Atmos Energy Corporation
2018 Integrated Annual Report
Our Vision:
To Be the Nation’s
Safest Natural
Gas Company
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Atmos Energy at a Glance
Delivering safe, clean and economical energy
to more than 3 million homes and businesses
Our Service Area
Colorado-Kansas Division
Denver, CO
West Texas Division
Lubbock, TX
Atmos Energy Corporation
Headquarters, Dallas, TX
Kentucky/Mid-States Division
Franklin, TN
Waha Hub
Mid-Tex Division
Atmos Pipeline-Texas Division
Dallas, TX
Carthage Hub
Mississippi Division
Flowood, MS
Katy Hub
Louisiana Division
Baton Rouge, LA
Natural gas distribution areas
Division offices
Proprietary storage
Major gas delivery hubs
Investment Highlights
> Regulated distribution assets in eight states serving more than 3 million customers.
> Projected annual capital expenditures of about $9 to $10 billion through fiscal 2023; over 80% spent
on safety and reliability.
> Earning on about 85% of annual capital expenditures within 6 months and on 99% within 12 months.
> 6% to 8% forecasted earnings per share and dividend growth through fiscal 2023.
> 16 consecutive years of annual EPS growth; 34 consecutive years of annual dividend growth.
ON THE COVER: Marc Scheller, Field Construction Coordinator (kneeling), and Ruben Ramos, Operation Supervisor, review maps for a project replacing
3.3 miles of 6-inch, 10-inch and 12-inch high pressure steel main lines, which serve as one of the main feeds into Greeley, Colorado.
s
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
To Our Shareholders
Atmos Energy is a company driven by investments: in our communities, in innovation, in our
operational assets and in our employees. We see this in our daily efforts to improve the lives of
others and to contribute to our communities. Our 4,600 employees are committed to serving
our customers exceptionally well while ensuring customer and employee safety in the 1,400
communities we serve. For Atmos Energy, fiscal year 2018 marked another successful milepost
in our long, sustainable journey to being the nation’s safest natural gas company.
We invested $1.5 billion in modernizing our transmission and distribution system. Earnings per diluted share increased
for the 16th consecutive year, and dividends increased for the 34th consecutive year. We were recognized as the
Most Trusted Utility Brand in the South by Market Strategies International in their annual Cogent Reports Utility
Trusted Brand and Customer Engagement: Residential Study. And our employees continue to execute our long-term
growth strategy of investing in the modernization of our system, mitigating risk, and providing exceptional service
to our customers in the communities where we live and work.
Today, there is heightened concern over the age and safety of our nation’s infrastructure, which includes
roads and bridges, as well as water, electrical and natural gas delivery systems. We recognized this need
long ago. We have been increasing our rate of pipe replacement each year, and it is now among the highest
of our peers nationwide. Over the last 10 years, we have invested $9 billion, and we plan to spend
$9-$10 billion over the next five years. Our long-term strategy of investing in safety and reliability benefits
our customers, employees, shareholders and the communities we serve.
Twenty years ago, we established the guiding principles that define our culture, which we refer to as AtmoSpirit. These
principles – Inspire Trust, Be at Your Best, Bring Out the Best in Others, Make a Difference and Focus on the Future –
summarize the values, beliefs and behaviors we embrace as a company. They are the foundation upon which we will meet
the needs of all of the stakeholders who are vital to the long-term sustainability of Atmos Energy. Our employees have
followed these principles without seeking recognition or awards, and it is this attitude that will propel our future.
Safely owning and operating more than 75,000 miles of distribution and transmission pipelines, many of which serve
some of the fastest-growing communities in the country, requires a strong partnership with all of our stakeholders.
That is why we are introducing our first integrated annual report. This report will highlight not only our fiscal 2018
financial performance, but also a few of the many things we do as a company every day to meet the needs of all of
our stakeholders.
We appreciate your interest in Atmos Energy, and we look forward to continuing on our journey to be the nation’s
safest natural gas company.
Kim R. Cocklin
Executive Chairman
of the Board
Michael E. Haefner
President and
Chief Executive Officer
November 15, 2018
ATMOS ENERGY CORPORATION | 1
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Corporate Governance
Strong governance is core to accomplishing our vision. From our Board of Directors to all
of our employees, we expect everyone to take responsibility for doing what is right for all
our stakeholders. That means conducting business ethically, instilling accountability in our
employees, and working with business partners who share our high standards and principles.
Our Operating Principles
Being the largest publicly traded, fully regulated natural gas-only company comes with great responsibility.
Our example reflects on the entire industry. We have a bold vision: to be the safest provider of natural gas
services, to be recognized for exceptional service, to be a great employer and to achieve superior financial
results. To achieve this vision, we must operate our business exceptionally well, invest in our people and
infrastructure, and enhance our culture. Our operating principles are essential to executing our strategy
and to sustaining our operating and financial performance.
Operating
Principles
1
2
3
4
5
6
Execute Exceptionally Well
Mitigate Risk
Improve Every Day
Adapt Quickly
Develop Employees, Grow Leaders
and Shape Culture
Build Relationships and Give Back
ATMOS ENERGY CORPORATION | 3
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
We evaluate new business partners not only for their quality and competence,
but also for their alignment with our ethical standards and values.
Leading with Integrity
Our Code of Conduct sets guidelines for ethical business
conduct among our directors, officers and employees.
They are required to complete annual code-of-conduct
training, which helps them recognize and deal with
ethical issues including, but not limited to, conflicts of
interest, gifts and entertainment, use of confidential
information, fair dealing, protection of corporate assets,
and compliance with rules and regulations. We provide
an anonymous hotline for employees and the public to
report any suspected violations.
We also expect our business partners to operate
ethically. We evaluate new business partners not only for
their quality and competence, but also for their alignment
with our ethical standards and values. Moreover, we use
local and minority-owned businesses in many of our
contracting services. We are a proud government contractor,
and we partner with a full range of well-qualified, diverse
local businesses, from landscapers and general contractors
to auto mechanics and plumbers.
Board of Directors
Our Board of Directors has the responsibility for risk
oversight of the Company as a whole. The Board’s leadership
structure is designed so that independent directors exercise
oversight of the Company’s management and key issues
related to strategy and risk. Only independent directors
serve on the Board’s Audit Committee, Human Resources
Committee, and Nominating and Corporate Governance
Committee, and all standing Board committees are chaired
by independent directors. Additionally, independent
directors regularly hold executive sessions of the Board
outside the presence of the Executive Chairman, the
President and CEO, or any other Company employee. And
they generally meet in a private session with the Executive
Chairman and the CEO at regularly scheduled Board
Leadership Demographics
21%
36%
60%
26%
Women on the Board of Directors
Women and minorities on the Board of Directors
Women or minority appointments to the Board in the last 5 years
Women and minority officers
New Hire Demographics
38%
38%
48%
Women or minority new hires
Women or minority senior engineers
Women or minority entry-level engineers
4 | ATMOS ENERGY CORPORATION
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Cybersecurity Commitment
We are dedicated to keeping sensitive information
about our employees, customers, vendors and
company secure. We are vigilant in assessing our risk
of cyber threats and respond accordingly. We have
a continued cycle of process improvement to help us
respond to the changing cybersecurity landscape.
Supporting Strong Governance
In addition to our Code of Conduct, our Board has adopted
several policies and guidelines to support good conduct
and governance:
•
Our Corporate Governance Guidelines assist the Board
in exercising its responsibilities to the Company and our
shareholders by providing a framework under which the
Board may conduct business.
Our Insider Trading Prevention Program governs
the purchase or sale of Company securities by our
directors and employees, especially when any material,
nonpublic information relating to the Company may
be in the possession of any director or employee.
Our Political Activities Policy provides guidelines on
our Company lobbying and political spending activities,
as well as engagement by our employees in the overall
political process.
Our Risk Compliance Committee has oversight over our
safety practices and cybersecurity.
Our shareholders vote on executive compensation
every year at our annual shareholders’ meeting.
•
•
•
•
meetings. Directors serve one-year terms upon election and
are re-elected to subsequent one-year terms by a shareholder
vote at the annual shareholder’s meeting.
Knowing that an effective Board of Directors represents
diverse viewpoints and backgrounds, we evaluate each
Director’s continued service annually, considering factors
such as diversity of skills, background and experience,
age, professional background, financial literacy, availability,
independence and other relevant leadership qualities.
Our Audit Committee is responsible for overseeing risks
associated with financial and accounting matters, including
compliance with all legal and regulatory requirements,
and internal control over financial reporting. In addition,
the Audit Committee has oversight responsibility for the
Company’s overall business risk management process,
which includes the identification, assessment, mitigation
and monitoring of key business risks, including cybersecurity,
on a company-wide basis.
Being a Diverse Company
Part of being a responsible business is recognizing the
value of diversity in our leadership and workforce. We
are committed to having a workforce that reflects the
diversity of each of the 1,400 unique communities we
serve. We are constantly striving to enhance our talent
pipeline by recruiting and hiring the best candidates.
Management Committee
Our Management Committee, composed of senior leaders,
leads the execution of the Company’s strategy as approved
by the Board of Directors. The Committee actively monitors
our operations and financial performance; ensures com-
pliance with our policies, procedures and ethical business
practices; and develops our strategy to achieve sustainable,
long-term performance.
ATMOS ENERGY CORPORATION | 5
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Fiscal 2018 Highlights
Earnings per diluted share increased for the 16th consecutive year, and dividends increased
for the 34th consecutive year. We invested $1.5 billion in modernizing our transmission and
distribution system. In addition, our consistent investment in the safety and technical training
of our workforce and our successful completion of infrastructure projects helped sustain our
financial stability and continued growth.
735 distribution miles 155 transmission miles
54,000 lines
127,000 hours
We replaced 735 miles
We replaced 155 miles
We replaced more than
We conducted 127,000
of aging natural gas
of transmission pipe-
54,000 service lines.
hours of safety and
distribution pipelines to
lines in fiscal 2018.
make our safe system
even safer and more
reliable.
technical training in
order to continue to
provide safe and
reliable service.
11.1%
$1.94 per share
255% return
$93.91 per share
Adjusted earnings per
Dividends paid in fiscal
Total shareholder return
Our stock closed at
diluted share from
2018 were $1.94 per
in fiscal 2018 was
$93.91 per share on
continuing operations
share. In November
14.5 percent. Since we
September 28, 2018.
increased 11.1 percent,
to $4.00* for fiscal
2018, marking our 16th
2018, the Board of
launched our growth
Directors increased the
through investment
dividend for the 35th
strategy in October
consecutive annual
consecutive year by
2011, total return to our
increase. Adjusted net
raising the indicated
shareholders has been
income for the fiscal
rate for fiscal 2019 to
255.6 percent.
year was $444 million,
$2.10 per share, an 8.2
compared to $396 million
percent increase over
in fiscal 2017.
fiscal 2018.
*This is a Non-GAAP measure. See page 8 for a reconciliation of our adjusted earnings per share to our GAAP financial results.
6 | ATMOS ENERGY CORPORATION
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
System Modernization
Supports Earnings Growth
Constructive Regulatory Mechanisms Support Efficient Conversion of
Investments in Safety and Reliability into Financial Results
$9 to $10 billion in annual capital
investments through 2023
Constructive rate mechanisms
reducing regulatory lag
6% to 8% consolidated EPS growth
)
s
n
o
i
l
l
i
b
n
i
(
e
s
a
B
e
t
a
R
$18.0
$16.0
$14.0
$12.0
$10.0
$8.0
$6.0
$4.0
$2.0
0
$14.5-$15.5
$8.0
$4.3
2013
2018
2023E
Pipeline and Storage
Distribution
Adjusted Earnings per Share
$5.40-$5.80
$4.002
$3.601
~85%
Earning on Annual Investments
Within 0–6 Months
Within 7–12 Months
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
Greater than 12 Months
2017
2018
2023E
1 Excludes $0.13 per share associated with discontinued operations
2 Excludes $1.43 per share associated with the implementation of the 2017 Tax Cuts and Jobs Act (TCJA)
5,000-6,000
miles
250,000-300,000
service lines
10 to 15% reduction
$66 per month
Over the next five years,
we expect to replace
5,000-6,000 miles of aging
natural gas distribution
and transmission pipelines
to make our system even
safer and more reliable.
Over the next five years,
we expect to replace
250,000-300,000 steel
service lines.
Over the next five years,
our system modernization
efforts are expected to
reduce methane emissions
from our system by 10-15
percent.
Our customers will
continue to enjoy safe
and clean natural gas at
affordable prices. By 2023,
we anticipate their average
monthly bill will be $66,
which is just 6 percent
higher than the average
monthly bill in 2008.
ATMOS ENERGY CORPORATION | 7
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Customer bills remain affordable, while shareholders have benefited from our
investments as our share price has appreciated with earnings growth.
Average Monthly Customer Bills
$70
$60
$50
$40
$30
$20
$10
$0
$66
$56
08
09
10
11
12
13
14
15
16
17
18
23E
Estimated bills for 2023 are based on normal weather.
Shareholder Value
Combining share appreciation and dividends, Atmos Energy has consistently delivered total shareholder return above
its gas distribution peers and the broader market over the past three and five years.
Continued Outstanding Positive Total Returns to our Shareholders*
151%
104%
92%
Atmos Energy
Peer Group
S&P 500 index
73%
58%
64%
15%
6%
18%
1-year
3-year
5-year
* Total shareholder
return contains share
price appreciation and
dividends paid.
Non-GAAP Reconciliation (in thousands, except per share data)
2018
2017
Income from continuing operations
TCJA non-cash income tax benefit
Adjusted income from continuing operations
Consolidated diluted EPS from continuing operations
Diluted EPS from TCJA non-cash income tax benefit
Adjusted diluted EPS from continuing operations
$
603,064
$
382,711
(158,782)
444,282
5.43
(1.43)
$
$
4.00
$
$
$
$
—
382,711
3.60
—
3.60
8 | ATMOS ENERGY CORPORATION
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Safety
With a commitment to being the safest provider of natural gas, we are doing our part to replace
the nation’s aging natural gas delivery network. Over the last ten years, we have invested
approximately $9 billion to modernize our pipeline infrastructure, which is more than three
times our profits during that time. We continued our trend of investment this year, with $1.5
billion spent to make our safe system even safer.
There’s Safety in Partnerships
We own and operate over 75,000 miles of natural gas pipelines, serving some of the fastest-growing
communities in the country. Safely owning, operating and modernizing such a dynamic system requires strong
partnerships between the communities we serve, the regulators who oversee our activities, and the investors
and creditors who ensure we have the financial resources necessary to continue improving our system.
In the jurisdictions where we operate, regulators understand
that it takes significant investment to modernize our natural
gas delivery network. Regulatory mechanisms allow us to
recover our costs and provide investors with a reasonable
Earnings vs. Investments ($ Millions)
Income from Continuing Operations
Capital Expenditures
1,600
1,400
1,200
1,000
800
600
400
200
0
09
10
11
12
13
14
15
return so that we can make these needed investments. Today,
we begin to earn on 85 percent of our capital spending within
the first six months and 99 percent within the first year.
Furthermore, the low price of natural gas enables us to
continue investing in the safety
and reliability of our system while
keeping customers’ bills afford-
able. During fiscal 2018, we were
among the first utilities in the
country to begin returning the
benefits of the 2017 Tax Cuts and
Jobs Act to our customers. Once
the TCJA is fully implemented,
our customers will save over $125
million per year. Since 2008, the
average customer monthly bill has
remained less than $60 a month.
While we plan to invest $9-$10
billion over the next five years, we
project that the average monthly
bill will remain a great value for
our customers.
16
17
18
ATMOS ENERGY CORPORATION | 9
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
As a company, we held over 53,000 hours of safety training in fiscal 2018.
Our OSHA rate of recordable injuries has decreased 23% since 2013.
Safety is Our Business
We operate our system safely and in full compliance with
state and federal regulations. We do this by monitoring our
system, repairing leaks, and operating an emergency hotline
24 hours a day, 7 days a week to respond to and investigate
reports of natural gas leaks. Every working day of the year,
company employees are performing regularly scheduled
leak surveys of our system, the frequency of which is governed
by regulations. To determine the schedule for pipeline
replacements, we use a risk-based prioritization model that
considers factors like the pipe’s age, location, material, leak
history, environmental factors and more.
Our number-one priority is the safety of our employees,
the public and our natural gas distribution system. To
perform their work well, Atmos Energy employees involved
in pipeline inspection and improvement are highly trained.
Field employees spend about one-fifth of their time in the
classroom, in addition to on-the-job training and education.
They also receive extensive training in safe processes and
how to keep customers and communities safe. As part of our
never-ending quest to be the safest provider of natural gas
services, field employees start each day with a safety meeting.
As a company, we conducted over 53,000 hours of safety
training in fiscal 2018. Our OSHA rate of recordable injuries
has decreased 23 percent in the last five years.
We have robust, multi-channel safety outreach efforts
through our public awareness campaigns, community
involvement, and continued relationships with regulators,
city leaders and first responders. We use a variety of ways to
deliver safety information to our customers and the public,
including bill inserts, on-hold messaging, signage, customer
e-mails and social media campaigns. In fiscal 2018, our social
media safety campaigns received over 11 million views.
Our safety mascots, Gus the Gopher and Rosie the Skunk,
engage our customers and the public in learning how to call
811 before you dig, and what to do if you smell natural gas.
We also partner with fire departments and other first
responders in order to provide a seamless response in the
event of a natural gas emergency. Our Atmos Energy First
Responder Natural Gas Workshops provide emergency
response teams with detailed information and procedures on
how to safely work around natural gas and carbon monoxide.
Meet Gus and Rosie
Gus the Gopher and Rosie the
Skunk are our natural gas safety
ambassadors. Gus reminds people
to call 811 before digging, and
Rosie teaches people to detect
natural gas using their senses.
Gus the Gopher wins
Our video “Gus the Gopher for
Call 811” won the top video
in the external category of
the American Gas Association
Safety Awareness Video
Excellence awards.
10 | ATMOS ENERGY CORPORATION
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Investing in Technology to Improve Safety
Atmos Energy reviews advances in technology and
incorporates them as appropriate for leak detec-
tion and monitoring. This includes state-of-the-art
technologies for leak detection, monitoring and
leak repair prioritization. We use the best available
monitoring methods for safety and to better serve
our customers, including advanced mobile detection
technology for surveying our distribution system
that is 1,000 times more sensitive than traditional
technologies. Examples include:
> Remote Methane Leak Detection (laser-based
gas detector – RMLD)
> Flame Ionization Detector (FID)
> Cavity Ring-Down Spectroscopy (CRDS)
> Combustible Gas Detector (CGI)
> Optical Methane Detector (OMD)
> Forward Looking Infrared Camera (FLIR)
We use FLIR cameras, RMLDs, FIDs and CGIs to monitor compressors, distribution gate stations and storage fields.
RMLD, CGI, CRDS and OMD are used to conduct mobile inspections of buried natural gas distribution and trans-
mission pipelines. Choosing the proper equipment to do a leak survey is dependent on several different criteria,
including but not limited to safety, weather, instrument capabilities, location, application and experience.
New Technologies Keep Everyone Safer
At Atmos Energy, we continually leverage new tech-
nologies to keep our employees, our delivery network
and the public safe. We use multiple technologies to
perform leak surveys, some of which include infrared-
based leak detection, laser-based technologies and
new technologies that have been developed for our
industry. We are always working with industry and
technology partners to develop and evaluate new
technologies to enhance safety. For years we have
partnered with the Gas Technology Institute, which
develops technology-based solutions for the natural
gas industry. We were among the early participants
in our industry to evaluate technologies that had the
potential to be adapted to our business. This part-
nership has produced tools we are incorporating into
our daily processes, such as mobile technology that
captures critical infrastructure data during construc-
tion and operations.
Safety Performance by the Numbers
OSHA RATE – Recordable Injuries per hours worked
DART RATE – Days Away/Restricted Duty/Transfer Injuries
per hours worked
RMVC RATE – Reportable Motor Vehicle Collision Rate
OSHA RATE
DART RATE
RMVC RATE
2013
3.79
1.93
4.99
2017
2.91
1.92
4.97
Reported on a calendar-year basis.
ATMOS ENERGY CORPORATION | 11
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
All Atmos Energy operations employees who are new to their roles spend weeks at
Gas City perfecting their skills and enhancing their knowledge.
A City Built for Training
We are proud of our state-of-the-art
training facility in Plano, Texas,
the Charles K. Vaughan Center. It’s
home to Gas City, where employees
received more than 73,000 hours
of hands-on technical training in
fiscal 2018 and over 850,000 hours
since the facility opened in 2010.
All Atmos Energy operations em-
ployees who are new to their roles
spend weeks at Gas City perfecting
their skills and enhancing their
knowledge. We also hold natural
gas safety events for first responders,
community officials and school
children at the center. Class is
always in session at Gas City.
Training Facts
53,000
73,000
850,000
Approximate total safety training
hours in FY 2018
Approximate total technical training
hours in FY2018
Approximate training hours since
the Charles K. Vaughan Center
opened in 2010
12 | ATMOS ENERGY CORPORATION
ATMOS ENERGY CORPORATION | 13
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Environment
As a distributor of natural gas, we work with the cleanest fossil fuel in existence. And thanks
to advances in technology, America’s supply of natural gas will likely meet our energy needs
for the next 100 years. Delivering this vital energy resource safely, reliably and with minimal
environmental impact is our top priority.
Natural Gas, the Cleanest Fossil Fuel
Natural gas is the cleanest fossil fuel. From extraction to delivery, natural gas is 92 percent energy efficient,
and it keeps improving. Local gas distribution systems are estimated to account for only 0.1 percent
of natural gas emissions, down 74 percent since 1990. Leaks are decreasing, too. They’re down 25 percent
from mains and 16 percent from service lines.
Modernizing Infrastructure to Reduce
our Carbon Footprint
Replacing pipelines also reduces leaks and methane
emissions. We track and report greenhouse gas
emissions in accordance with the Environmental
Protection Agency’s (EPA) Greenhouse Gas Reporting
Rule, which requires reporting of greenhouse gas data
and other relevant information from large sources and
suppliers in the United States. In addition, all of our
operating divisions report to various state agencies that
have environmental jurisdiction over our activities.
We are a founding partner of the EPA’s Natural Gas
STAR Methane Challenge Program, a voluntary part-
nership that encourages oil and natural gas companies
to improve efficiency and reduce methane emissions.
Since 2012, we’ve replaced over 3,500 miles of
pipe. In that time, we’ve decreased total emissions
due to the use and loss of natural gas by 13.7 percent.
Over the next five years, we plan to replace between
5,000 and 6,000 miles of distribution and transmission
pipes. Included in this total is the replacement of
all remaining cast iron main by 2021. As we continue
to replace infrastructure, we estimate a 50-percent
reduction in methane emissions by 2035.
Distribution Miles Replacement Rate
s
e
l
i
M
1,000
800
600
400
200
0
13
14
15
16
17
18
19E-23E
Industry Identified Materials – Bare Steel, Cast Iron, Vintage Plastics
Other Risk-Based Materials
Transmission Miles Replacement Rate
s
e
l
i
M
180
160
140
120
100
80
60
40
13
14
15
16
17
18
19E-23E
ATMOS ENERGY CORPORATION | 15
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Our LEED-certified buildings reduce water usage
by about 50 to 60% annually.
Protecting People, Places and Our Planet
The environment we share with our customers, shareholders
and communities is as important to us as it is to all
stakeholders. Our goals are to minimize the release of any
environmentally damaging substance; to reduce waste and
dispose of it wisely; and to lessen our environmental impact
by using safe technologies and procedures.
We strive to minimize methane emissions when we
install, repair and remove pipe. When possible, we use
compression to transport natural gas into another pipe
when we are temporarily taking assets out of service, which
reduces the loss of natural gas into the environment. When
compression is not a viable alternative, we flare or burn the
natural gas versus venting it. Burning the natural gas
converts it into carbon dioxide, which has a 21 percent
smaller global warming impact compared to the methane
released during venting.
D
E
E
L
We also practice sustainable facility design using
responsible materials and efficient building operations. We
are proud to have built nine LEED-certified buildings, with
four more underway as of September 30, 2018. Due to the
sustainable design of our buildings, we have reduced our
environmental footprint by approximately 541 metric tons
of carbon dioxide, 4,868 grams of sulfur dioxide and 2,372
grams of nitrous oxide per year. Additionally, we estimate
that our LEED-certified buildings reduce water usage by
about 50 to 60 percent annually.
Reclamation of areas disturbed during construction
projects is also a priority. Before beginning any project, we
conduct a comprehensive environmental review in order to
understand our possible impact on species habitat, water
and cultural resources. And when a project is finished,
16 | ATMOS ENERGY CORPORATION
we strive to leave the smallest possible
footprint. We sow seeds of native grasses
to help with environmental restoration,
and continue to monitor the surrounding
vegetation density of the project area.
In addition, we purchase credits from
wetland mitigation banks, if necessary,
to replace any wetlands that may have
been impacted in the area in which
we’ve worked.
Partnering with Others to Promote
Environmental Responsibility
According to the EPA, municipal solid
waste landfills are the third-largest source
of human-related methane emissions
in the United States. To prevent methane
from migrating into the atmosphere,
landfill gas producers capture and convert
the emissions from landfills into a
renewable energy source. Landfill gas
producers need transmission companies
like Atmos Energy to transport their
renewable gas to market. Since 2010, we
have partnered with one of the largest
landfill gas producers in Louisiana at
up to 4,500 Mcf/day. During non-peak
demand periods, we purchase pipeline-
quality natural gas, blend it with the
natural gas from the landfill gas so that
it meets pipeline quality standards, and
then sell this gas to a power generator
and local distribution company at cost.
Similarly in Texas, we partner with two landfill facilities
to receive and transport pipeline quality natural gas. Atmos
Energy receives up to 7,000 Mcf/day of gas from one landfill
and 3,100 Mcf/day of gas from the other. The methane pro-
duced naturally at these landfills is captured and processed
before it’s received to ensure it meets our current pipeline
gas specification. While the transportation of landfill gas
is a small part of what we do, it is an important part of
a solution to economically reduce methane emissions.
Reducing the consumption and transportation of paper
can make a big impact on our environment. That’s why
we have provided our customers with a better, more
environmentally friendly choice for receiving and paying
their utility bills. Over 40 percent of our customers have
signed up for electronic billing, giving us one of the highest
e-bill percentages in the industry. In 2018, we saved over
152,000 pounds of paper, or the equivalent of approximately
1,800 trees, which we could not have done without the
participation of our customers.
Pipeline Projects Abound
Pipeline replacement projects are in the works
throughout our eight-state service area. The D-9
Project in Texas (pictured above), which is replacing
3.3 miles of 18-inch, 1955-vintage pipe with
20-inch high-pressure steel pipe, not only makes
our system safer but also adds much-needed
natural gas capacity.
ATMOS ENERGY CORPORATION | 17
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Natural Gas: Making America Stronger
Natural gas is more than a clean, reliable energy source: it’s a great investment in
America’s future. By creating jobs, saving families money and helping protect the
environment, natural gas is doing good things for Americans all across the country.
number one
America is now the world’s number-one
producer of natural gas.
Low natural gas prices have saved American businesses
about $76 billion in energy savings since 2009.
$76 billion
2 million jobs
The industry supplies nearly 2 million jobs in America.
By 2035, this is expected to rise to 3.5 million.
Families save about $875 a year
using natural gas appliances.
$875 annually
18 | ATMOS ENERGY CORPORATION
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Natural Gas Advantage: Enhancing Communities
Affordable
It’s a fact that natural gas is helping to transform communities.
Along with creating good-paying jobs, natural gas is a corner-
stone of industries across our states, like manufacturing and
agriculture. It reduces costs and increases energy efficiency at our
schools. Because it’s reliable, natural gas ensures that hospitals
have dependable and efficient operations and patient comfort.
68
MILLION
U.S. HOMES USE
NATURAL GAS
Shippers, trucking fleets, municipalities, trash companies and public transit systems are achieving lower greenhouse gas
emissions through greater use of natural gas vehicles. In fact, there are over 175,000 natural gas vehicles
being used by companies such as UPS, Waste Management, AT&T, Ryder, Anheuser-Busch, Fed-Ex and others.
That’s not all – over 11,000 public transit buses and new bus orders use natural gas.
Natural Gas Advantage: Protecting Our Environment
lowest level in 25 years
You can breathe a little easier thanks to natural gas. Natural gas produces lower levels of emissions than other fossil
fuels, and helps to protect the environment. So while U.S. natural gas production has risen significantly,
our nation’s greenhouse gas emissions have dropped to their lowest level in over 25 years.
That’s a win-win for us and for our planet.
ATMOS ENERGY CORPORATION | 19
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Building Relationships
Beyond a doubt, we believe people are the ultimate source of energy. Our relationships with
our communities, employees and customers have earned us a reputation as an organization
with a deeply human spirit. We never forget that we live in the communities we serve, which
is all the more reason to give them our best.
Giving Where We Serve and Making a Difference
Giving back to the community is part of who we are as a company. We make a difference by offering
customer assistance programs to help the elderly, disabled, veterans and low-income families in our service
areas. Our Share the Warmth program, supported by donations from customers, employees and share-
holders, distributes funds to local nonprofit organizations to help pay natural gas bills for eligible customers.
We also participate in the federally funded Low Income Home Energy Assistance Program (LIHEAP), which
helps meet the energy needs of underserved families.
Being Good Neighbors
Living, working and raising families in the communities
we serve makes this commitment personal to all of our
employees. Community service is a key part of our culture.
In addition to providing energy assistance, we have a long
history of committing 1.5 percent of our distribution
division earnings to charitable organizations that offer
community services in the areas we care most about:
health, education and community development.
We partner with agencies such as United Way and
The Salvation Army during our annual week of giving
campaign. We offer employees the opportunity to make a
company-matched donation that supports the organization
of their choice. We host Science, Technology, Engineering
and Math (STEM) camps for youth, where we share
information about energy industry careers. Individually,
our employees also give generously of their time. Every
year, Atmos Energy employees volunteer an average of
more than 35,000 hours. Employees adopt a school, read
to children, deliver Meals on Wheels, support Special
Olympics, serve on local boards and commissions, and
volunteer through Habitat for Humanity.
FY 2018 Energy Assistance Programs
$2.7 million
Total assistance in FY 2018
11th
Share the Warmth bus donated
11,478
Number of families assisted
$1.2 million
Contributed by customers to
Share the Warmth
FY 2018 Charitable Contributions
$6.1 million
Donated by Atmos Energy
$700,000
Donated by employees
20 | ATMOS ENERGY CORPORATION
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
We provided our employees more than $1 million in
education assistance over the last five years.
Empowering Our People
Our employees are our greatest asset. They’re also our most
important investment. From recruitment to training to career
development, we believe in providing our employees with
the best tools and the most opportunities to succeed.
We recruit and hire people with a variety of skills,
talents, backgrounds and experiences who want to be part
of our energetic, diverse and safety-conscious workforce.
They learn about and experience our corporate culture in
our three-day onboarding program. Those who teach the
program are chosen based on how well they embody the
AtmoSpirit culture. Also, we have a Culture Council made
up of employees from across the enterprise chartered to
strengthen, promote and sustain our culture.
Employees who go through technical training learn every
aspect of their jobs, from safety to customer service, and
spend most of their time in hands-on training. They’re also
trained on the job with coaches who ensure each person is
ready to work properly and safely.
We also want our employees to take their education as
far as they desire, and we help them do so through the
Robert W. Best Education Assistance program. Over the last
five years, we provided our employees more than $1 million
in education assistance.
ATMOS ENERGY CORPORATION | 21
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Whether chatting with an agent or scheduling a service technician, customers receive efficient,
knowledgeable and courteous service from our customer contact centers.
Customer service by the numbers
3.9m
96%
97%
Calls in FY18
Customers satisfied with agents
Customers satisfied with on-site technicians
22 | ATMOS ENERGY CORPORATION
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Our 24/7 online Account Center makes it easy for customers
to interact with us when it is convenient for them.
18-Year ESL Volunteer
Collections Specialist Sonia Vazquez is director of the
350-student English as a Second Language (ESL)
program at Prestonwood Baptist Church in Plano, Texas,
where she has volunteered for 18 years, overseeing
11 classes. The primary student language is Spanish,
followed by Portuguese.
Classes are held two nights a week from September
to May. The five-level course curriculum starts with
Basic English and ends with idioms. “Idioms are the
most difficult for the students to grasp because they
translate the phrase literally,” Vazquez says. “Some-
thing like ‘I am feeling under the weather’ makes
them think: standing under an umbrella when it is
raining or snowing.”
Going the Extra Mile for Customers
Among the core values that make our company
sustainable is our dedication to exceptional customer
service. Because we continue to invest in technologies
which enable our customers to interact with us efficiently
and at times that are convenient for them, our customer
satisfaction scores keep climbing.
Customers certainly appreciate our relentless drive
to keep them safe, but they also notice that we go out
of our way to make every customer’s experience a
pleasant one. We’re friendly and efficient, we respond
to their needs quickly, and we’re easy to interact with.
We have continued to understand our customers’
needs and to invest in an advanced customer service
system that provides flexibility in how they interact
with us. These efforts have resulted in bills that are
easier to read and a convenient, user-friendly online
account center, which has increased the number of
customers managing their accounts online by 35 per-
cent. When customers do use our call center, we score
high marks on customer satisfaction.
Sharing the Warmth
When the temperature drops, Atmos Energy
generosity kicks in to help the elderly, disabled
and other vulnerable customers. We work with
hundreds of community action agencies to help
customers pay their bills and stay warm.
ATMOS ENERGY CORPORATION | 23
A T M O S E N E R G Y I N T E G R A T E D A N N U A L R E P O R T
Leadership
Board of Directors
Robert W. Best
Former Chairman of the Board,
Atmos Energy Corporation
Dallas, Texas
Board member since 1997
Kim R. Cocklin
Executive Chairman of the Board,
Atmos Energy Corporation
Dallas, Texas
Board member since 2009
Kelly H. Compton
Executive Director,
The Hoglund Foundation
Dallas, Texas
Board member since 2016
Committees: Audit,
Human Resources
Sean Donohue
Chief Executive Officer
Dallas/Fort Worth
International Airport
Dallas, Texas
Board member since 2018
Ruben E. Esquivel
Vice President for Community and
Corporate Relations,
UT Southwestern Medical Center
Dallas, Texas
Board member since 2008
Committees: Audit, Executive,
Human Resources, Work Session/
Annual Meeting (Chair)
Robert C. Grable
Founding Partner, Kelly Hart &
Hallman LLP
Fort Worth, Texas
Board member since 2009
Committees: Audit, Executive,
Nominating and Corporate
Governance (Chair), Work Session/
Annual Meeting
Stephen R. Springer
Retired Senior Vice President
and General Manager,
Midstream Division,
The Williams Companies, Inc.
Fort Myers Beach, Florida
Board member since 2005
Committee: Work Session/
Annual Meeting
Rafael G. Garza
President and Founder
of RGG Capital Partners, LLC,
and Co-Founder and
Managing Director, Bravo Equity, LP
Fort Worth, Texas
Board member since 2016
Committees: Audit, Nominating
and Corporate Governance
Richard K. Gordon
General Partner of Juniper
Capital LP, and Juniper Capital III;
Co-founder of Juniper Capital II,
Houston, Texas
Board member since 2001
Lead Director since 2016
Committees: Human Resources,
Nominating and Corporate
Governance
Michael E. Haefner
President and Chief Executive Officer,
Atmos Energy Corporation
Dallas, Texas
Board member since 2015
Diana J. Walters
Founder and Managing Partner,
575 Grant, LLC
New York, NY
Board member since 2018
Nancy K. Quinn
Independent Energy Consultant
Key Biscayne, Florida
Board member since 2004
Former Lead Director
Committees: Audit, Executive,
Human Resources (Chair)
Richard A. Sampson
General Partner and Founder,
RS Core Capital, LLC
Denver, Colorado
Board member since 2012
Committees: Audit (Chair),
Executive, Human Resources
Richard Ware II
Chairman, Amarillo National Bank
Amarillo, Texas
Board member since 1994
Committees: Nominating and
Corporate Governance, Audit,
Work Session/Annual Meeting
Charles K. Vaughan
Honorary Director, Retired Chairman
of the Board and Retired Lead Director,
Atmos Energy Corporation
Dallas, Texas
Board member from 1983 to 2012
Senior Management Team
Michael E. Haefner
President and Chief Executive Officer
Christopher T. Forsythe
Senior Vice President and
Chief Financial Officer
David J. Park
Senior Vice President,
Utility Operations
J. Kevin Akers
Executive Vice President,
Safety and Enterprise Services
Karen E. Hartsfield
Senior Vice President, General
Counsel and Corporate Secretary
J. Matt Robbins
Senior Vice President,
Human Resources
24 | ATMOS ENERGY CORPORATION
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
Í
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2018
‘
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
OR
Commission file number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
Texas and Virginia
(State or other jurisdiction of
incorporation or organization)
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
(Address of principal executive offices)
75-1743247
(IRS employer
identification no.)
75240
(Zip code)
Registrant’s telephone number, including area code:
(972) 934-9227
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common stock, No Par Value
Name of Each Exchange
on Which Registered
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 Í 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 Í
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 sub-
ject to such filing requirements for the past 90 days. Yes Í
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 Í
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. Í
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 Í 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 ‘
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
No Í
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
Glossary of Key Terms
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3
Part I
Item 1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Item 3.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . .
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure . . . .
Item 9.
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14.
4
15
20
20
22
22
22
24
25
45
46
103
103
105
105
106
106
106
106
Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
107
Part IV
[THIS PAGE INTENTIONALLY LEFT BLANK]
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 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mcf
MDWQ . . . . . . . . . . . . . . . . . . . . . . . . . Maximum daily withdrawal quantity
Mid-Tex ATM Cities . . . . . . . . . . . . . . Represents a coalition of 47 incorporated cities or approximately
. . . . . . . . . . . . . . . . . . . . . . . . . . . . Thousand cubic feet
1998 Long-Term Incentive Plan
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
The terms “we,” “our,” “us”, “Atmos Energy” and the “Company” refer to Atmos Energy Corporation and
its subsidiaries, unless the context suggests otherwise.
PART I
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, reli-
able, 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 pri-
marily 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% annu-
ally. 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 employ-
ees 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.
4
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.
Division
Service Areas
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Texas, including
the Dallas/Fort
Worth
Metroplex
Kentucky
Tennessee
Virginia
Louisiana
Amarillo,
Lubbock,
Midland
Mississippi
Colorado
Kansas
Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Communities
Served
550
Customer
Meters
1,697,171
230
270
80
110
170
182,510
150,661
24,396
362,233
313,828
269,333
120,384
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 oper-
ate. 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. Pur-
chased gas cost adjustment mechanisms provide natural gas distribution companies a method of recovering pur-
chased 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 meas-
ure 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 finan-
cial 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 quanti-
ties to match increases or decreases in requirements related to weather conditions.
5
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.
Currently, our distribution divisions utilize 38 pipeline transportation companies, both interstate and intra-
state, 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 nomi-
nated flowing supplies. These agreements have been negotiated with the shortest term necessary while still main-
taining 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 limi-
tations 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 agen-
cies, 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, extend-
ing 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 Infra-
structure 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 Serv-
ice 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
6
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 oper-
ate. 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 provid-
ing stable, predictable margins, which benefit both our customers and the Company. As a result of our rate-
making 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.
‰ 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 pro-
grams, 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.
7
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
Colorado-Kansas . . . . . . . . . . . . . . Colorado
Colorado SSIR
Kansas
Kansas GSRS
05/22/2018
05/03/2018
01/01/2018
03/17/2016
02/27/2018
05/03/2018
06/01/2017
12/27/2016
05/01/2018
07/01/2018
06/01/2017
02/14/2018
01/01/2018
Mississippi - SIR(7) 01/01/2018
Mississippi - SGR 01/01/2018
03/15/2017
06/05/2018
Texas-GRIP
LGS
(3)
(3)
(3)
8.87% 47/53
$2,122,194
7.55% 44/56
134,726
7.82% 48/52
29,855
(3)
200,564
(3)
12,514
7.41% 47/53
427,646
7.49% 47/53
302,953
(3)
47,581
7.26% 49/51
169,120
419,080
7.55% 44/56
2,362,937(2) 8.36% 45/55
(3)
7.47% 47/53
7.60% 47/53
8.70% 47/53
(3)
8.57% 48/52
(3)
377,954
70,141
23,718
(3)
507,831
(3)
(3)
11.50%
9.45%
9.60%
(3)
(3)
9.70%
9.80%
(3)
9.80%
9.80%
10.50%
(3)
9.67%
9.92%
12.00%
10.50%
10.50%
Kentucky/Mid-States . . . . . . . . . . . Kentucky
Tennessee(8)
Virginia
Louisiana . . . . . . . . . . . . . . . . . . . . Trans La
Mid-Tex Cities . . . . . . . . . . . . . . . . Texas(9)
Mid-Tex — Dallas . . . . . . . . . . . . . Texas
Mississippi . . . . . . . . . . . . . . . . . . . Mississippi(7)
West Texas(4) . . . . . . . . . . . . . . . . . Texas(10)
Division
Jurisdiction
Bad Debt
Rider(5)
Formula
Rate
Infrastructure
Mechanism
Performance Based
Rate Program(6)
WNA Period
Atmos Pipeline — Texas . . . . . Texas
Colorado-Kansas . . . . . . . . . . . Colorado
Kansas
Kentucky/Mid-States . . . . . . . . Kentucky
Tennessee
Virginia
Louisiana . . . . . . . . . . . . . . . . . Trans La
LGS
Mid-Tex Cities . . . . . . . . . . . . . Texas
Mid-Tex — Dallas . . . . . . . . . . Texas
Mississippi . . . . . . . . . . . . . . . . Mississippi
West Texas(4) . . . . . . . . . . . . . . Texas
No
No
Yes
Yes
Yes
Yes
No
No
Yes
Yes
No
Yes
Yes
No
No
No
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
N/A
No
No
Yes
Yes
No
No
No
No
No
Yes
No
N/A
N/A
October-May
November-April
October-April
January-December
December-March
December-March
November-April
November-April
November-April
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.
8
(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 invest-
ment 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 out-
comes 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.
Rate Action
Annual formula rate mechanisms . . . . . . . . . . . . . . . . . . .
Rate case filings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other ratemaking activity . . . . . . . . . . . . . . . . . . . . . . . . .
2018
Annual Increase (Decrease) to Operating
Income For the Fiscal Year Ended September 30
2017
(In thousands)
$ 90,427
12,961
784
$ 92,472
(12,853)
457
$114,974
7,716
(183)
2016
$ 80,076
$104,172
$122,507
9
Additionally, the following ratemaking efforts seeking $52.8 million in annual operating income were ini-
tiated during fiscal 2018 but had not been completed as of September 30, 2018:
Division
Rate Action
Jurisdiction
Operating Income
Requested
(In thousands)
Mid-Tex . . . . . . . . . . . . . . . . . . . . .
Mid-Tex . . . . . . . . . . . . . . . . . . . . .
Mid-Tex . . . . . . . . . . . . . . . . . . . . .
Mississippi . . . . . . . . . . . . . . . . . . .
Mississippi . . . . . . . . . . . . . . . . . . .
Kentucky/Mid-States . . . . . . . . . . .
Kentucky/Mid-States . . . . . . . . . . .
Kentucky/Mid-States . . . . . . . . . . .
Kentucky/Mid-States . . . . . . . . . . .
West Texas . . . . . . . . . . . . . . . . . .
West Texas . . . . . . . . . . . . . . . . . .
Formula Rate
Mechanism
Rate Case
Rate Case
Infrastructure
Mechanism
Formula Rate
Mechanism
Formula Rate
Mechanism
Formula Rate
Mechanism
True-Up
Rate Case
Rate Case
Formula Rate
Mechanism
Rate Case
Mid-Tex Cities(1)(2)
ATM Cities(1)
Environs(1)(7)
Mississippi(1)(3)
Mississippi(1)(3)
Tennessee(1)(4)
Tennessee(1)(5)
Kentucky(1)
Virginia(1)
WT Cities(1)(6)
Environs(1)(7)
$28,036
4,252
(1,875)
7,976
4,119
(5,032)
(3,220)
14,424
605
4,030
(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.
10
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.
State
Infrastructure Programs
Formula Rate Mechanisms
Annual Formula Rate Mechanisms
Colorado . . . . . . . . . . System Safety and Integrity Rider (SSIR) —
Kansas . . . . . . . . . . . . Gas System Reliability Surcharge
(GSRS)
Kentucky . . . . . . . . . . Pipeline Replacement Program (PRP)
Louisiana . . . . . . . . . .
(1)
Mississippi . . . . . . . . . System Integrity Rider (SIR)
Tennessee . . . . . . . . . —
Texas . . . . . . . . . . . . . Gas Reliability Infrastructure Program
(GRIP), (1)
Virginia . . . . . . . . . . . Steps to Advance Virginia Energy
(SAVE)
—
—
—
Rate Stabilization Clause (RSC)
Stable Rate Filing (SRF), Supplemental
Growth Filing (SGR)
Annual Rate Mechanism (ARM)
Dallas Annual Rate Review (DARR), Rate
Review Mechanism (RRM)
(1) Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capi-
tal 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.
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
(In thousands)
Effective
Date
2018 Filings:
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . LGS(1)
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amarillo,
Lubbock,
Dalhart and
Channing(1)
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Environs(1)
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Environs(1)
Atmos Pipeline — Texas . . . . . . . . . . . . . . . . . . . . . . Texas(1)
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Trans La(1)
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kansas GSRS
Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SIR
Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SGR(2)
Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SRF(2)
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . Colorado SSIR
Atmos Pipeline — Texas . . . . . . . . . . . . . . . . . . . . . . Texas
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . . . . . Kentucky-PRP
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . . . . . Virginia-
SAVE(3)
Total 2018 Filings . . . . . . . . . . . . . . . . . . . . . . . . .
12/2017
$
(1,521)
07/01/2018
12/2017
12/2017
12/2017
12/2017
09/2017
09/2018
10/2018
10/2018
10/2018
12/2018
12/2016
09/2018
09/2017
4,418
1,604
826
42,173
(1,913)
820
7,658
1,245
—
2,228
28,988
5,638
06/08/2018
06/05/2018
06/05/2018
05/22/2018
05/01/2018
02/27/2018
01/01/2018
01/01/2018
01/01/2018
12/20/2017
12/05/2017
10/27/2017
308
10/01/2017
$
92,472
11
Division
Jurisdiction
Test Year Ended
2017 Filings:
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . LGS
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Tex DARR
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Tex Cities RRM
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . Tennessee ARM
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Tex Environs
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . West Texas Environs
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . West Texas ALDC
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Trans La
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . West Texas Cities
RRM
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SRF
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SIR
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SGR
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . Kansas
Mississippi
Mississippi
Mississippi
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . Colorado-SSIR
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . Kentucky-PRP
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . Virginia-SAVE
Total 2017 Filings . . . . . . . . . . . . . . . . . . . . . .
2016 Filings:
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . LGS
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . Tennessee
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Tex Cities RRM
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Tex DARR
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Tex Environs
Atmos Pipeline — Texas . . . . . . . . . . . . . . . . . . Texas
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . West Texas Environs
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . West Texas ALDC
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Trans La
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . Colorado
Mississippi
Mississippi
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . Kentucky-PRP
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . Virginia-SAVE
West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . West Texas Cities
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SRF
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mississippi-SGR
12/2016
09/2016
12/2016
05/2018
12/2016
12/2016
12/2016
09/2016
09/2016
09/2016
10/2017
10/2017
10/2017
12/2017
09/2017
09/2017
12/2015
05/2017
12/2015
09/2015
12/2015
12/2015
12/2015
12/2015
09/2015
12/2016
10/2016
10/2016
09/2016
09/2016
09/2015
Increase
(Decrease) in
Annual
Operating
Income
(In thousands)
$
6,237
9,672
36,239
6,740
1,568
872
4,682
4,392
4,255
801
4,390
3,334
1,292
1,350
4,981
(378)
$ 90,427
$
8,686
4,888
25,816
5,429
1,325
40,658
646
3,484
6,216
764
9,192
250
3,786
118
3,716
Effective
Date
07/01/2017
06/01/2017
06/01/2017
06/01/2017
05/23/2017
05/23/2017
04/25/2017
04/01/2017
03/15/2017
02/09/2017
02/01/2017
01/01/2017
01/01/2017
01/01/2017
10/14/2016
10/01/2016
07/01/2016
06/01/2016
06/01/2016
06/01/2016
05/03/2016
05/03/2016
05/03/2016
04/26/2016
04/01/2016
01/01/2016
01/01/2016
12/01/2015
10/01/2015
10/01/2015
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
12
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
(In thousands)
Effective Date
2018 Rate Case Filings:
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Colorado(1)
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kentucky(1)
Mid-Tex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . City of
Dallas (1)
$
(241)
(7,504)
05/03/2018
05/03/2018
(5,108)
02/14/2018
Total 2018 Rate Case Filings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(12,853)
2017 Rate Case Filings:
Atmos Pipeline — Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Texas
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Virginia
Total 2017 Rate Case Filings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 Rate Case Filings:
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kentucky
Kentucky/Mid-States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Virginia
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kansas
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Colorado
Total 2016 Rate Case Filings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 12,955
6
$ 12,961
$ 2,723
537
2,372
2,084
$ 7,716
08/01/2017
12/27/2016
08/15/2016
04/01/2016
03/17/2016
01/01/2016
(1) The operating income reflects a 21% federal income tax rate resulting from the TCJA.
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
2018 Other Rate Activity:
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . .
Total 2018 Other Rate Activity . . . . . . .
2017 Other Rate Activity:
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . .
Total 2017 Other Rate Activity . . . . . . .
2016 Other Rate Activity:
Colorado-Kansas . . . . . . . . . . . . . . . . . . . . .
Total 2016 Other Rate Activity . . . . . . .
Kansas
Ad Valorem(1)
Kansas
Ad-Valorem(1)
Kansas
Ad-Valorem(1)
Increase
(Decrease) in
Annual
Operating
Income
(In thousands)
$ 457
$ 457
$ 784
$ 784
$(183)
$(183)
Effective
Date
02/01/2018
02/01/2017
02/01/2016
(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.
13
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 admin-
istrative or judicial proceedings arising under environmental quality statutes pending or known to be con-
templated 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 Hazard-
ous 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” inter-
state 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 require-
ments still under development that are similar to Dodd–Frank, our swap counterparties could be subject to addi-
tional 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 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 pipe-
lines 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 oper-
ations and 64 employees in our pipeline and storage operations.
14
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 practi-
cable, 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 reason-
ableness by the appropriate regulatory authorities or other third-party intervenors. In the normal course of busi-
ness, 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 effec-
tively reduce the regulatory lag 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.
15
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 legis-
lation also requires that our facilities, sites and other properties associated with our operations be operated, main-
tained, 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 pipe-
line and storage capacity. FERC has adopted rules designed to prevent market power abuse and market manipu-
lation 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 appli-
cable current FERC regulations, changes in FERC regulations or their interpretation by FERC or additional regu-
lations 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 oper-
ations 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
16
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 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, liquid-
ity 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 mar-
ket 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 concen-
tration 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 oper-
ate, 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 alter-
native energy sources, which could result in lower sales volumes.
17
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 sup-
ply 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 dis-
ruptions, 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.
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 oper-
ations historically have faced limited competition from other existing intrastate pipelines and gas marketers seek-
ing 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 eligi-
ble full-time employees. The costs of providing health care benefits to our employees could significantly increase
18
over time due to rapidly increasing health care inflation, and any future legislative changes related to the provi-
sion 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 post-
retirement health care benefits to eligible full-time employees and related funding requirements could be influ-
enced 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 benefi-
ciaries 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 temper-
atures 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 hurri-
canes 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 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
19
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 oper-
ating 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.
20
Storage Assets
We own underground gas storage facilities in several states to supplement the supply of natural gas in peri-
ods 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 . . . . . . . . . . . . . . . . . . . . . . . . .
Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mississippi . . . . . . . . . . . . . . . . . . . . . . . .
7,956,991
3,239,000
1,907,571
9,562,283
2,300,000
2,442,917
17,519,274
5,539,000
4,350,488
Total . . . . . . . . . . . . . . . . . . . . . . . . . . .
13,103,562
14,305,200
27,408,762
158,100
45,000
31,000
234,100
Pipeline and Storage Segment
Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . .
46,083,549
411,040
15,878,025
256,900
61,961,574
667,940
1,710,000
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
Distribution Segment
Colorado-Kansas Division
Kentucky/Mid-States Division
Louisiana Division
Mid-Tex Division
Mississippi Division
West Texas Division
Maximum
Storage
Quantity
(MMBtu)
6,129,562
8,175,103
2,536,779
5,500,000
5,083,801
5,000,000
Maximum
Daily
Withdrawal
Quantity
(MDWQ)(1)
136,996
226,739
174,805
225,000
163,627
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.
21
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.
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.
Quarter ended:
December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fiscal 2018
Fiscal 2017
$0.485
0.485
0.485
0.485
$ 1.94
$0.450
0.450
0.450
0.450
$ 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 fac-
tors. We sold no securities during fiscal 2018 that were not registered under the Securities Act of 1933, as
amended.
22
Performance Graph
The performance graph and table below compares the yearly percentage change in our total return to share-
holders for the last five fiscal years with the total return of the S&P 500 Stock Index (S&P 500) and the cumu-
lative 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 Sep-
tember 30, 2013 in our common stock, the S&P 500 and in the common stock of the companies in the Compar-
ison Company Indices, as well as a reinvestment of dividends paid on such investments throughout the period.
Comparison of Five-Year Cumulative Total Return
among Atmos Energy Corporation, S&P 500 Index
and Comparison Company Index
$260
$250
$240
$230
$220
$210
$200
$190
$180
$170
$160
$150
$140
$130
$120
$110
$100
$90
9/30/2013
9/30/2014
9/30/2015
9/30/2016
9/30/2017
9/30/2018
Atmos Energy Corporation
S&P 500
Peer Group
Cumulative Total Return
9/30/2013 9/30/2014 9/30/2015 9/30/2016 9/30/2017 9/30/2018
Atmos Energy Corporation . . . . . . . . . . . .
S&P 500 Stock Index . . . . . . . . . . . . . . . . .
Peer Group . . . . . . . . . . . . . . . . . . . . . . . . .
100.00
100.00
100.00
115.52
119.73
116.03
145.03
119.00
128.49
190.13
137.36
158.62
218.98
162.92
185.66
250.80
192.10
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.
23
The following table sets forth the number of securities authorized for issuance under our equity compensa-
tion plans at September 30, 2018.
Number of
securities to be issued
upon exercise of
outstanding options,
restricted stock units,
warrants and rights
(a)
Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))
(c)
Equity compensation plans approved
by security holders:
1998 Long-Term Incentive Plan . . . . . . .
1,041,519(1)
Total equity compensation plans
approved by security holders . . . . . .
1,041,519
Equity compensation plans not
approved by security holders . . . . . .
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,041,519
$
$
—
—
—
—
1,752,235
1,752,235
—
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.
Results of Operations
Operating revenues . . . . . . . . . . . . .
Contribution margin . . . . . . . . . . . .
Income from continuing
operations . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . .
Diluted income per share from
continuing operations . . . . . . . . .
Diluted net income per share . . . . . .
Cash dividends declared per
share . . . . . . . . . . . . . . . . . . . . . .
Financial Condition
Net property, plant and
equipment(1) . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . .
Capitalization:
Shareholders’ equity . . . . . . . . . .
Long-term debt (excluding
Fiscal Year Ended September 30
2018
2017
2016
2015
2014
(In thousands, except per share data)
$ 3,115,546
$ 1,947,698
$ 2,759,735
$ 1,834,199
$ 2,454,648
$ 1,708,456
$2,926,985
$1,631,310
$3,243,904
$1,521,844
$
$
$
$
$
603,064
603,064
5.43
5.43
1.94
$
$
$
$
$
382,711
396,421
3.60
3.73
1.80
$
$
$
$
$
345,542
350,104
$ 305,623
$ 315,075
$ 270,331
$ 289,817
3.33
3.38
1.68
$
$
$
3.00
3.09
1.56
$
$
$
2.76
2.96
1.48
$10,371,147
$11,874,437
$ 9,259,182
$10,749,596
$ 8,268,606
$10,010,889
$7,416,700
$9,075,072
$6,709,926
$8,581,006
$ 4,769,951
$ 3,898,666
$ 3,463,059
$3,194,797
$3,086,232
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.
24
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 con-
solidated 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 state-
ments 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 state-
ments 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, mar-
kets, 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 avail-
ability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; increased competi-
tion 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 judg-
ments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of
25
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.
Critical
Accounting Policy
Summary of 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 rate-
making 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 recog-
nized. 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 regu-
latory 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.
Unbilled Revenue . . . . . . . . . We follow the revenue accrual method of account-
ing for distribution segment revenues whereby
revenues attributable to gas delivered to custom-
ers, 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 author-
ities, subject to refund.We recognize this revenue
and establish a reserve for amounts that could be
refunded based on our experience for the juris-
diction in which the rates were implemented.
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, esti-
26
Pension and other
postretirement plans . . . . .
Factors Influencing
Application of the Policy
Decisions of regulatory
authorities
Issuance of new regu-
lations 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
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 esti-
mated deliveries
Estimates of amounts bil-
led subject to refund
General economic and
market conditions
Assumed investment
returns by asset class
Critical
Accounting Policy
Factors Influencing
Application of the Policy
Assumed future salary
increases
Assumed discount rate
Projected timing of future
cash disbursements
Health care cost experi-
ence trends
Participant demographic
information
Actuarial mortality
assumptions
Impact of legislation
Impact of regulation
Summary of Policy
mates 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 calculat-
ing the actuarial present value of our pension and
postretirement obligations and net periodic pen-
sion and postretirement benefit plan costs. When
establishing our discount rate, we consider high
quality corporate bond rates based on bonds avail-
able in the marketplace that are suitable for set-
tling the obligations, changes in those rates from
the prior year and the implied discount rate that is
derived from matching our projected benefit dis-
bursements 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 post-
retirement 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 repre-
sents the fair market value of the plan assets,
adjusted to smooth out short-term market fluctua-
tions 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
27
Critical
Accounting Policy
Summary of Policy
Factors Influencing
Application of the Policy
expense based upon our actual health care cost
experience, the effects of recently enacted legis-
lation 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.
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 stan-
dards.
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 dis-
counted cash flows
Judgment in the evalua-
tion of relevant data
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 operat-
ing revenues. As such, the following discussion and analysis of our financial performance will reference Con-
tribution 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 meas-
ure, 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
28
analysis of our financial performance will reference adjusted income from continuing operations and diluted
earnings per share, which is calculated as follows:
Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TCJA non-cash income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Fiscal Year Ended September 30
2018
Change
2017
(In thousands, except per share data)
$382,711
—
$ 603,064
(158,782)
$ 220,353
(158,782)
Adjusted income from continuing operations . . . . . . . . . . . . . . . . . . . . . . .
$ 444,282
$382,711
$ 61,571
Consolidated diluted EPS from continuing operations . . . . . . . . . . . . . . . .
Diluted EPS from TCJA non-cash income tax benefit . . . . . . . . . . . . . . . .
Adjusted diluted EPS from continuing operations . . . . . . . . . . . . . . . . . . .
$
$
5.43
(1.43)
4.00
$
$
3.60
—
3.60
$
$
1.83
(1.43)
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 sig-
nificant level of capital spending. We have the ability to begin recovering a significant portion of these invest-
ments 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 Sep-
tember 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.
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 dis-
count 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.
29
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 oper-
ations. 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 regu-
lators.
‰ Beginning in the second quarter of fiscal 2018, we established regulatory liabilities in all our juris-
dictions 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 cus-
tomers 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.
30
Consolidated Results
The following table presents our consolidated financial highlights for the fiscal years ended September 30,
2018, 2017 and 2016.
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased gas cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations before income taxes . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
One-time, non-cash income tax benefit
. . . . . . . . . . . . . . . .
Net income from continuing operations . . . . . . . . . . . . . . . .
Net income from discontinued operations . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted net income from continuing operations per share . .
Diluted net income from discontinued operations per
share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Fiscal Year Ended September 30
2016
2017
2018
(In thousands, except per share data)
$2,759,735
925,536
1,106,653
727,546
120,182
604,094
221,383
—
382,711
13,710
$ 396,421
3.60
$
$3,115,546
1,167,848
1,224,564
723,134
106,646
611,144
166,862
(158,782)
603,064
—
$ 603,064
5.43
$
$2,454,648
746,192
1,051,226
657,230
114,812
542,184
196,642
—
345,542
4,562
$ 350,104
3.33
$
—
0.13
3.73
$
0.05
3.38
Diluted net income per share . . . . . . . . . . . . . . . . . . . . . . . . .
$
5.43
$
Our consolidated net income during the last three fiscal years was earned across our business segments as
follows:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution segment
Pipeline and storage segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income from continuing operations . . . . . . . . . . . . . . . . . . . . .
Net income from discontinued natural gas marketing
operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018
For the Fiscal Year Ended September 30
2017
(In thousands)
$268,369
114,342
$442,966
160,098
$233,830
111,712
2016
603,064
382,711
345,542
—
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 compli-
cated 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 ini-
tiatives 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
31
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 asso-
ciated tax expense as a component of taxes, other than 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 cus-
tomers 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.
Operating revenues . . . . . . . . . . . . . . . .
Purchased gas cost . . . . . . . . . . . . . . . . .
$3,003,047
1,559,836
2018
For the Fiscal Year Ended September 30
2016
2017
(In thousands, unless otherwise noted)
$2,339,778
1,058,576
$ 353,872
290,380
$2,649,175
1,269,456
2018 vs. 2017
Contribution Margin . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . .
1,443,211
962,344
1,379,719
874,077
1,281,202
839,318
Operating income . . . . . . . . . . . . . . . .
. . . . .
Miscellaneous income (expense)
Interest charges . . . . . . . . . . . . . . . . . . .
Income before income taxes . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . .
One-time, non-cash income tax
480,867
(1,849)
65,850
413,168
107,880
505,642
(1,695)
79,789
424,158
155,789
441,884
1,171
78,238
364,817
130,987
63,492
88,267
(24,775)
(154)
(13,939)
(10,990)
(47,909)
2017 vs. 2016
$309,397
210,880
98,517
34,759
63,758
(2,866)
1,551
59,341
24,802
benefit . . . . . . . . . . . . . . . . . . . . . . . .
(137,678)
—
—
(137,678)
—
Net income . . . . . . . . . . . . . . . . . . . . . .
$ 442,966
$ 268,369
$ 233,830
$ 174,597
$ 34,539
Consolidated distribution sales
volumes — MMcf . . . . . . . . . . . . . . .
Consolidated distribution transportation
volumes — MMcf . . . . . . . . . . . . . . .
Total consolidated distribution
300,817
246,825
258,650
53,992
(11,825)
150,566
141,540
133,378
9,026
8,162
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
32
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 corre-
sponding $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.
‰ 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 invest-
ments.
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, off-
set by a corresponding $5.1 million increase in the related tax expense.
33
‰ 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 vs. 2017
2017
2016
2017 vs. 2016
Mid-Tex . . . . . . . . . . . . . . . . . . . . .
Kentucky/Mid-States . . . . . . . . . . .
Louisiana . . . . . . . . . . . . . . . . . . . .
West Texas . . . . . . . . . . . . . . . . . . .
Mississippi . . . . . . . . . . . . . . . . . . .
Colorado-Kansas . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . .
2018
$202,444
81,105
70,609
45,494
47,237
32,333
1,645
$233,158
75,214
69,300
46,859
38,505
34,658
7,948
(In thousands)
$210,608
63,730
55,857
41,131
37,398
31,840
1,320
$(30,714)
5,891
1,309
(1,365)
8,732
(2,325)
(6,303)
Total . . . . . . . . . . . . . . . . . . . . . . . .
$480,867
$505,642
$441,884
$(24,775)
$22,550
11,484
13,443
5,728
1,107
2,818
6,628
$63,758
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 custom-
ers, as well as marketers and producers. As part of its pipeline operations, APT owns and operates five under-
ground 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 pipe-
lines. 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
34
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 per-
cent 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 Sep-
tember 30, 2018, 2017 and 2016 are presented below.
2018
Mid-Tex / Affiliate transportation revenue . .
Third-party transportation revenue . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . .
$354,885
140,231
12,597
Total operating revenues . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . .
Total purchased gas cost
Contribution Margin . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . .
One-time, non-cash income tax benefit . . . . .
507,713
1,978
505,735
263,468
242,267
(3,495)
40,796
197,976
58,982
(21,104)
2016
For the Fiscal Year Ended September 30
2017
2018 vs. 2017
(In thousands, unless otherwise noted)
$ 16,035
40,131
(5,483)
$315,726
89,498
21,972
$338,850
100,100
18,080
457,030
2,506
454,524
232,620
221,904
(1,575)
40,393
179,936
65,594
—
427,196
(58)
427,254
211,908
215,346
(1,405)
36,574
177,367
65,655
—
50,683
(528)
51,211
30,848
20,363
(1,920)
403
18,040
(6,612)
(21,104)
2017 vs. 2016
$23,124
10,602
(3,892)
29,834
2,564
27,270
20,712
6,558
(170)
3,819
2,569
(61)
—
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 reli-
ability 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.
35
The increase in operating expenses is primarily due to higher depreciation expense of $25.8 million asso-
ciated 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.
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 dis-
continued operations for $2.7 million was recorded and net income of $11.0 million for AEM is reported as dis-
continued 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.
36
Review of Financial and Operating Results
Financial and operational highlights for our natural gas marketing segment for the fiscal years ended Sep-
tember 30, 2017 and 2016 are presented below.
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased gas cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contribution Margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of discontinued operations, net of tax . . . . . . . . . . . . . . . . .
25,920
7,874
18,046
30
241
17,835
6,841
10,994
2,716
For the Fiscal Year Ended September 30
2017
2016
(In thousands, unless otherwise noted)
$1,005,090
968,118
$(701,616)
(690,564)
2017 vs. 2016
$303,474
277,554
36,972
26,184
10,788
109
2,604
8,293
3,731
4,562
—
4,562
(11,052)
(18,310)
7,258
(79)
(2,363)
9,542
3,110
6,432
2,716
$
9,148
Net income from discontinued operations . . . . . . . . . . . . . . . . . . . . . .
$ 13,710
$
Gross natural gas marketing delivered gas sales volumes — MMcf . . . .
90,223
371,319
(281,096)
Consolidated natural gas marketing delivered gas sales
volumes — MMcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
78,646
325,537
(246,891)
Net physical position (Bcf)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
18.1
(18.1)
Fiscal year ended September 30, 2017 compared with fiscal year ended September 30, 2016
The $9.1 million year-over-year increase in net income from discontinued operations primarily reflects the
recognition of a net $6.6 million noncash gain from unwinding hedge accounting for certain of the natural gas
marketing business’s financial positions in connection with the sale of AEM. Additionally we recognized a
$2.7 million net gain on sale upon completion of the sale of AEM to CES in January 2017.
LIQUIDITY AND CAPITAL RESOURCES
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. External debt
financing is provided primarily through the issuance of long-term debt, a $1.5 billion commercial paper program
and three committed revolving credit facilities with a total availability from third-party lenders of approximately
$1.5 billion. The commercial paper program and credit facilities provide cost-effective, short-term financing until
it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired
capital structure with an equity-to-total-capitalization ratio between 50% and 60%, inclusive of long-term and
short-term debt. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we uti-
lize to purchase natural gas on a monthly basis. The liquidity provided by these sources is expected to be suffi-
cient to fund the Company’s working capital needs and capital expenditures program for fiscal year 2019 and
beyond. Please refer to the TCJA Impact section above regarding anticipated impacts on our liquidity, capital
resources and cash flows.
To support our capital market activities, we have a registration statement on file with the SEC that permits
us to issue a total of $2.5 billion in common stock and/or debt securities. The shelf registration statement expires
on March 26, 2019. Under the shelf registration statement, in November 2017, we filed a prospectus supplement
for an at-the-market (ATM) equity distribution program under which we may issue and sell shares of our com-
mon stock up to an aggregate offering price of $500 million.
37
At September 30, 2018, approximately $650.0 million of securities remained available for issuance under
the shelf registration statement. On October 4, 2018, we completed a public offering of $600 million of 4.30%
senior notes due 2048. The effective rate of this note is 4.37% after giving effect to the offering costs. We
received net proceeds from the offering, after underwriting discount and estimated offering expenses of approx-
imately $591 million, that were used to repay working capital borrowings pursuant to our commercial paper
program. The issuance of these notes effectively exhausted our existing shelf registration statement.
During the first quarter of fiscal 2019, we intend to file a new registration statement for the issuance, from
time to time, of up to $3.0 billion in common stock and/or debt securities In addition, during the first quarter of
fiscal 2019, we plan to enter into a new ATM equity distribution agreement under which we may issue and sell
shares of our common stock, up to an aggregate offering price of $500 million, under the new shelf registration
statement.
The following table presents our capitalization as of September 30, 2018 and 2017:
September 30
2018
2017
(In thousands, except percentages)
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 575,780
3,068,665
4,769,951
6.8% $ 447,745
36.5% 3,067,045
56.7% 3,898,666
6.0%
41.4%
52.6%
Total capitalization, including short-term debt . . . . . . . . . . . . . . . .
$8,414,396
100.0% $7,413,456
100.0%
Cash Flows
Our internally generated funds may change in the future due to a number of factors, some of which we
cannot control. These factors include regulatory changes, the price for our services, the demand for such products
and services, margin requirements resulting from significant changes in commodity prices, operational risks and
other factors.
Cash flows from operating, investing and financing activities for the years ended September 30, 2018, 2017
and 2016 are presented below.
Total cash provided by (used in)
Operating activities . . . . . . . . . . . . . .
Investing activities . . . . . . . . . . . . . .
Financing activities . . . . . . . . . . . . . .
Change in cash and cash
2018
For the Fiscal Year Ended September 30
2016
2017
(In thousands)
2018 vs. 2017
2017 vs. 2016
$ 1,124,662
(1,463,566)
326,266
$
867,090
(1,056,306)
168,091
$
794,990
(1,079,732)
303,623
$ 257,572
(407,260)
158,175
$ 72,100
23,426
(135,532)
equivalents . . . . . . . . . . . . . . . . . . .
(12,638)
(21,125)
18,881
8,487
(40,006)
Cash and cash equivalents at
beginning of period . . . . . . . . . . . .
26,409
47,534
28,653
(21,125)
18,881
Cash and cash equivalents at end of
period . . . . . . . . . . . . . . . . . . . . . . .
$
13,771
$
26,409
$
47,534
$ (12,638)
$ (21,125)
Cash flows from operating activities
Year-over-year changes in our operating cash flows primarily are attributable to changes in net income and
working capital changes, particularly within our distribution segment resulting from changes in the price of
natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost
recoveries.
38
Fiscal Year ended September 30, 2018 compared with fiscal year ended September 30, 2017
For the fiscal year ended September 30, 2018, we generated operating cash flows of $1,124.7 million com-
pared with $867.1 million in the prior year. The year-over-year increase primarily reflects the positive cash
effects of successful rate case outcomes achieved in fiscal 2017 driven primarily by increased safety and reli-
ability spending and changes in working capital, primarily as a result of the timing of gas cost recoveries under
our purchase gas cost mechanisms as a result of a year-over-year increase in sale volumes. This increase in sales
volumes also contributed to the year-over-year increase in operating cash flow.
Fiscal Year ended September 30, 2017 compared with fiscal year ended September 30, 2016
For the fiscal year ended September 30, 2017, we generated operating cash flows of $867.1 million com-
pared with $795.0 million in fiscal 2016. The year-over-year increase primarily reflects the positive cash effect of
successful rate case outcomes achieved in fiscal 2016.
Cash flows from investing activities
In recent years, we have used substantial amounts of cash to fund our ongoing construction program, which
enables us to improve safety and reliability by modernizing our distribution and transmission system, used to
provide distribution services to our existing customer base, expand our natural gas distribution services into new
markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. Over
the last three fiscal years, approximately 82 percent of our capital spending has been committed to improving the
safety and reliability of our system.
In executing our regulatory strategy, we target our capital spending on regulatory mechanisms that permit us
to earn an adequate return timely on our investment without compromising the safety or reliability of our system.
Substantially all of our regulated jurisdictions have rate tariffs that provide the opportunity to include in their rate
base approved capital costs on a periodic basis without being required to file a rate case.
For the fiscal year ended September 30, 2018, we had $1,467.6 million in capital expenditures compared
with $1,137.1 million for the fiscal year ended September 30, 2017 and $1,087.0 million for the fiscal year ended
September 30, 2016.
Fiscal Year ended September 30, 2018 compared with fiscal year ended September 30, 2017
The $330.5 million increase in capital expenditures in fiscal 2018 compared to fiscal 2017 primarily reflects
planned increases to modernize our distribution and transmission system, and increases in spending in our pipe-
line and storage segment to improve the reliability of gas service to our local distribution company customers.
The year-over-year increase also reflects the absence in the current year period of $140.3 million in net proceeds
received from the sale of AEM, $29.8 million in proceeds received from the completion of a State of Texas use
tax audit and the $86.1 million used to acquire a pipeline in December 2016.
Fiscal Year ended September 30, 2017 compared with fiscal year ended September 30, 2016
The $50.1 million increase in capital expenditures in fiscal 2017 compared to fiscal 2016 primarily
reflects a:
‰ $109.7 million increase due to planned increases in our distribution segment to replace vintage pipe.
‰ $59.2 million decrease in spending in our pipeline and storage segment as a result of the substantial com-
pletion of an APT project to improve the reliability of gas service to its local distribution company
customers.
Cash flows from investing activities for the year ended September 30, 2017 also include proceeds of $140.3
million received from the sale of AEM, proceeds received from the completion of a State of Texas use tax audit
and $86.1 million used to purchase a pipeline in the first fiscal quarter of 2017.
39
Cash flows from financing activities
We generated a net amount of $326.3 million, $168.1 million and $303.6 million in cash from financing
activities for fiscal years 2018, 2017 and 2016. Our significant financing activities for the fiscal years ended
September 30, 2018, 2017 and 2016 are summarized as follows:
2018
During the fiscal year ended September 30, 2018, our financing activities generated $326.3 million of cash
compared with $168.1 million of cash generated in the prior year. The $158.2 million increase in cash provided
by financing activities reflects higher net short-term borrowings due to increased capital expenditures and period-
over-period changes in working capital funding needs compared to the prior year, as well as net proceeds
received of $395.1 million from equity financing. Cash dividends increased due to a 7.8% increase in our divi-
dend rate and an increase in shares outstanding.
2017
During the fiscal year ended September 30, 2017, our financing activities generated $168.1 million of cash
compared with $303.6 million of cash generated in the prior year. The $135.5 million decrease in cash provided
by financing activities is primarily due to the reduction in our short–term debt, partially offset by an increase in
our long-term debt.
During fiscal 2017, we completed approximately $975 million of debt and equity financing. On June 8,
2017, we completed a public offering of $500 million of 3.00% senior unsecured notes due 2027 and
$250 million of 4.125% senior unsecured notes due 2044. The net proceeds of approximately $753 million were
used to repay our $250 million 6.35% senior unsecured notes at maturity on June 15, 2017 and for general corpo-
rate purposes, including the repayment of working capital borrowings pursuant to our commercial paper pro-
gram. In October 2016, we issued $125 million of long-term debt under our three year, $200 million multi-draw
term loan agreement.
Additionally, during fiscal 2017 we issued 1.3 million shares under our ATM program and received net
proceeds of $98.8 million. As of September 30, 2017, substantially all of shares under this program had been
issued.
2016
During the fiscal year ended September 30, 2016, our financing activities generated $303.6 million of cash
compared with $131.1 million of cash generated in fiscal 2015. The increase is primarily due to higher net short-
term borrowings due to increased capital expenditures and period-over-period changes in working capital funding
needs compared to the prior year, as well as proceeds received from the issuance of common stock under our
ATM program in the third fiscal quarter of 2016.
The following table shows the number of shares issued for the fiscal years ended September 30, 2018, 2017
and 2016:
Shares issued:
For the Fiscal Year Ended September 30
2017
2016
2018
Direct Stock Purchase Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retirement Savings Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1998 Long-Term Incentive Plan (LTIP) . . . . . . . . . . . . . . . . . . . . . . . . .
November 2017 Offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
At-the-Market (ATM) Equity Sales Program . . . . . . . . . . . . . . . . . . . . .
131,213
94,081
385,351
4,558,404
112,592
228,326
529,662
—
— 1,303,494
133,133
359,414
598,439
—
1,360,756
Total shares issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,169,049
2,174,074
2,451,742
40
Credit Ratings
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the
cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative
factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash
flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qual-
itative factors such as consistency of our earnings over time, the quality of our management and business strategy
and the regulatory environment in the states where we operate.
Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors
Service (Moody’s). As of September 30, 2018, both rating agencies maintained a stable outlook.
Our current debt ratings are all considered investment grade and are as follows:
S&P Moody’s
A
Senior unsecured long-term debt
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
A2
P-1
A significant degradation in our operating performance or a significant reduction in our liquidity caused by
more limited access to the private and public credit markets as a result of deteriorating global or national finan-
cial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit
ratings by the two credit rating agencies. This would mean more limited access to the private and public credit
markets and an increase in the costs of such borrowings.
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit
rating is AAA for S&P and Aaa for Moody’s. The lowest investment grade credit rating is BBB- for S&P and
Baa3 for Moody’s. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each
rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain
in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating
agency if, in its judgment, circumstances so warrant.
Debt Covenants
We were in compliance with all of our debt covenants as of September 30, 2018. Our debt covenants are
described in Note 5 to the consolidated financial statements.
Contractual Obligations and Commercial Commitments
The following table provides information about contractual obligations and commercial commitments at
September 30, 2018.
Contractual Obligations
. . . . . . . . . . . . . . . . . .
Long-term debt(1)
. . . . . . . . . . . . . . . . . .
Short-term debt(1)
Interest charges(2)
. . . . . . . . . . . . . . . . . .
Operating leases(3)
. . . . . . . . . . . . . . . . .
Financial instrument obligations(4) . . . . .
Pension and postretirement benefit plan
. . . . . . . . . . . . . . . . . .
. . . . . . . . . . . .
Uncertain tax positions(6)
contributions(5)
Total
Less than
1 year
Payments Due by Period
1-3 years
(In thousands)
3-5 years
More than
5 years
$3,085,000
575,780
2,257,307
104,191
56,837
$ 575,000
575,780
134,227
17,655
56,734
$
—
—
222,759
32,685
103
$
— $2,510,000
—
—
1,677,562
222,759
22,226
31,625
—
—
275,907
26,203
24,882
—
56,310
26,203
63,525
—
131,190
—
Total contractual obligations . . . . .
$6,381,225
$1,384,278
$338,060
$317,909
$4,340,978
(1) See Note 5 to the consolidated financial statements.
41
(2) Interest charges were calculated using the effective rate for each debt issuance.
(3) See Note 10 to the consolidated financial statements.
(4) Represents liabilities for natural gas commodity and interest rate financial instruments that were valued as of
September 30, 2018. The ultimate settlement amounts of these remaining liabilities are unknown because
they are subject to continuing market risk until the financial instruments are settled.
(5) Represents expected contributions to our pension and postretirement benefit plans, which are discussed in
Note 7 to the consolidated financial statements.
(6) Represents liabilities associated with uncertain tax positions claimed or expected to be claimed on tax
returns. The amount does not include interest and penalties that may be applied to these positions.
We maintain supply contracts with several vendors that generally cover a period of up to one year. Commit-
ments for estimated base gas volumes are established under these contracts on a monthly basis at contractually
negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in
accordance with the terms of individual contracts. Our Mid-Tex Division also maintains a limited number of
long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate
it to purchase specified volumes at market and fixed prices. At September 30, 2018, we were committed to pur-
chase 54.1 Bcf within one year and 37.2 Bcf within two to three years under indexed contracts.
The passage of the TCJA resulted in the remeasurement of our net deferred tax liability. At September 30,
2018, we recorded $744.9 million, which relates to our regulated operations and has been recorded as a regu-
latory liability. The period and timing of the return of the excess deferred taxes is being determined by regulators
in each of our jurisdictions. See Note 12 for further information.
Risk Management Activities
We use financial instruments to mitigate commodity price risk and, periodically, to manage interest rate
risk. In our distribution and pipeline and storage segments, we use a combination of physical storage, fixed phys-
ical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price
increases. Additionally, we manage interest rate risk by entering into financial instruments to effectively fix the
Treasury yield component of the interest cost associated with anticipated financings.
We record our financial instruments as a component of risk management assets and liabilities, which are
classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instru-
ment. Substantially all of our financial instruments are valued using external market quotes and indices.
The following table shows the components of the change in fair value of our financial instruments for the
fiscal year ended September 30, 2018 (in thousands):
Fair value of contracts at September 30, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contracts realized/settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of new contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other changes in value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(109,159)
(1,254)
241
54,954
Fair value of contracts at September 30, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Netting of cash collateral
(55,218)
—
Cash collateral and fair value of contracts at September 30, 2018 . . . . . . . . . . . . . . . . . . . . .
$ (55,218)
42
The fair value of our financial instruments at September 30, 2018, is presented below by time period and
fair value source:
Source of Fair Value
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices based on models and other valuation methods . . . . . . . .
$(55,365)
—
$147
—
Total Fair Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(55,365)
$147
$—
Fair Value of Contracts at September 30, 2018
Maturity in years
Less
than 1
1-3
Greater
than 5
4-5
(In thousands)
$—
—
$—
—
$—
Total Fair
Value
$(55,218)
—
$(55,218)
Employee Benefits Programs
An important element of our total compensation program, and a significant component of our operation and
maintenance expense, is the offering of various benefits programs to our employees. These programs include
medical and dental insurance coverage and pension and postretirement programs.
Medical and Dental Insurance
We offer medical and dental insurance programs to substantially all of our employees. We believe these
programs are compliant with all current regulatory provisions and are consistent with other programs in our
industry. In recent years, we have endeavored to actively manage our health care costs through the introduction
of a wellness strategy that is focused on helping employees to identify health risks and to manage these risks
through improved lifestyle choices.
Over the last five fiscal years, we have experienced annual medical and prescription inflation of approx-
imately seven percent. For fiscal 2019, we anticipate the medical and prescription drug inflation rate will increase
at approximately six percent, primarily due to the inflation of health care costs and normalization of large claim
activity.
Net Periodic Pension and Postretirement Benefit Costs
For the fiscal year ended September 30, 2018, our total net periodic pension and other benefits costs was
$41.4 million, compared with $49.0 million and $46.0 million for the fiscal years ended September 30, 2017 and
2016. These costs are recoverable through our rates. A portion of these costs is capitalized into our distribution
rate base and the remaining costs are recorded as a component of operation and maintenance expense.
Our fiscal 2018 costs were determined using a September 30, 2017 measurement date. At that date, interest
and corporate bond rates utilized to determine our discount rates were higher than the interest and corporate bond
rates as of September 30, 2016, the measurement date for our fiscal 2017 net periodic cost. Therefore, we
increased the discount rate used to measure our fiscal 2018 net periodic cost from 3.73 percent to 3.89 percent.
We lowered the expected return on plan assets from 7.00 percent to 6.75 percent in the determination of our fis-
cal 2018 net periodic pension cost based upon expected market returns for our targeted asset allocation. On
October 20, 2017, the Society of Actuaries released its annually-updated mortality improvement scale for pen-
sion plans incorporating new assumptions surrounding life expectancies in the United States. As of September
30, 2017, we updated our assumed mortality rates to incorporate the updated mortality table. As a result of the
net impact of changes in these and other assumptions, our fiscal 2018 pension and postretirement medical costs
were higher than in the prior year.
Our fiscal 2017 costs were determined using a September 30, 2016 measurement date. At that date, interest
and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond
rates as of September 30, 2015, the measurement date for our fiscal 2016 net periodic cost. Therefore, we
decreased the discount rate used to measure our fiscal 2017 net periodic cost from 4.55 percent to 3.73 percent.
We maintained the expected return on plan assets of 7.00 percent in the determination of our fiscal 2017 net
periodic pension cost based upon expected market returns for our targeted asset allocation. On October 20, 2016,
43
the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporat-
ing new assumptions surrounding life expectancies in the United States. As of September 30, 2016, we updated
our assumed mortality rates to incorporate the updated mortality table. As a result of the net impact of changes in
these and other assumptions, our fiscal 2017 pension and postretirement medical costs were consistent with the
prior year.
Pension and Postretirement Plan Funding
Generally, our funding policy is to contribute annually an amount that will at least equal the minimum
amount required to comply with the Employee Retirement Income Security Act of 1974 (ERISA). However,
additional voluntary contributions are made from time to time as considered necessary. Contributions are
intended to provide not only for benefits attributed to service to date but also for those expected to be earned in
the future.
In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans
as of January 1, 2018, 2017 and 2016. Based on these valuations, we have not had a minimum required con-
tribution for the last three fiscal years. However, we made voluntary contributions of $7.0 million, $5.0 million
and $15.0 million to our pension plans during fiscal 2018, 2017 and 2016 to achieve a desired PPA funding
threshold.
We contributed $17.4 million, $13.7 million and $16.6 million to our postretirement benefits plans for the
fiscal years ended September 30, 2018, 2017 and 2016. The contributions represent the portion of the postretire-
ment costs we are responsible for under the terms of our plan and minimum funding required by state regulatory
commissions.
Outlook for Fiscal 2019 and Beyond
As of September 30, 2018, interest and corporate bond rates were higher than the rates as of September 30,
2017. Therefore, we increased the discount rate used to measure our fiscal 2019 net periodic cost from
3.89 percent to 4.38 percent. The expected return on plan assets remained consistent with the prior year at
6.75 percent in the determination of our fiscal 2019 net periodic pension cost based upon expected market returns
for our targeted asset allocation. On October 23, 2018, the Society of Actuaries released its annually-updated
mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in
the United States. As of September 30, 2018, we updated our assumed mortality rates to incorporate the updated
mortality table. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2019
net periodic pension cost to be lower than fiscal 2018.
Based upon current market conditions, the current funded position of the plans and the funding requirements
under the PPA, we do not anticipate a minimum required contribution for fiscal 2019. However, we may consider
whether a voluntary contribution is prudent to maintain certain funding levels. The amount of this funding is
contingent upon several factors, including the issuance of new mortality tables by the US Treasury Department
used to establish plan funding requirements. With respect to our postretirement medical plans, we anticipate
contributing between $10 million and $20 million during fiscal 2019.
Actual changes in the fair market value of plan assets and differences between the actual and expected
return on plan assets could have a material effect on the amount of pension costs ultimately recognized. A
0.25 percent change in our discount rate would impact our pension and postretirement costs by approximately
$2.5 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement
costs by approximately $1.4 million.
The projected liability, future funding requirements and the amount of expense or income recognized for
each of our pension and other post-retirement benefit plans are subject to change, depending on the actuarial
value of plan assets, and the determination of future benefit obligations as of each subsequent calculation
date. These amounts are impacted by actual investment returns, changes in interest rates, changes in the demo-
graphic composition of the participants in the plans and other actuarial assumptions.
44
RECENT ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial position, results of operations and cash
flows are described in Note 2 to the consolidated financial statements.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are exposed to risks associated with commodity prices and interest rates. Commodity price risk is the
potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity.
Interest-rate risk is the potential increased cost we could incur when we issue debt instruments or to provide
financing and liquidity for our business activities. Additionally, interest-rate risk could affect our ability to issue
cost effective equity instruments.
We conduct risk management activities in our distribution and pipeline and storage segments. In our dis-
tribution segment, we use a combination of physical storage, fixed-price forward contracts and financial instru-
ments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas
price volatility on our customers during the winter heating season. Our risk management activities and related
accounting treatment are described in further detail in Note 13 to the consolidated financial statements.
Additionally, our earnings are affected by changes in short-term interest rates as a result of our issuance of short-
term commercial paper and our other short-term borrowings.
Commodity Price Risk
We purchase natural gas for our distribution operations. Substantially all of the costs of gas purchased for
distribution operations are recovered from our customers through purchased gas cost adjustment mechanisms.
Therefore, our distribution operations have limited commodity price risk exposure.
Interest Rate Risk
Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial
paper program and other short-term borrowings. We use a sensitivity analysis to estimate our short-term interest
rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our
actual interest expense for the period and estimated interest expense for the period assuming a hypothetical aver-
age one percent increase in the interest rates associated with our short-term borrowings. Had interest rates asso-
ciated with our short-term borrowings increased by an average of one percent, our net interest expense would
have increased by approximately $0.2 million during 2018.
45
ITEM 8.
Financial Statements and Supplementary Data.
Index to financial statements and financial statement schedule:
Report of independent registered public accounting firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial statements and supplementary data:
Consolidated balance sheets at September 30, 2018 and 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of income for the years ended September 30, 2018, 2017 and 2016 . . . . . . . . .
Consolidated statements of comprehensive income for the years ended September 30, 2018, 2017 and
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of shareholders’ equity for the years ended September 30, 2018, 2017 and
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of cash flow for the years ended September 30, 2018, 2017 and 2016 . . . . . . .
Notes to consolidated financial statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Quarterly Financial Data (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial statement schedule for the years ended September 30, 2018, 2017 and 2016
Page
47
48
49
50
51
52
53
101
Schedule II. Valuation and Qualifying Accounts
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
113
All other financial statement schedules are omitted because the required information is not present, or not
present in amounts sufficient to require submission of the schedule or because the information required is
included in the financial statements and accompanying notes thereto.
46
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Atmos Energy Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation (the
“Company“) as of September 30, 2018 and 2017, the related consolidated statements of income, comprehensive
income, shareholders‘ equity, and cash flows, for each of the three years in the period ended September 30, 2018,
and the related notes and financial statement schedule listed in the Index at Item 8 (collectively referred to as the
“financial statements”). In our opinion, the consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of September 30, 2018 and 2017, and the results of its oper-
ations and its cash flows for each of the three years in the period ended September 30, 2018, in conformity with
US generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the Company’s internal control over financial reporting as of September 30, 2018,
based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) and our report dated November 13, 2018
expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company‘s management. Our responsibility is to
express an opinion on the Company‘s financial statements based on our audits. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with
the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commis-
sion and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the
risks of material misstatement of the financial statements, whether due to error or fraud, and performing proce-
dures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the
amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles
used and significant estimates made by management, as well as evaluating the overall presentation of the finan-
cial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company‘s auditor since 1983.
Dallas, Texas
November 13, 2018
47
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
September 30
2018
2017
(In thousands,
except share data)
ASSETS
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,217,648 $11,001,910
299,394
Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
349,725
Less accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,567,373
2,196,226
11,301,304
2,042,122
Net property, plant and equipment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,371,147
9,259,182
Current assets
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, less allowance for doubtful accounts of $14,795 in 2018 and
$10,865 in 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas stored underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill
Deferred charges and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13,771
26,409
253,295
165,732
46,055
478,853
730,419
294,018
222,263
184,653
106,321
539,646
730,132
220,636
$11,874,437 $10,749,596
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share);
200,000,000 shares authorized; issued and outstanding:
2018 — 111,273,683 shares, 2017 — 106,104,634 shares . . . . . . . . . . . . . . . . . . $
556 $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt
2,974,926
(83,647)
1,878,116
4,769,951
2,493,665
531
2,536,365
(105,254)
1,467,024
3,898,666
3,067,045
Total capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,263,616
6,965,711
Commitments and contingencies (See Note 11)
Current liabilities
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current maturities of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory excess deferred taxes (See Note 12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory cost of removal obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and postretirement liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred credits and other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
217,283
547,068
575,780
575,000
1,915,131
1,154,067
739,670
466,405
177,520
158,028
233,050
332,648
447,745
—
1,013,443
1,878,699
—
485,420
230,588
175,735
$11,874,437 $10,749,596
See accompanying notes to consolidated financial statements.
48
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
2018
Year Ended September 30
2017
(In thousands, except per share data)
2016
Operating revenues
Distribution segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pipeline and storage segment
Intersegment eliminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,003,047
507,713
(395,214)
$2,649,175
457,030
(346,470)
$2,339,778
427,196
(312,326)
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,115,546
2,759,735
2,454,648
Purchased gas cost
Distribution segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pipeline and storage segment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment eliminations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total purchased gas cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operation and maintenance expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . . . . .
Taxes, other than income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations before income taxes . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from discontinued operations, net of tax ($0, $6,841 and
$3,731) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of discontinued operations, net of tax ($0, $10,215 and
$0) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,559,836
1,978
(393,966)
1,167,848
599,595
361,083
263,886
723,134
(5,344)
106,646
611,144
8,080
603,064
1,269,456
2,506
(346,426)
1,058,576
(58)
(312,326)
925,536
546,798
319,448
240,407
727,546
(3,270)
120,182
604,094
221,383
382,711
746,192
538,592
290,791
221,843
657,230
(234)
114,812
542,184
196,642
345,542
—
—
10,994
4,562
2,716
—
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 603,064
$ 396,421
$ 350,104
Basic and diluted net income per share
Income per share from continuing operations . . . . . . . . . . . . . . . . . .
Income per share from discontinued operations . . . . . . . . . . . . . . . .
Net income per share—basic and diluted . . . . . . . . . . . . . . . . . . . . .
$
$
5.43
—
5.43
$
$
3.60
0.13
3.73
$
$
3.33
0.05
3.38
Basic and diluted weighted average shares outstanding . . . . . . . . . . . .
111,012
106,100
103,524
See accompanying notes to consolidated financial statements.
49
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net
of tax of $(146), $1,473 and $(245) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements,
net of tax of $13,017, $43,238 and $(56,723) . . . . . . . . . . . . . . . . . .
Net unrealized gains on commodity cash flow hedges, net of tax of $0,
$3,183 and $13,078 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018
Year Ended September 30
2017
(In thousands)
$396,421
2016
$350,104
$603,064
(395)
2,564
(465)
44,936
75,222
(98,682)
—
4,982
82,768
20,455
(78,692)
Total other comprehensive income (loss)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
44,541
Total comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$647,605
$479,189
$271,412
See accompanying notes to consolidated financial statements.
50
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
Common stock
Number of
Shares
Stated
Value
Additional
Paid-in
Capital
Accumulated
Other
Comprehensive
Income
(Loss)
Retained
Earnings
Total
(In thousands, except share and per share data)
Balance, September 30, 2015 . . . . . . 101,478,818 $507 $2,230,591
Net income . . . . . . . . . . . . . . . . . . . . .
—
Other comprehensive loss . . . . . . . .
—
Cash dividends ($1.68 per share) . . .
—
Cumulative effect of accounting
— —
— —
— —
change . . . . . . . . . . . . . . . . . . . . . .
— —
—
Common stock issued:
Public offering . . . . . . . . . . . . . . . .
Direct stock purchase plan . . . . . . .
Retirement savings plan . . . . . . . . .
1998 Long-term incentive plan . . . .
Employee stock-based
compensation . . . . . . . . . . . . . . .
1,360,756
133,133
359,414
598,439
7
1
2
3
98,567
9,228
25,047
3,175
— —
21,419
$(109,330) $1,073,029 $3,194,797
350,104
(78,692)
(175,126)
350,104
—
(175,126)
—
(78,692)
—
—
—
—
—
—
—
14,527
14,527
—
—
—
—
—
98,574
9,229
25,049
3,178
21,419
Balance, September 30, 2016 . . . . . . 103,930,560
Net income . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income . . . . .
Cash dividends ($1.80 per share) . . .
Common stock issued:
520
— —
— —
— —
2,388,027
—
—
—
(188,022)
—
82,768
—
1,262,534
396,421
—
(191,931)
3,463,059
396,421
82,768
(191,931)
Public offering . . . . . . . . . . . . . . . .
Direct stock purchase plan . . . . . . .
Retirement savings plan . . . . . . . . .
1998 Long-term incentive plan . . . .
Employee stock-based
compensation . . . . . . . . . . . . . . .
1,303,494
112,592
228,326
529,662
6
1
1
3
98,749
8,970
17,551
3,698
— —
19,370
—
—
—
—
—
—
—
—
—
—
98,755
8,971
17,552
3,701
19,370
Balance, September 30, 2017 . . . . . . 106,104,634
Net income . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income . . . . .
Cash dividends ($1.94 per share) . . .
Cumulative effect of accounting
531
— —
— —
— —
2,536,365
—
—
—
(105,254)
—
44,541
—
1,467,024
603,064
—
(214,906)
3,898,666
603,064
44,541
(214,906)
change (1)
. . . . . . . . . . . . . . . . . . . .
— —
—
(22,934)
22,934
—
Common stock issued:
Public offering . . . . . . . . . . . . . . . .
Direct stock purchase plan . . . . . . .
Retirement savings plan . . . . . . . . .
1998 Long-term incentive plan . . . .
Employee stock-based
compensation . . . . . . . . . . . . . . .
4,558,404
22
1
131,213
94,081 —
2
385,351
395,070
11,322
8,240
3,469
— —
20,460
—
—
—
—
—
— 395,092
11,323
—
8,240
—
3,471
—
—
20,460
Balance, September 30, 2018 . . . . . . 111,273,683 $556 $2,974,926
$ (83,647) $1,878,116 $4,769,951
(1) See Note 2, “Recent Accounting Pronouncements” for additional information.
See accompanying notes to consolidated financial statements.
51
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
2018
Year Ended September 30
2017
(In thousands)
2016
603,064 $
396,421 $
350,104
CASH FLOWS FROM OPERATING ACTIVITIES
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
One-time income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discontinued cash flow hedging for commodity contracts . . . . . . . . . . . . . . . . .
Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in assets and liabilities:
(Increase) decrease in accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Increase) decrease in gas stored underground . . . . . . . . . . . . . . . . . . . . . . . . . .
(Increase) decrease in other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Increase) decrease in deferred charges and other assets . . . . . . . . . . . . . . . . . .
Increase (decrease) in accounts payable and accrued liabilities . . . . . . . . . . . . .
Increase (decrease) in other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase (decrease) in deferred credits and other liabilities . . . . . . . . . . . . . . . .
361,083
158,271
(158,782)
—
—
12,863
7,865
5,437
(29,208)
18,921
60,424
(10,049)
(11,857)
74,707
31,923
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,124,662
CASH FLOWS USED IN INVESTING ACTIVITIES
319,633
227,183
—
(12,931)
(10,579)
14,064
6,469
97
(58,696)
(35,126)
9,991
102,254
53,017
(78,651)
(66,056)
867,090
293,096
193,556
—
—
—
14,760
5,667
1,019
(4,847)
20,577
(18,739)
(24,860)
(5,195)
(44,482)
14,334
794,990
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from the sale of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . .
Maturities of available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Use tax refund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,467,591)
—
3,000
(46,401)
22,360
15,716
790
8,560
(1,137,089)
(86,128)
140,253
(53,597)
31,792
9,332
29,790
9,341
(1,086,950)
—
—
(32,551)
27,019
6,290
—
6,460
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,463,566)
(1,056,306)
(1,079,732)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from issuance of long-term debt, net of premium/discount
. . . . . . . . . .
Net proceeds from equity offering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuance of common stock through stock purchase and employee retirement
plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlement of interest rate agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate agreements cash collateral
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayment of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
128,035
—
395,092
19,563
—
—
—
(214,906)
—
(1,518)
(382,066)
884,911
98,755
26,523
(36,996)
25,670
(250,000)
(191,931)
(6,775)
—
371,884
—
98,574
34,278
—
(25,670)
—
(175,126)
(317)
—
Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
326,266
168,091
303,623
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . .
(12,638)
26,409
(21,125)
47,534
Cash and cash equivalents at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
13,771 $
26,409 $
18,881
28,653
47,534
CASH PAID (RECEIVED) DURING THE PERIOD FOR:
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
169,987 $
6,102 $
156,668 $
5,264 $
154,748
7,794
See accompanying notes to consolidated financial statements.
52
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and its subsidiaries are engaged in the
regulated natural gas distribution and pipeline and storage businesses. Through our distribution business, we
deliver natural gas through sales and transportation arrangements to over three million residential, commercial,
public-authority and industrial customers through our six regulated distribution divisions in the service areas
described below:
Division
Service Area
Atmos Energy Colorado-Kansas Division . . . . . . . . Colorado, Kansas
Atmos Energy Kentucky/Mid-States Division . . . . Kentucky, Tennessee, Virginia(1)
Atmos Energy Louisiana Division . . . . . . . . . . . . . . Louisiana
Atmos Energy Mid-Tex Division . . . . . . . . . . . . . . Texas, including the Dallas/Fort Worth
metropolitan area
Atmos Energy Mississippi Division . . . . . . . . . . . . Mississippi
Atmos Energy West Texas Division . . . . . . . . . . . . West Texas
(1) Denotes location where we have more limited service areas.
In addition, we transport natural gas for others through our distribution system. Our distribution business is
subject to federal and state regulation and/or regulation by local authorities in each of the states in which our dis-
tribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas,
and our customer support centers are located in Amarillo and Waco, Texas.
Our pipeline and storage business, which is also subject to federal and state regulation, consists of the the
pipeline and storage operations of our Atmos Pipeline—Texas (APT) Division and our natural gas transmission
business in Louisiana. The APT division 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 manages five underground storage facilites in Texas. We
also provide ancillary services customary to the pipeline industry including parking arrangements, lending and
sales of inventory on hand. 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.
2. Summary of Significant Accounting Policies
Principles of consolidation — The accompanying consolidated financial statements include the accounts of
Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been
eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery
under the affiliates’ rate regulation process.
Use of estimates — The preparation of financial statements in conformity with accounting principles gen-
erally accepted in the United States requires management to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allow-
ance for doubtful accounts, unbilled revenues, contingency accruals, pension and postretirement obligations,
deferred income taxes, impairment of long-lived assets, risk management and trading activities, fair value meas-
urements and the valuation of goodwill and other long-lived assets. Actual results could differ from those esti-
mates.
Regulation — Our distribution and pipeline and storage operations are subject to regulation with respect to
rates, service, maintenance of accounting records and various other matters by the respective regulatory author-
ities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking
and accounting practices and policies of the various regulatory commissions. Accounting principles generally
53
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the
authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are
permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain
costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory
liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to cus-
tomers through the ratemaking process. The amounts to be recovered or recognized are based upon historical
experience and our understanding of the regulations. Further, regulation may impact the period in which revenues
or expenses are recognized.
Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets
and a portion of our regulatory liabilities are recorded as a component of other current liabilities and deferred
credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and our
regulatory excess deferred taxes and regulatory cost of removal obligation are reported separately. Significant
regulatory assets and liabilities as of September 30, 2018 and 2017 included the following:
Regulatory assets:
. . . . . . . . . . . . . . . . . . . . . . . . .
Pension and postretirement benefit costs(1)
Infrastructure mechanisms(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred gas costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recoverable loss on reacquired debt
Deferred pipeline record collection costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
APT annual adjustment mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate case costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory liabilities:
Regulatory excess deferred taxes(3)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory cost of service reserve(4)
Regulatory cost of removal obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred gas costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
APT annual adjustment mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and postretirement benefit costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30
2018
2017
(In thousands)
$
6,496
96,739
1,927
8,702
20,467
—
2,741
6,739
$ 143,811
$ 744,895
22,508
522,175
94,705
12,887
35,228
69,113
9,486
$ 26,826
46,437
65,714
11,208
11,692
2,160
2,629
10,132
$176,798
$
—
—
521,330
15,559
12,827
—
—
5,941
$1,510,997
$555,657
(1) Includes $6.5 million and $9.4 million of pension and postretirement expense deferred pursuant to regulatory
authorization.
(2) Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all eligible expenses associated
with capital expenditures incurred pursuant to these rules, including the recording of interest on the deferred
expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs
would be recovered through base rates.
(3) The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. Of this
amount, $5.2 million is recorded in other current liabilities. The period and timing of the return of the excess
54
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
deferred taxes is being determined by regulators in each of our jurisdictions. See Note 12 for further
information.
(4) Effective January 1, 2018, regulators in each of our service areas required us to establish a regulatory
liability for the difference in recoverable federal taxes included in revenues based on the former 35% federal
statutory rate and the new 21% federal statutory rate for service provided on or after January 1, 2018. The
period and timing of the return of this liability to utility customers is being determined by regulators in each
of our jurisdictions. See Note 12 for further information.
Revenue recognition — Sales of natural gas to our distribution customers are billed on a monthly basis;
however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting
periods used for financial reporting purposes. We follow the revenue accrual method of accounting for dis-
tribution segment revenues whereby revenues applicable to gas delivered to customers, but not yet billed under
the cycle billing method, are estimated and accrued and the related costs are charged to expense.
On occasion, we are permitted to implement new rates that have not been formally approved by our state
regulatory commissions, which are subject to refund. As permitted by accounting principles generally accepted in
the United States, we recognize this revenue and establish a reserve for amounts that could be refunded based on
our experience for the jurisdiction in which the rates were implemented.
Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas
costs through purchased gas cost adjustment mechanisms. Purchased gas cost adjustment mechanisms provide
gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate
case to address all of their non-gas costs. There is no margin generated through purchased gas cost adjustments,
but they provide a dollar-for-dollar offset to increases or decreases in our distribution segment’s gas costs. The
effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our balance
sheet.
Operating revenues for our pipeline and storage segment are recognized in the period in which volumes are
transported.
Discontinued operations — Accounting policies specific to our discontinued natural gas marketing business
are described in more detail in Note 15.
Cash and cash equivalents — We consider all highly liquid investments with an original maturity of three
months or less to be cash equivalents.
Accounts receivable and allowance for doubtful accounts — Accounts receivable arise from natural gas
sales to residential, commercial, industrial, municipal and other customers. We establish an allowance for doubt-
ful accounts to reduce the net receivable balance to the amount we reasonably expect to collect based on our col-
lection experience or where we are aware of a specific customer’s inability or reluctance to pay. However, if
circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances
which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas
prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be
uncollectible.
Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to
support the winter season withdrawals for our distribution operations. The average cost method is used for all of
our distribution operations. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classi-
fied as property, plant and equipment and is valued at cost.
Property, plant and equipment — Regulated property, plant and equipment is stated at original cost, net of
contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs
(taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used
during construction. The allowance for funds used during construction represents the estimated cost of funds
55
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
used to finance the construction of major projects and are capitalized in the rate base for ratemaking purposes
when the completed projects are placed in service. Interest expense of $6.8 million, $2.5 million and $2.8 million
was capitalized in 2018, 2017 and 2016.
Major renewals, including replacement pipe, and betterments that are recoverable under our regulatory rate
base are capitalized while the costs of maintenance and repairs that are not capitalizable are charged to expense
as incurred. The costs of large projects are accumulated in construction in progress until the project is completed.
When the project is completed, tested and placed in service, the balance is transferred to the regulated plant in
service account included in the rate base and depreciation begins.
Regulated property, plant and equipment is depreciated at various rates on a straight-line basis. These rates
are approved by our regulatory commissions and are comprised of two components: one based on average serv-
ice life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a compo-
nent of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the
consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage,
are charged to the regulatory cost of removal accrual. The composite depreciation rate was 3.2 percent,
3.1 percent and 3.2 percent for the fiscal years ended September 30, 2018, 2017 and 2016.
Other property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line
method for financial reporting purposes based upon estimated useful lives.
Asset retirement obligations — We record a liability at fair value for an asset retirement obligation when
the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the
related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating
expense.
As of September 30, 2018 and 2017, we had asset retirement obligations of $12.9 million and $12.8 million.
Additionally, we had $7.5 million and $7.8 million of asset retirement costs recorded as a component of property,
plant and equipment that will be depreciated over the remaining life of the underlying associated assets.
We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not
recognized an asset retirement obligation associated with our storage facilities because we are not able to
determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service
permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.
Impairment of long-lived assets — We periodically evaluate whether events or circumstances have
occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may
warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived
assets by determining whether the carrying value will be recovered through the expected future cash flows. In the
event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value
of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.
Goodwill — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or
more frequently as impairment indicators arise. During the second quarter of fiscal 2018, we completed our
annual goodwill impairment assessment using a qualitative assessment, as permitted under U.S. GAAP. We test
goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs
or circumstances change that would more likely than not reduce the fair value of the reporting unit. Based on the
assessment performed, we determined that our goodwill was not impaired. Although not applicable for the fiscal
2018 analysis, if the qualitative assessment resulted in impairment indicators, we would then use a present value
technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are
dependent on several subjective factors including the timing of future cash flows, future growth rates and the
discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its
fair value.
56
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Marketable securities — As of September 30, 2018 and 2017, all of our marketable securities were classi-
fied as available for sale. In accordance with the current authoritative accounting standards, these securities,
including both debt and equity securities, are reported at market value with unrealized gains and losses shown as
a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these
investments on an individual investment by investment basis for impairment, taking into consideration the fund’s
purpose, volatility and current returns. If a determination is made that a decline in fair value is other than tempo-
rary, the related investment is written down to its estimated fair value. Beginning on October 1, 2018, changes in
fair value of our equity available for sale securities will be recorded in net income as discussed further below in
the Recent accounting pronouncements section.
Financial instruments and hedging activities — We use financial instruments to mitigate commodity price
risk in our distribution and pipeline and storage segments and to mitigate interest rate risk. The objectives and
strategies for using financial instruments have been tailored to our continuing business and are discussed in Note
13.
We record all of our financial instruments on the balance sheet at fair value, with changes in fair value ulti-
mately recorded in the income statement. These financial instruments are reported as risk management assets and
liabilities and are classified as current or noncurrent other assets or liabilities based upon the anticipated settle-
ment date of the underlying financial instrument. We record the cash flow impact of our financial instruments in
operating cash flows based upon their balance sheet classification.
The timing of when changes in fair value of our financial instruments are recorded in the income statement
depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship
or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments
that do not meet one of these criteria are recognized in the income statement as they occur.
Financial Instruments Associated with Commodity Price Risk
In our distribution segment, the costs associated with and the realized gains and losses arising from the use
of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment
mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial
instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated state-
ment of income as a component of purchased gas cost when the related costs are recovered through our rates and
recognized in revenue in accordance with accounting principles generally accepted in the United States. Accord-
ingly, there is no earnings impact on our distribution segment as a result of the use of financial instruments.
Financial Instruments Associated with Interest Rate Risk
We manage interest rate risk, primarily when we plan to issue long-term debt. We currently manage this risk
through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost
associated with anticipated financings. We designate these financial instruments as cash flow hedges at the time
the agreements are executed. Unrealized gains and losses associated with the instruments are recorded as a
component of accumulated other comprehensive income (loss). When the instruments settle, the realized gain or
loss is recorded as a component of accumulated other comprehensive income (loss) and recognized as a compo-
nent of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent
incurred is reported as a component of interest expense. As of September 30, 2018 and September 30, 2017, no
cash was required to be held in margin accounts.
Fair Value Measurements — We report certain assets and liabilities at fair value, which is defined as the
price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price). We primarily use quoted market prices and other observable
market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable
pricing inputs in our measurements.
57
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties
involved. Our counterparties consist primarily of financial institutions and major energy companies. This concen-
tration of counterparties may materially impact our exposure to credit risk resulting from market, economic or
regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial con-
dition and credit ratings and the use of collateral requirements under certain circumstances.
Amounts reported at fair value are subject to potentially significant volatility based upon changes in market
prices, including, but not limited to, the valuation of the portfolio of our contracts, maturity and settlement of
these contracts and newly originated transactions and interest rates, each of which directly affect the estimated
fair value of our financial instruments. We believe the market prices and models used to value these financial
instruments represent the best information available with respect to closing exchange and over-the-counter quota-
tions, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact
of an orderly liquidation of our positions over a reasonable period of time under then current market conditions.
Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to meas-
ure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels,
with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities
(Level 1) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described
below:
Level 1 — Represents unadjusted quoted prices in active markets for identical assets or liabilities. An active
market for the asset or liability is defined as a market in which transactions for the asset or liability occur with
sufficient frequency and volume to provide pricing information on an ongoing basis. Prices actively quoted on
national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our bal-
ance sheet at fair value.
Our Level 1 measurements consist primarily of our available-for-sale securities. The Level 1 measurements
for investments in the Atmos Energy Corporation Master Retirement Trust (the Master Trust), Supplemental
Executive Benefit Plan and postretirement benefit plan consist primarily of exchange-traded financial instru-
ments.
Level 2 — Represents pricing inputs other than quoted prices included in Level 1 that are either directly or
indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from,
or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-exchange-traded
financial instruments, such as over-the-counter options and swaps and municipal and corporate bonds where
market data for pricing is observable. The Level 2 measurements for investments in our Master Trust, Supple-
mental Executive Benefit Plan and postretirement benefit plan consist primarily of non-exchange traded financial
instruments such as corporate bonds and government securities.
Level 3 — Represents generally unobservable pricing inputs which are developed based on the best
information available, including our own internal data, in situations where there is little if any market activity for
the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would
use to determine fair value. We currently do not have any Level 3 investments.
Pension and other postretirement plans — Pension and other postretirement plan costs and liabilities are
determined on an actuarial basis and are affected by numerous assumptions and estimates including the market
value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demo-
graphic and actuarial mortality data. Our measurement date is September 30. The assumed discount rate and the
expected return are the assumptions that generally have the most significant impact on our pension costs and
liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement
generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rate is utilized principally in calculating the actuarial present value of our pension and post-
retirement obligation and net pension and postretirement cost. When establishing our discount rate, we consider
58
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the
obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching
our projected benefit disbursements with currently available high quality corporate bonds.
The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets
component of the annual pension and postretirement plan cost. We estimate the expected return on plan assets by
evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management,
the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our
investment advisors when making a final determination of our expected rate of return on assets. To the extent the
actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that
year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss is amortized over the
expected future working lifetime of the plan participants.
The expected return on plan assets is then calculated by applying the expected long-term rate of return on
plan assets to the market-related value of the plan assets. The market-related value of our plan assets represents
the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year
period. The use of this calculation will delay the impact of current market fluctuations on the pension expense for
the period.
We use a corridor approach to amortize actuarial gains and losses. Under this approach, net gains or losses
in excess of ten percent of the larger of the pension benefit obligation or the market-related value of the assets are
amortized on a straight-line basis. The period of amortization is the average remaining service of active partic-
ipants who are expected to receive benefits under the plan.
We estimate the assumed health care cost trend rate used in determining our annual postretirement net cost
based upon our actual health care cost experience, the effects of recently enacted legislation and general
economic conditions. Our assumed rate of retirement is estimated based upon the annual review of our partic-
ipant census information as of the measurement date.
Income taxes — Income taxes are determined based on the liability method, which results in income tax
assets and liabilities arising from temporary differences. Temporary differences are differences between the tax
bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or
deductible amounts in future years. The liability method requires the effect of tax rate changes on accumulated
deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method
also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the
assets will be realized.
The Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely
than not that the tax position will be sustained on examination by the taxing authorities, based on the technical
merits of the position. The tax benefits recognized in the financial statements from such a position should be
measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon
settlement with the taxing authorities. We recognize accrued interest related to unrecognized tax benefits as a
component of interest expense. We recognize penalties related to unrecognized tax benefits as a component of
miscellaneous income (expense) in accordance with regulatory requirements.
Tax collections — We are allowed to recover from customers revenue-related taxes that are imposed upon
us. We record such taxes as operating expenses and record the corresponding customer charges as operating
revenues. However, we do collect and remit various other taxes on behalf of various governmental authorities,
and we record these amounts in our consolidated balance sheets on a net basis. We do not collect income taxes
from our customers on behalf of governmental authorities.
Contingencies — In the normal course of business, we are confronted with issues or events that may result
in a contingent liability. These generally relate to lawsuits, claims made by third parties or the action of various
59
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
regulatory agencies. For such matters, we record liabilities when they are considered probable and estimable,
based on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the
future. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expect-
ations surrounding each potential exposure.
Subsequent events — Except as noted in Note 5 and 6 regarding the public offering of senior notes, no
events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial
statements.
Recent accounting pronouncements
Accounting pronouncements adopted in fiscal 2018
In February 2018, the Financial Accounting Standards Board (FASB) issued new guidance as a result of the
Tax Cuts and Jobs Act of 2017 (the “TCJA”), related to the treatment of certain tax effects from accumulated
other comprehensive income. The new guidance allows entities to reclassify from accumulated other compre-
hensive income to retained earnings the stranded tax effects resulting from the adoption of the TCJA. The new
guidance will be effective for us in the fiscal year beginning on October 1, 2019 and for interim periods within
that year. Early adoption is permitted, including adoption in any interim period for public business entities for
reporting periods for which financial statements have not yet been issued and should be applied either in the
period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S.
federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. We have early adopted the new
standard effective as of September 30, 2018, and reclassified the stranded tax effects of $22.9 million, resulting
from the TCJA from accumulated other comprehensive income to retained earnings. This change is reflected on
our consolidated statement of shareholders’ equity.
In January 2017, the FASB issued new guidance that simplified the accounting for goodwill impairments by
eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a
reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess,
limited to the total amount of goodwill allocated to that reporting unit. We early adopted the new standard, effec-
tive for our goodwill impairment test performed in our second fiscal quarter of 2018. The new standard did not
have a material impact on our results of operations, consolidated balance sheets or cash flows.
Accounting pronouncements that will be effective in fiscal 2019
In May 2014, the FASB issued a comprehensive new revenue recognition standard that superseded virtually
all existing revenue recognition guidance under generally accepted accounting principles in the United States.
Under the new standard, an entity recognizes revenue when it transfers promised goods or services to customers
in an amount that reflects the consideration to which the company expects to be entitled in exchange for those
goods or services. In doing so, companies may need to use more judgment and make more estimates than under
current guidance. The new guidance will become effective for us October 1, 2018 and can be applied either
retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption.
We have completed the evaluation of our sources of revenue and the impact that the new guidance will have
on our financial position, results of operations, cash flows and business processes. Based on this evaluation, we
do not believe the implementation of the new guidance will have a material effect on our financial position,
results of operations, cash flows or business processes. We intend to apply the new guidance using the modified
retrospective method on the date of adoption. The most impactful change from the adoption of this standard will
be the disclosure requirements. In the first quarter of fiscal 2019, we will add a new revenue footnote which will
contain a disaggregation of revenues from contracts with customers by customer type.
In March 2017, the FASB issued new guidance related to the income statement presentation of the compo-
nents of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement
60
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
plans. The new guidance requires entities to disaggregate the current service cost component of the net benefit
cost from the other components and present it with other current compensation costs for related employees in the
statement of income. The other components of net benefit cost will be presented outside of income from oper-
ations on the statement of income. In addition, only the service cost component of net benefit cost is eligible for
capitalization (e.g., as part of inventory or property, plant, and equipment). The Federal Energy Regulatory
Commission (“FERC”), which regulates interstate transmission pipelines and also establishes, through its Uni-
form System of Accounts, accounting practices for rate-regulated entities, has issued guidance that states it will
permit an election to either continue to capitalize non-service benefit costs or to cease capitalizing such costs for
regulatory purposes. Accounting guidelines by the FERC are typically also followed by state commissions. As
such, we plan to continue to capitalize into property, plant and equipment all components of net periodic benefit
cost for ratemaking purposes and will defer the non-service cost components as a regulatory asset for U.S. GAAP
reporting purposes. The new guidance will be effective for us in the fiscal year beginning on October 1, 2018 and
for interim periods within that year. The standard requires retrospective application for presentation of
non-service cost components outside of income from operations in the statement of income and prospective
application of the change in eligible costs for capitalization. We do not anticipate the new standard will have a
material impact on our financial position, results of operations and cash flows.
In January 2016, the FASB issued guidance related to the classification and measurement of financial
instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity
investments not consolidated or reported using the equity method. The guidance is effective for us beginning
October 1, 2018. The standard will require that changes in fair value of our available-for-sale equity securities be
recorded in net income. However, the accounting for our available-for-sale debt securities remains unchanged as
a result of this guidance. The new guidance will be applied by means of a cumulative-effect adjustment to the
balance sheet as of the beginning of fiscal year 2019. We expect to record a cumulative-effect adjustment of
approximately $8 million from accumulated other comprehensive income to retained earnings. We do not antici-
pate the new standard will have a material impact on our financial position, results of operations or cash flows.
In August 2018, the FASB issued new guidance aligning the requirements for capitalizing implementation
costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing
implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include
an internal-use software license). The amendments require a customer in a hosting arrangement that is a service
contract to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as an
asset related to the service contract and which costs to expense. The new guidance is effective for us in the fiscal
year beginning October 1, 2020 and for interim periods within that year. Early adoption is permitted, including
adoption in any interim period. The amendments should be applied either retrospectively or prospectively to all
implementation costs incurred after the date of adoption. We intend to early adopt the guidance prospectively as
of the fiscal year beginning October 1, 2018. We do not anticipate the new standard will have a material impact
on our financial position, results of operations or cash flows.
Recently issued accounting pronouncements that will be effective after fiscal 2019
In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recog-
nize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12
months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019; early adop-
tion is permitted. The new leasing standard requires modified retrospective transition, which requires application
of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. Addi-
tionally, in January 2018, the FASB issued amendments to the standard that provides a practical expedient for
entities to not evaluate existing or expired land easements that were not previously accounted for as leases under
the current guidance. In July 2018, the FASB issued an amendment to the standard that provides an additional
and optional transition method to adopt the standard at the adoption date and recognize a cumulative-effect
adjustment to the opening balance of retained earnings in the period of adoption. We are currently evaluating the
61
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
effect of this standard and amendments on our financial position, results of operations, cash flows and business
processes.
In June 2016, the FASB issued new guidance which will require credit losses on most financial assets meas-
ured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under
this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of
initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that
delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also
introduces a new impairment recognition model for available-for-sale securities that will require credit losses for
available-for-sale debt securities to be recorded through an allowance account. The new standard will be effec-
tive for us beginning on October 1, 2021; early adoption is permitted beginning on October 1, 2019. We are cur-
rently evaluating the potential impact of this new guidance on our financial position, results of operations and
cash flows.
In August 2018, the FASB issued new guidance that modifies the disclosure requirements for employers
that sponsor defined benefit pension or other postretirement plans. The guidance removes the disclosure
requirements for the amounts of gain/loss and prior service cost/credit amortization expected in the following
year and the disclosure of the effect of a one-percentage-point change in the health care cost trend rate, among
other changes. The guidance adds certain disclosures including the weighted average interest crediting rate for
cash balance plans and a narrative description for the significant change in gains and losses as well as any other
significant change in the plan obligations or assets. The new guidance is effective for us in the fiscal year begin-
ning October 1, 2020 and should be applied on a retrospective basis to all periods presented. Early adoption is
permitted. The adoption of this new guidance impacts only our disclosures; however we are still evaluating the
timing of our adoption.
3.
Segment Information
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.
Our determination of reportable segments considers the strategic operating units under which we manage
sales of various products and services to customers in differing regulatory environments. Although our dis-
tribution segment operations are geographically dispersed, they are aggregated and reported as a single segment
as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline
and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in
Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.
The accounting policies of the segments are the same as those described in the summary of significant
accounting policies. We evaluate performance based on net income or loss of the respective operating units. We
allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension
liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have
been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of
recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each
segment’s taxes were calculated on a separate return basis.
62
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Income statements and capital expenditures by segment are shown in the following tables.
Year Ended September 30, 2018
Distribution
Pipeline and
Storage
Eliminations
Consolidated
(In thousands)
Operating revenues from external parties . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,000,404
2,643
$115,142
392,571
$
(395,214)
— $3,115,546
—
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . .
Purchased gas cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operation and maintenance expense . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . .
Taxes, other than income . . . . . . . . . . . . . . . . . . . . . . . .
3,003,047
1,559,836
465,848
264,930
231,566
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes . . . . . . . . . . . . . . . . . . . . . .
Income tax (benefit) expense . . . . . . . . . . . . . . . . . . . . .
480,867
(1,849)
65,850
413,168
(29,798)
507,713
1,978
134,995
96,153
32,320
242,267
(3,495)
40,796
197,976
37,878
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 442,966
$160,098
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,025,800
$441,791
(395,214)
(393,966)
(1,248)
—
—
—
—
—
—
—
3,115,546
1,167,848
599,595
361,083
263,886
723,134
(5,344)
106,646
611,144
8,080
$
$
— $ 603,064
— $1,467,591
Distribution
Operating revenues from external
parties . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . .
$2,647,813
1,362
Total operating revenues . . . . . . . . . . .
Purchased gas cost . . . . . . . . . . . . . . . . . .
Operation and maintenance expense . . . .
Depreciation and amortization
expense . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes, other than income . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . .
Miscellaneous expense . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations
before income taxes . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . .
Income from continuing operations . . . . .
Income from discontinued operations, net
of tax . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of discontinued operations,
net of tax . . . . . . . . . . . . . . . . . . . . . . . .
2,649,175
1,269,456
413,077
249,071
211,929
505,642
(1,695)
79,789
424,158
155,789
268,369
—
—
$111,922
345,108
457,030
2,506
133,765
70,377
28,478
221,904
(1,575)
40,393
179,936
65,594
114,342
Pipeline and
Storage
Year Ended September 30, 2017
Natural Gas
Marketing
(In thousands)
Eliminations
Consolidated
$ —
—
$
(346,470)
— $2,759,735
—
—
—
—
—
—
—
—
—
—
—
—
(346,470)
(346,426)
(44)
2,759,735
925,536
546,798
—
—
—
—
—
—
—
—
—
—
319,448
240,407
727,546
(3,270)
120,182
604,094
221,383
382,711
10,994
2,716
—
—
10,994
2,716
Net income . . . . . . . . . . . . . . . . . . . .
$ 268,369
$114,342
$13,710
Capital expenditures . . . . . . . . . . . . . . . . .
$ 849,950
$287,139
$ —
$
$
— $ 396,421
— $1,137,089
63
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Distribution
Pipeline and
Storage
Year Ended September 30, 2016
Natural Gas
Marketing
(In thousands)
Eliminations
Consolidated
Operating revenues from external
parties . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . .
$2,338,404
1,374
$116,244
310,952
$ —
—
$
(312,326)
— $2,454,648
—
Total operating revenues . . . . . . . . . . .
Purchased gas cost . . . . . . . . . . . . . . . . . .
Operation and maintenance expense . . . .
Depreciation and amortization
expense . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes, other than income . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . .
Miscellaneous income (expense) . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations
before income taxes . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . .
Income from continuing operations . . . . .
Income from discontinued operations, net
of tax . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,339,778
1,058,576
407,982
234,109
197,227
441,884
1,171
78,238
364,817
130,987
233,830
427,196
(58)
130,610
56,682
24,616
215,346
(1,405)
36,574
177,367
65,655
111,712
—
—
Net income . . . . . . . . . . . . . . . . . . . .
$ 233,830
$111,712
Capital expenditures . . . . . . . . . . . . . . . . .
$ 740,246
$346,383
—
—
—
—
—
—
—
—
—
—
—
4,562
$4,562
$ 321
(312,326)
(312,326)
—
2,454,648
746,192
538,592
—
—
—
—
—
—
—
—
—
290,791
221,843
657,230
(234)
114,812
542,184
196,642
345,542
4,562
$
$
— $ 350,104
— $1,086,950
The following table summarizes our revenues from external parties by products and services for the fiscal
year ended September 30.
Distribution revenues:
Gas sales revenues:
2018
2017
(In thousands)
2016
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authority and other . . . . . . . . . . . . . . . . . . . . . . .
$1,916,101
797,073
131,267
47,714
Total gas sales revenues . . . . . . . . . . . . . . . . . . . . . .
Transportation revenues . . . . . . . . . . . . . . . . . . . . . . . . . .
Other gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total distribution revenues . . . . . . . . . . . . . . . . . . . . . .
Pipeline and storage revenues . . . . . . . . . . . . . . . . . . . . . . . .
2,892,155
99,250
8,999
3,000,404
115,142
$1,642,918
708,167
133,372
45,820
2,530,277
86,332
31,204
2,647,813
111,922
$1,477,049
619,979
98,439
41,307
2,236,774
76,690
24,940
2,338,404
116,244
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . .
$3,115,546
$2,759,735
$2,454,648
64
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Balance sheet information at September 30, 2018 and 2017 by segment is presented in the following tables.
Property, plant and equipment, net
. . . . . . . . . . . . .
$ 7,644,693
$2,726,454
$
— $10,371,147
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11,109,128
$2,963,480
$(2,198,171)
$11,874,437
September 30, 2018
Distribution
Pipeline and
Storage
Eliminations
Consolidated
(In thousands)
September 30, 2017
Distribution
Pipeline and
Storage
Eliminations
Consolidated
(In thousands)
Property, plant and equipment, net
. . . . . . . . . . . . .
$ 6,849,517
$2,409,665
$
— $ 9,259,182
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10,050,164
$2,621,601
$(1,922,169)
$10,749,596
4. Earnings Per Share
We use the two-class method of computing earnings per share because we have participating securities in
the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vest-
ing is predicated solely on the passage of time. The calculation of earnings per share using the two-class method
excludes income attributable to these participating securities from the numerator and excludes the dilutive impact
of those shares from the denominator.
Basic and diluted earnings per share for the fiscal years ended September 30 are calculated as follows:
2018
2016
2017
(In thousands, except per share data)
Basic and Diluted Earnings Per Share from continuing
operations
Income from continuing operations . . . . . . . . . . . . . . . . . . . . . .
Less: Income from continuing operations allocated to
participating securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations available to common
$603,064
$382,711
$345,542
580
475
538
shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$602,484
$382,236
$345,004
Basic and diluted weighted average shares outstanding . . . . . .
111,012
106,100
103,524
Income from continuing operations per share — Basic and
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
5.43
$
3.60
$
3.33
Basic and Diluted Earnings Per Share from discontinued
operations
Income from discontinued operations . . . . . . . . . . . . . . . . . . . .
Less: Income from discontinued operations allocated to
participating securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from discontinued operations available to common
$
— $ 13,710
$
4,562
—
12
8
shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $ 13,698
$
4,554
Basic and diluted weighted average shares outstanding . . . . . .
111,012
106,100
103,524
Income from discontinued operations per share — Basic and
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income per share — Basic and Diluted . . . . . . . . . . . . . .
$
$
— $
5.43
$
0.13
3.73
$
$
0.05
3.38
65
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
5. Debt
Long-term debt
Long-term debt at September 30, 2018 and 2017 consisted of the following:
2018
2017
(In thousands)
Unsecured 8.50% Senior Notes, due March 2019 . . . . . . . . . . . . . . . . . . . .
Unsecured 3.00% Senior Notes, due 2027 . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured 5.95% Senior Notes, due 2034 . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured 5.50% Senior Notes, due 2041 . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured 4.15% Senior Notes, due 2043 . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured 4.125% Senior Notes, due 2044 . . . . . . . . . . . . . . . . . . . . . . . . .
Medium term Series A notes, 1995-1, 6.67%, due 2025 . . . . . . . . . . . . . . .
Unsecured 6.75% Debentures, due 2028 . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
Floating-rate term loan, due September 2019(1)
$ 450,000
500,000
200,000
400,000
500,000
750,000
10,000
150,000
125,000
$ 450,000
500,000
200,000
400,000
500,000
750,000
10,000
150,000
125,000
Total long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,085,000
3,085,000
Less:
Original issue (premium) / discount on unsecured senior notes and
debentures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(4,439)
20,774
575,000
(4,384)
22,339
—
$2,493,665
$3,067,045
(1) Up to $200 million can be drawn under this term loan.
Maturities of long-term debt at September 30, 2018 were as follows (in thousands):
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
$ 575,000
—
—
—
—
2,510,000
$3,085,000
On October 4, 2018, we completed a public offering of $600 million of 4.30% senior notes due 2048. We
received net proceeds from the offering, after the 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.
On June 8, 2017, we completed a public offering of $500 million of 3.00% senior notes due 2027 and
$250 million of 4.125% senior notes due 2044. The effective rate of these notes is 3.12% and 4.40%, after giving
effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net pro-
ceeds, excluding the loss on the settlement of the interest rate swaps of $37 million, of approximately
$753 million were used to repay our $250 million 6.35% senior unsecured notes at maturity on June 15, 2017 and
for general corporate purposes, including the repayment of working capital borrowings pursuant to our commer-
cial paper program.
66
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
We utilize short-term debt to provide cost-effective, short-term financing until it can be replaced with a
balance of long-term debt and equity financing that achieves the Company’s desired capital structure with an
equity-to-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Our short-term
borrowing requirements are affected primarily by the seasonal nature of the natural gas business. Changes in the
price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly
affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter
months.
Currently, our short-term borrowing requirements are satisfied through a combination of a $1.5 billion
commercial paper program and three committed revolving credit facilities with third-party lenders that provide
approximately $1.5 billion of total working capital funding. The primary source of our funding is our commercial
paper program, which is supported by a five-year unsecured $1.5 billion credit facility. On March 26, 2018, we
executed one of our two one-year extension options which extended the maturity date from September 25, 2021
to September 25, 2022. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable inter-
est period, plus a spread ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. Addi-
tionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the
total committed loan to $1.75 billion. At September 30, 2018 and 2017, there was $575.8 million and
$447.7 million outstanding under our commercial paper program with weighted average interest rates of 2.15%
and 1.25%, with weighted average maturities of less than one month.
Additionally, we have a $25 million 364-day unsecured facility, which was renewed on April 1, 2018 and
expires March 31, 2019, and a $10 million 364-day unsecured revolving credit facility, which is used primarily to
issue letters of credit and which was renewed on September 30, 2018. At September 30, 2018, there were no
borrowings outstanding under either of these facilities; however, outstanding letters of credit reduced the total
amount available to us under our $10 million unsecured revolving facility to $4.4 million.
The availability of funds under these credit facilities is subject to conditions specified in the respective
credit agreements, all of which we currently satisfy. These conditions include our compliance with financial
covenants and the continued accuracy of representations and warranties contained in these agreements. We are
required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio
of total debt to total capitalization of no greater than 70 percent. At September 30, 2018, our total-debt-to-total-
capitalization ratio, as defined, was 44 percent. In addition, both the interest margin and the fee that we pay on
unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.
These credit facilities and our public indentures contain usual and customary covenants for our business,
including covenants substantially limiting liens, substantial asset sales and mergers. Additionally, our public debt
indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each
contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements
in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is
not paid at maturity. We were in compliance with all of our debt covenants as of September 30, 2018. If we were
unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on
demand, provide additional collateral or take other corrective actions.
6. Shareholders’ Equity
Shelf Registration, At-the-Market Equity Sales Program and Equity Issuance
On March 28, 2016, we filed a registration statement with the Securities and Exchange Commission (SEC)
that originally permitted us to issue, from time to time, up to $2.5 billion in common stock and/or debt securities,
which expires March 28, 2019. At September 30, 2018, approximately $650.0 million of securities remained
available for issuance under the shelf registration statement. The issuance of our $600 million senior unsecured
notes in October 2018, as discussed in Note 5, effectively exhausted this shelf registration statement.
67
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
On November 14, 2017, we filed a prospectus supplement under the registration statement relating to an
at-the-market (ATM) equity sales program under which we may issue and sell shares of our common stock up to
an aggregate offering price of $500 million, which expires March 28, 2019. During the year ended September 30,
2018, no shares of common stock were sold under our ATM equity sales program.
On November 30, 2017, we filed a prospectus supplement under the registration statement relating to an
underwriting agreement to sell 4,558,404 shares of our common stock for $400 million. After expenses, net pro-
ceeds from the offering were $395.1 million.
1998 Long-Term Incentive Plan
In August 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (LTIP),
which became effective in October 1998 after approval by our shareholders. The LTIP is a comprehensive, long-
term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified
stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units,
performance-based restricted stock units and stock units to certain employees and non-employee directors of the
Company and our subsidiaries. The objectives of this plan include attracting and retaining the best available
personnel, providing for additional performance incentives and promoting our success by providing employees
with the opportunity to acquire our common stock.
Accumulated Other Comprehensive Income (Loss)
We record deferred gains (losses) in accumulated other comprehensive income (AOCI) related to
available-for-sale securities, which include equity and debt securities, interest rate agreement cash flow hedges
and commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and
commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses)
related to our interest rate agreement cash flow hedges are recognized in earnings as a component of interest
expense, as they are amortized. The following tables provide the components of our accumulated other compre-
hensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive
income (loss). Additionally, as discussed further in Note 2, we have early adopted a new accounting standard
effective as of September 30, 2018. The adoption resulted in a reclassification of the stranded tax effects result-
ing from the TCJA, from accumulated other comprehensive income to retained earnings, as seen in the table
below.
September 30, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income (loss) before reclassifications . . . . . . . . . . . .
Amounts reclassified from accumulated other comprehensive income . . . .
$ 7,048
1,426
(1,821)
Available-
for-Sale
Securities
Interest
Rate
Agreement
Cash Flow
Hedges
(In thousands)
$(112,302)
43,184
1,752
Total
$(105,254)
44,610
(69)
Net current-period other comprehensive income (loss) . . . . . . . . . . . . . . . .
(395)
44,936
44,541
Cumulative effect of accounting change . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,471
(24,405)
(22,934)
September 30, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 8,124
$ (91,771)
$ (83,647)
68
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
September 30, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income (loss) before
Available-
for-Sale
Securities
Interest
Rate
Agreement
Cash Flow
Hedges
Commodity
Contracts
Cash Flow
Hedges
(In thousands)
Total
$4,484
$(187,524)
$(4,982)
$(188,022)
reclassifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,502
74,560
9,847
86,909
Amounts reclassified from accumulated other
comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . .
62
Net current-period other comprehensive income . . . . . . . . . .
2,564
662
75,222
(4,865)
4,982
(4,141)
82,768
September 30, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$7,048
$(112,302)
$ — $(105,254)
The following tables detail reclassifications out of AOCI for the fiscal years ended September 30, 2018 and
2017. Amounts in parentheses below indicate decreases to net income in the statement of income.
Accumulated Other Comprehensive Income Components
Available-for-sale securities(2) . . . . . . . . . . . . . . .
Fiscal Year Ended September 30, 2018
Amount Reclassified from
Accumulated Other
Comprehensive Income
(In thousands)
$ 2,360
Affected Line Item in the
Statement of Income
Operation and maintenance expense
Cash flow hedges
Interest rate agreements . . . . . . . . . . . . . . . . . . . .
Total reclassifications . . . . . . . . . . . . . . . . . . . . .
2,360
(539)
Total before tax
Tax expense
$ 1,821
Net of tax
$(2,375)
(2,375)
623
$(1,752)
$
69
Interest charges
Total before tax
Tax benefit
Net of tax
Net of tax
69
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Accumulated Other Comprehensive Income Components
Fiscal Year Ended September 30, 2017
Amount Reclassified from
Accumulated Other
Comprehensive Income
(In thousands)
Affected Line Item in the
Statement of Income
Available-for-sale securities(2) . . . . . . . . . . . . . . .
$
(97)
Operation and maintenance expense
Cash flow hedges
Interest rate agreements . . . . . . . . . . . . . . . . . . . .
Commodity contracts . . . . . . . . . . . . . . . . . . . . . .
Total reclassifications . . . . . . . . . . . . . . . . . . . . .
(97)
35
Total before tax
Tax benefit
$
(62)
Net of tax
$(1,043)
7,967
6,924
(2,721)
$ 4,203
$ 4,141
Interest charges
Purchased gas cost(1)
Total before tax
Tax expense
Net of tax
Net of tax
(1) Amounts are presented as part of income from discontinued operations on the consolidated statements of
income.
(2) Our available-for-sale securities include both debt and equity securities.
7. Retirement and Post-Retirement Employee Benefit Plans
We have both funded and unfunded noncontributory defined benefit plans that together cover most of our
employees. We also maintain post-retirement plans that provide health care benefits to retired employees.
Finally, we sponsor a defined contribution plan that covers substantially all employees. These plans are discussed
in further detail below.
As a rate regulated entity, we generally recover our pension costs in our rates over a period of up to
15 years. The amounts that have not yet been recognized in net periodic pension cost that have been recorded as
regulatory assets or liabilities are as follows:
September 30, 2018
Unrecognized prior service (credit)
cost . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized actuarial (gain) loss . . . . .
September 30, 2017
Unrecognized prior service (credit)
cost . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized actuarial (gain) loss . . . . .
Defined
Benefit Plan
Supplemental
Executive
Retirement Plans
Postretirement
Plans
Total
(In thousands)
$ —
33,912
$33,912
$ —
42,170
$42,170
$
1,298
(100,966)
$
251
(69,364)
$ (99,668)
$(69,113)
$
1,309
(87,196)
$
31
17,362
$ (85,887)
$ 17,393
$ (1,047)
(2,310)
$ (3,357)
$ (1,278)
62,388
$61,110
70
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Defined Benefit Plans
Employee Pension Plan
As of September 30, 2018, we maintained one defined benefit plan, the Atmos Energy Corporation Pension
Account Plan (the Plan). The assets of the Plan are held within the Atmos Energy Corporation Master Retirement
Trust (the Master Trust). The Plan is a cash balance pension plan that was established effective January 1999 and
covers most of the employees of Atmos Energy that were hired on or before September 30, 2010. The plan was
closed to new participants effective October 1, 2010.
Opening account balances were established for participants as of January 1999 equal to the present value of
their respective accrued benefits under the pension plans which were previously in effect as of December 31,
1998. The Plan credits an allocation to each participant’s account at the end of each year according to a formula
based on the participant’s age, service and total pay (excluding incentive pay). In addition, at the end of each
year, a participant’s account is credited with interest on the employee’s prior year account balance. Participants
are fully vested in their account balances after three years of service and may choose to receive their account
balances as a lump sum or an annuity.
Generally, our funding policy is to contribute annually an amount in accordance with the requirements of
the Employee Retirement Income Security Act of 1974, including the funding requirements under the Pension
Protection Act of 2006 (PPA). However, additional voluntary contributions are made from time to time as
considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but
also for those expected to be earned in the future.
During fiscal 2018 and 2017 we contributed $7.0 million and $5.0 million in cash to the Plan to achieve a
desired level of funding while maximizing the tax deductibility of this payment. Based upon market conditions at
September 30, 2018, the current funded position of the Plan and the funding requirements under the PPA, we do
not anticipate a minimum required contribution for fiscal 2019. However, we may consider whether a voluntary
contribution is prudent to maintain certain funding levels.
We make investment decisions and evaluate performance of the assets in the Master Trust on a medium-
term horizon of at least three to five years. We also consider our current financial status when making recom-
mendations and decisions regarding the Master Trust’s assets. Finally, we strive to ensure the Master Trust’s
assets are appropriately invested to maintain an acceptable level of risk and meet the Master Trust’s long-term
asset investment policy adopted by the Board of Directors.
To achieve these objectives, we invest the Master Trust’s assets in equity securities, fixed income securities,
interests in commingled pension trust funds, other investment assets and cash and cash equivalents. Investments
in equity securities are diversified among the market’s various subsectors in an effort to diversify risk and max-
imize returns. Fixed income securities are invested in investment grade securities. Cash equivalents are invested
in securities that either are short term (less than 180 days) or readily convertible to cash with modest risk.
The following table presents asset allocation information for the Master Trust as of September 30, 2018 and
2017.
Security Class
Targeted
Allocation Range
Domestic equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Company stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35%-55%
10%-20%
5%-30%
0%-15%
0%-20%
71
Actual
Allocation
September 30
2017
2018
44.3% 43.9%
15.4% 17.2%
16.9% 10.6%
12.7% 11.8%
10.7% 16.5%
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
At September 30, 2018 and 2017, the Plan held 716,700 shares of our common stock which represented
12.7 percent and 11.8 percent of total Plan assets. These shares generated dividend income for the Plan of
approximately $1.4 million and $1.7 million during fiscal 2018 and 2017.
Our employee pension plan expenses and liabilities are determined on an actuarial basis and are affected by
numerous assumptions and estimates including the market value of plan assets, estimates of the expected return
on plan assets and assumed discount rates and demographic data. We review the estimates and assumptions
underlying our employee pension plans annually based upon a September 30 measurement date. The develop-
ment of our assumptions is fully described in our significant accounting policies in Note 2. The actuarial assump-
tions used to determine the pension liability for the Plan was determined as of September 30, 2018 and 2017 and
the actuarial assumptions used to determine the net periodic pension cost for the Plan was determined as of Sep-
tember 30, 2017, 2016 and 2015. On October 23, 2018, the Society of Actuaries released its annually-updated
mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in
the United States. As of September 30, 2018, we updated our assumed mortality rates to incorporate the updated
mortality table.
Additional assumptions are presented in the following table:
Pension
Liability
2018
2017
2018
Pension Cost
2017
2016
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate of compensation increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.38% 3.89% 3.89% 3.73% 4.55%
3.50% 3.50% 3.50% 3.50% 3.50%
6.75% 6.75% 6.75% 7.00% 7.00%
The following table presents the Plan’s accumulated benefit obligation, projected benefit obligation and
funded status as of September 30, 2018 and 2017:
2018
2017
(In thousands)
Accumulated benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$478,750
$505,355
Change in projected benefit obligation:
Benefit obligation at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial (gain) loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$533,455
17,264
20,803
(29,087)
(37,716)
$545,480
18,109
20,443
(16,347)
(34,230)
Benefit obligation at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
504,719
533,455
Change in plan assets:
Fair value of plan assets at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
508,244
54,163
7,000
(37,716)
473,950
63,524
5,000
(34,230)
Fair value of plan assets at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
531,691
508,244
Reconciliation:
Funded status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized prior service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26,972
—
—
(25,211)
—
—
Net amount recognized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 26,972
$ (25,211)
72
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Net periodic pension cost for the Plan for fiscal 2018, 2017 and 2016 is recorded as operating expense and
included the following components:
Fiscal Year Ended September 30
2017
2016
2018
(In thousands)
Components of net periodic pension cost:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost
Interest cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of prior service credit . . . . . . . . . . . . . . . . . . . . . . .
Recognized actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 17,264
20,803
(27,666)
(231)
9,114
$ 18,109
20,443
(27,975)
(231)
12,744
$ 16,419
23,193
(27,522)
(226)
10,693
Net periodic pension cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 19,284
$ 23,090
$ 22,557
The following table sets forth by level, within the fair value hierarchy, the Plan’s assets at fair value as of
September 30, 2018 and 2017. As required by authoritative accounting literature, assets are categorized in their
entirety based on the lowest level of input that is significant to the fair value measurement. The methods used to
determine fair value for the assets held by the Plan are fully described in Note 2. Investments in our common/
collective trusts and limited partnerships that are measured at net asset value per share equivalent are not classi-
fied in the fair value hierarchy. The net asset value amounts presented are intended to reconcile the fair value
hierarchy to the total investments. In addition to the assets shown below, the Plan had net accounts receivable of
$2.0 million and $0.6 million at September 30, 2018 and 2017, which materially approximates fair value due to
the short-term nature of these assets.
Assets at Fair Value as of September 30, 2018
Level 1
Level 2
Level 3
Total
(In thousands)
Investments:
Common stocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money market funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Registered investment companies . . . . . . . . . . . . . . . . . . .
Government securities:
Mortgage-backed securities . . . . . . . . . . . . . . . . . . . . . .
U.S. treasuries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$197,577
—
50,895
—
23,071
—
$ —
19,153
—
18,821
868
46,498
Total investments at fair value . . . . . . . . . . . . . . . . . . . . . . .
$271,543
$85,340
$
Investments measured at net asset value:
Common/collective trusts(1) . . . . . . . . . . . . . . . . . . . . . .
Limited partnerships(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
Total investments at fair value . . . . . . . . . . . . . . . . . . . . . . .
73
$
— $197,577
19,153
—
50,895
—
—
—
—
—
18,821
23,939
46,498
356,883
108,391
64,399
$529,673
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Assets at Fair Value as of September 30, 2017
Level 1
Level 2
Level 3
Total
(In thousands)
Investments:
Common stocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money market funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Registered investment companies . . . . . . . . . . . . . . . . . . .
Government securities:
Mortgage-backed securities . . . . . . . . . . . . . . . . . . . . . .
U.S. treasuries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$164,910
—
64,102
—
5,129
—
$ —
9,588
—
15,664
822
32,314
Total assets in the fair value hierarchy . . . . . . . . . . . . . . . . .
$234,141
$58,388
$
Investments measured at net asset value:
Common/collective trusts(1) . . . . . . . . . . . . . . . . . . . . . .
Limited partnerships(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
Total investments at fair value . . . . . . . . . . . . . . . . . . . . . . .
$
— $164,910
9,588
—
64,102
—
—
—
—
—
15,664
5,951
32,314
292,529
150,976
64,135
$507,640
(1) The fair value of our common/collective trusts and limited partnerships are measured using the net asset
value per share practical expedient. There are no redemption restrictions, redemption notice periods or
unfunded commitments for these investments. The redemption frequency is daily.
Supplemental Executive Retirement Plans
We have three nonqualified supplemental plans which provide additional pension, disability and death bene-
fits to our officers, division presidents and certain other employees of the Company.
The first plan is referred to as the Supplemental Executive Benefits Plan (SEBP) and covers our officers,
division presidents and certain other employees of the Company who were employed on or before August 12,
1998. The SEBP is a defined benefit arrangement which provides a benefit equal to 75 percent of covered com-
pensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the bene-
fits under the SEBP.
In August 1998, we adopted the Supplemental Executive Retirement Plan (SERP) (formerly known as the
Performance-Based Supplemental Executive Benefits Plan), which covers all officers or division presidents
selected to participate in the plan between August 12, 1998 and August 5, 2009 and any corporate officer who
was appointed to the Management Committee through December 31, 2016. The SERP is a defined benefit
arrangement which provides a benefit equal to 60 percent of covered compensation under which benefits paid
from the underlying qualified defined benefit plan are an offset to the benefits under the SERP.
Effective August 5, 2009, we adopted a new defined benefit Supplemental Executive Retirement Plan (the
2009 SERP), for corporate officers, division presidents or any other employees selected at the discretion of the
Board. Under the 2009 SERP, a nominal account has been established for each participant, to which the Com-
pany contributes at the end of each calendar year an amount equal to ten percent (25 percent for members of the
Management Committee appointed on or after January 1, 2017) of the total of each participant’s base salary and
cash incentive compensation earned during each prior calendar year, beginning December 31, 2009. The benefits
vest after three years of service and attainment of age 55 and earn interest credits at the same annual rate as the
Company’s Pension Account Plan (currently 4.69%).
Due to the retirement of certain executives, during fiscal 2018 we recognized a one-time settlement charge
of $4.2 million associated with our SERP and paid $13.9 million in lump sums in relation to the retirements.
74
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Similar to our employee pension plans, we review the estimates and assumptions underlying our supple-
mental plans annually based upon a September 30 measurement date using the same techniques as our employee
pension plans. The actuarial assumptions used to determine the pension liability for the supplemental plans were
determined as of September 30, 2018 and 2017 and the actuarial assumptions used to determine the net periodic
pension cost for the supplemental plans were determined as of September 30, 2017, 2016 and 2015. These
assumptions are presented in the following table:
Pension
Liability
2018
2017
2018
Pension Cost
2017
2016
Discount rate(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate of compensation increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.38% 3.89% 4.08% 3.73% 4.55%
3.50% 3.50% 3.50% 3.50% 3.50%
(1) Reflects a weighted average discount rate for pension cost for fiscal 2018 due to settlements during the year.
The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obli-
gation and funded status as of September 30, 2018 and 2017:
2018
2017
(In thousands)
Accumulated benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 116,943
$ 130,070
Change in projected benefit obligation:
Benefit obligation at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial (gain) loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 134,480
1,332
4,988
(1,020)
(4,523)
(13,887)
$ 142,574
2,756
4,744
(2,452)
(4,588)
(8,554)
Benefit obligation at end of year
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
121,370
134,480
Change in plan assets:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of plan assets at beginning of year
Employer contribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
18,410
(4,523)
(13,887)
Fair value of plan assets at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
13,142
(4,588)
(8,554)
—
Reconciliation:
Funded status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(121,370)
—
—
(134,480)
—
—
Accrued pension cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(121,370)
$(134,480)
Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2018 and 2017, assets
held in the rabbi trusts consisted of available-for-sale securities of $46.5 million and $42.9 million, which are
included in our fair value disclosures in Note 14.
75
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Net periodic pension cost for the supplemental plans for fiscal 2018, 2017 and 2016 is recorded as operating
expense and included the following components:
Fiscal Year Ended September 30
2017
2016
2018
(In thousands)
Components of net periodic pension cost:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost
Interest cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recognized actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,332
4,988
3,079
4,159
$ 2,756
4,744
4,251
2,685
$ 2,371
5,185
2,586
—
Net periodic pension cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$13,558
$14,436
$10,142
Estimated Future Benefit Payments
The following benefit payments for our defined benefit plans, which reflect expected future service, as
appropriate, are expected to be paid in the following fiscal years:
Pension
Plan
Supplemental
Plans
(In thousands)
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024-2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 32,603
33,509
35,838
37,176
38,684
206,563
$10,475
24,778
4,597
20,882
12,735
43,070
Postretirement Benefits
We sponsor the Retiree Medical Plan for Retirees and Disabled Employees of Atmos Energy Corporation
(the Atmos Retiree Medical Plan). This plan provides medical and prescription drug protection to all qualified
participants based on their date of retirement. The Atmos Retiree Medical Plan provides different levels of bene-
fits depending on the level of coverage chosen by the participants and the terms of predecessor plans; however,
we generally pay 80 percent of the projected net claims and administrative costs and participants pay the remain-
ing 20 percent. Effective January 1, 2015, for employees who had not met the participation requirements by
September 30, 2009, the contribution rates for the Company are limited to a three percent cost increase in claims
and administrative costs each year, with the participant responsible for the additional costs.
Generally, our funding policy is to contribute annually an amount in accordance with the requirements of
ERISA. However, additional voluntary contributions are made annually as considered necessary. Contributions
are intended to provide not only for benefits attributed to service to date but also for those expected to be earned
in the future. We expect to contribute between $10 million and $20 million to our postretirement benefits plan
during fiscal 2019.
We maintain a formal investment policy with respect to the assets in our postretirement benefits plan to
ensure the assets funding the postretirement benefit plan are appropriately invested to maintain an acceptable
level of risk. We also consider our current financial status when making recommendations and decisions regard-
ing the postretirement benefits plan.
76
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
We currently invest the assets funding our postretirement benefit plan in diversified investment funds which
consist of common stocks, preferred stocks and fixed income securities. The diversified investment funds may
invest up to 75 percent of assets in common stocks and convertible securities. The following table presents asset
allocation information for the postretirement benefit plan assets as of September 30, 2018 and 2017.
Security Class
Actual
Allocation
September 30
2017
2018
Diversified investment funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
97.5% 97.5%
2.5% 2.5%
Similar to our employee pension and supplemental plans, we review the estimates and assumptions under-
lying our postretirement benefit plan annually based upon a September 30 measurement date using the same
techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for
our postretirement plan were determined as of September 30, 2018 and 2017 and the actuarial assumptions used
to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2017,
2016 and 2015. The assumptions are presented in the following table:
Postretirement
Liability
2018
2017
Postretirement Cost
2017
2018
2016
4.38% 3.89% 3.89% 3.73% 4.55%
5.33% 4.29% 4.29% 4.45% 4.45%
6.50% 7.00% 7.00% 7.50% 7.50%
5.00% 5.00% 5.00% 5.00% 5.00%
2022
2022
2021
2022
2022
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . .
Initial trend rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ultimate trend rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ultimate trend reached in . . . . . . . . . . . . . . . . . . . . . . . . . . . .
77
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table presents the postretirement plan’s benefit obligation and funded status as of Sep-
tember 30, 2018 and 2017:
2018
2017
(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan participants’ contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial gain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$274,098
12,078
10,907
4,720
(17,252)
(18,565)
—
$279,222
12,436
10,679
4,936
(21,750)
(13,970)
2,545
Benefit obligation at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
265,986
274,098
Change in plan assets:
Fair value of plan assets at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . .
Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan participants’ contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
184,790
10,997
17,419
4,720
(18,565)
158,977
21,160
13,687
4,936
(13,970)
Fair value of plan assets at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
199,361
184,790
Reconciliation:
Funded status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized prior service cost
Unrecognized net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(66,625)
—
—
—
(89,308)
—
—
—
Accrued postretirement cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (66,625)
$ (89,308)
Net periodic postretirement cost for fiscal 2018, 2017 and 2016 is recorded as operating expense and
included the components presented below.
Fiscal Year Ended September 30
2017
2016
2018
(In thousands)
Components of net periodic postretirement cost:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost
Interest cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of transition obligation . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of prior service cost (credit) . . . . . . . . . . . . . . . . . . . .
Recognized actuarial gain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$12,078
10,907
(8,006)
—
11
(6,473)
$12,436
10,679
(7,185)
—
(1,644)
(2,827)
$10,823
12,424
(6,264)
82
(1,644)
(2,167)
Net periodic postretirement cost
. . . . . . . . . . . . . . . . . . . . . . . . .
$ 8,517
$11,459
$13,254
78
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Assumed health care cost trend rates have a significant effect on the amounts reported for the plan. A
one-percentage point change in assumed health care cost trend rates would have the following effects on the lat-
est actuarial calculations:
One-Percentage
Point Increase
One-Percentage
Point Decrease
(In thousands)
Effect on total service and interest cost components . . . . . . . . . . . . . . .
Effect on postretirement benefit obligation . . . . . . . . . . . . . . . . . . . . . .
$ 4,228
$38,633
$ (3,377)
$(31,872)
We are currently recovering other postretirement benefits costs through our regulated rates in substantially
all of our service areas under accrual accounting as prescribed by accounting principles generally accepted in the
United States. Other postretirement benefits costs have been specifically addressed in rate orders in each juris-
diction served by our Kentucky/Mid-States, West Texas, Mid-Tex and Mississippi Divisions as well as our
Kansas jurisdiction and Atmos Pipeline – Texas or have been included in a rate case and not disallowed.
Management believes that this accounting method is appropriate and will continue to seek rate recovery of
accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses.
The following tables set forth by level, within the fair value hierarchy, the Retiree Medical Plan’s assets at
fair value as of September 30, 2018 and 2017. The methods used to determine fair value for the assets held by the
Retiree Medical Plan are fully described in Note 2.
Assets at Fair Value as of September 30, 2018
Level 1
Level 2
Level 3
Total
(In thousands)
Investments:
Money market funds . . . . . . . . . . . . . . . . . . . . . . . . .
Registered investment companies . . . . . . . . . . . . . . .
$
— $5,003
—
194,358
Total investments at fair value . . . . . . . . . . . . . . . . . . .
$194,358
$5,003
$
$
— $
—
5,003
194,358
— $199,361
Assets at Fair Value as of September 30, 2017
Level 1
Level 2
Level 3
Total
(In thousands)
Investments:
Money market funds . . . . . . . . . . . . . . . . . . . . . . . . .
Registered investment companies . . . . . . . . . . . . . . .
$
— $4,534
—
180,256
Total investments at fair value . . . . . . . . . . . . . . . . . . .
$180,256
$4,534
$
$
— $
—
4,534
180,256
— $184,790
79
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Estimated Future Benefit Payments
The following benefit payments paid by us, retirees and prescription drug subsidy payments for our post-
retirement benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the fol-
lowing fiscal years. Company payments for fiscal 2018 include contributions to our postretirement plan trusts.
Company
Payments
Retiree
Payments
Subsidy
Payments
Total
Postretirement
Benefits
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024-2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$14,407
13,363
13,572
14,503
15,405
88,120
(In thousands)
$—
—
—
—
—
—
$ 3,532
3,742
3,975
4,412
4,832
29,514
$ 17,939
17,105
17,547
18,915
20,237
117,634
Defined Contribution Plan
The Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) covers
substantially all employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code.
Effective January 1, 2007, employees automatically become participants of the Retirement Savings Plan on the
date of employment. Participants may elect a salary reduction up to a maximum of 65 percent of eligible
compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. New
participants are automatically enrolled in the Plan at a contribution rate of four percent of eligible compensation,
from which they may opt out. We match 100 percent of a participant’s contributions, limited to four percent of
the participant’s salary. Participants are eligible to receive matching contributions after completing one year of
service, in which they are immediately vested. Participants are also permitted to take out a loan against their
accounts subject to certain restrictions. Employees hired on or after October 1, 2010 participate in the enhanced
plan in which participants receive a fixed annual contribution of four percent of eligible earnings to their Retire-
ment Savings Plan account. Participants will continue to be eligible for company matching contributions of up to
four percent of their eligible earnings and will be fully vested in the fixed annual contribution after three years of
service.
Matching and fixed annual contributions to the Retirement Savings Plan are expensed as incurred and
amounted to $16.2 million, $15.4 million and $15.8 million for fiscal years 2018, 2017 and 2016. At Sep-
tember 30, 2018 and 2017, the Retirement Savings Plan held 3.2 percent and 3.7 percent of our outstanding
common stock.
8. Stock and Other Compensation Plans
Stock-Based Compensation Plans
Total stock-based compensation cost was $23.9 million, $23.1 million and $24.6 million for the fiscal years
ended September 30, 2018, 2017 and 2016. Of this amount, $11.1 million, $9.0 million and $9.8 million was
capitalized. Tax benefits related to stock-based compensation were $2.3 million, $4.4 million and $5.0 million
for the fiscal years ended September 30, 2018, 2017 and 2016.
1998 Long-Term Incentive Plan
We have a Long-Term Incentive Plan (LTIP), which provides a long-term incentive compensation plan
providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation
rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted
80
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
stock units and stock units to certain employees and non-employee directors of the Company and our sub-
sidiaries. The objectives of this plan include attracting and retaining the best available personnel, providing for
additional performance incentives and promoting our success by providing employees with the opportunity to
acquire common stock.
As of September 30, 2018, we were authorized to grant awards for up to a maximum cumulative amount of
11.2 million shares of common stock under this plan subject to certain adjustment provisions. As of Sep-
tember 30, 2018, non-qualified stock options, bonus stock, time-lapse restricted stock, time-lapse restricted stock
units, performance-based restricted stock units and stock units had been issued under this plan, and 1.8 million
shares are available for future issuance through September 30, 2021.
Restricted Stock Units Award Grants
As noted above, the LTIP provides for discretionary awards of restricted stock units to help attract, retain
and reward employees of Atmos Energy and its subsidiaries. Certain of these awards vest based upon the passage
of time and other awards vest based upon the passage of time and the achievement of specified performance tar-
gets. The fair value of the awards granted is based on the market price of our stock at the date of grant. We esti-
mate forfeitures using our historical forfeiture rate. The associated expense is recognized ratably over the vesting
period. We use authorized and unissued shares to meet share requirements for the vesting of restricted stock
units.
Employees who are granted time-lapse restricted stock units under our LTIP have a nonforfeitable right to
dividend equivalents that are paid at the same rate and at the same time at which they are paid on shares of stock
without restrictions. Time-lapse restricted stock units contain only a service condition that the employee recipi-
ents render continuous services to the Company for a period of three years from the date of grant, except for
accelerated vesting in the event of death, disability, change of control of the Company or termination without
cause (with certain exceptions). There are no performance conditions required to be met for employees to be
vested in time-lapse restricted stock units.
Employees who are granted performance-based restricted stock units under our LTIP have a forfeitable right
to dividend equivalents that accrue at the same rate at which they are paid on shares of stock without restrictions.
Dividend equivalents on the performance-based restricted stock units are paid either in cash or in the form of
shares upon the vesting of the award. Performance-based restricted stock units contain a service condition that
the employee recipients render continuous services to the Company for a period of three years from the begin-
ning of the applicable three-year performance period, except for accelerated vesting in the event of death, dis-
ability, change of control of the Company or termination without cause (with certain exceptions) and a
performance condition based on a cumulative earnings per share target amount.
The following summarizes information regarding the restricted stock units granted under the plan during the
fiscal years ended September 30, 2018, 2017 and 2016:
2018
2017
2016
Weighted
Average
Grant-Date
Fair
Value
Number of
Restricted
Units
Nonvested at beginning of year
570,814
. . . .
Granted . . . . . . . . . . . . . . . . . . . . .
248,710
Vested . . . . . . . . . . . . . . . . . . . . . . (274,392)
(6,540)
Forfeited . . . . . . . . . . . . . . . . . . . .
$69.45
85.62
64.43
74.87
Weighted
Average
Grant-Date
Fair
Value
$57.66
74.15
52.23
63.48
Weighted
Average
Grant-Date
Fair
Value
$48.24
65.98
45.88
53.52
Number of
Restricted
Units
878,104
357,323
(448,136)
(4,860)
Number of
Restricted
Units
782,431
273,497
(448,326)
(36,788)
Nonvested at end of year . . . . . . . . . .
538,592
$80.91
570,814
$69.45
782,431
$57.66
81
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As of September 30, 2018, there was $11.5 million of total unrecognized compensation cost related to non-
vested restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted
average period of 1.6 years. The fair value of restricted stock vested during the fiscal years ended September 30,
2018, 2017 and 2016 was $17.2 million, $23.4 million and $20.6 million.
Other Plans
Direct Stock Purchase Plan
We maintain a Direct Stock Purchase Plan, open to all investors, which allows participants to have all or
part of their cash dividends paid quarterly in additional shares of our common stock. The minimum initial
investment required to join the plan is $1,250. Direct Stock Purchase Plan participants may purchase additional
shares of our common stock as often as weekly with voluntary cash payments of at least $25, up to an annual
maximum of $100,000.
Equity Incentive and Deferred Compensation Plan for Non-Employee Directors
We have an Equity Incentive and Deferred Compensation Plan for Non–Employee Directors, which pro-
vides non-employee directors of Atmos Energy with the opportunity to defer receipt, until retirement, of
compensation for services rendered to the Company and invest deferred compensation into either a cash account
or a stock account.
Other Discretionary Compensation Plans
We have an annual incentive program covering substantially all employees to give each employee an oppor-
tunity to share in our financial success based on the achievement of key performance measures considered crit-
ical to achieving business objectives for a given year with minimum and maximum thresholds. The Company
must meet the minimum threshold for the plan to be funded and distributed to employees. These performance
measures may include earnings growth objectives, improved cash flow objectives or crucial customer satisfaction
and safety results. We monitor progress towards the achievement of the performance measures throughout the
year and record accruals based upon the expected payout using the best estimates available at the time the accrual
is recorded. During the last several fiscal years, we have used earnings per share as our sole performance meas-
ure.
9. Details of Selected Consolidated Balance Sheet Captions
The following tables provide additional information regarding the composition of certain of our balance
sheet captions.
Accounts receivable
Accounts receivable was comprised of the following at September 30, 2018 and 2017:
September 30
2018
2017
(In thousands)
Billed accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unbilled revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$138,794
81,005
48,291
$135,091
73,143
24,894
Total accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
268,090
(14,795)
233,128
(10,865)
Net accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$253,295
$222,263
82
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other current assets
Other current assets as of September 30, 2018 and 2017 were comprised of the following accounts.
September 30
2018
2017
(In thousands)
Deferred gas costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets from risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,927
33,233
8,106
1,369
1,420
$ 65,714
32,163
4,472
2,436
1,536
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$46,055
$106,321
Property, plant and equipment
Property, plant and equipment was comprised of the following as of September 30, 2018 and 2017:
Storage plant
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General plant
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible plant
Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . .
September 30
2018
2017
(In thousands)
$
414,857
2,851,423
8,141,733
771,355
38,280
12,217,648
349,725
12,567,373
(2,196,226)
$
369,510
2,521,671
7,306,021
765,728
38,980
11,001,910
299,394
11,301,304
(2,042,122)
Net property, plant and equipment(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10,371,147
$ 9,259,182
(1) Net property, plant and equipment includes plant acquisition adjustments of $(55.5) million and $(64.1) mil-
lion at September 30, 2018 and 2017.
Goodwill
The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal
year ended September 30, 2018:
Balance as of September 30, 2017 . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax adjustments on prior acquisitions(1) . . . . . . . . . . . .
$587,080
262
Distribution
Pipeline and
Storage
(In thousands)
$143,052
25
Total
$730,132
287
Balance as of September 30, 2018 . . . . . . . . . . . . . . . . . . . . . . .
$587,342
$143,077
$730,419
(1) We annually adjust certain deferred taxes recorded in connection with acquisitions completed in fiscal 2001
and fiscal 2005, which resulted in an increase to goodwill and net deferred tax liabilities of $0.3 million for
fiscal 2018.
83
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Deferred charges and other assets
Deferred charges and other assets as of September 30, 2018 and 2017 were comprised of the following
accounts.
September 30
2018
2017
(In thousands)
Marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets from risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 99,385
141,778
250
26,972
10,099
15,534
$ 88,409
110,977
803
—
—
20,447
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$294,018
$220,636
Accounts payable and accrued liabilities
Accounts payable and accrued liabilities as of September 30, 2018 and 2017 were comprised of the follow-
ing accounts.
September 30
2018
2017
(In thousands)
Trade accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued gas payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$135,159
48,721
33,403
$143,422
50,253
39,375
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$217,283
$233,050
Other current liabilities
Other current liabilities as of September 30, 2018 and 2017 were comprised of the following accounts.
September 30
2018
2017
(In thousands)
Customer credit balances and deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued employee costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred gas costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities from risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and postretirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory cost of service reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory cost of removal obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
APT annual adjustment mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory excess deferred taxes (See Note 12) . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 52,648
52,101
94,705
39,486
56,734
123,457
10,475
22,508
55,770
19,918
5,225
14,041
$ 54,627
46,653
15,559
39,624
322
116,291
18,411
—
35,910
—
—
5,251
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$547,068
$332,648
84
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Deferred credits and other liabilities
Deferred credits and other liabilities as of September 30, 2018 and 2017 were comprised of the following
accounts.
September 30
2018
2017
(In thousands)
Customer advances for construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities from risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
APT annual adjustment mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 11,010
78,599
12,887
103
15,310
40,119
$
9,309
5,257
12,827
112,076
—
36,266
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$158,028
$175,735
10. Leases
We have entered into operating leases for towers, office and warehouse space, vehicles and heavy equip-
ment used in our operations. The remaining lease terms range from one to 13 years and generally provide for the
payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases.
The related future minimum lease payments at September 30, 2018 were as follows:
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
Operating
Leases(1)
(In thousands)
$ 17,655
16,483
16,202
16,004
15,621
22,226
Total minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$104,191
(1) Future minimum lease payments do not include amounts for fleet leases and other de minimis items that can
be renewed beyond the initial lease term. The Company anticipates renewing the leases beyond the initial
term, but the anticipated payments associated with the renewals do not meet the definition of expected
minimum lease payments and therefore are not included above. Expected payments are $17.7 million in
2019, $14.7 million in 2020, $11.3 million in 2021, $8.0 million in 2022, $4.6 million in 2023 and
$2.3 million thereafter.
Consolidated lease and rental expense amounted to $33.8 million, $32.7 million and $32.6 million for fiscal
2018, 2017 and 2016.
11. Commitments and Contingencies
Litigation
In the normal course of business, we are subject to various legal and regulatory proceedings. For such mat-
ters, we record liabilities when they are considered probable and estimable, based on currently available facts,
85
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
our historical experience, and our estimates of the ultimate outcome or resolution of the liability in the future.
While the outcome of these proceedings is uncertain and a loss in excess of the amount we have accrued is
possible though not reasonably estimable, it is the opinion of management that any amounts exceeding the
accruals will not have a material adverse impact on our financial position, results of operations or cash flows.
We maintain liability insurance for various risks associated with the operation of our natural gas pipelines
and facilities, including for property damage and bodily injury. These liability insurance policies generally
require us to be responsible for the first $1.0 million (self-insured retention) of each incident.
The National Transportation Safety Board (NTSB) is investigating an incident that occurred at a Dallas,
Texas residence on February 23, 2018 that resulted in one fatality and injuries to four other residents. Together
with the Railroad Commission of Texas and the Pipeline and Hazardous Materials Safety Administration, Atmos
Energy is a party to the investigation and in that capacity is working closely with the NTSB to help determine the
cause of this incident.
On March 29, 2018, a civil action was filed in Dallas, Texas against Atmos Energy in response to the Febru-
ary 23rd incident. The plaintiffs seek over $1.0 million in damages for, among with others, wrongful death and
personal injury.
We are a party to various other litigation or claims that have arisen in the ordinary course of our business.
While the results of such litigation or claims cannot be predicted with certainty, we continue to believe the final
outcome of such litigation or claims will not have a material adverse effect on our financial condition, results of
operations or cash flows.
Environmental Matters
We are a party to environmental matters and claims that have arisen in the ordinary course of our business.
While the ultimate results of response actions to these environmental matters and claims cannot be predicted with
certainty, we believe the final outcome of such response actions will not have a material adverse effect on our
financial condition, results of operations or cash flows because we believe that the expenditures related to such
response actions will either be recovered through rates, shared with other parties or are adequately covered by
insurance.
Purchase Commitments
Our distribution and pipeline and storage segments maintain supply contracts with several vendors that
generally cover a period of up to one year. Commitments for estimated base gas volumes are established under
these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily pur-
chases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division maintains a limited number of long-term supply contracts to ensure a reliable source
of gas for our customers in its service area which obligate it to purchase specified volumes at prices indexed to
natural gas trading hubs. At September 30, 2018, we were committed to purchase 54.1 Bcf within one year and
37.2 Bcf within two to three years under indexed contracts. Purchases under these contracts totaled $57.2 million,
$49.7 million and $85.3 million for 2018, 2017 and 2016.
Regulatory Matters
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.
86
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
However, depending on the substance of these final rules, in addition to certain international regulatory require-
ments still under development that are similar to Dodd–Frank, our swap counterparties could be subject to addi-
tional and potentially significant capitalization requirements. These regulations could motivate counterparties to
increase our collateral requirements or cash postings.
As of September 30, 2018, formula rate mechanisms were pending regulatory approval in our Mississippi
and Tennessee service areas, infrastructure mechanisms were pending regulatory approval in our Mississippi
service area and rate cases were pending regulatory approval in our Kentucky, Mid-Tex, Virginia and West
Texas service areas. These regulatory proceedings are discussed in further detail above in the Business — Rate-
making Activity section. Additionally, as discussed in further detail in Note 12, all jurisdictions are addressing
impacts of the TCJA.
12.
Income Taxes
Impact of the Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “TCJA”) was signed into law. The TCJA
introduced several significant changes to corporate income tax laws in the United States. The most significant
change that affects Atmos Energy is the reduction of the federal statutory income tax rate from 35% to 21%. As a
rate-regulated entity, the accelerated capital expensing and the limitation on interest deductibility provisions
included in the TCJA are not applicable to us.
Under generally accepted accounting principles, we use the asset and liability method of accounting for
income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax con-
sequences attributable to differences between the financial statement carrying amounts of existing assets and
liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary differences are expected to be recov-
ered or settled.
At September 30, 2017, we measured our net deferred tax liability using the enacted federal statutory tax
rate of 35%. The enactment of the TCJA on December 22, 2017 required us to remeasure our deferred tax assets
and liabilities, including our U.S. federal income tax net operating loss carryforwards, at the newly enacted
federal statutory income tax rate of 21%. As the Company’s fiscal year end is September 30, 2018, the Internal
Revenue Code requires the Company to use a blended statutory federal corporate income tax rate of 24.5% for
fiscal 2018.
The decrease in the federal statutory income tax rate reduced our net deferred tax liability by $905.3 million.
Of this amount, $746.5 million relates to regulated operations and has been recorded as a regulatory liability, a
portion of which is currently being returned to utility customers in accordance with issued regulatory orders and
the Internal Revenue Code. The remaining $158.8 million has been reflected as a one-time income tax benefit in
our consolidated statement of income for the year ended September 30, 2018, because these taxes are not related
to our cost of service ratemaking.
The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118), which allows us to record provi-
sional amounts during a one-year measurement period, similar to the measurement period in accounting for busi-
ness combinations. The Company has determined a reasonable estimate for the measurement and accounting for
certain effects of the TCJA, including the remeasurement of our net deferred tax liabilities and the establishment
of a regulatory liability, which have been reflected as provisional amounts in the September 30, 2018 con-
solidated financial statements. The amounts represent our best estimates based upon records, information and
current guidance. We are still analyzing certain aspects of the TCJA, refining our calculations and expecting
additional guidance relating to the TCJA from the U.S. Department of the Treasury and the Internal Revenue
Service. Any additional guidance issued or future actions of our regulators could potentially affect the final
determination of the accounting effects arising from the implementation of the TCJA.
87
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
We have and continue to work with our regulators in each jurisdiction to determine the amortization of the
excess deferred taxes regulatory liability of $746.5 million of which the balance is $744.9 million as of Sep-
tember 30, 2018. In addition, we have recorded a cost of service regulatory liability of $22.5 million as of Sep-
tember 30, 2018. Accounting orders were issued for all our service areas that required us to establish, effective
January 1, 2018, a separate regulatory liability for the difference in taxes included in our rates that have been
calculated based on a 35% statutory income tax rate and the new 21% statutory income tax rate. The establish-
ment of this regulatory liability relating to our cost of service rates resulted in a reduction to our revenues begin-
ning in the second quarter of fiscal 2018.
We have received approval from regulators to update our cost of service rates to reflect the decrease in the
statutory income tax rate in our Colorado, Kansas, Kentucky, Louisiana and Texas service areas. We are still
working with regulators in Mississippi, Tennessee and Virginia to reflect the effects of the lower statutory
income tax rate in our cost of service in rates. As of September 30, 2018, we received approval from regulators to
return amounts to customers related to the regulatory liabilities recorded for differences in our cost of service
rates due to change in the federal statutory income tax rate in Colorado and Kansas.
As of September 30, 2018, we received approval from regulators to return amounts to customers related to
the regulatory liabilities recorded for the excess deferred taxes created upon implementation of the TCJA in
Colorado, Kentucky and Louisiana in accordance with regulatory proceedings on a provisional basis over periods
ranging from 18 to 40 years. In our remaining jurisdictions, the treatment of the effects of the TCJA in rates is
being addressed in ongoing or will be addressed in future regulatory proceedings.
Income Tax Expense
The components of income tax expense from continuing operations for 2018, 2017 and 2016 were as fol-
lows:
Current
2018
2017
(In thousands)
2016
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (10,099)
11,075
$
— $
9,022
—
5,667
Deferred
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TCJA Impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
150,556
15,330
(158,782)
—
197,013
15,348
—
—
178,630
12,350
—
(5)
$
8,080
$221,383
$196,642
88
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions
for income taxes from continuing operations for 2018, 2017 and 2016 are set forth below:
Tax at statutory rate(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock dividends deductible for tax reporting . . . . . . . . .
State taxes (net of federal benefit) . . . . . . . . . . . . . . . . . . . . . . . .
Change in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of excess deferred taxes . . . . . . . . . . . . . . . . . . . . .
Remeasurement due to TCJA . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018
$ 149,730
(1,745)
19,826
—
(1,219)
(158,782)
270
2017
(In thousands)
$211,433
(2,584)
16,100
—
—
—
(3,566)
2016
$189,764
(2,570)
11,133
1,324
—
—
(3,009)
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
8,080
$221,383
$196,642
(1) Tax expense is calculated at the statutory federal income tax rate of 24.5% for the year ended September 30,
2018 and 35% for the years ended September 30, 2017 and 2016.
Deferred income taxes reflect the tax effect of differences between the basis of assets and liabilities for book
and tax purposes. The tax effect of temporary differences that gave rise to significant components of the deferred
tax liabilities and deferred tax assets at September 30, 2018 and 2017 are presented below:
Deferred tax assets:
Employee benefit plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net operating loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Charitable and other credit carryforwards . . . . . . . . . . . . . . . . . . . . . . .
Regulatory excess deferred tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities:
2018
2017
(In thousands)
72,745
27,135
461,481
6,818
169,947
13,804
751,930
(1,465)
750,465
$
121,288
65,171
555,043
18,873
—
10,218
770,593
(5,403)
765,190
Difference in net book value and net tax value of assets . . . . . . . . . . . .
Pension funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas cost adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,859,787)
(6,986)
1,005
(38,764)
(2,528,485)
(13,101)
(60,376)
(41,927)
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,904,532)
(2,643,889)
Net deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(1,154,067)
$(1,878,699)
Deferred credits for rate regulated entities . . . . . . . . . . . . . . . . . . . . . . . . .
$
762
$
985
At September 30, 2018, we had $430.0 million of federal net operating loss carryforwards. The federal net
operating loss carryforwards are available to offset taxable income and will begin to expire in 2029. The Com-
pany also has $10.1 million of federal alternative minimum tax credit carryforwards, which do not expire and are
expected to be fully refunded to us between 2019 and 2022 as a result of changes introduced by the TCJA. These
credit carryforwards are now reflected as taxes receivable within the deferred charges and other assets line item
89
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
on our consolidated balance sheet. In addition, the Company has $5.3 million in remeasured charitable con-
tribution carryforwards to offset future taxable income. The Company’s charitable contribution carryforwards
expiration period begins in 2019.
The Company also has $31.4 million of state net operating loss carryforwards (net of $8.4 million of remeas-
ured federal effects) and $1.5 million of state tax credits carryforwards (net of $0.4 million of remeasured federal
effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards
expiration period begins in 2019.
Due to the changes introduced by the TCJA, we now believe it is more likely than not that the benefit from
certain charitable contribution carryforwards for which a valuation allowance was previously established will be
realized. As a result, we reduced our valuation allowance by $4.2 million during the first quarter of fiscal 2018.
This amount is included in the $158.8 million one-time income tax benefit.
We believe it is more likely than not that the benefit from certain state net operating loss carryforwards and
state credit carryforwards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax
asset recorded for the carryforwards, a re-measured valuation allowance of $1.5 million continues to be estab-
lished for the year ended September 30, 2018. No additional valuation allowance was recorded for the year ended
September 30, 2018.
At September 30, 2018, we had recorded liabilities associated with unrecognized tax benefits totaling
$26.2 million. The following table reconciles the beginning and ending balance of our unrecognized tax benefits:
Unrecognized tax benefits — beginning balance . . . . . . . . . . . . . . . . . . . . . . .
Increase (decrease) resulting from prior period tax positions . . . . . . . . . . .
Increase resulting from current period tax positions . . . . . . . . . . . . . . . . . .
$23,719
22
2,462
2018
2017
(In thousands)
$20,298
(366)
3,787
Unrecognized tax benefits — ending balance . . . . . . . . . . . . . . . . . . . . . . . . .
Less: deferred federal and state income tax benefits . . . . . . . . . . . . . . . . . . . . . .
26,203
(5,503)
23,719
(8,302)
2016
$17,069
(290)
3,519
20,298
(7,104)
Total unrecognized tax benefits that, if recognized, would impact the effective
income tax rate as of the end of the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$20,700
$15,417
$13,194
The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penal-
ties included within interest charges in our consolidated statement of income. During the years ended Sep-
tember 30, 2018, 2017 and 2016, the Company recognized approximately $1.6 million, $1.1 million and
$2.5 million in interest and penalties. The Company had approximately $6.1 million, $4.5 million and
$3.3 million for the payment of interest and penalties accrued at September 30, 2018, 2017 and 2016.
We file income tax returns in the U.S. federal jurisdiction as well as in various states where we have oper-
ations. We have concluded substantially all U.S. federal income tax matters through fiscal year 2009 and con-
cluded substantially all Texas income tax matters through fiscal year 2010.
13. Financial Instruments
We use financial instruments to mitigate commodity price risk and interest rate risk. Our financial instru-
ments do not contain any credit-risk-related or other contingent features that could cause accelerated payments
when our financial instruments are in net liability positions.
As discussed in Note 2 and Note 15, we report our financial instruments as risk management assets and
liabilities, each of which is classified as current or noncurrent based upon the anticipated settlement date of the
90
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
underlying financial instrument. The following table shows the fair values of our risk management assets and
liabilities at September 30, 2018 and 2017.
September 30
2018
2017
(In thousands)
Assets from risk management activities, current . . . . . . . . . . . . . . . . . . . . . . . .
Assets from risk management activities, noncurrent . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . .
Liabilities from risk management activities, current
. . . . . . . . . . . . . . . . . .
Liabilities from risk management activities, noncurrent
$ 1,369
250
(56,734)
(103)
$
2,436
803
(322)
(112,076)
Net assets (liabilities) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(55,218)
$(109,159)
Commodity Risk Management Activities
Our purchased gas cost adjustment mechanisms essentially insulate our distribution segment from commod-
ity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this
exposure through a combination of physical storage, fixed-price forward contracts and financial instruments,
primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price
volatility on our customers during the winter heating season.
Our distribution gas supply department is responsible for executing this segment’s commodity risk manage-
ment activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate
commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of
heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this
level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial
instruments. For the 2017-2018 heating season (generally October through March), in the jurisdictions where we
are permitted to utilize financial instruments, we hedged approximately 26 percent, or approximately 15.0 Bcf of
the winter flowing gas requirements at a weighted average cost of approximately $3.20 per Mcf. We have not
designated these financial instruments as hedges for accounting purposes.
Interest Rate Risk Management Activities
We currently manage interest rate risk through the use of forward starting interest rate swaps to fix the Treas-
ury yield component of the interest cost associated with anticipated financings.
In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component
associated with $210 million of the then anticipated issuance of $250 million unsecured senior notes in fiscal
2017. These notes were issued as planned in June 2017 and we settled swaps with the payment of $37.0 million.
Because the swaps were effective, the realized loss was recorded as a component of accumulated other compre-
hensive income (loss) and is being recognized as a component of interest expense over the 27-year life of the
senior notes.
Additionally, in fiscal 2014 and 2015, we entered into forward starting interest rate swaps to effectively fix
the Treasury yield component associated with $450 million of the anticipated issuance of $450 million unsecured
senior notes in fiscal 2019. We designated all of these swaps as cash flow hedges at the time the agreements were
executed. Accordingly, unrealized gains and losses associated with the forward starting interest rate swaps will
be recorded as a component of accumulated other comprehensive income (loss). When the forward starting inter-
est rate swaps settle, the realized gain or loss will be recorded as a component of accumulated other compre-
hensive income (loss) and recognized as a component of interest expense over the life of the related financing
arrangement. Hedge ineffectiveness to the extent incurred, will be reported as a component of interest expense.
Prior to fiscal 2012, we entered into several interest rate agreements to fix the Treasury yield component of
the interest cost of financing for various issuances of long-term debt and senior notes. The gains and losses
91
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
realized upon settlement of these interest rate agreements were recorded as a component of accumulated other
comprehensive income (loss) when they were settled and are being recognized as a component of interest
expense over the life of the associated notes from the date of settlement. The remaining amortization periods for
the settled interest rate agreements extend through fiscal 2045.
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our
consolidated balance sheet and income statements.
As of September 30, 2018, our financial instruments were comprised of both long and short commodity
positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the
commodity. As of September 30, 2018, we had 22,874 MMcf of net long commodity contracts outstanding.
These contracts have not been designated as hedges.
Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments as of
September 30, 2018 and 2017. The gross amounts of recognized assets and liabilities are netted within our Con-
solidated Balance Sheets to the extent that we have netting arrangements with the counterparties.
Balance Sheet Location
Assets
Liabilities
(In thousands)
September 30, 2018
Designated As Hedges:
Interest rate swap agreements . . . . . . . . . Other current assets /
Other current liabilities
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Not Designated As Hedges:
Commodity contracts . . . . . . . . . . . . . . . Other current assets /
Other current liabilities
Commodity contracts . . . . . . . . . . . . . . . Deferred charges and other assets /
Deferred credits and other liabilities
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross Financial Instruments . . . . . . . . . . . .
Gross Amounts Offset on Consolidated
Balance Sheet:
Contract netting . . . . . . . . . . . . . . . . . . . . . .
Net Financial Instruments . . . . . . . . . . . . . .
Cash collateral . . . . . . . . . . . . . . . . . . . . . . .
Net Assets/Liabilities from Risk
Management Activities . . . . . . . . . . . . . . .
$ — $(56,499)
— (56,499)
1,369
250
1,619
1,619
—
1,619
—
(235)
(103)
(338)
(56,837)
—
(56,837)
—
$1,619
$(56,837)
92
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Balance Sheet Location
Assets
Liabilities
(In thousands)
September 30, 2017
Designated As Hedges:
Interest rate swap agreements . . . . . . . . . Deferred charges and other assets /
Deferred credits and other liabilities
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Not Designated As Hedges:
Commodity contracts . . . . . . . . . . . . . . . Other current assets /
Other current liabilities
Commodity contracts . . . . . . . . . . . . . . . Deferred charges and other assets /
Deferred credits and other liabilities
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross Financial Instruments . . . . . . . . . . . .
Gross Amounts Offset on Consolidated
Balance Sheet:
Contract netting . . . . . . . . . . . . . . . . . . . . . .
Net Financial Instruments . . . . . . . . . . . . . .
Cash collateral . . . . . . . . . . . . . . . . . . . . . . .
Net Assets/Liabilities from Risk
Management Activities . . . . . . . . . . . . . . .
$ — $(112,076)
— (112,076)
2,436
803
3,239
3,239
(322)
—
(322)
(112,398)
—
3,239
—
—
(112,398)
—
$3,239
$(112,398)
Impact of Financial Instruments on the Income Statement
Cash Flow Hedges
As discussed above, our distribution segment has interest rate swap agreements, which we designated as a
cash flow hedge at the time the swaps were executed. The net loss on settled interest rate agreements reclassified
from AOCI into interest charges on our consolidated income statements for the years ended September 30, 2018,
2017 and 2016 was $(2.4) million, $(1.0) million and $(0.5) million.
The following table summarizes the gains and losses arising from hedging transactions that were recognized
as a component of other comprehensive income (loss), net of taxes, for the years ended September 30, 2018 and
2017. The amounts included in the table below exclude gains and losses arising from ineffectiveness because
these amounts are immediately recognized in the income statement as incurred.
Fiscal Year Ended
September 30
2018
2017
(In thousands)
Increase in fair value:
Interest rate agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forward commodity contracts(1)
$43,184
—
$74,560
9,847
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forward commodity contracts(1)
1,752
—
662
(4,865)
Total other comprehensive income from hedging, net of tax(2)
. . . . . . . . . . . . . . .
$44,936
$80,204
93
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(1) Due to the sale of AEM, these amounts are included in income from discontinued operations
(2) Utilizing an income tax rate of approximately 23 percent for fiscal 2018 and an income tax rate ranging from
approximately 37 percent to 39 percent for fiscal 2017 based on the effective rates in each taxing juris-
diction.
Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in
earnings as they are amortized. The following amounts, net of deferred taxes, represent the expected recognition
in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon
the fair values of these financial instruments as of September 30, 2018. However, the table below does not
include the expected recognition in earnings of our outstanding interest rate agreements as those financial
instruments have not yet settled.
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
Interest Rate
Agreements
(In thousands)
$ (1,863)
(1,893)
(1,893)
(1,893)
(1,893)
(38,729)
Total(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(48,164)
(1) Utilizing an income tax rate of approximately 23 percent.
Financial Instruments Not Designated as Hedges
As discussed above, financial instruments used in our distribution segment are not designated as hedges.
However, there is no earnings impact on our distribution segment as a result of the use of these financial instru-
ments because the gains and losses arising from the use of these financial instruments are recognized in the con-
solidated statement of income as a component of purchased gas cost when the related costs are recovered through
our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this
presentation.
14. Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as the price that would be received to
sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measure-
ment date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carry-
ing value, which substantially approximates fair value due to the short-term nature of these assets and liabilities.
For other financial assets and liabilities, we primarily use quoted market prices and other observable market pric-
ing information to minimize the use of unobservable pricing inputs in our measurements when determining fair
value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2.
Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. The fair
value of these assets is presented in Note 7.
94
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market
data are observable or corroborated by observable market data. The following tables summarize, by level within
the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of
September 30, 2018 and 2017. As required under authoritative accounting literature, assets and liabilities are
categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
Assets:
Financial instruments . . . . . . . . . . . . . . . . . . . . .
Available-for-sale securities
Quoted
Prices in
Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)(1)
Significant
Other
Unobservable
Inputs
(Level 3)
(In thousands)
Netting and
Cash
Collateral
September 30,
2018
$ — $
1,619
$
— $
— $
1,619
Registered investment companies . . . . . . . . .
Bond mutual funds . . . . . . . . . . . . . . . . . . . . .
Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money market funds . . . . . . . . . . . . . . . . . . .
42,644
21,507
—
—
Total available-for-sale securities . . . . . . . . . . .
64,151
—
—
31,400
3,834
35,234
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$64,151
$ 36,853
Liabilities:
Financial instruments . . . . . . . . . . . . . . . . . . . . .
$ — $ 56,837
$
$
—
—
—
—
—
—
—
—
—
—
42,644
21,507
31,400
3,834
99,385
— $ — $101,004
— $
— $ 56,837
Assets:
Financial instruments . . . . . . . . . . . . . . . . . . . . .
Available-for-sale securities
Quoted
Prices in
Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)(1)
Significant
Other
Unobservable
Inputs
(Level 3)
(In thousands)
Netting and
Cash
Collateral
September 30,
2017
$ — $
3,239
$
— $
— $
3,239
Registered investment companies . . . . . . . . .
Bond mutual funds . . . . . . . . . . . . . . . . . . . . .
Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money market funds . . . . . . . . . . . . . . . . . . .
41,097
16,371
—
—
Total available-for-sale securities . . . . . . . . . . .
57,468
—
—
29,104
1,837
30,941
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$57,468
$ 34,180
Liabilities:
Financial instruments . . . . . . . . . . . . . . . . . . . . .
$ — $112,398
$
$
—
—
—
—
—
—
—
—
—
—
41,097
16,371
29,104
1,837
88,409
— $ — $ 91,648
— $
— $112,398
(1) Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-
based approach in which observable market prices are adjusted for criteria specific to each instrument, such
as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued
based on the most recent available quoted market prices and money market funds which are valued at cost.
95
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Available-for-sale securities, which include debt and equity securities, are comprised of the following:
Amortized
Cost
Gross
Unrealized
Gain
Gross
Unrealized
Loss
(In thousands)
As of September 30, 2018
Domestic equity mutual funds . . . . . . . . . . . . . . . . .
Foreign equity mutual funds . . . . . . . . . . . . . . . . . .
Bond mutual funds . . . . . . . . . . . . . . . . . . . . . . . . . .
Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money market funds . . . . . . . . . . . . . . . . . . . . . . . .
$26,950
4,656
21,810
31,511
3,834
$ 9,363
2,028
—
13
—
$88,761
$11,404
As of September 30, 2017
Domestic equity mutual funds . . . . . . . . . . . . . . . . .
Foreign equity mutual funds . . . . . . . . . . . . . . . . . .
Bond mutual funds . . . . . . . . . . . . . . . . . . . . . . . . . .
Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money market funds . . . . . . . . . . . . . . . . . . . . . . . .
$25,361
4,581
16,391
29,074
1,837
$ 8,920
2,235
2
46
—
$77,244
$11,203
$(353)
—
(303)
(124)
—
$(780)
$ —
—
(22)
(16)
—
$ (38)
Fair
Value
$35,960
6,684
21,507
31,400
3,834
$99,385
$34,281
6,816
16,371
29,104
1,837
$88,409
At September 30, 2018 and 2017, our available-for-sale securities included $46.5 million and $42.9 million
related to assets held in separate rabbi trusts for our supplemental executive retirement plans as discussed in Note
7. At September 30, 2018 we maintained investments in bonds that have contractual maturity dates ranging from
October 2018 through September 2021.
Other Fair Value Measures
In addition to the financial instruments above, we have several financial and nonfinancial assets and
liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents,
accounts receivable, accounts payable and debt. The nonfinancial assets and liabilities include asset retirement
obligations and pension and post-retirement plan assets. We record cash and cash equivalents, accounts receiv-
able, accounts payable and debt at carrying value. For cash and cash equivalents, accounts receivable and
accounts payable, we consider carrying value to materially approximate fair value due to the short-term nature of
these assets and liabilities.
Our debt is recorded at carrying value. The fair value of our debt is determined using third party market
value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent,
observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using
the most recent available quoted market price. The following table presents the carrying value and fair value of
our debt as of September 30, 2018:
Carrying Amount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30,
2018
(In thousands)
$3,085,000
$3,161,679
96
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
15. Discontinued Operations
On October 29, 2016, we entered into a Membership Interest Purchase Agreement (the Agreement) with
CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES) to sell all of the equity inter-
ests of AEM. The transaction closed on January 3, 2017, with an effective date of January 1, 2017. CES paid a
cash purchase price of $38.3 million plus working capital of $109.0 million for total cash consideration of
$147.3 million. Of this amount, $7.0 million was placed into escrow, to be paid to the Company within 24
months, net of any indemnification claims agreed upon between the two companies. In January 2018,
$3.0 million of this escrowed amount was released and received by the Company. We recognized a net gain of
$0.03 per diluted share on the sale in the second quarter of fiscal 2017 and completed the working capital true–up
during the third quarter of fiscal 2017.
The operating results of our natural gas marketing reportable segment have been reported on the con-
solidated statements of income as income from discontinued operations, net of income tax for the years ended
September 30, 2017 and 2016. Accordingly, expenses related to allocable general corporate overhead and interest
expense are not included in these results. The decision to report this segment as a discontinued operation was
predicated, in part, on the following qualitative and quantitative factors: 1) the disposal resulted in the company
becoming a fully regulated entity; 2) the fact that an entire reportable segment was disposed and 3) the fact the
disposed segment represented in excess of 30 percent of consolidated revenues over the last five fiscal years.
The tables below set forth selected financial information related to discontinued operations. Operating
expenses include operation and maintenance expense, provision for doubtful accounts, depreciation and amor-
tization expense and taxes, other than income. At September 30, 2018 and 2017 we did not have any assets or
liabilities held for sale.
The following table presents statement of income data related to discontinued operations.
Year Ended September 30
2017
2016
(In thousands)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased gas cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$303,474
277,554
7,874
$1,005,090
968,118
26,184
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other nonoperating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from discontinued operations before income taxes . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . .
Gain on sale from discontinued operations, net of tax ($10,215 and $0)
18,046
(211)
17,835
6,841
10,994
2,716
Net income from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 13,710
$
10,788
(2,495)
8,293
3,731
4,562
—
4,562
The following table presents statement of cash flow data related to discontinued operations.
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash loss in commodity contract cash flow hedges . . . . . . . . . . . . . . . . . . . .
Year Ended
September 30
2017
2016
(In thousands)
$
185
$ — $
$(8,165)
$ 2,304
321
$(33,533)
97
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Significant Accounting Policies Related to Discontinued Operations
Except as noted below, AEM adhered to the same Significant Accounting Policies as described in Note 2.
Revenue recognition — Operating revenues for our natural gas marketing segment were recognized in the
period in which actual volumes were transported and storage services were provided. Operating revenues for our
natural gas marketing segment and the associated carrying value of natural gas inventory (inclusive of storage
costs) were recognized when we sold the gas and physically delivered it to our customers. Operating revenues
include realized gains and losses arising from the settlement of financial instruments used in our natural gas
marketing activities.
Gas stored underground — Gas stored underground was comprised of natural gas injected into storage to
conduct the operations of the natural gas marketing segment. Our natural gas marketing segment utilized the
average cost method; however, most of this inventory was hedged and was therefore reported at fair value at the
end of each month.
Property, plant and equipment — Natural gas marketing property, plant and equipment was stated at cost.
Depreciation was generally computed on the straight-line method for financial reporting purposes based upon
estimated useful lives ranging from 3 to 30 years.
Financial instruments and hedging activities — In our natural gas marketing segment, we previously des-
ignated most of the natural gas inventory held by this operating segment as the hedged item in a fair-value hedge.
This inventory was marked to market at the end of each month based on the Gas Daily index, with changes in fair
value recognized as unrealized gains or losses in purchased gas cost, which is reflected in income from dis-
continued operations in the period of change. The financial instruments associated with this natural gas inventory
were designated as fair-value hedges and were marked to market each month based upon the NYMEX price with
changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. We
elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value
hedges.
Additionally, we previously elected to treat fixed-price forward contracts used in our natural gas marketing
segment to deliver natural gas as normal purchases and normal sales. As such, these deliveries were recorded on
an accrual basis in accordance with our revenue recognition policy. Financial instruments used to mitigate the
commodity price risk associated with these contracts were designated as cash flow hedges of anticipated pur-
chases and sales at indexed prices. Accordingly, unrealized gains and losses on these open financial instruments
were recorded as a component of accumulated other comprehensive income, and were recognized in earnings as
a component of purchased gas cost which is reflected in income from discontinued operations when the hedged
volumes were sold.
Gains and losses from hedge ineffectiveness were recognized in the income statement. Fair value and cash
flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged
inventory and the delivery location specified in the financial instruments is referred to as basis ineffectiveness.
Ineffectiveness arising from changes in the fair value of the fair value hedges due to changes in the difference
between the spot price and the futures price, as well as the difference between the timing of the settlement of the
futures and the valuation of the underlying physical commodity is referred to as timing ineffectiveness. Hedge
ineffectiveness, to the extent incurred, is reported as a component of purchased gas cost reflected in income from
discontinued operations for the years ended September 30, 2017 and 2016.
Our natural gas marketing segment also utilized master netting agreements with significant counterparties
that allow us to offset gains and losses arising from financial instruments that would be settled in cash with gains
and losses arising from financial instruments that could be settled with the physical commodity. Assets and
liabilities from risk management activities, as well as accounts receivable and payable, reflect the master netting
agreements in place. Additionally, the accounting guidance for master netting arrangements requires us to
98
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
include the fair value of cash collateral or the obligation to return cash in the amounts that have been netted under
master netting agreements used to offset gains and losses arising from financial instruments.
Fair Value Measurements — Our discontinued operations used the same fair value measurement policies
as described in Note 2 for our continuing operations. Level 1 measurements included primarily exchange-traded
financial instruments and gas stored underground that was been designated as the hedged item in a fair value
hedge. Within our natural gas marketing operations, we utilized a mid-market pricing convention (the mid-point
between the bid and ask prices), as permitted under current accounting standards. Values derived from these
sources reflected the market in which transactions involving these financial instruments are executed. Level 2
measurements primarily consisted of non-exchange-traded financial instruments, such as over-the-counter
options and swaps.
Short-term Debt Related to Discontinued Operations
AEM had one uncommitted $25 million 364-day bilateral credit facility that was scheduled to expire on
July 31, 2017 and one committed $15 million 364-day bilateral credit facility that was scheduled to expire on
September 30, 2017. In connection with the sale of AEM, both facilities were terminated on January 3, 2017.
Commodity Risk Management Activities
Our discontinued natural gas marketing segment was exposed to risks associated with changes in the market
price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices.
Through December 31, 2016, we managed our exposure to such risks through a combination of physical storage
and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts
with counterparties. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.
Due to the sale of AEM, we determined that the cash flows associated with our natural gas marketing
commodity cash flow hedges were no longer probable of occurring; therefore, we discontinued hedge accounting
as of December 31, 2016. As a result, we reclassified the gain in accumulated other comprehensive income asso-
ciated with the commodity contracts into earnings as a reduction of purchased gas cost and recognized a pre-tax
gain of $10.6 million, which is included in income from discontinued operations on the consolidated statement of
income for the year ended September 30, 2017.
The Company’s other risk management activities are discussed in Note 13.
Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our natural gas marketing segment was recorded as a component of purchased gas
cost, which is included in discontinued operations on the consolidated statements of income, and primarily
results from differences in the location and timing of the derivative instrument and the hedged item. For the years
ended September 30, 2017 and 2016, we recognized a gain arising from fair value and cash flow hedge
ineffectiveness of $3.4 million and $21.6 million. Additional information regarding ineffectiveness recognized in
the income statement is included in the tables below.
99
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fair Value Hedges
The impact of our natural gas marketing segment commodity contracts designated as fair value hedges and
the related hedged item on the results of discontinued operations on our consolidated income statement for the
years ended September 30, 2017 and 2016 is presented below.
Commodity contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value adjustment for natural gas inventory designated as the hedged
Year Ended September 30
2017
2016
(In thousands)
$ (9,567)
$ 3,516
item . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,858
18,079
Total decrease in purchased gas cost reflected in income from discontinued
operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 3,291
$21,595
The decrease in purchased gas cost reflected in income from discontinued
operations is comprised of the following:
Basis ineffectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Timing ineffectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (597)
3,888
$ (1,390)
22,985
$ 3,291
$21,595
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged
inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to
changes in the difference between the spot price and the futures price, as well as the difference between the tim-
ing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity
contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or
eliminate the impact of this ineffectiveness on purchased gas cost.
Cash Flow Hedges
The impact of our natural gas marketing segment cash flow hedges on our consolidated income statements
for the years ended September 30, 2017 and 2016 is presented below. Note that this presentation does not reflect
the financial impact arising from the hedged physical transactions. Therefore, this presentation is not indicative
of the economic margin we realized when the underlying physical and financial transactions were settled.
Year Ended September 30
2017
2016
(In thousands)
Loss reclassified from AOCI for effective portion of natural gas marketing
commodity contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (2,612)
$(52,651)
Gain (loss) arising from ineffective portion of natural gas marketing
commodity contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
111
Gain on discontinuance of cash flow hedging of natural gas marketing
commodity contracts reclassified from AOCI
. . . . . . . . . . . . . . . . . . . . . . .
10,579
(19)
—
Total impact on purchased gas cost reflected in income from discontinued
operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 8,078
$(52,670)
Financial Instruments Not Designated as Hedges
The impact of financial instruments that have not been designated as hedges on our consolidated income
statements for the years ended September 30, 2017 and 2016 was an increase (decrease) in purchased gas cost
reflected in income from discontinued operations of $(6.8) million and $15.5 million, which is included in dis-
continued operations on the consolidated statements of income. Note that this presentation does not reflect the
100
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
expected gains or losses arising from the underlying physical transactions associated with these financial instru-
ments. Therefore, this presentation is not indicative of the economic margin we realized when the underlying
physical and financial transactions were settled.
16. Concentration of Credit Risk
Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We
engage in transactions for the purchase and sale of products and services with major companies in the energy
industry and with industrial, commercial, residential and municipal energy consumers. These transactions princi-
pally occur in the southern and midwestern regions of the United States. We believe that this geographic concen-
tration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade
accounts receivable for the distribution segment is mitigated by the large number of individual customers and the
diversity in our customer base. The credit risk for our other segment is not significant.
17.
Selected Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data is presented below. The sum of net income per share by
quarter may not equal the net income per share for the fiscal year due to variations in the weighted average shares
outstanding used in computing such amounts. Our businesses are seasonal due to weather conditions in our serv-
ice areas. For further information on its effects on quarterly results, see the “Results of Operations” discussion
included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sec-
tion herein.
Quarter Ended
December 31
March 31
June 30
September 30
(In thousands, except per share data)
Fiscal year 2018:
Operating revenues
Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pipeline and storage . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment eliminations . . . . . . . . . . . . . . . . . . .
$860,792
126,463
(98,063)
$1,199,291
120,955
(100,837)
$ 535,488
127,633
(100,876)
$407,476
132,662
(95,438)
Total operating revenues . . . . . . . . . . . . . . . . . .
Purchased gas cost . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic and diluted earnings per share . . . . . . . . . . . . .
Net income per share — basic and diluted . . . . . . .
889,192
366,917
241,561
314,132
1,219,409
626,960
268,988
178,992
562,245
130,886
122,993
71,193
444,700
43,085
89,592
38,747
$
2.89
$
1.60
$
0.64
$
0.35
101
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Quarter Ended
December 31
March 31
June 30
September 30
(In thousands, except per share data)
Fiscal year 2017:
Operating revenues
Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pipeline and storage . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment eliminations . . . . . . . . . . . . . . . . . . . . . .
$754,656
109,952
(84,440)
$962,541
111,972
(86,327)
$494,060
117,283
(84,842)
$437,918
117,823
(90,861)
Total operating revenues . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased gas cost
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations . . . . . . . . . . . . . . . .
Income from discontinued operations . . . . . . . . . . . . . .
Gain on sale of discontinued operations . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic and diluted earnings per share . . . . . . . . . . . . . . .
Income per share from continuing operations . . . . . .
Income per share from discontinued operations . . . . .
Net income per share — basic and diluted . . . . . . . . .
780,168
311,305
209,918
114,038
10,994
—
125,032
988,186
427,494
285,172
162,012
—
2,716
164,728
526,501
114,176
140,664
70,808
—
—
70,808
464,880
72,561
91,792
35,853
—
—
35,853
$
$
1.08
0.11
1.19
$
$
1.52
0.03
1.55
$
$
0.67
—
0.67
$
$
0.34
—
0.34
102
ITEM 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
ITEM 9A. Controls and Procedures.
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including
our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure
controls and procedures, as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as
amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal
financial officer have concluded that the Company’s disclosure controls and procedures were effective as of
September 30, 2018 to provide reasonable assurance that information required to be disclosed by us, including
our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed,
summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable
level of assurance that such information is accumulated and communicated to our management, including our
principal executive and principal financial officers, as appropriate to allow timely decisions regarding required
disclosure.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f), in providing reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accord-
ance with generally accepted accounting principles. Under the supervision and with the participation of our
management, including our principal executive officer and principal financial officer, we evaluated the effective-
ness of our internal control over financial reporting based on the framework in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 frame-
work) (COSO). Based on our evaluation under the framework in Internal Control-Integrated Framework issued
by COSO and applicable Securities and Exchange Commission rules, our management concluded that our
internal control over financial reporting was effective as of September 30, 2018, in providing reasonable assur-
ance regarding the reliability of financial reporting and the preparation of financial statements for external pur-
poses in accordance with generally accepted accounting principles.
Ernst & Young LLP has issued its report on the effectiveness of the Company’s internal control over finan-
cial reporting. That report appears below.
/s/ MICHAEL E. HAEFNER
/s/ CHRISTOPHER T. FORSYTHE
Michael E. Haefner
President, Chief Executive Officer and Director
Christopher T. Forsythe
Senior Vice President and
Chief Financial Officer
November 13, 2018
103
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Atmos Energy Corporation
Opinion on Internal Control over Financial Reporting
We have audited Atmos Energy Corporation’s internal control over financial reporting as of September 30, 2018,
based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Atmos Energy
Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of
September 30, 2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the 2018 consolidated financial statements of the Company and our report dated
November 13, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and
for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Man-
agement’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting
was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that
our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accu-
rately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance
that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance
with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstate-
ments. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures
may deteriorate.
/s/
Ernst & Young LLP
Dallas, Texas
November 13, 2018
104
Changes in Internal Control over Financial Reporting
We did not make any changes in our internal control over financial reporting (as defined in Rule 13a-15(f)
and 15d-15(f) under the Act) during the fourth quarter of the fiscal year ended September 30, 2018 that have
materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. Other Information.
Not applicable.
PART III
ITEM 10. Directors, Executive Officers and Corporate Governance.
Information regarding directors and compliance with Section 16(a) of the Securities Exchange Act of 1934
is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 6, 2019. Information regarding executive officers is reported below:
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of September 30, 2018, regarding the executive officers
of the Company. It is followed by a brief description of the business experience of each executive officer.
Name
Age
Years of
Service
Office Currently Held
Kim R. Cocklin . . . . . . . . . . . . . . . . . . . . . .
Michael E. Haefner . . . . . . . . . . . . . . . . . . .
Christopher T. Forsythe . . . . . . . . . . . . . . .
David J. Park . . . . . . . . . . . . . . . . . . . . . . . .
John K. Akers . . . . . . . . . . . . . . . . . . . . . . .
Karen E. Hartsfield . . . . . . . . . . . . . . . . . . .
John M. Robbins . . . . . . . . . . . . . . . . . . . . .
67
58
47
47
55
48
48
12
10
15
14
27
3
5
Executive Chairman of the Board
President, Chief Executive Officer and
Director
Senior Vice President and Chief
Financial Officer
Senior Vice President, Utility
Operations
Senior Vice President, Safety and
Enterprise Services
Senior Vice President, General Counsel
and Corporate Secretary
Senior Vice President, Human
Resources
Kim R. Cocklin was named Executive Chairman of the Board on October 1, 2017. From October 1, 2010
through September 30, 2015, Mr. Cocklin served the Company as President and Chief Executive Officer and
from October 1, 2015 through September 30, 2017, as Chief Executive Officer. Mr. Cocklin joined the Company
in June 2006 and served as President and Chief Operating Officer of the Company from October 1, 2008 through
September 30, 2010, after having served as Senior Vice President, Regulated Operations from October 2006
through September 2008. Mr. Cocklin was appointed to the Board of Directors on November 10, 2009.
Michael E. Haefner was named President and Chief Executive Officer, effective October 1, 2017.
Mr. Haefner joined the Company in June 2008 as Senior Vice President, Human Resources. On January 19,
2015, Mr. Haefner was promoted to Executive Vice President and assumed oversight responsibility for Atmos
Pipeline — Texas, Atmos Energy Holdings, Inc. and the gas supply and services function. On October 1, 2015,
Mr. Haefner was promoted to the role of President and Chief Operating Officer in which he also assumed over-
sight responsibility for the operations of our six utility divisions and customer service. Mr. Haefner was
appointed to the Board of Directors on November 4, 2015.
Christopher T. Forsythe was named Senior Vice President and Chief Financial Officer effective February 1,
2017. Mr. Forsythe joined the Company in June 2003 and prior to his promotion, served as the Company’s Vice
President and Controller from May 2009 through January 2017.
105
David J. Park was named Senior Vice President of Utility Operations, effective January 1, 2017. In this role,
Mr. Park is responsible for the operations of Atmos Energy’s six utility divisions as well as gas supply. Prior to
this promotion, Mr. Park served as the President of the West Texas Division from July 2012 to December 2016.
Mr. Park also served as Vice President of Rates and Regulatory Affairs in the Mid-Tex Division and previously
held positions in Engineering and Public Affairs. Prior to joining Atmos Energy in 2004, Mr. Park had 10 years
of experience in the industry.
John K. (Kevin) Akers was named Senior Vice President, Safety and Enterprise Services, effective Jan-
uary 1, 2017. In this role, Mr. Akers is responsible for customer service, facilities management, safety and supply
chain management. Mr. Akers joined the company in 1991. Mr. Akers assumed increased responsibilities over
time and was named President of the Mississippi Division in 2002. He was later named President of the Ken-
tucky/Mid-States Division in May 2007, a position he held until December 2016.
Karen E. Hartsfield was named Senior Vice President, General Counsel and Corporate Secretary of Atmos
Energy, effective August 7, 2017. Ms. Hartsfield joined the Company in June 2015, after having served in private
practice for 19 years, most recently as Managing Partner of Jackson Lewis LLP in its Dallas office from July
2013 to June 2015. Prior to joining Jackson Lewis as a partner in January 2009, Ms. Hartsfield was a partner with
Baker Botts LLP in Dallas.
John M. (Matt) Robbins was named Senior Vice President, Human Resources, effective January 1, 2017.
Mr. Robbins joined the Company in May 2013 and prior to this promotion served as Vice President, Human
Resources from February 2015 to December 2016. Before joining Atmos Energy, Matt had over 20 years of
experience in human resources.
Identification of the members of the Audit Committee of the Board of Directors as well as the Board of
Directors’ determination as to whether one or more audit committee financial experts are serving on the Audit
Committee of the Board of Directors is incorporated herein by reference to the Company’s Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 6, 2019.
The Company has adopted a code of ethics for its principal executive officer, principal financial officer and
principal accounting officer. Such code of ethics is represented by the Company’s Code of Conduct, which is
applicable to all directors, officers and employees of the Company, including the Company’s principal executive
officer, principal financial officer and principal accounting officer. A copy of the Company’s Code of Conduct is
posted on the Company’s website at www.atmosenergy.com under “Corporate Responsibility.” In addition, any
amendment to or waiver granted from a provision of the Company’s Code of Conduct will be posted on the
Company’s website under “Corporate Responsibility.”
ITEM 11. Executive Compensation.
Information on executive compensation is incorporated herein by reference to the Company’s Definitive
Proxy Statement for the Annual Meeting of Shareholders on February 6, 2019.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
Security ownership of certain beneficial owners and of management is incorporated herein by reference to
the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 6, 2019.
Information concerning our equity compensation plans is provided in Part II, Item 5, “Market for Registrant’s
Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities”, of this Annual Report
on Form 10-K.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence.
Information on certain relationships and related transactions as well as director independence is
incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Share-
holders on February 6, 2019.
ITEM 14. Principal Accountant Fees and Services.
Information on our principal accountant’s fees and services is incorporated herein by reference to the
Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 6, 2019.
106
ITEM 15. Exhibits and Financial Statement Schedules.
(a) 1. and 2. Financial statements and financial statement schedules.
PART IV
The financial statements and financial statement schedule listed in the Index to Financial Statements in
Item 8 are filed as part of this Form 10-K.
3.
Exhibits
Exhibit
Number
Description
2.1
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
4.7(a)
4.7(b)
Plan of Acquisition, Reorganization,
Arrangement, Liquidation or Succession
Membership Interest Purchase Agreement by
and between Atmos Energy Holdings, Inc. as
Seller and CenterPoint Energy Services, Inc. as
Buyer, dated as of October 29, 2016
Articles of Incorporation and Bylaws
Restated Articles of Incorporation of Atmos
Energy Corporation — Texas (As Amended
Effective February 3, 2010)
Restated Articles of Incorporation of Atmos
Energy Corporation — Virginia (As Amended
Effective February 3, 2010)
Amended and Restated Bylaws of Atmos
Energy Corporation (as of September 28, 2015)
Instruments Defining Rights of Security
Holders, Including Indentures
Specimen Common Stock Certificate (Atmos
Energy Corporation)
Indenture dated as of November 15, 1995
between United Cities Gas Company and Bank
of America Illinois, Trustee
Indenture dated as of July 15, 1998 between
Atmos Energy Corporation and U.S. Bank Trust
National Association, Trustee
Indenture dated as of May 22, 2001 between
Atmos Energy Corporation and SunTrust Bank,
Trustee
Indenture dated as of June 14, 2007, between
Atmos Energy Corporation and U.S. Bank
National Association, Trustee
Indenture dated as of March 23, 2009 between
Atmos Energy Corporation and U.S. Bank
National Corporation, Trustee
Debenture Certificate for the 6 3/4%
Debentures due 2028
Global Security for the 5.95% Senior Notes due
2034
107
Page Number or
Incorporation by
Reference to
Exhibit 2.1 to Form 8-K dated October 29, 2016
(File No. 1-10042)
Exhibit 3.1 to Form 10-Q dated March 31, 2010
(File No. 1-10042)
Exhibit 3.2 to Form 10-Q dated March 31, 2010
(File No. 1-10042)
Exhibit 3.1 to Form 8-K dated September 28,
2015 (File No. 1-10042)
Exhibit 4.1 to Form 10-K for fiscal year ended
September 30, 2012 (File No. 1-10042)
Exhibit 4.11(a) to Form S-3 dated August 31,
2004 (File No. 333-118706)
Exhibit 4.8 to Form S-3 dated August 31, 2004
(File No. 333-118706)
Exhibit 99.3 to Form 8-K dated May 15, 2001
(File No. 1-10042)
Exhibit 4.1 to Form 8-K dated June 11, 2007
(File No. 1-10042)
Exhibit 4.1 to Form 8-K dated March 26, 2009
(File No. 1-10042)
Exhibit 99.2 to Form 8-K dated July 22, 1998
(File No. 1-10042)
Exhibit 10(2)(g) to Form 10-K for fiscal year
ended September 30, 2004 (File No. 1-10042)
Page Number or
Incorporation by
Reference to
Exhibit 4.2 to Form 8-K dated March 26, 2009
(File No. 1-10042)
Exhibit 4.2 to Form 8-K dated June 10, 2011
(File No. 1-10042)
Exhibit 4.2 to Form 8-K dated January 8, 2013
(File No. 1-10042)
Exhibit 4.2 to Form 8-K dated October 15, 2014
(File No. 1-10042)
Exhibit 4.2 to Form 8-K dated June 8, 2017
(File No. 1-10042)
Exhibit 4.3 to Form 8-K dated June 8, 2017
(File No. 1-10042)
Exhibit 4.2 to Form 8-K dated October 4, 2018
(File No. 1-10042)
Exhibit 4.3 to Form 8-K dated October 4, 2018
(File No. 1-10042)
Exhibit 10.1 to Form 8-K dated October 1, 2015
(File No. 1-10042)
Exhibit 10.1 to Form 8-K dated October 5, 2016
(File No. 1-10042)
Exhibit 10.1 to Form 8-K dated September 22,
2016 (File No. 1-10042)
Exhibit
Number
4.7(c)
4.7(d)
4.7(e)
4.7(f)
4.7(g)
4.7(h)
4.7(i)
4.7(j)
10.1(a)
10.1(b)
10.1(c)
10.1(d)
10.1(e)
Description
Global Security for the 8.50% Senior Notes due
2019
Global Security for the 5.5% Senior Notes due
2041
Global Security for the 4.15% Senior Notes due
2043
Global Security for the 4.125% Senior Notes
due 2044
Global Security for the 3.000% Senior Notes
due 2027
Global Security for the 4.125% Senior Notes
due 2044
Global Security for the 4.300% Senior Notes
due 2048
Global Security for the 4.300% Senior Notes
due 2048
Material Contracts
Revolving Credit Agreement, dated as of
September 25, 2015 among Atmos Energy
Corporation, the Lenders from time to time
parties thereto, Crédit Agricole Corporate and
Investment Bank as Administrative Agent, and
Mizuho Bank Ltd., as Syndication Agent
First Amendment to Revolving Credit
Agreement, dated as of October 5, 2016, by and
among Atmos Energy Corporation, the lenders
from time to time parties thereto (the
“Lenders”) and Credit Agricole Corporate and
Investment Bank, in its capacity as
administrative agent for the Lenders
Second Amendment to Revolving Credit
Agreement, dated as of September 7, 2017, by
and among Atmos Energy Corporation, the
lenders from time to time parties thereto (the
“Lenders”) and Credit Agricole Corporate and
Investment Bank, in its capacity as
administrative agent for the Lenders
Term Loan Agreement, dated as of
September 22, 2016, by and among Atmos
Energy Corporation, the Lenders from time to
time parties thereto and Branch Banking and
Trust Company as Administrative Agent
First Amendment to Term Loan Agreement,
dated as of September 7, 2017, by and among
Atmos Energy Corporation, the lenders from
time to time parties thereto (the “Lenders”) and
Branch Banking and Trust Company, in its
capacity as administrative agent for the Lenders
108
Exhibit
Number
10.2
Description
10.5*
10.4(a)*
10.6(a)*
10.3(a)*
10.6(b)*
10.3(b)*
10.4(b)*
Equity Distribution Agreement, dated as of
November 14, 2017, among Atmos Energy
Corporation, Goldman, Sachs & Co. LLC,
Merrill Lynch, Pierce, Fenner & Smith
Incorporated, Morgan Stanley & Co. LLC and
J.P. Morgan Securities LLC
Executive Compensation Plans and
Arrangements
Form of Atmos Energy Corporation Change in
Control Severance Agreement — Tier I
Form of Atmos Energy Corporation Change in
Control Severance Agreement — Tier II
Atmos Energy Corporation Executive Retiree
Life Plan
Amendment No. 1 to the Atmos Energy
Corporation Executive Retiree Life Plan
Atmos Energy Corporation Annual Incentive
Plan for Management (as amended and restated
October 1, 2016)
Atmos Energy Corporation Supplemental
Executive Benefits Plan, Amended and Restated
in its Entirety August 7, 2007
Form of Individual Trust Agreement for the
Supplemental Executive Benefits Plan
Atmos Energy Corporation Supplemental
Executive Retirement Plan (As Amended and
Restated, Effective as of January 1, 2016)
Atmos Energy Corporation Performance-Based
Supplemental Executive Benefits Plan Trust
Agreement, Effective Date December 1, 2000
Atmos Energy Corporation Account Balance
Supplemental Executive Retirement Plan (As
Amended and Restated, Effective as of
January 1, 2016)
Mini-Med/Dental Benefit Extension Agreement
dated October 1, 1994
Amendment No. 1 to Mini-Med/Dental Benefit
Extension Agreement dated August 14, 2001
Amendment No. 2 to Mini-Med/Dental Benefit
Extension Agreement dated December 31, 2002
Atmos Energy Corporation Equity Incentive
and Deferred Compensation Plan for
Non-Employee Directors, Amended and
Restated as of January 1, 2012
10.11(a)* Atmos Energy Corporation 1998 Long-Term
10.9(b)*
10.7(b)*
10.7(a)*
10.9(c)*
10.9(a)*
10.10*
10.8*
Incentive Plan (as amended and restated
February 3, 2016)
109
Page Number or
Incorporation by
Reference to
Exhibit 1.1 to Form 8-K dated November 14,
2017 (File No. 1-10042)
Exhibit 10.7(a) to Form 10-K for fiscal year
ended September 30, 2010 (File No. 1-10042)
Exhibit 10.7(b) to Form 10-K for fiscal year
ended September 30, 2010 (File No. 1-10042)
Exhibit 10.31 to Form 10-K for fiscal year
ended September 30, 1997 (File No. 1-10042)
Exhibit 10.31(a) to Form 10-K for fiscal year
ended September 30, 1997 (File No. 1-10042)
Exhibit 10.5 to Form 10-K for fiscal year ended
September 30, 2016 (File No. 1-10042)
Exhibit 10.8(a) to Form 10-K for fiscal year
ended September 30, 2008 (File No. 1-10042)
Exhibit 10.3 to Form 10-Q for quarter ended
December 31, 2000 (File No. 1-10042)
Exhibit 10.7(a) to Form 10-K for fiscal year
ended September 30, 2016 (File No. 1-10042)
Exhibit 10.1 to Form 10-Q for quarter ended
December 31, 2000 (File No. 1-10042)
Exhibit 10.8 to Form 10-K for fiscal year ended
September 30, 2016 (File No. 1-10042)
Exhibit 10.28(f) to Form 10-K for fiscal year
ended September 30, 2001 (File No. 1-10042)
Exhibit 10.28(g) to Form 10-K for fiscal year
ended September 30, 2001 (File No. 1-10042)
Exhibit 10.1 to Form 10-Q for quarter ended
December 31, 2002 (File No. 1-10042)
Exhibit 10.1 to Form 10-Q for quarter ended
December 31, 2011 (File No. 1-10042)
Exhibit 99.1 to Form S-8 dated March 29, 2016
(File No. 333-210461)
Page Number or
Incorporation by
Reference to
Signature page of Form 10-K for fiscal year
ended September 30, 2018
Exhibit
Number
10.11(b)*
10.11(c)*
21
23.1
24
31
32
101.INS
101.SCH
101.CAL
101.DEF
101.LAB
101.PRE
Description
Form of Award Agreement of Time-Lapse
Restricted Stock Units under the Atmos Energy
Corporation 1998 Long-Term Incentive Plan
Form of Award Agreement of Performance-
Based Restricted Stock Units under the Atmos
Energy Corporation 1998 Long-Term Incentive
Plan
Other Exhibits, as indicated
Subsidiaries of the registrant
Consent of independent registered public
accounting firm, Ernst & Young LLP
Power of Attorney
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications**
Interactive Data File
XBRL Instance Document
XBRL Taxonomy Extension Schema
XBRL Taxonomy Extension Calculation
Linkbase
XBRL Taxonomy Extension Definition
Linkbase
XBRL Taxonomy Extension Labels Linkbase
XBRL Taxonomy Extension Presentation
Linkbase
* This exhibit constitutes a “management contract or compensatory plan, contract, or arrangement.”
** These certifications pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and
Chief Financial Officer, furnished as Exhibit 32 to this Annual Report on Form 10-K, will not be deemed to
be filed with the Securities and Exchange Commission or incorporated by reference into any filing by the
Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that
the Company specifically incorporates such certifications by reference.
110
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
ATMOS ENERGY CORPORATION
(Registrant)
By:
/s/ CHRISTOPHER T. FORSYTHE
Christopher T. Forsythe
Senior Vice President and Chief Financial
Officer
Date: November 13, 2018
111
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby con-
stitutes and appoints Michael E. Haefner and Christopher T. Forsythe, or either of them acting alone or together,
as his true and lawful attorney-in-fact and agent with full power to act alone, for him and in his name, place and
stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file
the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform
each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents
and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and
agent, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by
the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ KIM R. COCKLIN
Kim R. Cocklin
/s/ MICHAEL E. HAEFNER
Michael E. Haefner
Executive Chairman of the Board
November 13, 2018
President, Chief Executive Officer
and Director
November 13, 2018
/s/ CHRISTOPHER T. FORSYTHE
Christopher T. Forsythe
Senior Vice President and Chief
Financial Officer
November 13, 2018
/s/ RICHARD M. THOMAS
Richard M. Thomas
/s/ ROBERT W. BEST
Robert W. Best
/s/ KELLY H. COMPTON
Kelly H. Compton
/s/ SEAN DONOHUE
Sean Donohue
/s/ RUBEN E. ESQUIVEL
Ruben E. Esquivel
/s/ RAFAEL G. GARZA
Rafael G. Garza
/s/ RICHARD K. GORDON
Richard K. Gordon
/s/ ROBERT C. GRABLE
Robert C. Grable
/s/ NANCY K. QUINN
Nancy K. Quinn
/s/ RICHARD A. SAMPSON
Richard A. Sampson
/s/ STEPHEN R. SPRINGER
Stephen R. Springer
/s/ DIANA J. WALTERS
Diana J. Walters
/s/ RICHARD WARE II
Richard Ware II
Vice President and Controller
(Principal Accounting Officer)
November 13, 2018
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
112
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
November 13, 2018
Schedule II
ATMOS ENERGY CORPORATION
Valuation and Qualifying Accounts
Three Years Ended September 30, 2018
Additions
Balance at
beginning
of period
Charged to
cost &
expenses
Charged to
other
accounts
Deductions
Balance
at end
of period
(In thousands)
2018
Allowance for doubtful accounts . . . . . . . . . . . .
$10,865
$14,894
2017
Allowance for doubtful accounts . . . . . . . . . . . .
$11,056
$12,269
2016
Allowance for doubtful accounts . . . . . . . . . . . .
$12,934
$10,414
$—
$—
$—
$10,964(1)
$14,795
$12,460(1)
$10,865
$12,292(1)
$11,056
(1) Uncollectible accounts written off.
113
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Corporate Information
Common Stock Listing
New York Stock Exchange. Trading symbol: ATO
Stock Transfer Agent and Registrar
American Stock Transfer & Trust Company, LLC
Operations Center
6201 15th Avenue
Brooklyn, New York 11219
800-543-3038
To inquire about your Atmos Energy common stock, please call AST at the telephone number above. You may use the
agent’s interactive voice response system 24 hours a day to learn about transferring stock or to check your recent
account activity, all without the assistance of a customer service representative. Please have available your Atmos Energy
shareholder account number and your Social Security or federal taxpayer ID number.
To speak to an AST customer service representative, please call the same number between 8 a.m. and
8 p.m. Eastern time, Monday through Friday.
You also may send an email message on our transfer agent’s website at www.amstock.com. Please refer to Atmos Energy
in your email message and include your Atmos Energy shareholder account number.
Independent Registered Public Accounting Firm
Ernst & Young LLP
One Victory Park
Suite 2000
2323 Victory Avenue
Dallas, Texas 75219
214-969-8000
Annual Report
Atmos Energy Corporation’s 2018 Integrated Annual Report including our Form 10-K is available at no charge from
Investor Relations, Atmos Energy Corporation, P.O. Box 650205, Dallas, Texas 75265-0205 or by calling 972-855-3729,
Monday through Friday, between 8 a.m. and 5 p.m. Central time. Atmos Energy’s 2018 Integrated Annual Report also
may be viewed on Atmos Energy’s website at www.atmosenergy.com.
Annual Meeting of Shareholders
The 2019 Annual Meeting of Shareholders will be held at the Charles K. Vaughan Center, 3697 Mapleshade Lane,
Plano, Texas 75075 on Wednesday, February 6, 2019, at 9:00 a.m. Central time.
Direct Stock Purchase Plan
Atmos Energy has a Direct Stock Purchase Plan that is available to all investors. For an Enrollment Application Form
and a Plan Prospectus, please call AST at 800-543-3038. The Prospectus is also available at www.atmosenergy.com.
You may also obtain information by writing to Investor Relations, Atmos Energy Corporation, P.O. Box 650205, Dallas,
Texas 75265-0205.
This is not an offer to sell, or a solicitation to buy, any securities of Atmos Energy Corporation. Shares of Atmos Energy
common stock purchased through the Direct Stock Purchase Plan will be offered only by prospectus.
Atmos Energy on the Internet
Information about Atmos Energy is available at www.atmosenergy.com. Our website includes news releases, current
and historical financial reports, other investor data, corporate governance documents, management biographies,
customer information and facts about Atmos Energy’s operations.
Atmos Energy Corporation Contacts
To contact Atmos Energy’s Investor Relations, call 972-855-3729, Monday through Friday, between 8 a.m. and 5 p.m.
Central time or send an email message to InvestorRelations@atmosenergy.com.
Securities analysts and investment managers, please contact:
Jennifer P. Hills
Vice President, Investor Relations
972-855-3729 (voice) 972-855-3040 (fax)
InvestorRelations@atmosenergy.com
Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas 75265-0205
atmosenergy.com