010
 
2009(1)
 
(In thousands, except per share data)
Results of Operations
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,886,257

 
$
3,438,483

 
$
4,286,435

 
$
4,661,060

 
$
4,793,248

Gross profit
$
1,412,050

 
$
1,323,739

 
$
1,300,820

 
$
1,314,136

 
$
1,297,682

Income from continuing operations
$
230,698

 
$
192,196

 
$
189,588

 
$
189,851

 
$
175,026

Net income
$
243,194

 
$
216,717

 
$
207,601

 
$
205,839

 
$
190,978

Diluted income per share from continuing operations
$
2.50

 
$
2.10

 
$
2.07

 
$
2.03

 
$
1.90

Diluted net income per share
$
2.64

 
$
2.37

 
$
2.27

 
$
2.20

 
$
2.07

Cash dividends declared per share
$
1.40

 
$
1.38

 
$
1.36

 
$
1.34

 
$
1.32

Financial Condition
 
 
 
 
 
 
 
 
 
Net property, plant and equipment(2)
$
6,030,655

 
$
5,475,604

 
$
5,147,918

 
$
4,793,075

 
$
4,439,103

Total assets
$
7,940,401

 
$
7,495,675

 
$
7,282,871

 
$
6,763,791

 
$
6,367,083

Capitalization:
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
2,580,409

 
$
2,359,243

 
$
2,255,421

 
$
2,178,348

 
$
2,176,761

Long-term debt (excluding current maturities)
2,455,671

 
1,956,305

 
2,206,117

 
1,809,551

 
2,169,400

Total capitalization
$
5,036,080

 
$
4,315,548

 
$
4,461,538

 
$
3,987,899

 
$
4,346,161


22


 
(1) 
Financial results for fiscal years 2012, 2011 and 2009 include a $5.3 million, $30.3 million and a $5.4 million pre-tax loss for the impairment of certain assets.
(2) 
Amounts shown for fiscal 2012 and 2011 are net of assets held for sale.

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; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; the impact of adverse economic conditions on our customers; the effects of inflation and changes in the availability and price of natural gas; market risks beyond our control affecting our risk management activities, including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our gas distribution business; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; 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 inherent hazards and risks involved in operating our gas distribution business; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; 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
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 base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from estimates.
Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. The accounting policies discussed below are both important to the presentation of our financial condition and results of operations and require

23


management to make difficult, subjective or complex accounting estimates. Accordingly, these critical accounting policies are reviewed periodically by the Audit Committee of the Board of Directors.
Critical
Accounting Policy
Summary of Policy
Factors Influencing Application of the Policy
Regulation
Our natural gas distribution and regulated transmission and storage operations meet the criteria of a cost-based, rate-regulated entity under accounting principles generally accepted in the United States. Accordingly, the financial results for these operations reflect the effects of the ratemaking and accounting practices and policies of the various regulatory commissions to which we are subject.

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. 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.

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.
Decisions of regulatory authorities

Issuance of new regulations

Assessing the probability of the recoverability of deferred costs
Unbilled Revenue
We follow the revenue accrual method of accounting for natural gas distribution segment revenues whereby revenues attributable 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.
Estimates of delivered sales volumes based on actual tariff information and weather information and estimates of customer consumption and/or behavior

Estimates of purchased gas costs related to estimated deliveries

Estimates of uncollectible amounts billed subject to refund

24


Critical
Accounting Policy
Summary of Policy
Factors Influencing Application of the Policy
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 methodology 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.
General economic and market conditions

Assumed investment returns by asset class

Assumed future salary increases

Projected timing of future cash disbursements

Health care cost experience trends

Participant demographic information

Actuarial mortality assumptions

Impact of legislation

Contingencies
In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to uncollectible receivables, lawsuits, claims made by third parties or the action of various regulatory agencies. We recognize these contingencies in our consolidated financial statements when we determine, based on currently available facts and circumstances it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated.

Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure. Changes in the estimates related to contingencies could have a negative impact on our consolidated results of operations, cash flows or financial position. Our contingencies are further discussed in Note 10 to our consolidated financial statements.
Currently available facts

Management’s estimate of future resolution


25


Critical
Accounting Policy
Summary of Policy
Factors Influencing Application of the Policy
Financial instruments and hedging activities
We use financial instruments to mitigate commodity price risk and interest rate risk. The objectives for using financial instruments have been tailored to meet the needs of our regulated and nonregulated businesses. These objectives are more fully described in Note 12 to the consolidated financial statements.

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 recognition of the changes in fair value of these financial instruments recorded in the income statement is contingent upon 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. Our accounting elections for financial instruments and hedging activities utilized are more fully described in Note 12 to the consolidated financial statements.

The criteria used to determine if a financial instrument meets the definition of a derivative and qualifies for hedge accounting treatment are complex and require management to exercise professional judgment. Further, as more fully discussed below, significant changes in the fair value of these financial instruments could materially impact our financial position, results of operations or cash flows. Finally, changes in the effectiveness of the hedge relationship could impact the accounting treatment.
Designation of contracts under the hedge accounting rules

Judgment in the application of accounting guidance

Assessment of the probability that future hedged transactions will occur

Changes in market conditions and the related impact on the fair value of the hedged item and the associated designated financial instrument

Changes in the effectiveness of the hedge relationship
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).

The fair value of our financial instruments is subject to potentially significant volatility based on numerous considerations including, but not limited to changes in commodity prices, interest rates, maturity and settlement of these financial instruments.

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) 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 financial instruments represent the best information available with respect to the market in which transactions involving these financial instruments are executed, the closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts.

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. 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.
General economic and market conditions

Volatility in underlying market conditions

Maturity dates of financial instruments

Creditworthiness of our counterparties

Creditworthiness of Atmos Energy

Impact of credit risk mitigation activities on the assessment of the creditworthiness of Atmos Energy and its counterparties

26


Critical
Accounting Policy
Summary of Policy
Factors Influencing Application of the Policy
Impairment assessments
We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstance indicate that such carrying values may not be recoverable, and at least annually for goodwill, as required by U.S. accounting standards.

The evaluation of our goodwill balances and other long-lived assets or identifiable assets for which uncertainty exists regarding the recoverability of the carrying value of such assets involves the assessment of future cash flows and external market conditions and other subjective factors that could impact the estimation of future cash flows including, but not limited to the commodity prices, the amount and timing of future cash flows, future growth rates and the discount rate. Unforeseen events and changes in circumstances or market conditions could adversely affect these estimates, which could result in an impairment charge.
General economic and market conditions

Projected timing and amount of future discounted cash flows

Judgment in the evaluation of relevant data

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. Historically, this has generally resulted 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 54 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years. However, we believe rate design changes implemented during the first quarter of fiscal 2013 in our Mid-Tex and West Texas Divisions should continue to cause this pattern to change. The rate design approved in these regulatory proceedings includes an increase to the customer base charge and a decrease in the consumption charge applied to customer usage. The effect of this change in rate design should result in a more equal distribution of operating income earned over the fiscal year for approximately 50 percent of our natural gas distribution segment.
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 2013, we earned $243.2 million, or $2.64 per diluted share, which represents a twelve percent increase in net income and diluted net income per share over fiscal 2012, primarily due to recent improvements in rate designs in our natural gas distribution and regulated transmission and storage segments combined with a two percent year-over-year increase in consolidated natural gas distribution throughput due to colder weather.
We completed the sale of our Georgia natural gas distribution operations on April 1, 2013 to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million pursuant to a purchase agreement executed on August 8, 2012. In connection with the sale, we recognized a net of tax gain of $5.3 million. Accordingly, the results of operations for this service area are shown in discontinued operations for all periods presented. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The sale of these three service areas was completed in August 2012.
We also took several steps during the year ended September 30, 2013 to further strengthen our balance sheet and borrowing capability. In December 2012, we amended our $750 million revolving credit agreement primarily to (i) increase our borrowing capacity to $950 million while retaining the accordion feature that would allow an increase in borrowing capacity up to $1.2 billion and (ii) to permit same-day funding on base rate loans. In August 2013, we amended our revolving credit agreement primarily to increase the term through August 2018. We also terminated Atmos Energy Marketing’s $200 million committed and secured credit facility and replaced this facility with two $25 million 364-day bilateral facilities, which should result in a decrease in external credit expense incurred in our nonregulated operations. After giving effect to these changes, we have over $1 billion of working capital funding from four committed revolving credit facilities and one noncommitted revolving credit facility.

27


On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which replaced, on a long-term basis, our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012. The net proceeds of approximately $494 million were used to repay $260 million outstanding under the short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes.
Consolidated Results
The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2013, 2012 and 2011.
 
 
For the Fiscal Year Ended September 30
 
2013
 
2012
 
2011
 
(In thousands, except per share data)
Operating revenues
$
3,886,257

 
$
3,438,483

 
$
4,286,435

Gross profit
1,412,050

 
1,323,739

 
1,300,820

Operating expenses
910,171

 
877,499

 
874,834

Operating income
501,879

 
446,240

 
425,986

Miscellaneous income (expense)
(197
)
 
(14,644
)
 
21,184

Interest charges
128,385

 
141,174

 
150,763

Income from continuing operations before income taxes
373,297

 
290,422

 
296,407

Income tax expense
142,599

 
98,226

 
106,819

Income from continuing operations
230,698

 
192,196

 
189,588

Income from discontinued operations, net of tax
7,202

 
18,172

 
18,013

Gain on sale of discontinued operations, net of tax
5,294

 
6,349

 

Net income
$
243,194

 
$
216,717

 
$
207,601

Diluted net income per share from continuing operations
$
2.50

 
$
2.10

 
$
2.07

Diluted net income per share from discontinued operations
$
0.14

 
$
0.27

 
$
0.20

Diluted net income per share
$
2.64

 
$
2.37

 
$
2.27

Regulated operations contributed 95 percent, 97 percent and 104 percent to our consolidated net income from continuing operations for fiscal years 2013, 2012 and 2011. 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
 
2013
 
2012
 
2011
 
(In thousands)
Natural gas distribution segment
$
150,856

 
$
123,848

 
$
144,705

Regulated transmission and storage segment
68,260

 
63,059

 
52,415

Nonregulated segment
11,582

 
5,289

 
(7,532
)
Net income from continuing operations
230,698

 
192,196

 
189,588

Net income from discontinued operations
12,496

 
24,521

 
18,013

Net income
$
243,194

 
$
216,717

 
$
207,601


28


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
 
2013
 
2012
 
2011
 
(In thousands, except per share data)
Regulated operations
$
219,116

 
$
186,907

 
$
197,120

Nonregulated operations
11,582

 
5,289

 
(7,532
)
Net income from continuing operations
230,698

 
192,196

 
189,588

Net income from discontinued operations
12,496

 
24,521

 
18,013

Net income
$
243,194

 
$
216,717

 
$
207,601

Diluted EPS from continuing regulated operations
$
2.38

 
$
2.04

 
$
2.15

Diluted EPS from nonregulated operations
0.12

 
0.06

 
(0.08
)
Diluted EPS from continuing operations
2.50

 
2.10

 
2.07

Diluted EPS from discontinued operations
0.14

 
0.27

 
0.20

Consolidated diluted EPS
$
2.64

 
$
2.37

 
$
2.27

We reported net income of $243.2 million, or $2.64 per diluted share for the year ended September 30, 2013, compared with net income of $216.7 million or $2.37 per diluted share in the prior year. Income from continuing operations was $230.7 million, or $2.50 per diluted share compared with $192.2 million, or $2.10 per diluted share in the prior-year period. Income from discontinued operations was $12.5 million or $0.14 per diluted share for the year, which includes the gain on sale of substantially all our assets in Georgia of $5.3 million, compared with $24.5 million or $0.27 per diluted share in the prior year. Unrealized gains in our nonregulated operations during the current year increased net income by $5.3 million or $0.05 per diluted share compared with net losses recorded in the prior year of $5.0 million, or $0.05 per diluted share. Additionally, net income in both periods was impacted by nonrecurring items. In fiscal 2012, net income included the net positive impact of several one-time items totaling $10.3 million, or $0.11 per diluted share related to the pre-tax items, which are discussed in further detail below. In fiscal 2013, net income includes an $8.2 million ($5.3 million, net of tax), or $0.06 per diluted share, favorable impact related to the gain recorded in association with the April 1, 2013 completion of the sale of our Georgia assets.
We reported net income of $216.7 million, or $2.37 per diluted share for the year ended September 30, 2012, compared with net income of $207.6 million or $2.27 per diluted share in fiscal 2011. Income from continuing operations was $192.2 million, or $2.10 per diluted share compared with $189.6 million, or $2.07 per diluted share in fiscal 2011. Income from discontinued operations was $24.5 million or $0.27 per diluted share for the year, which includes the gain on sale of substantially all our assets in Missouri, Illinois and Iowa of $6.3 million, compared with $18.0 million or $0.20 per diluted share in fiscal 2011. Unrealized losses in our nonregulated operations during fiscal 2012 reduced net income by $5.0 million or $0.05 per diluted share compared with net losses recorded in fiscal 2011 of $6.6 million, or $0.07 per diluted share. Additionally, net income in both periods was impacted by nonrecurring items. In fiscal 2011, net income included the net positive impact of several one-time items totaling $3.2 million, or $0.03 per diluted share related to pre-tax items. In fiscal 2012, net income included the net positive impact of several one-time items totaling $10.3 million, or $0.11 per diluted share related to the following amounts:
$13.6 million positive impact of a deferred tax rate adjustment.
$10.0 million ($6.3 million, net of tax) unfavorable impact related to a one-time donation to a donor advised fund.
$9.9 million ($6.3 million, net of tax) favorable impact related to the gain recorded in association with the August 1, 2012 completion of the sale of our Iowa, Illinois and Missouri assets.
$5.3 million ($3.3 million, net of tax) unfavorable impact related to the noncash impairment of certain assets in our nonregulated business.
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

29


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 receipt taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenue 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.
Although the cost of gas typically does not have a direct impact on our gross profit, higher gas costs 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. 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 75 percent of our residential and commercial margins.
We completed the sale of our Georgia natural gas distribution operations on April 1, 2013 to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million. In connection with the sale, we recognized a net of tax gain of $5.3 million. On August 1, 2012, we completed the sale of substantially all of our natural gas distribution operations in Missouri, Illinois and Iowa.

During fiscal 2013, we completed 13 regulatory proceedings, which should result in a $71.4 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase to the base customer charge and a decrease in the commodity charge applied to customer consumption. The effect of this change in rate design allows the Company’s rates to be more closely aligned with the utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as they are now less dependent on customer consumption.

30


Review of Financial and Operating Results
Financial and operational highlights for our natural gas distribution segment for the fiscal years ended September 30, 2013, 2012 and 2011 are presented below.
 
For the Fiscal Year Ended September 30
 
2013
 
2012
 
2011
 
2013 vs. 2012
 
2012 vs. 2011
 
(In thousands, unless otherwise noted)
Gross profit
$
1,081,236

 
$
1,022,743

 
$
1,017,943

 
$
58,493

 
$
4,800

Operating expenses
738,143

 
718,282

 
695,855

 
19,861

 
22,427

Operating income
343,093

 
304,461

 
322,088

 
38,632

 
(17,627
)
Miscellaneous income (expense)
2,535

 
(12,657
)
 
16,242

 
15,192

 
(28,899
)
Interest charges
98,296

 
110,642

 
115,740

 
(12,346
)
 
(5,098
)
Income from continuing operations before income taxes
247,332

 
181,162

 
222,590

 
66,170

 
(41,428
)
Income tax expense
96,476

 
57,314

 
77,885

 
39,162

 
(20,571
)
Income from continuing operations
150,856

 
123,848

 
144,705

 
27,008

 
(20,857
)
Income from discontinued operations, net of tax
7,202

 
18,172

 
18,013

 
(10,970
)
 
159

Gain on sale of discontinued operations, net of tax
5,649

 
6,349

 

 
(700
)
 
6,349

Net Income
$
163,707

 
$
148,369

 
$
162,718

 
$
15,338

 
$
(14,349
)
Consolidated natural gas distribution sales volumes from continuing operations — MMcf
269,162

 
244,466

 
275,540

 
24,696

 
(31,074
)
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf
123,144

 
128,222

 
125,812

 
(5,078
)
 
2,410

Consolidated natural gas distribution throughput from continuing operations — MMcf
392,306

 
372,688

 
401,352

 
19,618

 
(28,664
)
Consolidated natural gas distribution throughput from discontinued operations — MMcf
4,731

 
18,295

 
22,668

 
(13,564
)
 
(4,373
)
Total consolidated natural gas distribution throughput — MMcf
397,037

 
390,983

 
424,020

 
6,054

 
(33,037
)
Consolidated natural gas distribution average transportation revenue per Mcf
$
0.46

 
$
0.43

 
$
0.47

 
$
0.03

 
$
(0.04
)
Consolidated natural gas distribution average cost of gas per Mcf sold
$
4.91

 
$
4.64

 
$
5.30

 
$
0.27

 
$
(0.66
)

Fiscal year ended September 30, 2013 compared with fiscal year ended September 30, 2012
The $58.5 million period-over-period increase in natural gas distribution gross profit primarily reflects the following:
$25.7 million increase in our Mid-Tex and West Texas divisions associated with the rate design changes implemented in the fiscal first quarter.
$16.1 million increase in rates in our Kentucky/Mid-States, Mississippi, Colorado-Kansas and Louisiana divisions.
$7.5 million increase due to colder weather, primarily in the Mississippi, Kentucky/Mid-States and Colorado-Kansas divisions.
$5.9 million increase in revenue-related taxes in our Mid-Tex and West Texas service areas primarily due to higher revenues on which the tax is calculated.
$4.5 million increase in transportation revenues.
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased by $19.9 million, primarily due to the following:
$12.2 million increase in employee-related expenses due to lower labor capitalization rates, increased benefit costs and increased variable compensation expense.

31


$11.7 million increase primarily associated with higher line locate activities, pipeline and right-of-way maintenance spending to improve the safety and reliability of our system.
$5.0 million increase in taxes, other than income due to higher revenue-related taxes, as discussed above.
$6.8 million increase in bad debt expense primarily attributable to an increase in revenue arising from the rate design changes and the temporary suspension of active customer collection activities following the implementation of a new customer information system during the third fiscal quarter.
These increases were partially offset by:
$6.9 million decrease in legal and other administrative costs.
$6.4 million decrease in depreciation expense due to new depreciation rates approved in the most recent Mid-Tex rate case that went into effect in January 2013.
$2.4 million gain realized on the sale of certain investments.
Miscellaneous income increased $15.2 million, primarily due to the absence of a $10.0 million one-time donation to a donor advised fund in the prior year, the completion of a periodic review of our performance-based ratemaking (PBR) mechanism in our Tennessee service area and the implementation of a new PBR program in our Mississippi Division during fiscal 2013.

Interest charges decreased $12.3 million, primarily from interest deferrals associated with our infrastructure spending activities in Texas.
Fiscal year ended September 30, 2012 compared with fiscal year ended September 30, 2011
The $4.8 million increase in natural gas distribution gross profit was primarily due to a $17.7 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Mississippi, West Texas and Kentucky service areas.
These increases were partially offset by the following:
$11.1 million decrease in revenue-related taxes in our Mid-Tex, West Texas and Mississippi service areas, primarily due to lower revenues on which the tax is calculated.
$1.6 million decrease due to an eight percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather in the current year compared to fiscal 2011 in most of our service areas.
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $22.4 million primarily due to the following:
$11.2 million increase in legal costs, primarily due to settlements.
$10.6 million increase in employee-related costs.
$8.4 million increase in depreciation and amortization associated with an increase in our net plant as a result of our capital investments in fiscal 2011.
$2.6 million increase in software maintenance costs.
These increases were partially offset by the following:
$6.8 million decrease in operating expenses due to increased capital spending and warmer weather allowing us time to complete more capital work than in the prior year.
$2.9 million decrease due to the establishment of regulatory assets for pension and postretirement costs.
Miscellaneous income decreased $28.9 million primarily due to the absence of a $21.8 million pre-tax gain recognized in fiscal 2011 as a result of unwinding two Treasury locks ($13.6 million, net of tax) and a $10.0 million one-time donation to a donor advised fund in fiscal 2012.
Interest charges decreased $5.1 million compared to the prior year due primarily to the prepayment of our 5.125% $250 million senior notes in the fourth quarter of fiscal 2012, refinancing long-term debt at reduced interest rates and reducing commitment fees from decreasing the number of credit facilities and extending the length of their terms in fiscal 2011.
Additionally, results for fiscal 2012 were favorably impacted by a state tax benefit of $11.3 million. Due to the completion of the sale of our Missouri, Iowa and Illinois service areas in the fiscal fourth quarter, the Company updated its analysis of the tax rate at which deferred taxes would reverse in the future to reflect the sale of these service areas. The updated

32


analysis supported a reduction in the deferred tax rate which when applied to the balance of taxable income deferred to future periods resulted in a reduction of the Company’s overall deferred tax liability.
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, 2013, 2012 and 2011. 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
 
2013
 
2012
 
2011
 
2013 vs. 2012
 
2012 vs. 2011
 
(In thousands)
Mid-Tex
$
158,900

 
$
142,755

 
$
144,204

 
$
16,145

 
$
(1,449
)
Kentucky/Mid-States
46,164

 
32,185

 
37,593

 
13,979

 
(5,408
)
Louisiana
52,125

 
48,958

 
50,442

 
3,167

 
(1,484
)
West Texas
28,085

 
27,875

 
29,686

 
210

 
(1,811
)
Mississippi
29,112

 
27,369

 
26,338

 
1,743

 
1,031

Colorado-Kansas
25,478

 
23,898

 
25,920

 
1,580

 
(2,022
)
Other
3,229

 
1,421

 
7,905

 
1,808

 
(6,484
)
Total
$
343,093

 
$
304,461

 
$
322,088

 
$
38,632

 
$
(17,627
)
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.
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.
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.

33


Review of Financial and Operating Results
Financial and operational highlights for our regulated transmission and storage segment for the fiscal years ended September 30, 2013, 2012 and 2011 are presented below.
 
For the Fiscal Year Ended September 30
 
2013
 
2012
 
2011
 
2013 vs. 2012
 
2012 vs. 2011
 
(In thousands, unless otherwise noted)
Mid-Tex Division transportation
$
179,628

 
$
162,808

 
$
125,973

 
$
16,820

 
$
36,835

Third-party transportation
66,939

 
64,158

 
73,676

 
2,781

 
(9,518
)
Storage and park and lend services
5,985

 
6,764

 
7,995

 
(779
)
 
(1,231
)
Other
16,348

 
13,621

 
11,729

 
2,727

 
1,892

Gross profit
268,900

 
247,351

 
219,373

 
21,549

 
27,978

Operating expenses
129,047

 
118,527

 
111,098

 
10,520

 
7,429

Operating income
139,853

 
128,824

 
108,275

 
11,029

 
20,549

Miscellaneous income (expense)
(2,285
)
 
(1,051
)
 
4,715

 
(1,234
)
 
(5,766
)
Interest charges
30,678

 
29,414

 
31,432

 
1,264

 
(2,018
)
Income before income taxes
106,890

 
98,359

 
81,558

 
8,531

 
16,801

Income tax expense
38,630

 
35,300

 
29,143

 
3,330

 
6,157

Net income
$
68,260

 
$
63,059

 
$
52,415

 
$
5,201

 
$
10,644

Gross pipeline transportation volumes — MMcf
649,740

 
640,732

 
620,904

 
9,008

 
19,828

Consolidated pipeline transportation volumes — MMcf
467,178

 
466,527

 
435,012

 
651

 
31,515

Fiscal year ended September 30, 2013 compared with fiscal year ended September 30, 2012

The $21.5 million increase in regulated transmission and storage gross profit compared to the prior-year period was primarily a result of the Gas Reliability Infrastructure Program (GRIP) filings approved by the Railroad Commission of Texas (RRC) during fiscal 2012 and 2013. During fiscal 2012, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $14.7 million, effective April 2012. On May 7, 2013, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $26.7 million that went into effect with bills rendered on and after May 7, 2013. GRIP filings increased period-over-period gross profit by $19.7 million.
This increase was partially offset by a $10.5 million increase in operating expenses largely attributable to increased depreciation expense as a result of increased capital investments and increased levels of pipeline and right-of-way maintenance activities to improve the safety and reliability of our system.
The APT rate case approved by the RRC on April 18, 2011 contained an annual adjustment mechanism, approved for a three-year pilot program, that adjusted regulated rates up or down by 75 percent of the difference between APT’s non-regulated annual revenue and a pre-defined base credit. The annual adjustment mechanism expired on June 30, 2013. APT requested to extend the annual adjustment mechanism until November 1, 2017. A hearing to review the request was held on October 29, 2013 with a final decision expected in December 2013.
Fiscal year ended September 30, 2012 compared with fiscal year ended September 30, 2011

The $28.0 million increase in regulated transmission and storage gross profit compared to the prior year was primarily a result of the rate case that was finalized and became effective in May 2011 as well as the GRIP filings approved by the RRC during fiscal 2011 and 2012. In May 2011, the RRC issued an order in the rate case of Atmos Pipeline - Texas that approved an annual operating income increase of $20.4 million. During fiscal 2011, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $12.6 million that went into effect in the fiscal fourth quarter. On April 10, 2012, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $14.7 million that went into effect with bills rendered on an after April 10, 2012.

Operating expenses increased $7.4 million primarily due to a $5.4 million increase in depreciation expense, resulting from higher investment in net plant.


34


Additionally, results for fiscal 2012 were favorably impacted by a state tax benefit of $2.3 million associated with an update of the estimated tax rate at which deferred taxes would reverse in future periods after the completion of the sale of our Missouri, Illinois and Iowa assets. Net income for this segment for fiscal 2011 was favorably impacted by a $6.0 million pre-tax gain recognized in March 2011 as a result of unwinding two Treasury locks ($3.9 million, net of tax).
Nonregulated Segment
Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation and represent approximately five percent of our consolidated net income.
AEH's primary business is to buy, sell and deliver natural gas at competitive prices to approximately 1,000 customers located primarily in the Midwest and Southeast areas of the United States. AEH accomplishes this objective by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.
AEH also earns storage and transportation demand fees primarily from our regulated natural gas distribution operations in Louisiana and Kentucky. These demand fees are subject to regulatory oversight and are renewed periodically.

Our nonregulated activities are significantly influenced by competitive factors in the industry and general economic conditions. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of buying, selling and delivering natural gas to offer more competitive pricing to those customers.
Further, natural gas market conditions, most notably the price of natural gas and the level of price volatility affect our nonregulated businesses. Natural gas prices and the level of volatility are influenced by a number of factors including, but not limited to, general economic conditions, the demand for natural gas in different parts of the country, the level of domestic natural gas production and the level of natural gas inventory levels.
Natural gas prices can influence:
The demand for natural gas. Higher prices may cause customers to conserve or use alternative energy sources. Conversely, lower prices could cause customers such as electric power generators to switch from alternative energy sources to natural gas.
Collection of accounts receivable from customers, which could affect the level of bad debt expense recognized by this segment.
The level of borrowings under our credit facilities, which affects the level of interest expense recognized by this segment.
Natural gas price volatility can also influence our nonregulated business in the following ways:
Price volatility influences basis differentials, which provide opportunities to profit from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access.
Increased or decreased 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.
Our nonregulated segment manages its exposure to natural gas commodity price risk through a combination of physical storage and financial instruments. Therefore, results for this segment include unrealized gains or losses on its net physical gas position and the related financial instruments used to manage commodity price risk. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. 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.

35


Review of Financial and Operating Results
Financial and operational highlights for our nonregulated segment for the fiscal years ended September 30, 2013, 2012 and 2011 are presented below.
  
For the Fiscal Year Ended September 30
 
2013
 
2012
 
2011
 
2013 vs. 2012
 
2012 vs. 2011
 
(In thousands, unless otherwise noted)
Realized margins
 
 
 
 
 
 
 
 
 
Gas delivery and related services
$
39,839

 
$
46,578

 
$
58,990

 
$
(6,739
)
 
$
(12,412
)
Storage and transportation services
14,641

 
13,382

 
14,570

 
1,259

 
(1,188
)
Other
(103
)
 
3,179

 
1,841

 
(3,282
)
 
1,338