10-K 1 ato201893010-k.htm 10-K Document

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, 2018
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 every Interactive Data File required to be submitted 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 such files).    Yes  þ        No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer    þ    Accelerated filer    ¨    Non-accelerated filer    ¨    Smaller reporting company    ¨    Emerging growth company    ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
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, 2018, was $9,175,655,493.
As of November 8, 2018, the registrant had 111,352,649 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 6, 2019 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
Adjusted diluted EPS from continuing operations
Non-GAAP measure defined as diluted earnings per share from continuing operations before the one-time, non-cash income tax benefit
Adjusted income from continuing operations
Non-GAAP measure defined as income from continuing operations before the one-time, non-cash income tax benefit
AEC
Atmos Energy Corporation
AEH
Atmos Energy Holdings, Inc.
AEM
Atmos Energy Marketing, LLC
AOCI
Accumulated Other Comprehensive Income
ARM
Annual Rate Mechanism
ATO
Trading symbol for Atmos Energy Corporation common stock on the NYSE
Bcf
Billion cubic feet
Contribution Margin
Non-GAAP measure defined as operating revenues less purchased gas cost
COSO
Committee of Sponsoring Organizations of the Treadway Commission
DARR
Dallas Annual Rate Review
ERISA
Employee Retirement Income Security Act of 1974
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Generally Accepted Accounting Principles
GRIP
Gas Reliability Infrastructure Program
GSRS
Gas System Reliability Surcharge
LTIP
1998 Long-Term Incentive Plan
Mcf
Thousand cubic feet
MDWQ
Maximum daily withdrawal quantity
Mid-Tex ATM Cities
Represents a coalition of 47 incorporated cities or approximately 8 percent of the Mid-Tex Division's customers.
Mid-Tex Cities
Represents all incorporated cities other than Dallas and Mid-Tex ATM Cities, or approximately 72 percent of the Mid-Tex Division’s customers.
MMcf
Million cubic feet
Moody’s
Moody’s Investor Service, Inc.
NGA
Natural Gas Act of 1938
NYMEX
New York Mercantile Exchange, Inc.
NYSE
New York Stock Exchange
PHMSA
Pipeline and Hazardous Materials Safety Administration
PPA
Pension Protection Act of 2006
PRP
Pipeline Replacement Program
RRC
Railroad Commission of Texas
RRM
Rate Review Mechanism
RSC
Rate Stabilization Clause
S&P
Standard & Poor’s Corporation
SAVE
Steps to Advance Virginia Energy
SEC
United States Securities and Exchange Commission
SGR
Supplemental Growth Rider
SIR
System Integrity Rider
SRF
Stable Rate Filing
SSIR
System Safety and Integrity Rider
TCJA
Tax Cuts and Jobs Act of 2017
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 one of the country’s largest natural-gas-only distributors based on number of customers. We deliver safe, clean, reliable, efficient, affordable and abundant 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. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.
Atmos Energy's vision is to be the safest provider of natural gas services. We intend to achieve this vision by:
operating our business exceptionally well
investing in our people and infrastructure
enhancing our culture.
Since 2011, our operating strategy has focused on modernizing our distribution and transmission system to improve safety and reliability. Since that time, our capital expenditures have increased approximately 13% annually. Additionally, during this period, we have added new or modified existing regulatory mechanisms to reduce regulatory lag. Our ability to increase capital spending annually to modernize our system has increased our rate base, which has resulted in rising earnings per share and shareholder value.
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
As of September 30, 2018, we manage and review our consolidated operations through the following three reportable segments:
The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states.
The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana.
The natural gas marketing segment is comprised of our discontinued natural gas marketing business.
These operating segments are described in greater detail below.
Distribution Segment Overview
Our distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The following table summarizes key information about our six regulated natural gas distribution divisions, presented in order of total rate base.

4


Division
 
Service Areas
 
Communities Served
 
Customer Meters
Mid-Tex
 
Texas, including the Dallas/Fort Worth Metroplex
 
550
 
1,697,171
Kentucky/Mid-States
 
Kentucky
 
230
 
182,510
 
 
Tennessee
 
 
 
150,661
 
 
Virginia
 
 
 
24,396
Louisiana
 
Louisiana
 
270
 
362,233
West Texas
 
Amarillo, Lubbock, Midland
 
80
 
313,828
Mississippi
 
Mississippi
 
110
 
269,333
Colorado-Kansas
 
Colorado
 
170
 
120,384
 
 
Kansas
 
 
 
135,820
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, 2018, we held 1,013 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. Historically, we have successfully renewed these franchises and believe that we will continue to be able to renew our franchises as they expire.
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, including a reasonable return on invested capital. In addition, we transport natural gas for others through our distribution systems.
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 the cost natural gas. Therefore, although substantially all of our distribution operating revenues fluctuate with the cost of gas that we purchase, distribution Contribution Margin (a Non-GAAP measure defined as operating revenues less purchased gas cost) is generally not affected by fluctuations in the cost of gas.
Additionally, some jurisdictions have performance-based ratemaking adjustments to provide incentives to 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 adjustments, purchased gas costs savings are shared between the utility and its customers.
Our supply of natural gas is provided by a variety of suppliers, including independent producers, marketers and pipeline companies, withdrawals of gas from proprietary and contracted storage assets and peaking and spot purchase agreements, as needed.
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 2018 were Castleton Commodities Merchant Trading L.P., CenterPoint Energy Services, Inc., Concord Energy LLC, ConocoPhillips Company, Devon Gas Services, L.P., DTE Energy Trading Inc., Mieco Inc., Sequent Energy Management, L.P., Targa Gas Marketing LLC and Tenaska Gas Storage & Marketing Ventures, LLC.
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 distribution operations in fiscal 2018 was on January 16, 2018, when sales to customers reached approximately 3.8 Bcf.

5


Currently, our distribution divisions utilize 38 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 (APT).
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 do not anticipate any problems with obtaining additional gas supply as needed for our customers.
Pipeline and Storage Segment Overview
Our pipeline and storage segment consists of the pipeline and storage operations of APT and our natural gas transmission operations in Louisiana. 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 Barnett Shale, the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Through its system, APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage reservoirs in Texas.
Revenues earned from transportation and storage services for APT are subject to traditional ratemaking governed by the RRC. Rates are updated through periodic 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; the most recent of which was completed in August 2017. APT’s existing regulatory mechanisms allow certain transportation and storage services to be provided under market-based rates.
Our natural gas transmission operations in Louisiana are comprised of a proprietary 21-mile pipeline located in the New Orleans, Louisiana area that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans in Louisiana that serve distribution affiliates of the Company, which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements.
Natural Gas Marketing Segment Overview
Through December 31, 2016, we were engaged in a nonregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. Additionally, AEM utilized proprietary and customer-owned transportation and storage assets to provide various services to its customers requested.
As more fully described in Note 15, effective January 1, 2017, we sold all of the equity interests of AEM to CenterPoint Energy Services, Inc. (CES), a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy has fully exited the nonregulated natural gas marketing business. Accordingly, these operations have been reported as discontinued operations.
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, including 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:
Formula rate mechanisms in place in four states that provide for an annual rate review and adjustment to rates.

6


Infrastructure programs in place in the majority of our states that provide for an annual adjustment to rates for qualifying capital expenditures. Through our annual formula rate mechanisms and infrastructure programs, we have the ability to recover over 85 percent of our capital expenditures within six months and 99 percent within twelve months.
Authorization in tariffs, statute or commission rules that allows us to defer certain elements of our cost of service such as depreciation, ad valorem taxes and pension costs, until they are included in rates.
WNA mechanisms in seven states that serve to minimize the effects of weather on approximately 97 percent of our distribution Contribution Margin.
The ability to recover the gas cost portion of bad debts in five states.
The following table provides a jurisdictional rate summary for our regulated operations as of September 30, 2018. 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
 
05/22/2018
 
$2,122,194
 
8.87%
 
47/53
11.50%
Colorado-Kansas
 
Colorado
 
05/03/2018
 
134,726
 
7.55%
 
44/56
9.45%
 
 
Colorado SSIR
 
01/01/2018
 
29,855
 
7.82%
 
48/52
9.60%
 
 
Kansas
 
03/17/2016
 
200,564
 
(3)
 
(3)
(3)
 
 
Kansas GSRS
 
02/27/2018
 
12,514
 
(3)
 
(3)
(3)
Kentucky/Mid-States
 
Kentucky
 
05/03/2018
 
427,646
 
7.41%
 
47/53
9.70%
 
 
Tennessee(8)
 
06/01/2017
 
302,953
 
7.49%
 
47/53
9.80%
 
 
Virginia
 
12/27/2016
 
47,581
 
(3)
 
(3)
(3)
Louisiana
 
Trans La
 
05/01/2018
 
169,120
 
7.26%
 
49/51
9.80%
 
 
LGS
 
07/01/2018
 
419,080
 
7.55%
 
44/56
9.80%
Mid-Tex Cities
 
Texas(9)
 
06/01/2017
 
2,362,937(2)
 
8.36%
 
45/55
10.50%
Mid-Tex — Dallas
 
Texas
 
02/14/2018
 
(3)
 
(3)
 
(3)
(3)
Mississippi
 
Mississippi(7)
 
01/01/2018
 
377,954
 
7.47%
 
47/53
9.67%
 
 
Mississippi - SIR(7)
 
01/01/2018
 
70,141
 
7.60%
 
47/53
9.92%
 
 
Mississippi - SGR
 
01/01/2018
 
23,718
 
8.70%
 
47/53
12.00%
West Texas(4)
 
Texas(10)
 
03/15/2017
 
(3)
 
(3)
 
(3)
10.50%
 
 
Texas-GRIP
 
06/05/2018
 
507,831
 
8.57%
 
48/52
10.50%
 

7


Division
 
Jurisdiction
 
Bad  Debt
Rider(5)
 
Formula Rate
 
Infrastructure Mechanism
Performance Based
Rate Program(6)
 
WNA Period
Atmos Pipeline —  Texas
 
Texas
 
No
 
Yes
 
Yes
N/A
 
N/A
Colorado-Kansas
 
Colorado
 
No
 
No
 
Yes
No
 
N/A
 
 
Kansas
 
Yes
 
No
 
Yes
No
 
October-May
Kentucky/Mid-States
 
Kentucky
 
Yes
 
No
 
No
Yes
 
November-April
 
 
Tennessee
 
Yes
 
Yes
 
No
Yes
 
October-April
 
 
Virginia
 
Yes
 
No
 
Yes
No
 
January-December
Louisiana
 
Trans La
 
No
 
Yes
 
Yes
No
 
December-March
 
 
LGS
 
No
 
Yes
 
Yes
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
 
Yes
Yes
 
November-April
West Texas(4)
 
Texas
 
Yes
 
Yes
 
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 regulatory 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)
The Mid-Tex rate base represents a “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base.
(3)
A rate base, rate of return, return on equity or debt/equity ratio was not included in the respective state commission’s final decision.
(4)
The West Texas Cities includes all West Texas Division cities except Amarillo, Channing, Dalhart and Lubbock.
(5)
The bad debt rider allows us to recover from ratepayers the gas cost portion of uncollectible accounts.
(6)
The performance-based rate program provides incentives to distribution companies to minimize purchased gas costs by allowing the companies and their customers to share the purchased gas costs savings.
(7)
The Mississippi Public Service Commission approved a settlement at its meeting on October 23, 2018, which included a rate base of $541.7 million, an authorized return of 7.81%, a debt/equity ratio of 45/55 and an authorized ROE of 10.24%. New rates were implemented November 1, 2018.
(8)
The Tennessee Public Utility Commission approved the Formula Rate Mechanism filing at its meeting on October 15, 2018, which included a rate base of $351.8 million, an authorized return of 7.26%, a debt/equity ratio of 49/51 and an authorized ROE of 9.8%.
(9)
The Mid-Tex Cities approved the Formula Rate Mechanism filing with rates effective October 1, 2018, which included a rate base of $2,587.3 million, an authorized return of 7.87%, a debt/equity ratio of 42/58 and an authorized ROE of 9.80%.
(10)
The West Texas Cities approved the Formula Rate Mechanism filing with rates effective October 1, 2018, which included a rate base of $505.7 million, an authorized return of 7.87%, a debt/equity ratio of 42/58 and an authorized ROE of 9.80%.
Although substantial progress has been made in recent years to improve rate design and recovery of investment across our service areas, we are continuing to seek improvements in rate design to address cost variations and pursue tariffs that reduce regulatory lag associated with investments. Further, potential changes in federal energy policy, federal safety regulations and changing economic conditions will necessitate continued vigilance by the Company and our regulators in meeting the challenges presented by these external factors.
Recent Ratemaking Activity
Net operating income increases resulting from ratemaking activity totaling $80.1 million, $104.2 million and $122.5 million, became effective in fiscal 2018, 2017 and 2016, as summarized below. The ratemaking outcomes for fiscal 2018 include the effect of tax reform legislation enacted effective January 1, 2018 and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit we will receive due to the decrease in our statutory tax rate.
 
 
Annual Increase (Decrease) to Operating
Income For the Fiscal Year Ended September 30
Rate Action
 
2018
 
2017
 
2016
 
 
(In thousands)
Annual formula rate mechanisms
 
$
92,472

 
$
90,427

 
$
114,974

Rate case filings
 
(12,853
)
 
12,961

 
7,716

Other ratemaking activity
 
457

 
784

 
(183
)
 
 
$
80,076

 
$
104,172

 
$
122,507



8


Additionally, the following ratemaking efforts seeking $52.8 million in annual operating income were initiated during fiscal 2018 but had not been completed as of September 30, 2018:
Division
 
Rate Action
 
Jurisdiction
 
Operating Income
Requested
 
 
 
 
 
 
(In thousands)
Mid-Tex
 
Formula Rate Mechanism
 
Mid-Tex Cities (1) (2)
 
$
28,036

Mid-Tex
 
Rate Case
 
ATM Cities (1)
 
4,252

Mid-Tex
 
Rate Case
 
Environs (1) (7)
 
(1,875
)
Mississippi
 
Infrastructure Mechanism
 
Mississippi (1) (3)
 
7,976

Mississippi
 
Formula Rate Mechanism
 
Mississippi (1) (3)
 
4,119

Kentucky/Mid-States
 
Formula Rate Mechanism
 
Tennessee (1) (4)
 
(5,032
)
Kentucky/Mid-States
 
Formula Rate Mechanism True-Up
 
Tennessee (1) (5)
 
(3,220
)
Kentucky/Mid-States
 
Rate Case
 
Kentucky (1)
 
14,424

Kentucky/Mid-States
 
Rate Case
 
Virginia (1)
 
605

West Texas
 
Formula Rate Mechanism
 
WT Cities (1) (6)
 
4,030

West Texas
 
Rate Case
 
Environs (1) (7)
 
(485
)
 
 
 
 
 
 
$
52,830


(1)
The filing amount reflects a 21% federal income tax rate resulting from the Tax Cuts and Jobs Act of 2017 (TCJA).
(2)
The Mid-Tex Cities approved a rate increase of $17.6 million effective October 1, 2018.
(3)
The Mississippi Public Service Commission approved a settlement at its meeting on October 23, 2018, for a combined $7.0 million increase. New rates were implemented November 1, 2018.
(4)
The Tennessee Public Utility Commission approved the Formula Rate Mechanism filing, which included $0.4 million related to the May 2017 true-up, at its October 15, 2018 meeting.
(5)
The Tennessee Formula Rate Mechanism Test Period Ended May 2018 reflects the discontinuance of the prior year true-up.
(6)
The West Texas Cities approved a rate increase of $2.8 million effective October 1, 2018.
(7)
Settlement pending Texas Railroad Commission approval.

Our recent ratemaking activity is discussed in greater detail below.
Annual Formula Rate Mechanisms
As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual 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. The following table summarizes our annual formula rate mechanisms by state.
 
 
Annual Formula Rate Mechanisms
State
 
Infrastructure Programs
 
Formula Rate Mechanisms
 
 
 
 
 
Colorado
 
System Safety and Integrity Rider (SSIR)
 
Kansas
 
Gas System Reliability Surcharge (GSRS)
 
Kentucky
 
Pipeline Replacement Program (PRP)
 
Louisiana
 
(1)
 
Rate Stabilization Clause (RSC)
Mississippi
 
System Integrity Rider (SIR)
 
Stable Rate Filing (SRF), Supplemental Growth Filing (SGR)
Tennessee
 
 
Annual Rate Mechanism (ARM)
Texas
 
Gas Reliability Infrastructure Program (GRIP), (1)
 
Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM)
Virginia
 
Steps to Advance Virginia Energy (SAVE)
 
(1)
Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation and other taxes (Texas only), until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.

9


The following table summarizes our annual formula rate mechanisms with effective dates during the fiscal years ended September 30, 2018, 2017 and 2016:
Division
 
Jurisdiction
 
Test Year Ended
 
Increase
(Decrease) in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
 
 
(In thousands)
 
 
2018 Filings:
 
 
 
 
 
 
 
 
Louisiana
 
LGS(1)
 
12/2017
 
$
(1,521
)
 
07/01/2018
West Texas
 
Amarillo, Lubbock, Dalhart and Channing(1)
 
12/2017
 
4,418

 
06/08/2018
Mid-Tex
 
Environs(1)
 
12/2017
 
1,604

 
06/05/2018
West Texas
 
Environs(1)
 
12/2017
 
826

 
06/05/2018
Atmos Pipeline - Texas
 
Texas(1)
 
12/2017
 
42,173

 
05/22/2018
Louisiana
 
Trans La(1)
 
09/2017
 
(1,913
)
 
05/01/2018
Colorado-Kansas
 
Kansas GSRS
 
09/2018
 
820

 
02/27/2018
Mississippi
 
Mississippi - SIR
 
10/2018
 
7,658

 
01/01/2018
Mississippi
 
Mississippi - SGR (2)
 
10/2018
 
1,245

 
01/01/2018
Mississippi
 
Mississippi - SRF (2)
 
10/2018
 

 
01/01/2018
Colorado-Kansas
 
Colorado SSIR
 
12/2018
 
2,228

 
12/20/2017
Atmos Pipeline - Texas
 
Texas
 
12/2016
 
28,988

 
12/05/2017
Kentucky/Mid-States
 
Kentucky - PRP
 
09/2018
 
5,638

 
10/27/2017
Kentucky/Mid-States
 
Virginia - SAVE (3)
 
09/2017
 
308

 
10/01/2017
Total 2018 Filings
 
 
 
 
 
$
92,472

 
 
 
 
 
 
 
 
 
 
 
2017 Filings:
 
 
 
 
 
 
 
 
Louisiana
 
LGS
 
12/2016
 
$
6,237

 
07/01/2017
Mid-Tex
 
Mid-Tex DARR
 
09/2016
 
9,672

 
06/01/2017
Mid-Tex
 
Mid-Tex Cities RRM
 
12/2016
 
36,239

 
06/01/2017
Kentucky/Mid-States
 
Tennessee ARM
 
05/2018
 
6,740

 
06/01/2017
Mid-Tex
 
Mid-Tex Environs
 
12/2016
 
1,568

 
05/23/2017
West Texas
 
West Texas Environs
 
12/2016
 
872

 
05/23/2017
West Texas
 
West Texas ALDC
 
12/2016
 
4,682

 
04/25/2017
Louisiana
 
Trans La
 
09/2016
 
4,392

 
04/01/2017
West Texas
 
West Texas Cities RRM
 
09/2016
 
4,255

 
03/15/2017
Colorado-Kansas
 
Kansas
 
09/2016
 
801

 
02/09/2017
Mississippi
 
Mississippi - SRF
 
10/2017
 
4,390

 
02/01/2017
Mississippi
 
Mississippi - SIR
 
10/2017
 
3,334

 
01/01/2017
Mississippi
 
Mississippi - SGR
 
10/2017
 
1,292

 
01/01/2017
Colorado-Kansas
 
Colorado - SSIR
 
12/2017
 
1,350

 
01/01/2017
Kentucky/Mid-States
 
Kentucky - PRP
 
09/2017
 
4,981

 
10/14/2016
Kentucky/Mid-States
 
Virginia - SAVE
 
09/2017
 
(378
)
 
10/01/2016
Total 2017 Filings
 
 
 
 
 
$
90,427

 
 
 
 
 
 
 
 
 
 
 
2016 Filings:
 
 
 
 
 
 
 
 
Louisiana
 
LGS
 
12/2015
 
$
8,686

 
07/01/2016
Kentucky/Mid-States
 
Tennessee
 
05/2017
 
4,888

 
06/01/2016
Mid-Tex
 
Mid-Tex Cities RRM
 
12/2015
 
25,816

 
06/01/2016

10


Mid-Tex
 
Mid-Tex DARR
 
09/2015
 
5,429

 
06/01/2016
Mid-Tex
 
Mid-Tex Environs
 
12/2015
 
1,325

 
05/03/2016
Atmos Pipeline - Texas
 
Texas
 
12/2015
 
40,658

 
05/03/2016
West Texas
 
West Texas Environs
 
12/2015
 
646

 
05/03/2016
West Texas
 
West Texas ALDC
 
12/2015
 
3,484

 
04/26/2016
Louisiana
 
Trans La
 
09/2015
 
6,216

 
04/01/2016
Colorado-Kansas
 
Colorado
 
12/2016
 
764

 
01/01/2016
Mississippi
 
Mississippi - SRF
 
10/2016
 
9,192

 
01/01/2016
Mississippi
 
Mississippi - SGR
 
10/2016
 
250

 
12/01/2015
Kentucky/Mid-States
 
Kentucky - PRP
 
09/2016
 
3,786

 
10/01/2015
Kentucky/Mid-States
 
Virginia - SAVE
 
09/2016
 
118

 
10/01/2015
West Texas
 
West Texas Cities
 
09/2015
 
3,716

 
10/01/2015
Total 2016 Filings
 
 
 
 
 
$
114,974

 
 

(1)
The operating income reflects a 21% federal income tax rate resulting from the TCJA.
(2)
In our next SRF filing, the SGR rate base will be combined with the SRF rate base, per Commission order.
(3)
The Company completed our Steps to Advance Virginia Energy (SAVE) program. On October 1, 2017 a refund factor was removed from the rate resulting in an operating income increase of $0.3 million.
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 (Decrease) in Annual
Operating Income
 
Effective Date
 
 
 
 
(In thousands)
 
 
2018 Rate Case Filings:
 
 
 
 
 
 
Colorado-Kansas
 
Colorado (1)
 
$
(241
)
 
05/03/2018
Kentucky/Mid-States
 
Kentucky (1)
 
(7,504
)
 
05/03/2018
Mid-Tex
 
City of Dallas (1)
 
(5,108
)
 
02/14/2018
Total 2018 Rate Case Filings
 
 
 
$
(12,853
)
 
 
2017 Rate Case Filings:
 
 
 
 
 
 
Atmos Pipeline - Texas
 
Texas
 
$
12,955

 
08/01/2017
Kentucky/Mid-States
 
Virginia
 
6

 
12/27/2016
Total 2017 Rate Case Filings
 
 
 
$
12,961

 
 
2016 Rate Case Filings:
 
 
 
 
 
 
Kentucky/Mid-States
 
Kentucky
 
$
2,723

 
08/15/2016
Kentucky/Mid-States
 
Virginia
 
537

 
04/01/2016
Colorado-Kansas
 
Kansas
 
2,372

 
03/17/2016
Colorado-Kansas
 
Colorado
 
2,084

 
01/01/2016
Total 2016 Rate Case Filings
 
 
 
$
7,716

 
 

 (1) The operating income reflects a 21% federal income tax rate resulting from the TCJA.


11


Other Ratemaking Activity
The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2018, 2017 and 2016:
Division
 
Jurisdiction
 
Rate Activity
 
Increase (Decrease) in Annual
Operating Income
 
Effective
Date
 
 
 
 
 
 
(In thousands)
 
 
2018 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad Valorem(1)
 
$
457

 
02/01/2018
Total 2018 Other Rate Activity
 
 
 
 
 
$
457

 
 
2017 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad-Valorem(1)
 
$
784

 
02/01/2017
Total 2017 Other Rate Activity
 
 
 
 
 
$
784

 
 
2016 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad-Valorem(1)
 
$
(183
)
 
02/01/2016
Total 2016 Other Rate Activity
 
 
 
 
 
$
(183
)
 
 
 
(1)
The Ad Valorem filing relates to property taxes that are either over or uncollected compared to the amount included in our Kansas service area’s base rates.
Other Regulation
We are 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 operations are also subject to various state and federal laws regulating environmental matters. From time to time, we receive inquiries regarding various environmental matters. We believe that our properties and operations substantially comply with, and are operated in substantial conformity with, applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which would have a material adverse effect on us or our operations. Our environmental claims have arisen primarily from former manufactured gas plant sites. The Pipeline and Hazardous Materials Safety Administration (PHMSA), within the U.S. Department of Transportation, develops and enforces regulations for the safe, reliable and environmentally sound operation of the pipeline transportation system. The PHMSA pipeline safety statutes provide for states to assume safety authority over intrastate and natural gas pipelines. State pipeline safety programs are responsible for adopting and enforcing the federal and state pipeline safety regulations for intrastate natural gas transmission and distribution pipelines.
The Federal Energy Regulatory Commission (FERC) allows, pursuant to Section 311 of the Natural Gas Policy Act (NGA), 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 under the NGA. Additionally, the FERC has regulatory authority over 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.
The SEC and the Commodities Futures Trading Commission, pursuant to the Dodd–Frank Act, established numerous regulations relating to U.S. financial markets. We enacted procedures and modified existing business practices and contractual arrangements to comply with such regulations. There are, however, some rulemaking proceedings that have not yet been finalized, including those relating to capital and margin rules for (non–cleared) swaps. We do not expect these rules to directly impact our business practices or collateral requirements. However, depending on the substance of these final rules, in addition to certain international regulatory requirements still under development that are similar to Dodd–Frank, our swap counterparties could be subject to additional and potentially significant capitalization requirements. These regulations could motivate counterparties to increase our collateral requirements or cash postings.
Competition
Although our regulated 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

12


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 pipeline and storage operations have historically faced competition from other existing intrastate pipelines seeking to provide or arrange transportation, storage and other services for customers. In the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.
Employees
At September 30, 2018, we had 4,628 employees, consisting of 4,564 employees in our distribution operations and 64 employees in our pipeline and storage 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) at their website, www.sec.gov, are also 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 2018, Michael E. Haefner, certified to the New York Stock Exchange that he was not aware of any violations by the Company of NYSE corporate governance listing standards. The Board of Directors also annually reviews and updates, if necessary, the charters for each of its Audit, Human Resources and Nominating and Corporate Governance Committees. All of the foregoing documents are posted on the Corporate Responsibility 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:
We are subject to state and local regulations that affect our operations and financial results.
We 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, as a regulated entity, we often need 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 in the context of traditional ratemaking. 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.”
However, in the last several years, a number of regulatory authorities in the states we serve have approved rate mechanisms that provide for annual adjustments to rates that allow us to recover the cost of investments made to replace existing infrastructure or reflect changes in our cost of service. These mechanisms work to effectively reduce the regulatory lag

13


inherent in the ratemaking process. However, regulatory lag could significantly increase if the regulatory authorities modify or terminate these rate mechanisms. 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.
We are also 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.
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 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 may experience increased federal, state and local regulation of the safety of our operations.
The safety and protection of the public, our customers and our employees is our top priority. We constantly monitor and maintain our pipeline and distribution systems to ensure that natural gas is delivered safely, reliably and efficiently through our network of more than 75,000 miles of distribution and transmission lines. However, in recent years, natural gas distribution and pipeline companies have faced 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 new laws and regulations may have at least a short-term adverse impact on our operating costs and financial results.
Distributing, transporting and storing natural gas involve risks that may result in accidents and additional operating costs.
Our operations involve a number of hazards and operating risks inherent in storing and transporting natural gas that could affect the public safety and reliability of our distribution system. While Atmos Energy, with the support from each of its regulatory commissions, is accelerating the replacement of aging pipeline infrastructure, operating issues such as as leaks, accidents, equipment problems and incidents, including explosions and fire, could result in legal liability, repair and remediation costs, increased operating costs, significant increased capital expenditures, regulatory fines and penalties and other costs and a loss of customer confidence. We maintain liability and property insurance coverage in place for many of these hazards and risks. However, because some of our transmission pipeline and storage 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 our general liability and property insurance, which policies are subject to certain limits and deductibles, our operations or financial results could be adversely affected.
Our growth in the future may be limited by the nature of our business, which requires extensive capital spending.
Our operations are capital-intensive. We must make significant capital expenditures on a long-term basis to modernize our distribution and transmission system to improve the safety and reliability and to comply with the safety rules and regulations issued by the regulatory authorities responsible for the service areas we operate. In addition, we must continually build new capacity to serve the growing needs of the communities we serve. The magnitude of these expenditures may be affected by a number of factors, including new regulations, the general state of the economy and weather.
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. The cost and availability of borrowing funds from third party lenders or issuing equity is dependent on the liquidity of the credit markets, interest rates and other market conditions. This in turn may limit the amount of funds we can invest in our infrastructure.
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 and Moody’s Investors Service, Inc. Similar to most companies, we rely upon access to both short-term and long-term credit and capital markets to

14


satisfy our liquidity requirements. If adverse credit conditions were to cause a significant limitation on our access to the private credit 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 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.
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 exposed to market risks that are beyond our control, which could adversely affect our financial results.
We are subject to market risks beyond our control, including (i) commodity price volatility caused by market supply and demand dynamics, counterparty performance or counterparty creditworthiness, and (ii) interest rate risk. We are generally insulated from commodity price risk through our 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 to the extent that we do not recover our actual interest expense in our rates.
The concentration of our operations in the State of Texas exposes our operations and financial results to economic conditions, weather patterns and regulatory decisions in Texas.
Approximately 70 percent of our consolidated 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, weather patterns and regulatory decisions by state and local regulatory authorities in Texas.
A deterioration in economic conditions could adversely affect our customers and negatively impact our financial results.
Any adverse changes in economic conditions in the United States, especially in the states in which we operate, could adversely affect the financial resources of many domestic households. As a result, our customers could seek to use less gas and it may be more difficult for them to pay their gas bills. This would likely lead to slower collections and higher than normal levels of accounts receivable. This, in turn, could increase our financing requirements. Additionally, should economic conditions deteriorate, our industrial customers could seek alternative energy sources, which could result in lower sales volumes.
Increased gas costs could adversely impact our customer base and customer collections and increase our level of indebtedness.
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.
If contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner, our ability to meet our customers’ natural gas requirements may be impaired and our financial condition may be adversely affected.
In order to meet our customers’ annual and seasonal natural gas demands, we must obtain a sufficient supply of natural gas, interstate pipeline capacity and storage capacity. If we are unable to obtain these, either from our suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, our financial condition and results of operations may be adversely affected. If a substantial disruption to or reduction in interstate natural gas pipelines’ transmission and storage capacity occurred due to operational failures or disruptions, legislative or regulatory actions, hurricanes, tornadoes, floods, terrorist or cyber-attacks or acts of war, our operations or financial results could be adversely affected.
Our operations are subject to increased competition.
In residential and commercial customer markets, our 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 our customer growth slows or if our customers further conserve their use of gas, resulting in reduced gas purchases and customer billings.

15


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 pipeline 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.
Adverse weather conditions could affect our operations or financial results.
We have weather-normalized rates for approximately 97 percent of our residential and commercial meters in our distribution operations, 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 operating results may continue to vary somewhat with the actual temperatures during the winter heating season. Additionally, sustained cold weather could challenge our ability to adequately meet customer demand in our operations.
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, 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, and any future legislative changes related to the provision of health care benefits. The impact of additional costs which are likely to be passed on to the Company is difficult to measure at this time.
The costs of providing a cash-balance pension plan to eligible full-time employees prior to 2011 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 due to sustained declines in equity markets or a reduction in bond yields could increase the costs of our 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; (ii) various actuarial calculations and assumptions which may differ materially from actual results due primarily to changing market and economic conditions, including changes in interest rates, and higher or lower withdrawal rates; and (iii) future government regulation.
The costs to the Company of providing these benefits and related funding requirements could also increase materially in the future, should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our financial results.
The inability to continue to hire, train and retain operational, technical and managerial personnel could adversely affect our results of operations.
Although the average age of the employee base of Atmos Energy is not significantly changing year over year, there are still a number of employees who will become eligible to retire within the next five to 10 years. If we were unable to hire appropriate personnel or contractors to fill future needs, the Company could encounter operating challenges and increased costs, primarily due to a loss of knowledge, errors due to inexperience or the lengthy time period typically required to adequately train replacement personnel. In addition, higher costs could result from loss of productivity or increased safety compliance issues. The inability to hire, train and retain new operational, technical and managerial personnel adequately and to transfer institutional knowledge and expertise could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.
The operations and financial results of the Company could be adversely impacted as a result of climate change or related additional legislation or regulation in the future.
To the extent climate change occurs, our businesses could be adversely impacted, although we believe it is likely that any such resulting impacts would occur very gradually over a long period of time and thus would be difficult to quantify with any degree of specificity. To the extent climate change would result in warmer temperatures in our service territories, financial results could be adversely affected through lower gas volumes and revenues. Such climate change could also cause shifts in population, including customers moving away from our service territories near the Gulf Coast in Louisiana and Mississippi. 
Another possible climate change would be more frequent and more severe weather events, such as hurricanes and tornadoes, which could increase our costs to repair damaged facilities and restore service to our customers. If we were unable to deliver natural gas to our customers, our financial results would be impacted by lost revenues, and we generally would have to

16


seek approval from regulators to recover restoration costs. To the extent we would be unable to recover those costs, or if higher rates resulting from our recovery of such costs would result in reduced demand for our services, our future business, financial condition or financial results could be adversely impacted. 
In addition, 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.
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, even though the Company has implemented policies, procedures and controls to prevent and detect these activities. We use our information technology systems to manage our distribution and intrastate pipeline and storage 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 and storage 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 to the extent not fully covered by such insurance coverage.
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 become 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, 2018, in our distribution segment, we owned an aggregate of 70,071 miles of underground distribution and transmission mains throughout our distribution systems. These mains are located on easements or rights-of-way. 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 pipeline and storage segment we owned 5,678 miles of gas transmission lines as well.

17


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, 2018:
State
 
Usable Capacity
(Mcf)
 
Cushion
Gas
(Mcf)(1)
 
Total
Capacity
(Mcf)
 
Maximum
Daily Delivery
Capability
(Mcf)
Distribution Segment
 
 
 
 
 
 
 
 
Kentucky
 
7,956,991

 
9,562,283

 
17,519,274

 
158,100

Kansas
 
3,239,000

 
2,300,000

 
5,539,000

 
45,000

Mississippi
 
1,907,571

 
2,442,917

 
4,350,488

 
31,000

Total
 
13,103,562

 
14,305,200

 
27,408,762

 
234,100

Pipeline and Storage Segment
 
 
 
 
 


 
 
Texas
 
46,083,549

 
15,878,025

 
61,961,574

 
1,710,000

Louisiana
 
411,040

 
256,900

 
667,940

 
56,000

Total
 
46,494,589

 
16,134,925

 
62,629,514

 
1,766,000

Total
 
59,598,151

 
30,440,125

 
90,038,276

 
2,000,100

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

Additionally, we contract for storage service in underground storage facilities on many of the interstate and intrastate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2018:
Segment
 
Division/Company
 
Maximum
Storage
Quantity
(MMBtu)
 
Maximum
Daily
Withdrawal
Quantity
(MDWQ)(1)
Distribution Segment
 
 
 
 
 
 
 
 
Colorado-Kansas Division
 
6,129,562

 
136,996

 
 
Kentucky/Mid-States Division
 
8,175,103

 
226,739

 
 
Louisiana Division
 
2,536,779

 
174,805

 
 
Mid-Tex Division
 
5,500,000

 
225,000

 
 
Mississippi Division
 
5,083,801

 
163,627

 
 
West Texas Division
 
5,000,000

 
161,000

Total
 
32,425,245

 
1,088,167

Pipeline and Storage Segment
 
 
 
 
 
 
Trans Louisiana Gas Pipeline, Inc.
 
1,000,000

 
47,500

 
 
 
 
 
Total Contracted Storage Capacity
 
33,425,245

 
1,135,667

 
(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, some of which are located in leased facilities.
ITEM 3.
Legal Proceedings.
See Note 11 to the consolidated financial statements, which is incorporated in this Item 3 by reference.

ITEM 4.
Mine Safety Disclosures.
Not applicable.

18



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 dividends paid per share of our common stock for fiscal 2018 and 2017 are listed below.
 
 
Fiscal 2018
 
Fiscal 2017
Quarter ended:
 
 
 
 
December 31
 
$
0.485

 
$
0.450

March 31
 
0.485

 
0.450

June 30
 
0.485

 
0.450

September 30
 
0.485

 
0.450

 
 
$
1.94

 
$
1.80

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, 2018 was 12,550. 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 2018 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 (S&P 500) 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, 2013 in our common stock, the S&P 500 and in the common stock of the companies in the Comparison Company Indices, as well as a reinvestment of dividends paid on such investments throughout the period.


19


Comparison of Five-Year Cumulative Total Return
among Atmos Energy Corporation, S&P 500 Index
and Comparison Company Index
chart-94cfb7f484ef547fbc9.jpg
    
 
Cumulative Total Return
 
9/30/2013
 
9/30/2014
 
9/30/2015
 
9/30/2016
 
9/30/2017
 
9/30/2018
Atmos Energy Corporation
100.00

 
115.52

 
145.03

 
190.13

 
218.98

 
250.80

S&P 500 Stock Index
100.00

 
119.73

 
119.00

 
137.36

 
162.92

 
192.10

Peer Group
100.00

 
116.03

 
128.49

 
158.62

 
185.66

 
196.95


The Comparison Company Index reflects the cumulative total return of companies in our peer group, which is comprised of 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 in the index are Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, DTE Energy Company, National Fuel Gas Company, NiSource Inc., ONE Gas, Inc., Spire Inc. (formerly The Laclede Group, Inc.), Vectren Corporation, WEC Energy Group, Inc., WGL Holdings, Inc., and Xcel Energy, Inc.

(1)
WGL Holdings Inc. was acquired prior to September 30, 2018. As a result, the cumulative total return of this company is not included in the Comparison Company Index represented in the graph above.


20


The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2018.
 
Number of
securities to be issued
upon exercise of
outstanding options, restricted stock units,
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
1,041,519

(1) 
$

 
1,752,235

Total equity compensation plans approved by security holders
1,041,519

 

 
1,752,235

Equity compensation plans not approved by security holders

 

 

Total
1,041,519

 
$

 
1,752,235


(1)
Comprised of a total of 422,996 time-lapse restricted stock units, 343,952 director share units and 274,571 performance-based restricted stock units at the target level of performance granted under our 1998 Long-Term Incentive Plan.
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
 
2018
 
2017
 
2016
 
2015
 
2014
 
(In thousands, except per share data)
Results of Operations
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,115,546

 
$
2,759,735

 
$
2,454,648

 
$
2,926,985

 
$
3,243,904

Contribution margin
$
1,947,698

 
$
1,834,199

 
$
1,708,456

 
$
1,631,310

 
$
1,521,844

Income from continuing operations
$
603,064

 
$
382,711

 
$
345,542

 
$
305,623

 
$
270,331

Net income
$
603,064

 
$
396,421

 
$
350,104

 
$
315,075

 
$
289,817

Diluted income per share from continuing operations
$
5.43

 
$
3.60

 
$
3.33

 
$
3.00

 
$
2.76

Diluted net income per share
$
5.43

 
$
3.73

 
$
3.38

 
$
3.09

 
$
2.96

Cash dividends declared per share
$
1.94

 
$
1.80

 
$
1.68

 
$
1.56

 
$
1.48

Financial Condition
 
 
 
 
 
 
 
 
 
Net property, plant and equipment(1)
$
10,371,147

 
$
9,259,182

 
$
8,268,606

 
$
7,416,700

 
$
6,709,926

Total assets
$
11,874,437

 
$
10,749,596

 
$
10,010,889

 
$
9,075,072

 
$
8,581,006

Capitalization:
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
4,769,951

 
$
3,898,666

 
$
3,463,059

 
$
3,194,797

 
$
3,086,232

Long-term debt (excluding current maturities)
2,493,665

 
3,067,045

 
2,188,779

 
2,437,515

 
2,442,288

Total capitalization
$
7,263,616

 
$
6,965,711

 
$
5,651,838

 
$
5,632,312

 
$
5,528,520

 
(1)
Amounts shown are net of assets held for sale related to the divestiture of our natural gas marketing business for fiscal years 2014 through 2016.

21


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: state and local regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; possible increased federal, state and local regulation of the safety of our operations; the inherent hazards and risks involved in distributing, transporting and storing natural gas; the capital-intensive nature of our business; our ability to continue to access the credit and capital markets to execute our business strategy; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; the impact of adverse economic conditions on our customers; changes in the availability and price of natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain operational, technical and managerial personnel; the impact of climate change or related additional legislation or regulation in the future; the threat of cyber-attacks or acts of cyber-terrorism that 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; 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 Notes 2 and 15 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 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.

22



Critical
Accounting Policy
Summary of Policy
Factors Influencing Application of the Policy
Regulation
Our distribution and pipeline 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 expected 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 or changes in the accounting for our various regulatory mechanisms 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 or regulatory mechanisms

Assessing the probability of the recoverability of deferred costs

Continuing to meet the criteria of a cost-based, rate regulated entity for accounting purposes

Unbilled Revenue
We follow the revenue accrual method of accounting for 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.

When permitted, we implement rates that have not been formally approved by our regulatory authorities, 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 amounts billed subject to refund

23


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

Assumed discount rate

Projected timing of future cash disbursements

Health care cost experience trends

Participant demographic information

Actuarial mortality assumptions

Impact of legislation

Impact of regulation

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



24


Non-GAAP Financial Measures
Our operations are affected by the cost of natural gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the income statement as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe Contribution Margin, a non-GAAP financial measure, defined as operating revenues less purchased gas cost, is a more useful and relevant measure to analyze our financial performance than operating revenues. As such, the following discussion and analysis of our financial performance will reference Contribution Margin rather than operating revenues and purchased gas cost individually. Further, the term Contribution Margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.
As described further in Note 12, the enactment of the Tax Cuts and Jobs Act of 2017 (the "TCJA") required us to remeasure our deferred tax assets and liabilities at our new federal statutory income tax rate as of December 22, 2017. The remeasurement of our net deferred tax liabilities resulted in the recognition of a non-cash income tax benefit of $158.8 million for the fiscal year ended September 30, 2018. Due to the non-recurring nature of this benefit, we believe that income from continuing operations and diluted earnings per share from continuing operations before the non-cash income tax benefit provide a more relevant measure to analyze our financial performance than income from continuing operations and consolidated diluted earnings per share from continuing operations in order to allow investors to better analyze our core results and allow the information to be presented on a comparative basis to the prior year. Accordingly, the following discussion and analysis of our financial performance will reference adjusted income from continuing operations and diluted earnings per share, which is calculated as follows:
 
For the Fiscal Year Ended September 30
 
2018
 
2017
 
Change
 
(In thousands, except per share data)
Income from continuing operations
$
603,064

 
$
382,711

 
$
220,353

TCJA non-cash income tax benefit
(158,782
)
 

 
(158,782
)
Adjusted income from continuing operations
$
444,282

 
$
382,711

 
$
61,571

 
 
 
 
 
 
Consolidated diluted EPS from continuing operations
$
5.43

 
$
3.60

 
$
1.83

Diluted EPS from TCJA non-cash income tax benefit
(1.43
)
 

 
(1.43
)
Adjusted diluted EPS from continuing operations
$
4.00

 
$
3.60

 
$
0.40


RESULTS OF OPERATIONS
Overview
Atmos Energy strives to operate its businesses safely and reliably while delivering superior shareholder value. Our commitment to modernizing our natural gas distribution and transmission systems requires a significant level of capital spending. We have the ability to begin recovering a significant portion of these investments timely through rate designs and mechanisms that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. The execution of our capital spending program, the ability to recover these investments timely and our ability to access the capital markets to satisfy our financing needs are the primary drivers that affect our financial performance.
During fiscal 2018, we recorded income from continuing operations of $603.1 million, or $5.43 per diluted share, compared to income from continuing operations of $382.7 million, or $3.60 per diluted share in the prior year.
After adjusting for the nonrecurring benefit recognized after implementing the TCJA, we recognized adjusted income from continuing operations of $444.3 million, or $4.00 per diluted share for the year ended September 30, 2018, compared to adjusted income from continuing operations of $382.7 million, or $3.60 per diluted share for the year ended September 30, 2017. The year-over-year increase of $61.6 million, or 16 percent, largely reflects rate increases driven by safety and reliability spending, weather that was 36 percent colder than the prior year, customer growth in our distribution business and the impact of the TCJA on our effective income tax rate, partially offset by reduced revenues as a result of implementing the TCJA. During the year ended September 30, 2018, we completed 18 regulatory proceedings, resulting in an increase in annual operating income of $80.1 million and had 11 ratemaking efforts in progress at September 30, 2018, seeking a total increase in annual operating income of $52.8 million.

25


Capital expenditures for fiscal 2018 totaled $1,467.6 million. Over 80 percent was invested to improve the safety and reliability of our distribution and transmission systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce regulatory lag to six months or less. We funded our current-year capital expenditures program primarily through operating cash flows of $1,124.7 million. Additionally, we issued $400 million of common stock during the year ended September 30, 2018. The net proceeds from the issuance were primarily used to repay short-term debt under our commercial paper program, to fund capital spending and for general corporate purposes. On October 4, 2018, we completed a public offering of $600 million 4.30% senior notes due 2048. We received net proceeds from the offering, after underwriting discount and estimated offering expenses of approximately $591 million, that were used to repay working capital borrowings pursuant to our commercial paper program. The effective interest rate of these notes is 4.37% after giving effect to the offering costs.
As a result of the continued contribution and stability of our earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 8.2% percent for fiscal 2019.

TCJA Impact
The TCJA introduced several significant changes to corporate income tax laws in the United States, which have been reflected in our consolidated financial statements for the year ended September 30, 2018. As a rate regulated entity, the effects of lower tax rates included in our cost of service rates will ultimately flow through to our utility customers in the form of adjusted rates. Therefore, the favorable impact of the reduction in our federal statutory income tax rate on our financial performance will be limited to items that impact our income before income taxes in the current period that have not yet been reflected in our rates (most notably increases to and decreases in commission-approved regulatory assets and liabilities recorded on our consolidated balance sheet) and market-based revenues that are earned from customers who utilize our assets. Note 12 to the consolidated financial statements details the various impacts of the TCJA on our financial position and results from operations. The most significant changes are summarized as follows:
Because our fiscal year started on October 1, 2017, our federal statutory income tax rate for fiscal 2018 was reduced from 35% to 24.5%. Our effective income tax rate for fiscal 2018 was 27.5%, before the effect of the return of the excess deferred tax liability and the one-time, non-cash income tax benefit. Our federal statutory income tax rate declined to 21% on October 1, 2018.
As a result of implementing the TCJA, we remeasured our net deferred tax liability using our new federal statutory income tax rate, which reduced our net deferred tax liability by $905.3 million. Of this amount, $746.5 million was reclassified to a regulatory liability called excess deferred tax liability. The remaining $158.8 million was recognized as a one-time, non-cash income tax benefit in our consolidated statement of income for the year ended September 30, 2018.
Atmos Energy supports our regulators' efforts to ensure our utility customers receive the full benefits of changes in our cost of service rates arising from tax reform. Income taxes, like other costs, are passed through to our customers in our rates; however, changes to customer rates must be approved by our regulators.
Beginning in the second quarter of fiscal 2018, we established regulatory liabilities in all our jurisdictions for the difference in taxes included in our cost of service rates that have been calculated based on a 35% statutory income tax rate and a 21% statutory income tax rate, which reduced our revenues. We have received approval from most of our regulators to adjust customer rates for the lower statutory income tax rate.
We have also received approval from regulators in several of our states to return amounts to customers related to the regulatory liability recorded for differences in our cost of service rates due to the change in the statutory income tax rate within one year.
We have received approval from regulators in several of our states to begin returning the Excess Deferred Tax Liability created upon implementation of the TCJA, as discussed above, over a period ranging from 18 to 40 years. For the year ended September 30, 2018, we amortized $1.6 million of this regulatory liability.
The enactment of the TCJA is expected to reduce our future cash flows from operations primarily due to 1) the collection of taxes at a lower rate and 2) the return of regulatory liabilities established in response to the enactment of the TCJA and regulatory activities to our utility customers. We intend to externally finance this reduction in operating cash flow in a balanced fashion in order to maintain an equity-to-total-capitalization ratio ranging from 50% to 60% to maintain our current credit ratings.


26


Consolidated Results
The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2018, 2017 and 2016.
 
 
For the Fiscal Year Ended September 30
 
2018
 
2017
 
2016
 
(In thousands, except per share data)
Operating revenues
$
3,115,546

 
$
2,759,735

 
$
2,454,648

Purchased gas cost
1,167,848

 
925,536

 
746,192

Operating expenses
1,224,564

 
1,106,653

 
1,051,226

Operating income
723,134

 
727,546

 
657,230

Interest charges
106,646

 
120,182

 
114,812

Income from continuing operations before income taxes
611,144

 
604,094

 
542,184

Income tax expense
166,862

 
221,383

 
196,642

One-time, non-cash income tax benefit
(158,782
)
 

 

Net income from continuing operations
603,064

 
382,711

 
345,542

Net income from discontinued operations

 
13,710

 
4,562

Net income
$
603,064

 
$
396,421

 
$
350,104

 
 
 
 
 
 
Diluted net income from continuing operations per share
$
5.43

 
$
3.60

 
$
3.33

Diluted net income from discontinued operations per share

 
0.13

 
0.05

Diluted net income per share
$
5.43

 
$
3.73

 
$
3.38

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
 
2018
 
2017
 
2016
 
(In thousands)
Distribution segment
$
442,966

 
$
268,369

 
$
233,830

Pipeline and storage segment
160,098

 
114,342

 
111,712

Net income from continuing operations
603,064

 
382,711

 
345,542

Net income from discontinued natural gas marketing operations

 
13,710

 
4,562

Net income
$
603,064

 
$
396,421

 
$
350,104

 
 
 
 
 
 
See the following discussion regarding the results of operations for each of our business operating segments.
Distribution Segment
The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of our distribution operations are our ability to earn our authorized rates of return, 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 to minimize regulatory lag and, ultimately, separate the recovery of our approved rates from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. The “Ratemaking Activity” section of this Form 10-K describes our current rate strategy, progress towards implementing that strategy and recent ratemaking initiatives in more detail.
We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Contribution margin 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 associated tax expense as a component of taxes, other than

27


income. Although changes in revenue related taxes arising from changes in gas costs affect Contribution Margin, over time the impact is offset within operating income.
Although the cost of gas typically does not have a direct impact on our Contribution Margin, 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. Currently, gas cost risk has been mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.
During fiscal 2018, we completed 16 regulatory proceedings in our distribution segment, resulting in an $8.9 million increase in annual operating income.
Review of Financial and Operating Results
Financial and operational highlights for our distribution segment for the fiscal years ended September 30, 2018, 2017 and 2016 are presented below.
 
For the Fiscal Year Ended September 30
 
2018
 
2017
 
2016
 
2018 vs. 2017
 
2017 vs. 2016
 
(In thousands, unless otherwise noted)
Operating revenues
$
3,003,047

 
$
2,649,175

 
$
2,339,778

 
$
353,872

 
$
309,397

Purchased gas cost
1,559,836

 
1,269,456

 
1,058,576

 
290,380

 
210,880

Contribution Margin
1,443,211

 
1,379,719

 
1,281,202

 
63,492

 
98,517

Operating expenses
962,344

 
874,077

 
839,318

 
88,267

 
34,759

Operating income
480,867

 
505,642

 
441,884

 
(24,775
)
 
63,758

Miscellaneous income (expense)
(1,849
)
 
(1,695
)
 
1,171

 
(154
)
 
(2,866
)
Interest charges
65,850

 
79,789

 
78,238

 
(13,939
)
 
1,551

Income before income taxes
413,168

 
424,158

 
364,817

 
(10,990
)
 
59,341

Income tax expense
107,880

 
155,789

 
130,987

 
(47,909
)
 
24,802

One-time, non-cash income tax benefit
(137,678
)
 

 

 
(137,678
)
 

Net income
$
442,966

 
$
268,369

 
$
233,830

 
$
174,597

 
$
34,539

Consolidated distribution sales volumes — MMcf
300,817

 
246,825

 
258,650

 
53,992

 
(11,825
)
Consolidated distribution transportation volumes — MMcf
150,566

 
141,540

 
133,378

 
9,026

 
8,162

Total consolidated distribution throughput — MMcf
451,383

 
388,365

 
392,028

 
63,018

 
(3,663
)
Consolidated distribution average cost of gas per Mcf sold
$
5.19

 
$
5.14

 
$
4.09

 
$
0.05

 
$
1.05


Fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017
Income before income taxes for our distribution segment decreased three percent, primarily due to an $88.3 million increase in operating expenses, partially offset by a $63.5 million increase in Contribution Margin. The year-to-date increase in Contribution Margin primarily reflects:
a $70.7 million net increase in rate adjustments, excluding rate adjustments resulting from the TCJA, primarily in our Mid-Tex, Kentucky/Mid-States, Mississippi and West Texas Divisions. These rate adjustments were driven primarily by increased safety and reliability spending.
a $12.2 million increase in net consumption, primarily in our Mid-Tex, Mississippi, Kentucky/Mid-States and Louisiana Divisions.
a $14.8 million increase in revenue-related taxes primarily in our Mid-Tex Division, offset by a corresponding $15.5 million increase in the related tax expense.
an $8.9 million increase in transportation margin primarily in our Kentucky/Mid-States Division.
an $8.4 million increase from customer growth, primarily in our Mid-Tex Division.

28


a $51.3 million decrease in Contribution Margin due to the inclusion of the lower statutory federal income tax rate in our revenues due to implementation of the TCJA. Of this amount, $30.0 million has been reflected in customer bills. The remaining $21.3 million relates to the establishment of regulatory liabilities for the difference between the former 35% federal statutory income tax rate and the current 21% rate.
The increase in operating expenses, which include operation and maintenance expense, bad debt expense, depreciation and amortization expense and taxes, other than income, largely reflects expenses incurred after we decided to undertake a planned outage of our natural gas distribution system in Northwest Dallas that affected approximately 2,400 homes. While the system was replaced, we provided financial assistance to the affected residents and incurred other related costs of approximately $24 million.
The remaining increase in operating expenses is primarily attributable to an increase in employee-related costs and incremental system integrity activities of $19.3 million, increased revenue-related taxes, as discussed above, and increased depreciation and property taxes of $22.5 million associated with increased capital investments.
Interest charges decreased $13.9 million, primarily from interest deferrals associated with our infrastructure spending activities in Texas and Louisiana.
The decrease in income tax expense primarily reflects a reduction in our effective tax rate from 36.7% to 26.1%, as a result of the TCJA. During fiscal 2018, in certain jurisdictions, we began amortizing the excess deferred income taxes in the amount of $1.6 million.
Fiscal year ended September 30, 2017 compared with fiscal year ended September 30, 2016
Income before income taxes for our distribution segment increased 16 percent, primarily due to a $98.5 million increase in Contribution Margin, partially offset by a $34.8 million increase in operating expenses. The year-over-year increase in Contribution Margin primarily reflects:
a $72.4 million net increase in rate adjustments, primarily in our Mid-Tex, Louisiana, Mississippi and West Texas Divisions. These rate adjustments were driven primarily by increased safety and reliability spending.
Customer growth, primarily in our Mid-Tex and Kentucky/Mid-States Divisions, which contributed an incremental $5.8 million.
a $5.8 million increase in transportation margin, primarily in the Kentucky/Mid-States and Mid-Tex Divisions.
a $5.2 million increase in revenue-related taxes primarily in our Mid-Tex and West Texas Divisions, offset by a corresponding $5.1 million increase in the related tax expense.
a $2.9 million increase in net consumption, despite weather that was 12 percent warmer than the prior year.
The increase in operating expenses was primarily due to increased depreciation expense and property taxes associated with increased capital investments, higher employee-related costs, increased revenue-related taxes, as discussed above, and higher pipeline maintenance and related activities, partially offset by lower legal costs.
The following table shows our operating income by distribution division, in order of total rate base, for the fiscal years ended September 30, 2018, 2017 and 2016. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
For the Fiscal Year Ended September 30
 
2018
 
2017
 
2016
 
2018 vs. 2017
 
2017 vs. 2016
 
(In thousands)
Mid-Tex
$
202,444

 
$
233,158

 
$
210,608

 
$
(30,714
)
 
$
22,550

Kentucky/Mid-States
81,105

 
75,214

 
63,730

 
5,891

 
11,484

Louisiana
70,609

 
69,300

 
55,857

 
1,309

 
13,443

West Texas
45,494

 
46,859

 
41,131

 
(1,365
)
 
5,728

Mississippi
47,237

 
38,505

 
37,398

 
8,732

 
1,107

Colorado-Kansas
32,333

 
34,658

 
31,840

 
(2,325
)
 
2,818

Other
1,645

 
7,948

 
1,320

 
(6,303
)
 
6,628

Total
$
480,867

 
$
505,642

 
$
441,884

 
$
(24,775
)
 
$
63,758


29


Pipeline and Storage Segment
Our pipeline and storage segment consists of the pipeline and storage operations of Atmos Pipeline-Texas Division (APT) and our natural gas transmission operations in Louisiana. 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 Barnett Shale, the Texas Gulf Coast and the Delaware and Midland Basins of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, as well as marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage facilities in Texas.
Our natural gas transmission operations in Louisiana are comprised of a proprietary 21-mile pipeline located in the New Orleans, Louisiana area that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and, on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans, which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements.
Our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Texas and Louisiana service areas. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation and storage of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the supply areas that we serve, which may influence the level of throughput we may be able to transport on our pipelines. Further, natural gas price differences between the various hubs that we serve in Texas could influences the volumes of gas transported for shippers through Texas pipeline systems and rates for such transportation.
The results of APT are also significantly impacted by the natural gas requirements of its local distribution company customers. Additionally, its operations may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
APT annually uses the Gas Reliability Infrastructure Program (GRIP) to recover capital costs incurred in the prior calendar year. Following the conclusion of its rate case in August 2017, APT made a GRIP filing that covered changes in net investment from October 1, 2016 through December 31, 2016 with a requested increase in operating income of $29.0 million. On December 5, 2017, the filing was approved. On February 15, 2018, APT made a GRIP filing that covered changes in net investment from January 1, 2017 through December 31, 2017 with a requested increase in operating income of $42.2 million. On May 22, 2018, the filing was approved.
On December 21, 2016, the Louisiana Public Service Commission approved an annual increase of five percent to the demand fee charged by our natural gas transmission pipeline for each of the next 10 years, effective October 1, 2017.
Review of Financial and Operating Results
Financial and operational highlights for our pipeline and storage segment for the fiscal years ended September 30, 2018, 2017 and 2016 are presented below.

30


 
For the Fiscal Year Ended September 30
 
2018
 
2017
 
2016
 
2018 vs. 2017
 
2017 vs. 2016
 
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue
$
354,885

 
$
338,850

 
$
315,726

 
$
16,035

 
$
23,124

Third-party transportation revenue
140,231

 
100,100

 
89,498

 
40,131

 
10,602

Other revenue
12,597

 
18,080

 
21,972

 
(5,483
)
 
(3,892
)
Total operating revenues
507,713

 
457,030

 
427,196

 
50,683

 
29,834

Total purchased gas cost
1,978

 
2,506

 
(58
)
 
(528
)
 
2,564

Contribution Margin
505,735

 
454,524

 
427,254

 
51,211

 
27,270

Operating expenses
263,468

 
232,620

 
211,908

 
30,848

 
20,712

Operating income
242,267

 
221,904

 
215,346

 
20,363

 
6,558

Miscellaneous expense
(3,495
)
 
(1,575
)
 
(1,405
)
 
(1,920
)
 
(170
)
Interest charges
40,796

 
40,393

 
36,574

 
403

 
3,819

Income before income taxes
197,976

 
179,936

 
177,367

 
18,040

 
2,569

Income tax expense
58,982

 
65,594

 
65,655

 
(6,612
)
 
(61
)
One-time, non-cash income tax benefit
(21,104
)
 

 

 
(21,104
)
 

Net income
$
160,098

 
$
114,342

 
$
111,712

 
$
45,756

 
$
2,630

Gross pipeline transportation volumes — MMcf
871,904

 
770,348

 
686,042

 
101,556

 
84,306

Consolidated pipeline transportation volumes — MMcf
663,900

 
596,179

 
505,303

 
67,721

 
90,876

Fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017
Income before income taxes for our pipeline and storage segment increased ten percent, primarily due to a $51.2 million increase in Contribution Margin, partially offset by a $30.8 million increase in operating expenses. The increase in Contribution Margin primarily reflects:
a $74.3 million increase in rates from the approved APT rate case and the GRIP filings approved in December 2017 and May 2018. The increase in rates was driven primarily by increased safety and reliability spending.
a net increase of $1.3 million due to wider spreads and positive supply and demand dynamics affecting the Permian Basin.
a $24.1 million decrease in Contribution Margin due to the inclusion of the lower statutory federal income tax rate in our revenues due to implementation of the TCJA. Of this amount, $11.4 million has been reflected in customer bills. The remaining $12.7 million relates to the establishment of regulatory liabilities, as discussed above.
The increase in operating expenses is primarily due to higher depreciation expense of $25.8 million associated with increased capital investments and an increase in employee-related costs.
The decrease in income tax expense primarily reflects a reduction in our effective tax rate from 36.5% to 29.8%, as a result of the TCJA.
Fiscal year ended September 30, 2017 compared with fiscal year ended September 30, 2016
Income before income taxes for our pipeline and storage segment increased slightly, primarily due to a $27.3 million increase in Contribution Margin, partially offset by a $20.7 million increase in operating expenses. The increase in Contribution Margin primarily reflects a $24.6 million increase in rates from the approved 2016 GRIP filing and the rate case finalized in August 2017 and higher through system revenue of $8.3 million, largely related to higher basis spreads due to increased production in the Permian Basin and incremental throughput on a pipeline acquired in the first quarter of fiscal 2017. Partially offsetting these increases was a decrease in Contribution Margin of $2.3 million due to lower excess retention gas sales in the current year. As noted above, as a result of the annual rate case, we did not file our annual GRIP filing during the second quarter of fiscal 2017, which influenced this segment's performance year-over-year.
Operating expenses increased $20.7 million, primarily due to increased depreciation expense and property taxes associated with increased capital investments.

31


Natural Gas Marketing Segment
Through December 31, 2016, we were engaged in an unregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices.
As more fully described in Note 15, effective January 1, 2017, we sold all of the equity interests of AEM to CenterPoint Energy Services, Inc. (CES), a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy has fully exited the nonregulated natural gas marketing business. Accordingly, a gain on sale from discontinued operations for $2.7 million was recorded and net income of $11.0 million for AEM is reported as discontinued operations for the year ended September 30, 2017, compared to net income of $4.6 million for AEM reported for discontinued operations for the year ended September 30, 2016.
Review of Financial and Operating Results
Financial and operational highlights for our natural gas marketing segment for the fiscal years ended September 30, 2017 and 2016 are presented below.
  
For the Fiscal Year Ended September 30
 
2017
 
2016
 
2017 vs. 2016
 
(In thousands, unless otherwise noted)
Operating revenues
$
303,474

 
$
1,005,090

 
$
(701,616
)
Purchased gas cost
277,554

 
968,118

 
(690,564
)
Contribution Margin
25,920

 
36,972

 
(11,052
)
Operating expenses
7,874

 
26,184

 
(18,310
)
Operating income
18,046

 
10,788

 
7,258

Miscellaneous income
30

 
109

 
(79
)
Interest charges
241

 
2,604

 
(2,363
)
Income before income taxes
17,835

 
8,293

 
9,542

Income tax expense
6,841

 
3,731

 
3,110

Income from discontinued operations
10,994

 
4,562

 
6,432

Gain on sale of discontinued operations, net of tax
2,716

 

 
2,716

Net income from discontinued operations
$
13,710

 
$
4,562

 
$
9,148

Gross natural gas marketing delivered gas sales volumes — MMcf
90,223

 
371,319

 
(281,096
)