ONE Gas, Inc. is a 100-percent regulated natural gas
utility, and trades on the New York Stock Exchange
under the symbol “OGS.” ONE Gas is included in the
S&P MidCap 400 Index, and is one of the largest natural
gas utilities in the United States.
ONE Gas
Investing for a Better Tomorrow
ONE Gas provides natural gas
distribution services to more than
2 million customers in Oklahoma,
Kansas and Texas.
ONE Gas is headquartered
in Tulsa, Okla.
Our divisions include:
Oklahoma Natural Gas, the
largest natural gas distributor
in Oklahoma;
Kansas Gas Service, the
largest in Kansas; and
Texas Gas Service, the third
largest in Texas, in terms
of customers.
Our largest natural gas distribution
markets by customer count are
Oklahoma City and Tulsa, Okla.;
Kansas City, Wichita and Topeka, Kan.;
and Austin and El Paso, Texas.
We serve residential, commercial,
industrial, transportation and
wholesale customers in all three states.
Mission – Why We Exist
We deliver natural gas for a better tomorrow.
Vision – What We Want to Be
To be a premier natural gas distribution company
creating exceptional value for our stakeholders.
Core Values
Safety: We are committed to operating safely and in an
environmentally responsible manner.
Inclusion and Diversity: We embrace and promote
diversity and collaboration; every employee makes a
difference and contributes to our success.
Ethics: We are accountable to the highest ethical
standards; honesty, trust and integrity matter.
Service: We provide exceptional service and make
continuous improvements in our pursuit of excellence.
Value: We create value for all stakeholders, including
our employees, customers, investors and communities.
Visit us: www.ONEGas.com
Like us on Facebook: facebook.com/onegasincorporated
Follow us on Twitter: @ONEGasInc
1
ONE Gas, Inc. is a 100-percent regulated natural gas
utility, and trades on the New York Stock Exchange
under the symbol “OGS.” ONE Gas is included in the
S&P MidCap 400 Index, and is one of the largest natural
gas utilities in the United States.
ONE Gas
Investing for a Better Tomorrow
ONE Gas provides natural gas
distribution services to more than
2 million customers in Oklahoma,
Kansas and Texas.
ONE Gas is headquartered
in Tulsa, Okla.
Our divisions include:
Oklahoma Natural Gas, the
largest natural gas distributor
in Oklahoma;
Kansas Gas Service, the
largest in Kansas; and
Texas Gas Service, the third
largest in Texas, in terms
of customers.
Our largest natural gas distribution
markets by customer count are
Oklahoma City and Tulsa, Okla.;
Kansas City, Wichita and Topeka, Kan.;
and Austin and El Paso, Texas.
We serve residential, commercial,
industrial, transportation and
wholesale customers in all three states.
Mission – Why We Exist
We deliver natural gas for a better tomorrow.
Vision – What We Want to Be
To be a premier natural gas distribution company
creating exceptional value for our stakeholders.
Core Values
Safety: We are committed to operating safely and in an
environmentally responsible manner.
Inclusion and Diversity: We embrace and promote
diversity and collaboration; every employee makes a
difference and contributes to our success.
Ethics: We are accountable to the highest ethical
standards; honesty, trust and integrity matter.
Service: We provide exceptional service and make
continuous improvements in our pursuit of excellence.
Value: We create value for all stakeholders, including
our employees, customers, investors and communities.
Visit us: www.ONEGas.com
Like us on Facebook: facebook.com/onegasincorporated
Follow us on Twitter: @ONEGasInc
1
2015 Highlights
Our second year as a company
was another year fi lled with
accomplishments, thanks to
the hard work and dedication
of our employees.
We delivered a total shareholder return
of approximately 25 percent in 2015,
outperforming our peer group and the
S&P MidCap Utilities Index. Shareholder
returns refl ect solid operating and
fi nancial results, and the continued
investments in our assets.
We expect net income and earnings
per share to increase by an average
of 5 to 8 percent annually between
2015 and 2020.
We increased the quarterly dividend
by 5 cents per share to 35 cents per
share, effective for the fi rst quarter 2016,
resulting in an annualized dividend of
$1.40 per share.
We expect an average annual
dividend increase of 8 to 10 percent
between 2015 and 2020, while
maintaining a 55 to 65 percent
dividend payout ratio.
Shareholder letter
To Our Fellow Shareholders:
This time last year, we were wrapping up our fi rst full
year as a new, stand-alone publicly traded company. We
spent a lot of time during year one laying out plans and
goals for the future success of our company. Our mission
is straightforward and simple. We deliver natural gas for
a better tomorrow. In year two, we were able to put our
strategic plan into action – working toward our goals and
measuring our success. We are extremely proud of our
employees and all that they’ve accomplished.
Last year, we challenged ourselves to focus on the fi ve
key themes that would make the greatest impact on our
company – safety, high-performing workforce, leveraging
technology, growth and regulatory. We are pleased to say
we’ve made great strides in executing on the objectives
and initiatives supporting these fi ve key themes.
When it comes to safety, our results continue to improve
and refl ect our emphasis on keeping our employees,
customers and communities safe. Compared with
2014, we achieved a 10 percent reduction in our Total
Recordable Injury Rate and a 7 percent reduction in
our Preventable Vehicle Incident Rate. As a company,
we’ve committed to focusing on processes, policies and
guidelines that result in driving toward “zero harm” and
“zero injuries” every day.
In 2015, employees in leadership roles participated in
our Leadership Development Program. This program
provided them the opportunity to learn and grow in their
leadership skills. In a continued effort to cultivate a
high-performing workforce, we will introduce an ongoing
Aspiring Leader Program this year, which will focus on
developing the future leaders of our company. It will
also provide them with a unique opportunity to develop
skills that are necessary for sustaining and growing our
company for years to come.
After a demanding year of rolling out new technology
to two-thirds of our fi eld workforce, we are beginning to
see the benefi ts of that hard work. New technology for
operations is increasing our effi ciency and productivity
in the fi eld, as employees become more familiar with
new equipment and processes. Additionally, new mobile
apps have been released to our customers, making it
easier for customers to manage their own accounts by
tracking usage and paying their bill, among other things.
We are pleased with the progress toward our leveraging
technology objective, and eager to see its continued
impact on the work that we do.
Growth remains a top priority, and we made great
progress in 2015. One way we grow is by investing in
our existing systems. We invested $294 million in capital
expenditures in 2015, of which more than 70 percent
went toward system integrity and replacement projects.
Another way we grow is by adding customers. We
averaged 13,000 more customers in 2015 compared
with 2014.
We continue to execute on our regulatory strategy
through collaborative relationships with regulators and
fi nding opportunities that allow us to provide the most
cost-effective, safe and reliable service to our customers.
Rate activity across all three of our states – Oklahoma,
Kansas and Texas – resulted in a base revenue increase
of $27.5 million, compared with 2014. Rate adjustments
allow us to continue serving our customers with safe
and reliable natural gas service.
We believe that natural gas remains well positioned to be
competitive against other energy options and is among
the best carbon fuels for maintaining limited emissions.
We remain diligent at being good stewards of our
product. This includes focusing on reducing emissions
and fi nding innovative ways to use natural gas. Natural
gas goes beyond the four touchpoints in our homes –
the natural gas furnace, clothes dryer, stove top and
water heater. It provides even more – reliability, warmth,
comfort and convenience.
We look forward to the year ahead – and while we’re
always looking forward to our future, we know that
a better tomorrow starts today.
John W. Gibson
Chairman
ONE Gas, Inc.
April 1, 2016
Pierce H. Norton II
President and Chief Executive Offi cer
ONE Gas, Inc.
April 1, 2016
2
3
2015 Highlights
Our second year as a company
was another year fi lled with
accomplishments, thanks to
the hard work and dedication
of our employees.
We delivered a total shareholder return
of approximately 25 percent in 2015,
outperforming our peer group and the
S&P MidCap Utilities Index. Shareholder
returns refl ect solid operating and
fi nancial results, and the continued
investments in our assets.
We expect net income and earnings
per share to increase by an average
of 5 to 8 percent annually between
2015 and 2020.
We increased the quarterly dividend
by 5 cents per share to 35 cents per
share, effective for the fi rst quarter 2016,
resulting in an annualized dividend of
$1.40 per share.
We expect an average annual
dividend increase of 8 to 10 percent
between 2015 and 2020, while
maintaining a 55 to 65 percent
dividend payout ratio.
Shareholder letter
To Our Fellow Shareholders:
This time last year, we were wrapping up our fi rst full
year as a new, stand-alone publicly traded company. We
spent a lot of time during year one laying out plans and
goals for the future success of our company. Our mission
is straightforward and simple. We deliver natural gas for
a better tomorrow. In year two, we were able to put our
strategic plan into action – working toward our goals and
measuring our success. We are extremely proud of our
employees and all that they’ve accomplished.
Last year, we challenged ourselves to focus on the fi ve
key themes that would make the greatest impact on our
company – safety, high-performing workforce, leveraging
technology, growth and regulatory. We are pleased to say
we’ve made great strides in executing on the objectives
and initiatives supporting these fi ve key themes.
When it comes to safety, our results continue to improve
and refl ect our emphasis on keeping our employees,
customers and communities safe. Compared with
2014, we achieved a 10 percent reduction in our Total
Recordable Injury Rate and a 7 percent reduction in
our Preventable Vehicle Incident Rate. As a company,
we’ve committed to focusing on processes, policies and
guidelines that result in driving toward “zero harm” and
“zero injuries” every day.
In 2015, employees in leadership roles participated in
our Leadership Development Program. This program
provided them the opportunity to learn and grow in their
leadership skills. In a continued effort to cultivate a
high-performing workforce, we will introduce an ongoing
Aspiring Leader Program this year, which will focus on
developing the future leaders of our company. It will
also provide them with a unique opportunity to develop
skills that are necessary for sustaining and growing our
company for years to come.
After a demanding year of rolling out new technology
to two-thirds of our fi eld workforce, we are beginning to
see the benefi ts of that hard work. New technology for
operations is increasing our effi ciency and productivity
in the fi eld, as employees become more familiar with
new equipment and processes. Additionally, new mobile
apps have been released to our customers, making it
easier for customers to manage their own accounts by
tracking usage and paying their bill, among other things.
We are pleased with the progress toward our leveraging
technology objective, and eager to see its continued
impact on the work that we do.
Growth remains a top priority, and we made great
progress in 2015. One way we grow is by investing in
our existing systems. We invested $294 million in capital
expenditures in 2015, of which more than 70 percent
went toward system integrity and replacement projects.
Another way we grow is by adding customers. We
averaged 13,000 more customers in 2015 compared
with 2014.
We continue to execute on our regulatory strategy
through collaborative relationships with regulators and
fi nding opportunities that allow us to provide the most
cost-effective, safe and reliable service to our customers.
Rate activity across all three of our states – Oklahoma,
Kansas and Texas – resulted in a base revenue increase
of $27.5 million, compared with 2014. Rate adjustments
allow us to continue serving our customers with safe
and reliable natural gas service.
We believe that natural gas remains well positioned to be
competitive against other energy options and is among
the best carbon fuels for maintaining limited emissions.
We remain diligent at being good stewards of our
product. This includes focusing on reducing emissions
and fi nding innovative ways to use natural gas. Natural
gas goes beyond the four touchpoints in our homes –
the natural gas furnace, clothes dryer, stove top and
water heater. It provides even more – reliability, warmth,
comfort and convenience.
We look forward to the year ahead – and while we’re
always looking forward to our future, we know that
a better tomorrow starts today.
John W. Gibson
Chairman
ONE Gas, Inc.
April 1, 2016
Pierce H. Norton II
President and Chief Executive Offi cer
ONE Gas, Inc.
April 1, 2016
2
3
Financial Overview
2015 Summary
We reported full-year 2015 net income of $119.0 million,
or $2.24 per diluted share, compared with $109.8 million,
or $2.07 per diluted share, in 2014; and full-year 2015
capital expenditures of $294.3 million, compared with
$297.1 million in 2014.
Our operating income was $239.1 million, compared
with $225.3 million in 2014, as net margin increased
by $14.7 million compared with last year.
Net margin increases in 2015 primarily refl ected new
rates in Oklahoma and Texas along with an increase in
our average residential customer count in these states.
We lowered operating costs in 2015, which were
$469.6 million, compared with $476.0 million in 2014,
Highlights
Earnings and Dividends
Net Income (thousands)
Earnings Per Share of Common Stock
Basic
Diluted
Dividends Per Share
Margin, Volumes and Weather
Net Margin (thousands)
Total Volumes Sold (Bcf)
Total Volumes Delivered (Bcf)
Actual Heating Degree Days
Normal Heating Degree Days
Customers and Employees
Average Number of Customers (thousands)
Total Employees
Common Stock
Signifi cant Scale
High Percentage of Residential Customers
83%
Residential
92%
Residential
16%
Commercial /
Industrial
1%
Other
Net Sales Margin
(Excludes transportation)
Customer Count
(Excludes transportation)
7%
Commercial /
Industrial
1%
Other
which primarily refl ects decreases in information technology
costs associated with our separation in 2014 from
ONEOK, Inc. We also benefi ted from a decrease in outside
services expenses, bad debt and fl eet-related expenses.
On January 19, 2016, the ONE Gas Board of Directors
increased the quarterly dividend by 5 cents per share to
35 cents per share, effective in the fi rst quarter 2016,
resulting in an annualized dividend of $1.40 per share.
Our average annual dividend growth rate is expected to
increase 8 to 10 percent between 2015 and 2020, with
a targeted dividend payout ratio of 55 to 65 percent of
net income, all subject to board of directors’ approval.
2015
2014
2013
$ 119,030
$ 109,790
$
$
$
2.26
2.24
1.20
$
$
$
2.10
2.07
0.84
$
$
$
$
99,195
1.90
1.90
–
$ 841,733
$ 826,957
$
813,008
Oklahoma
Kansas
Texas
Average Total:
154.0
358.8
9,114
9,962
2,140
3,400
166.3
379.8
10,615
9,965
2,127
3,300
164.2
370.1
11,036
9,970
2,114
–
–
2015 Fixed Charges
Sales Customers*
87%
55%
72%
73%
Average Annual Heating
Degree Days – Normal
3,317
4,860
1,785
–
Weather Normalization**
100%
100%
62%
89%
Market Value Per Share – Year-End Closing Price
$
50.17
$
41.22
Average Shares of Common Stock, Outstanding (thousands)
Basic
Diluted
52,578
53,254
52,364
52,946
52,319
52,319
* Prior to 2014, historical basic and diluted earnings per share for the periods presented were calculated based on the number
of shares distributed to ONEOK shareholders on separation plus any shares associated with fully vested stock awards that had
not been issued and considered outstanding as of the beginning of each period prior to the separation.
4
* Fixed percentage of total net margin on natural gas sales
** Percent of customers who are in jurisdictions with weather normalization adjustment mechanisms
5
Financial Overview
2015 Summary
We reported full-year 2015 net income of $119.0 million,
or $2.24 per diluted share, compared with $109.8 million,
or $2.07 per diluted share, in 2014; and full-year 2015
capital expenditures of $294.3 million, compared with
$297.1 million in 2014.
Our operating income was $239.1 million, compared
with $225.3 million in 2014, as net margin increased
by $14.7 million compared with last year.
Net margin increases in 2015 primarily refl ected new
rates in Oklahoma and Texas along with an increase in
our average residential customer count in these states.
We lowered operating costs in 2015, which were
$469.6 million, compared with $476.0 million in 2014,
Highlights
Earnings and Dividends
Net Income (thousands)
Earnings Per Share of Common Stock
Basic
Diluted
Dividends Per Share
Margin, Volumes and Weather
Net Margin (thousands)
Total Volumes Sold (Bcf)
Total Volumes Delivered (Bcf)
Actual Heating Degree Days
Normal Heating Degree Days
Customers and Employees
Average Number of Customers (thousands)
Total Employees
Common Stock
Signifi cant Scale
High Percentage of Residential Customers
83%
Residential
92%
Residential
16%
Commercial /
Industrial
1%
Other
Net Sales Margin
(Excludes transportation)
Customer Count
(Excludes transportation)
7%
Commercial /
Industrial
1%
Other
which primarily refl ects decreases in information technology
costs associated with our separation in 2014 from
ONEOK, Inc. We also benefi ted from a decrease in outside
services expenses, bad debt and fl eet-related expenses.
On January 19, 2016, the ONE Gas Board of Directors
increased the quarterly dividend by 5 cents per share to
35 cents per share, effective in the fi rst quarter 2016,
resulting in an annualized dividend of $1.40 per share.
Our average annual dividend growth rate is expected to
increase 8 to 10 percent between 2015 and 2020, with
a targeted dividend payout ratio of 55 to 65 percent of
net income, all subject to board of directors’ approval.
2015
2014
2013
$ 119,030
$ 109,790
$
$
$
2.26
2.24
1.20
$
$
$
2.10
2.07
0.84
$
$
$
$
99,195
1.90
1.90
–
$ 841,733
$ 826,957
$
813,008
Oklahoma
Kansas
Texas
Average Total:
154.0
358.8
9,114
9,962
2,140
3,400
166.3
379.8
10,615
9,965
2,127
3,300
164.2
370.1
11,036
9,970
2,114
–
–
2015 Fixed Charges
Sales Customers*
87%
55%
72%
73%
Average Annual Heating
Degree Days – Normal
3,317
4,860
1,785
–
Weather Normalization**
100%
100%
62%
89%
Market Value Per Share – Year-End Closing Price
$
50.17
$
41.22
Average Shares of Common Stock, Outstanding (thousands)
Basic
Diluted
52,578
53,254
52,364
52,946
52,319
52,319
* Prior to 2014, historical basic and diluted earnings per share for the periods presented were calculated based on the number
of shares distributed to ONEOK shareholders on separation plus any shares associated with fully vested stock awards that had
not been issued and considered outstanding as of the beginning of each period prior to the separation.
4
* Fixed percentage of total net margin on natural gas sales
** Percent of customers who are in jurisdictions with weather normalization adjustment mechanisms
5
Natural Gas
6
7
Beyond the Touchpoints
Natural gas touches every part of our daily lives. It is the better source of energy for heat, hot water
and cooking in homes and businesses in the U.S. In addition to its effi ciency, natural gas provides
a greater quality of life.
Natural gas not only fuels your home, it fuels your family by providing clean clothes, hot showers and
a warm home. In your kitchen, in your laundry room or on your back patio, natural gas delivers heat
and energy that fuels your family’s needs.
Using natural gas to fuel your home provides a sense of comfort, knowing you have chosen one of the
most effi cient energy options.
Natural Gas
6
7
Beyond the Touchpoints
Natural gas touches every part of our daily lives. It is the better source of energy for heat, hot water
and cooking in homes and businesses in the U.S. In addition to its effi ciency, natural gas provides
a greater quality of life.
Natural gas not only fuels your home, it fuels your family by providing clean clothes, hot showers and
a warm home. In your kitchen, in your laundry room or on your back patio, natural gas delivers heat
and energy that fuels your family’s needs.
Using natural gas to fuel your home provides a sense of comfort, knowing you have chosen one of the
most effi cient energy options.
Growth
Expanding Services to Fuel Tomorrow
As a 100-percent regulated natural gas utility, we are
committed to growth that aligns with our long-term
strategy. Our growth opportunities are a result of capital
investments related to the safety and reliability of our
existing system, and system growth related to the
economic and population growth in our service territories.
As a result of our commitment to enhance the safety,
integrity and reliability of our existing infrastructure, we
are making signifi cant investments in our system, which
we expect to further grow our rate base.
Many service territories continue to experience economic
growth, allowing us opportunities to invest in new service
lines and main line extensions, predominately in the
major metropolitan areas.
We believe the competitiveness of natural gas is
increasing relative to other energy alternatives, creating
new market opportunities for natural gas as an energy
source within our existing service territories.
This past year, we invested in growth in several
areas, including:
The Stillwater Energy Center
Oklahoma Natural Gas installed a fi ve-mile, 12-inch
pipeline to tie the new high-effi ciency, natural gas-fi red
power plant to an existing midstream transmission
pipeline, ultimately powering the 56-megawatt energy
center, which when in service in 2016 will provide
electricity for the Stillwater, Okla., community.
Pipeline Upgrades in Kansas
In 2015, Kansas Gas Service completed a new main
extension in Overland Park that will support future growth
in southern Johnson County, bringing much-needed
volume capacity to the area.
UTMB
Texas Gas Service completed construction on a new
four-mile, 8-inch natural gas distribution pipeline to the
University of Texas Medical Branch at Galveston (UTMB).
The project allowed the company to provide additional
natural gas service and energy capacity to UTMB,
Galveston’s largest employer.
Oklahoma Natural Gas completed a pipeline project to supply the
Stillwater Energy Center with effi cient natural gas.
System Integrity
A better tomorrow started companywide in 2015 with
an enhanced system integrity strategy to make us even
more effi cient and proactive in ensuring safe and
reliable natural gas service.
Our System Integrity department is benefi ting from
leadership focused on more effi cient and effective
processes. Implementation of enterprise-wide
technology has enabled us to evaluate assets and
projects using a consistent risk management
framework – a game changer for the way we plan
for work and capital expenditures.
In 2015, we were able to:
Create clear visibility within our organizational
structure by merging asset management and
engineering to form a new System Integrity
department;
Verify alignment of asset management processes
and integrity management programs;
Focus on an enterprise-wide, risk-based
approach to asset replacement; and
Continue to improve asset records and long-term
plans for system integrity improvements.
8
9
Employees near Sapulpa, Okla. insert a “pig” as part of procedures to
inspect a pipeline. Pigs are used to perform various maintenance tasks
and inspections on certain pipelines.
Growth
Expanding Services to Fuel Tomorrow
As a 100-percent regulated natural gas utility, we are
committed to growth that aligns with our long-term
strategy. Our growth opportunities are a result of capital
investments related to the safety and reliability of our
existing system, and system growth related to the
economic and population growth in our service territories.
As a result of our commitment to enhance the safety,
integrity and reliability of our existing infrastructure, we
are making signifi cant investments in our system, which
we expect to further grow our rate base.
Many service territories continue to experience economic
growth, allowing us opportunities to invest in new service
lines and main line extensions, predominately in the
major metropolitan areas.
We believe the competitiveness of natural gas is
increasing relative to other energy alternatives, creating
new market opportunities for natural gas as an energy
source within our existing service territories.
This past year, we invested in growth in several
areas, including:
The Stillwater Energy Center
Oklahoma Natural Gas installed a fi ve-mile, 12-inch
pipeline to tie the new high-effi ciency, natural gas-fi red
power plant to an existing midstream transmission
pipeline, ultimately powering the 56-megawatt energy
center, which when in service in 2016 will provide
electricity for the Stillwater, Okla., community.
Pipeline Upgrades in Kansas
In 2015, Kansas Gas Service completed a new main
extension in Overland Park that will support future growth
in southern Johnson County, bringing much-needed
volume capacity to the area.
UTMB
Texas Gas Service completed construction on a new
four-mile, 8-inch natural gas distribution pipeline to the
University of Texas Medical Branch at Galveston (UTMB).
The project allowed the company to provide additional
natural gas service and energy capacity to UTMB,
Galveston’s largest employer.
Oklahoma Natural Gas completed a pipeline project to supply the
Stillwater Energy Center with effi cient natural gas.
System Integrity
A better tomorrow started companywide in 2015 with
an enhanced system integrity strategy to make us even
more effi cient and proactive in ensuring safe and
reliable natural gas service.
Our System Integrity department is benefi ting from
leadership focused on more effi cient and effective
processes. Implementation of enterprise-wide
technology has enabled us to evaluate assets and
projects using a consistent risk management
framework – a game changer for the way we plan
for work and capital expenditures.
In 2015, we were able to:
Create clear visibility within our organizational
structure by merging asset management and
engineering to form a new System Integrity
department;
Verify alignment of asset management processes
and integrity management programs;
Focus on an enterprise-wide, risk-based
approach to asset replacement; and
Continue to improve asset records and long-term
plans for system integrity improvements.
8
9
Employees near Sapulpa, Okla. insert a “pig” as part of procedures to
inspect a pipeline. Pigs are used to perform various maintenance tasks
and inspections on certain pipelines.
Commitment to ZERO
Even a single accident is one too many.
Our “Zero Is Possible” perspective guides us when
it comes to safety. Zero injuries and incidents is our
target each and every day.
To work toward this goal in 2015, we continued to
focus on three particular safety initiatives that brought
meaningful results: Employees achieved a 10 percent
reduction from the previous year in the Total
Recordable Injury Rate AND a 7 percent reduction
in the Preventable Vehicle Incident Rate.
1. Since incorporating MoveSMART® into their day-to-
day work three years ago, employees have achieved
an overall reduction of 52 percent in sprain and
strain injuries.
By learning this method of body mechanics and
body positioning, employees can achieve maximum
strength and balance to avoid injury.
2. In 2015, employees performed more than 8,800
peer-to-peer observations through our Behavior-Based
Safety program.
Trained employees voluntarily go to fi eld locations
to observe other employees performing their job
duties. The result is constructive feedback on how
employees were working safely or how they may
have been putting themselves or others at risk.
The observers and the observed discuss ways to
replace at-risk behavior with safe behavior.
3. Implementation of the Smith System® driving
program has been instrumental in reducing motor
vehicle accidents companywide.
The Smith System is one of the best established
and most widely used defensive driving programs
for fl eet operations.
It keeps drivers engaged in their surroundings and
focused on the task at hand, which is safe driving.
Preventable Vehicle Incident Rate (PVIR)
was 1.88 incidents per million miles driven.
American Gas Association PVIR Quartile Data
4th Q.
3rd
2nd
1st
3.58
2.73
2.35
2.24
1.77
2.03
1.88
2009
2010
2011
2012
2013
2014
2015
Total Recordable Incident Rate (TRIR)
was 2.20 incidents per 200,000 work hours.
American Gas Association TRIR Quartile Data
6.34
4th Q.
5.36
3rd
2nd
1st
4.28
3.62
2.98
2.45
2.20
2009
2010
2011
2012
2013
2014
2015
The American Gas Association represents local
energy companies that deliver clean natural gas
throughout the U.S.
ONE Gas drivers log more than 30 million miles annually, so defensive driving is a must.
10%
percent reduction from the
previous year in the Total
Recordable Injury Rate.
8,800
peer-to-peer observations
through our Behavior-Based
Safety program.
7%
reduction in the Preventable
Vehicle Incident Rate.
52%
reduction in sprain
and strain injuries.
10
11
Commitment to ZERO
Even a single accident is one too many.
Our “Zero Is Possible” perspective guides us when
it comes to safety. Zero injuries and incidents is our
target each and every day.
To work toward this goal in 2015, we continued to
focus on three particular safety initiatives that brought
meaningful results: Employees achieved a 10 percent
reduction from the previous year in the Total
Recordable Injury Rate AND a 7 percent reduction
in the Preventable Vehicle Incident Rate.
1. Since incorporating MoveSMART® into their day-to-
day work three years ago, employees have achieved
an overall reduction of 52 percent in sprain and
strain injuries.
By learning this method of body mechanics and
body positioning, employees can achieve maximum
strength and balance to avoid injury.
2. In 2015, employees performed more than 8,800
peer-to-peer observations through our Behavior-Based
Safety program.
Trained employees voluntarily go to fi eld locations
to observe other employees performing their job
duties. The result is constructive feedback on how
employees were working safely or how they may
have been putting themselves or others at risk.
The observers and the observed discuss ways to
replace at-risk behavior with safe behavior.
3. Implementation of the Smith System® driving
program has been instrumental in reducing motor
vehicle accidents companywide.
The Smith System is one of the best established
and most widely used defensive driving programs
for fl eet operations.
It keeps drivers engaged in their surroundings and
focused on the task at hand, which is safe driving.
Preventable Vehicle Incident Rate (PVIR)
was 1.88 incidents per million miles driven.
American Gas Association PVIR Quartile Data
4th Q.
3rd
2nd
1st
3.58
2.73
2.35
2.24
1.77
2.03
1.88
2009
2010
2011
2012
2013
2014
2015
Total Recordable Incident Rate (TRIR)
was 2.20 incidents per 200,000 work hours.
American Gas Association TRIR Quartile Data
6.34
4th Q.
5.36
3rd
2nd
1st
4.28
3.62
2.98
2.45
2.20
2009
2010
2011
2012
2013
2014
2015
The American Gas Association represents local
energy companies that deliver clean natural gas
throughout the U.S.
ONE Gas drivers log more than 30 million miles annually, so defensive driving is a must.
10%
percent reduction from the
previous year in the Total
Recordable Injury Rate.
8,800
peer-to-peer observations
through our Behavior-Based
Safety program.
7%
reduction in the Preventable
Vehicle Incident Rate.
52%
reduction in sprain
and strain injuries.
10
11
In 2015, through our ONE Gas
Foundation, civic and corporate
contributions, we invested more than
$2.2 million
in communities where we serve.
Community Investment
ONE Gas recognizes that our employees, retirees and
board of directors support community organizations in the
areas where we live, work and operate, which underscores
the ONE Gas Foundation's guiding principles:
Optimize Impact
Give Hope
Strengthen Communities
As a company, we believe that better tomorrows
require a commitment to making communities better
today through charitable giving and volunteerism.
47
approved requests for grants
by the ONE Gas Foundation.
$40,000
to Habitat for Humanity.
199 Matching Grants awarded
totaling more than
$114,000.
2,026 employees, retirees and directors
pledged $743,000 to United Way
agencies in 2015, all matched dollar
for dollar totaling more than
$1.4 million.
26
public school foundation grants.
6,118
Employee Volunteer Hours
Habitat for Humanity Local Food Banks Meals on Wheels Special Olympics Boys & Girls Club
12
13
In 2015, through our ONE Gas
Foundation, civic and corporate
contributions, we invested more than
$2.2 million
in communities where we serve.
Community Investment
ONE Gas recognizes that our employees, retirees and
board of directors support community organizations in the
areas where we live, work and operate, which underscores
the ONE Gas Foundation's guiding principles:
Optimize Impact
Give Hope
Strengthen Communities
As a company, we believe that better tomorrows
require a commitment to making communities better
today through charitable giving and volunteerism.
47
approved requests for grants
by the ONE Gas Foundation.
$40,000
to Habitat for Humanity.
199 Matching Grants awarded
totaling more than
$114,000.
2,026 employees, retirees and directors
pledged $743,000 to United Way
agencies in 2015, all matched dollar
for dollar totaling more than
$1.4 million.
26
public school foundation grants.
6,118
Employee Volunteer Hours
Habitat for Humanity Local Food Banks Meals on Wheels Special Olympics Boys & Girls Club
12
13
A Cleaner,
More Efficient Fuel
A Better Tomorrow for All
We understand we have a responsibility to all of our
stakeholders to operate safely, effi ciently and
environmentally responsibly. We plan to meet this
expectation by focusing on our mission while keeping
our values intact.
According to the American Gas Association, a study
published in Environmental Science & Technology led by
a team from Washington State University found that
emission estimates from local natural gas distribution
systems in cities and towns throughout the U.S. have
decreased in the past 20 years to levels 36 to 70 percent
lower than the 2011 U.S. Environmental Protection
Agency inventory.
The study concludes that as little as 0.1 percent of the
natural gas delivered nationwide is emitted from local
distribution systems.
ONE Gas is committed to operating in an environmentally
responsible manner. We are accountable for providing
services that are aligned with efforts to reduce emissions.
In 2015, we retired or replaced approximately 425 miles
of distribution and transmission facilities, which will result
in decreased emissions of methane.
Commitment to the Methane
Challenge Program
In 2015, ONE Gas actively participated in the
development of the U.S. Environmental Protection
Agency (EPA) Natural Gas STAR Methane Challenge
Program to voluntarily reduce greenhouse gas emissions.
The program is a flexible, voluntary partnership with
natural gas companies and the EPA to promote and
track the reduction of methane emissions beyond what
is federally required.
The program requires a signed commitment to reduce
emissions through a Best Management Practice
Commitment, a companywide implementation of
best practices focused on reducing emissions from
key sources.
Energy Efficiency
In 2015, our Energy Efficiency Program in Oklahoma
and the Austin Conservation Program in Texas issued
more than 67,800 rebates combined – totaling
approximately $11.15 million in energy-efficiency
customer rebates on natural gas appliances and energy-
efficient home improvements.
Wildlife and Endangered
Species Preservation
We are committed to working to resolve any potential
issues with endangered species, migratory birds, cultural
or historical assets and government agency permitting
requirements. We not only follow the regulations but also
work with our subcontractors and consultants to do
the same.
14
15
A Cleaner,
More Efficient Fuel
A Better Tomorrow for All
We understand we have a responsibility to all of our
stakeholders to operate safely, effi ciently and
environmentally responsibly. We plan to meet this
expectation by focusing on our mission while keeping
our values intact.
According to the American Gas Association, a study
published in Environmental Science & Technology led by
a team from Washington State University found that
emission estimates from local natural gas distribution
systems in cities and towns throughout the U.S. have
decreased in the past 20 years to levels 36 to 70 percent
lower than the 2011 U.S. Environmental Protection
Agency inventory.
The study concludes that as little as 0.1 percent of the
natural gas delivered nationwide is emitted from local
distribution systems.
ONE Gas is committed to operating in an environmentally
responsible manner. We are accountable for providing
services that are aligned with efforts to reduce emissions.
In 2015, we retired or replaced approximately 425 miles
of distribution and transmission facilities, which will result
in decreased emissions of methane.
Commitment to the Methane
Challenge Program
In 2015, ONE Gas actively participated in the
development of the U.S. Environmental Protection
Agency (EPA) Natural Gas STAR Methane Challenge
Program to voluntarily reduce greenhouse gas emissions.
The program is a flexible, voluntary partnership with
natural gas companies and the EPA to promote and
track the reduction of methane emissions beyond what
is federally required.
The program requires a signed commitment to reduce
emissions through a Best Management Practice
Commitment, a companywide implementation of
best practices focused on reducing emissions from
key sources.
Energy Efficiency
In 2015, our Energy Efficiency Program in Oklahoma
and the Austin Conservation Program in Texas issued
more than 67,800 rebates combined – totaling
approximately $11.15 million in energy-efficiency
customer rebates on natural gas appliances and energy-
efficient home improvements.
Wildlife and Endangered
Species Preservation
We are committed to working to resolve any potential
issues with endangered species, migratory birds, cultural
or historical assets and government agency permitting
requirements. We not only follow the regulations but also
work with our subcontractors and consultants to do
the same.
14
15
Forward-looking Statements
Statements contained in this annual report that include company
expectations or predictions should be considered forward-looking
statements that are covered by the safe harbor provisions of the
Securities Act of 1933 and the Securities Exchange Act of 1934,
as amended.
It is important to note that the actual results could differ materially
from those projected in such forward-looking statements.
For additional information that could cause actual results to differ
materially from such forward-looking statements, refer to ONE Gas’
Securities and Exchange Commission fi lings.
Shareholder Information
Wells Fargo Shareowner Services
P.O. Box 64874
St. Paul, MN 55164-0856
P: 1-855-217-6403
P: (Outside U.S.) 1-651-450-4064
TDD number: 1-651-450-4144
www.shareowneronline.com
Direct Stock Purchase & Dividend Reinvestment Plan
ONE Gas’ Direct Stock Purchase and Dividend Reinvestment Plan
provides new investors and current shareholders a convenient way to
purchase ONE Gas common stock without paying processing fees or
service charges and to reinvest cash dividends. For more information
or to enroll in the plan, call Wells Fargo at 1-855-217-6403. The
Prospectus is also available at www.onegas.com.
Annual Meeting Details
First Place Tower
15 East Fifth Street
Tulsa, OK 74103
May 26, 2016 – 9 a.m. CDT
Auditors
PricewaterhouseCoopers LLP
Two Warren Place
6120 South Yale Avenue, Suite 1850
Tulsa, OK 74136
Corporate Headquarters
First Place Tower
15 East Fifth Street
Tulsa, OK 74103
Credit Ratings
Moody’s: A2 (Stable)
Standard & Poor’s: A- (Stable)
Investor Relations
ONE Gas Investor Relations
Department
P.O. Box 21049
Tulsa, OK 74121
P: 1-855-496-0200
E: IR@onegas.com
Andrew Ziola, Vice President,
Investor Relations and Public Affairs
P: 1-918-947-7163
E: andrew.ziola@onegas.com
Board of Directors
From left to right:
Douglas H. Yaeger
Retired Chairman, President and Chief Executive Offi cer, Laclede Gas Company
John W. Gibson
Chairman, ONE Gas, Inc.
Eduardo A. Rodriguez
President, Strategic Communications Consulting Group
Robert B. Evans
Retired President and Chief Executive Offi cer, Duke Energy Americas
Pattye L. Moore
Chairman, Red Robin Gourmet Burgers
Pierce H. Norton II
President and Chief Executive Offi cer, ONE Gas, Inc.
Michael G. Hutchinson
Retired Partner, Deloitte & Touche
Executive Team
Joseph L. McCormick, 56
Senior Vice President, General
Counsel and Assistant Secretary
Caron A. Lawhorn, 55
Senior Vice President, Commercial
Robert S. McAnnally, 52
Senior Vice President, Operations
Mark A. Bender, 51
Senior Vice President,
Administration,
Chief Information Offi cer
Andrew J. Ziola, 46
Vice President,
Investor Relations and
Public Aff airs
Pierce H. Norton II, 56
President and Chief
Executive Offi cer
Curtis L. Dinan, 48
Senior Vice President,
Chief Financial Offi cer
and Treasurer
16
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015.
OR
__ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.
Commission file number 001-36108
ONE Gas, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma
(State or other jurisdiction of
incorporation or organization)
46-3561936
(I.R.S. Employer Identification No.)
15 East Fifth Street, Tulsa, OK
(Address of principal executive offices)
74103
(Zip Code)
Registrant’s telephone number, including area code (918) 947-7000
Securities registered pursuant to Section 12(b) of the Act:
Common stock, par value of $0.01
(Title of each class)
New York Stock Exchange
(Name of each exchange on which registered)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No__
Securities registered pursuant to Section 12(g) of the Act: None
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 X
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes X No __
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes X No _
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) 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. X
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one) Large accelerated
filer X Accelerated filer __
Smaller reporting company __
Non-accelerated filer __
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes__ No X
The aggregate market value of the equity securities held by nonaffiliates based on the closing trade price of the registrant on June 30, 2015, was $2.1 billion.
On February 5, 2016, we had 52,292,154 shares of common stock outstanding.
Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 26, 2016, are
incorporated by reference in Part III.
DOCUMENTS INCORPORATED BY REFERENCE:
ONE Gas, Inc.
2015 ANNUAL REPORT
Page No.
Part I.
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Part II.
Item 5.
Item 6.
Item 7.
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
Part III.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Part IV.
Item 15.
Signatures
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits, Financial Statement Schedules
5
13
23
23
24
24
25
27
27
43
45
82
82
82
82
83
83
84
84
85
89
As used in this Annual Report, references to “we,” “our,” “us” or the “company” refer to ONE Gas, Inc., an Oklahoma
corporation, and its predecessors and subsidiary, unless the context indicates otherwise.
2
GLOSSARY
The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
ACA
AFUDC
Annual Report
ATSR
Bcf
Bcf/d
CERCLA
CFTC
Clean Air Act
Clean Water Act
Code
COG
COGR
COSA
DOT
Dth
EPA
EPARR
EPS
EPSA
Exchange Act
FERC
GAAP
GRIP
GSRS
Heating Degree Day or HDD
IFRS
IRS
IRS Ruling
KCC
KDHE
LDCs
LIBOR
Moody’s
MMcf
NYSE
OCC
ONE Gas
ONE Gas Credit Agreement
ONE Gas Predecessor
ONEOK
ONEOK Partners
OSHA
PBRC
PGA
Annual Cost Adjustment
Allowance for funds used during construction
Annual Report on Form 10-K for the year ended December 31, 2015
Ad Valorem Tax Surcharge Rider
Billion cubic feet
Billion cubic feet per day
Federal Comprehensive Environmental Response, Compensation and Liability Act
of 1980, as amended
Commodities Futures Trading Commission
Federal Clean Air Act, as amended
Federal Water Pollution Control Amendments of 1972, as amended
Internal Revenue Code of 1986, as amended
Cost of gas
Cost of gas rider
Cost-of-Service Adjustment
United States Department of Transportation
Dekatherm
United States Environmental Protection Agency
El Paso Annual Rate Review
Earnings per share
El Paso Service Area
Securities Exchange Act of 1934, as amended
Federal Energy Regulatory Commission
Accounting principles generally accepted in the United States of America
Texas Gas Reliability Infrastructure Program
Gas System Reliability Surcharge
A measure designed to reflect the demand for energy needed for heating based on
the extent to which the daily average temperature falls below a reference
temperature for which no heating is required, usually 65 degrees Fahrenheit
International Financial Reporting Standards
U.S. Internal Revenue Service
Private Letter Ruling from IRS
Kansas Corporation Commission
Kansas Department of Health and Environment
Local distribution companies
London Interbank Offered Rate
Moody’s Investors Service, Inc.
Million cubic feet
New York Stock Exchange
Oklahoma Corporation Commission
ONE Gas, Inc.
ONE Gas’ $700 million revolving credit agreement, which expires in January
2019
ONE Gas’ predecessor for accounting purposes that consists of the business
attributable to ONEOK’s natural gas distribution segment that was transferred to
ONE Gas in connection with its separation from ONEOK
ONEOK, Inc. and its subsidiaries
ONEOK Partners, L.P. and its subsidiaries
Occupational Safety and Health Administration
Performance-Based Rate Change
Purchased Gas Adjustment
3
PHMSA
Pipeline Safety Improvement Act
Pipeline Safety, Regulatory Certainty and
Job Creation Act
ROE
RRC
S&P
SEC
Securities Act
Separation and Distribution Agreement
TAC
Tax Matters Agreement
Transition Services Agreement
WNA
XBRL
United States Department of Transportation Pipeline and Hazardous Materials
Safety Administration
Pipeline Safety Improvement Act of 2002, as amended
Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended
Return on equity calculated consistent with utility ratemaking principles in each
jurisdiction in which we operate
Railroad Commission of Texas
Standard and Poor’s Rating Services
Securities and Exchange Commission
Securities Act of 1933, as amended
Separation and Distribution Agreement dated January 14, 2014, between ONEOK
and ONE Gas
Temperature Adjustment Clause
Tax Matters Agreement dated January 14, 2014, between ONEOK and ONE Gas
Transition Services Agreement dated January 14, 2014, between ONEOK
and ONE Gas
Weather normalization adjustments
eXtensible Business Reporting Language
The statements in this Annual Report that are not historical information, including statements concerning plans and objectives
of management for future operations, economic performance or related assumptions, are forward-looking statements.
Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,”
“believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and
other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on
reasonable assumptions, we can give no assurance that such expectations and assumptions will be achieved. Important factors
that could cause actual results to differ materially from those in the forward-looking statements are described under Part I,
Item 1A, “Risk Factors,” and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of
Operation and “Forward-Looking Statements,” in this Annual Report.
4
ITEM 1.
BUSINESS
SEPARATION FROM ONEOK, INC.
PART I
On January 8, 2014, ONEOK’s board of directors approved the distribution of all the shares of our common stock to holders of
ONEOK common stock.
In order for ONEOK to effect the distribution, we requested, and the SEC declared effective, our Registration Statement on
Form 10 on January 10, 2014. ONEOK transferred all of the assets and liabilities primarily related to its natural gas
distribution business to us. Assets and liabilities included accounts receivable and payable, natural gas in storage, regulatory
assets and liabilities, pipeline and other natural gas distribution facilities, customer deposits, employee-related assets and
liabilities, including amounts attributable to pension and other postemployment benefits, tax-related assets and liabilities and
other assets and liabilities primarily associated with providing natural gas distribution service in Oklahoma, Kansas and Texas.
Cash and certain corporate assets, such as office space in the corporate headquarters and certain IT hardware and software,
were not transferred to us; however, the Transition Services Agreement between ONEOK and us provided temporary access to
such corporate assets as necessary to operate our business prior to obtaining applicable corporate assets on our own.
Immediately prior to the contribution of the natural gas distribution business to us, ONEOK contributed to the capital of the
natural gas distribution business all of the amounts outstanding on the natural gas distribution business’s short-term note
payable to and long-term line of credit with ONEOK. We received approximately $1.19 billion of cash from a private
placement of senior notes (which were later exchanged for registered notes), then used a portion of those proceeds to fund a
cash payment of approximately $1.13 billion to ONEOK. On January 31, 2014, ONEOK distributed one share of our common
stock for every four shares of ONEOK common stock held by ONEOK shareholders of record as of the close of business on
January 21, 2014, the record date of the distribution. At the close of business on January 31, 2014, ONE Gas became an
independent, publicly traded company as a result of the distribution. Our common stock began trading “regular-way” under the
ticker symbol “OGS” on the NYSE on February 3, 2014. ONEOK did not retain any ownership interest in our company.
OUR BUSINESS
We are an independent, publicly traded, 100 percent regulated natural gas distribution utility. We are one of the largest natural
gas utilities in the United States. We are an Oklahoma corporation and are the successor to the company founded in 1906 as
Oklahoma Natural Gas Company. We are the largest natural gas distributor in Oklahoma and Kansas and the third largest in
Texas, providing service as a regulated public utility. We serve residential, commercial and industrial, transportation and
wholesale and public authority customers in all three states. Our largest natural gas distribution markets in terms of customers
are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita and Topeka, Kansas; and Austin and El Paso, Texas. Our three
divisions, Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, distribute natural gas as public utilities to
approximately 88 percent, 72 percent and 14 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas,
respectively.
Prior to our separation from ONEOK, our financial statements were derived from ONEOK’s financial statements, which
included its natural gas distribution business as if we, for accounting purposes, had been a separate company for all periods
presented. The assets and liabilities in the financial statements have been reflected on a historical basis. The financial
statements for periods prior to the separation also include expense allocations for certain corporate functions historically
performed by ONEOK, including allocations of general corporate expenses related to executive oversight, accounting, treasury,
tax, legal, information technology and other services. We believe our assumptions underlying the financial statements,
including the assumptions regarding the allocation of general corporate expenses from ONEOK, are reasonable. However, the
financial statements may not include all of the actual expenses that would have been incurred by us and may not reflect our
results of operations, financial position and cash flows had we been a separate publicly traded company during the periods
presented prior to the separation.
5
OUR STRATEGY
Our business strategy is focused on operating our systems in a safe, reliable and environmentally responsible manner, growing
our business strategically, while delivering quality customer service to our customers. Over time, we believe this will enable us
to generate a competitive total return for our shareholders and maintain our financial stability, leading to our strategic goals of
zero harm and a fair return. We intend to accomplish our objectives by executing on the strategies listed below:
•
Focus on Safety, Reliability and Compliance - We are committed to pursuing a zero-incident safety and compliance
culture through programs, procedures, policies, guidelines and other internal controls designed to mitigate risk and
incidents that may harm our employees, contractors, customers, the public or the environment. In addition, a
significant portion of our capital spending is focused on the safety, reliability and efficiency of our natural gas
distribution system. We are committed to compliance with all federal, state and local laws and regulations.
• High-performing Workforce - The foundation of our company consists of our employees. We are committed to
attracting, retaining and developing a high-performing workforce where every employee understands that they can and
do make a difference. We embrace and promote inclusion, diversity and collaboration. We expect a high standard of
performance from our employees. We encourage our workforce to measure their productivity and be accountable for
the best work possible. Each day that we do our best to safely and efficiently meet the needs of our customers is a day
that leads to individual success and, ultimately, the success of the company.
•
Increase Our Achieved ROE - We continually seek to improve our achieved ROE through improved operational
performance and regulatory mechanisms. The difference between our achieved and allowed ROE is related primarily
to regulatory lag. We make investments that increase our rate base and we incur increases in our costs that are above
the amounts reflected in the rates we charge for our service.
We have several initiatives underway to improve our operational performance. These initiatives include leveraging
and implementing technology that is expected to result in increased efficiency, thereby helping reduce the rate of
increase in operating expenses.
Our focus on our credit metrics and maintaining a balanced approach to capital management are significant objectives
in providing reasonable rates to customers while also providing a fair return to shareholders. We believe that
maintaining an investment-grade credit rating is prudent for our business as we seek to access the capital markets to
finance capital investments. As a 100 percent regulated utility, we intend to maintain strong credit metrics while we
pursue a balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe
will be competitive with our peer group.
• Advocate Constructive Relationships with Key Stakeholders - We plan to continue our constructive, transparent
relationships with our key stakeholders, which include our customers, employees, investors and regulators. Our
strategy includes seeking outcomes in future rate proceedings that provide a fair return on our infrastructure
investments, while also meeting the needs of our customers through safe, reliable and efficient service.
•
Identify and Pursue Growth Opportunities - Our growth opportunities are a result of capital investments related to
safety and reliability of our existing system, and system growth related to the economic and population growth in our
service territories. As a result of our commitment to enhance the integrity, reliability and safety of our existing
infrastructure, we are making significant investments in our existing system, which we expect to further grow our rate
base. In addition, as our service territories continue to experience economic growth, we expect to grow our rate base
through capital investments in new service lines and main line extensions, predominately in the major metropolitan
areas.
We believe that the competitiveness of natural gas is increasing, creating new market opportunities for natural gas as
an energy source within our existing service territories.
We remain committed to maintaining our status as a 100 percent regulated company, but will evaluate strategic
acquisition opportunities that fall within that guideline based on our disciplined financial and operating approach,
while weighing these alternatives against future investment opportunities with respect to our existing rate base.
6
REGULATORY OVERVIEW
We are subject to the regulations and oversight of the state and local regulatory authorities of the territories in which we
operate. Rates and charges for natural gas distribution services are established by the OCC for Oklahoma Natural Gas and by
the KCC for Kansas Gas Service. Texas Gas Service is subject to regulatory oversight by the various municipalities that it
serves, which have primary jurisdiction in their respective areas. Rates in unincorporated areas of Texas and all appellate
matters are subject to regulatory oversight by the RRC. These regulatory authorities have the responsibility of ensuring that the
utilities in their jurisdictions provide safe and reliable service at a reasonable cost, while providing utility companies the
opportunity to earn a fair and reasonable return on their investments.
Generally, our rates and charges are established in rate case proceedings. Regulatory authorities may also approve mechanisms
that allow for adjustments for specific costs or investments made between rate cases. Due to the nature of the regulatory
process, there is an inherent lag between the time that we make investments or incur additional costs and the setting of new
rates and/or charges to recover those investments or costs. Additionally, we are not allowed recovery of certain costs we incur.
The delay between the time investments are made or increases in costs are incurred and the time that our rates are adjusted to
reflect these investments and costs is referred to as regulatory lag.
The following provides additional detail on the regulatory mechanisms in the jurisdictions we serve.
Oklahoma - Oklahoma Natural Gas currently operates under a PBRC mechanism, which provides for streamlined annual rate
reviews between rate cases and includes adjustments for incremental capital investment and allowed expenses. Under this
mechanism, we have an allowed ROE of between 9 percent and 10 percent. If our achieved ROE is below 9 percent, our base
rates are increased upon OCC approval to an amount necessary to restore the ROE to 9.5 percent. If our achieved ROE
exceeds 10 percent, the portion of the earnings above 10 percent is shared with our customers, who receive the benefit of 75
percent of the earnings above 10 percent. We receive the benefit of the remaining 25 percent. Oklahoma Natural Gas is
required to file a rate case on or before June 20, 2021, based on a test year consisting of the twelve months ending December
31, 2020. Other regulatory mechanisms in Oklahoma include the following:
•
PGA Clause - Oklahoma Natural Gas’ commodity, transportation, storage and gas purchase operations and
maintenance costs are passed through to its sales customers without markup via the PGA. Any costs associated with
natural gas that is lost, used or unaccounted for in operations and the fuel-related portion of bad debts are also
recovered through the PGA.
• TAC - The TAC is designed to reduce the delivery charge component of customers’ bills for the additional volumes
used when the actual heating degree days exceed the normalized heating degree days and to increase the delivery
charge component of customers’ bills for volumes not used when actual heating degree days are less than the normal
heating degree days. The TAC is in effect from November through April.
• Energy Efficiency Programs - Oklahoma Natural Gas has an Energy-Efficiency Program, available to all of its sales
customers. The costs associated with these programs and an incentive to offer these programs are recovered through a
monthly surcharge on customer bills. Oklahoma Natural Gas collects approximately $11.5 million each year from
sales customers to fund the program, which provides appliance rebates, education and heating system check-ups to
promote energy efficiency.
• Rate Design for Residential Customers - Oklahoma Natural Gas is authorized to utilize a rate structure with two
choices. Rate Choice “A” is designed for customers whose annual normalized volume is less than 50 Dth. The tariff
for these customers contains both a fixed monthly service charge and a per Dth delivery fee. Although a portion of the
net margin for customers in Rate Choice “A” is dependent on usage, these customers use relatively small quantities of
natural gas and therefore the net margin that is dependent on usage is not significant. The fixed monthly residential
customer charge for Oklahoma Natural Gas is $16.43, with a delivery fee of $4.1143 per Dth for Rate Choice “A”
customers. Rate Choice “B” is designed for customers whose annual normalized volume is 50 Dth or greater. The
tariff for these customers contains only a fixed monthly service charge of $33.57. At December 31, 2015, 71 percent of
Oklahoma Natural Gas’ residential customers are on Rate Choice “B.”
• Rate Design for Commercial and Industrial Customers - Oklahoma Natural Gas is authorized to utilize a rate structure
with two different rate choices for its Small Commercial and Industrial, or SCI, customers. Rate Choice “A” is
designed for SCI customers whose annual normalized volume is less than 40 Dth. The tariff for these customers
contains both a fixed monthly service charge of $20.55 and a delivery fee of $4.5599 per Dth. Rate Choice “B” is
designed for SCI customers whose annual normalized volume is 40 Dth or greater but less than 150 Dth. The tariff for
these customers contains only a fixed monthly service charge of $35.75. All of Oklahoma Natural Gas’ Large
Commercial and Industrial, or LCI, customers, whose annual volume is 150 Dth or greater, but less than 5,000 Dth,
are on a fixed monthly service charge of $93.22. At December 31, 2015, 75 percent of Oklahoma Natural Gas’
commercial and industrial customers are on either SCI Rate Choice “B” or LCI.
7
• Compressed Natural Gas Rebate Program - The CNG Rebate Program is designed to promote and support the CNG
market in the state of Oklahoma by offering rebates to Oklahoma residents who purchase dedicated and bi-fueled
natural gas vehicles or install residential CNG fueling stations. The rebates are funded by a $0.25 per gasoline gallon
equivalent surcharge that Oklahoma Natural Gas is authorized to collect on fuel purchased from a CNG dispenser
owned by Oklahoma Natural Gas. Collections from the surcharge to fund the program were not material in 2015.
For the year ended December 31, 2015, approximately 87 percent of Oklahoma Natural Gas’ net margin from its sales
customers was recovered from fixed charges.
Kansas - Kansas Gas Service operates under a traditional regulatory framework, whereby periodic rate cases are filed with the
KCC as needed to increase base rates to give Kansas Gas Service the opportunity to earn its authorized ROE. Other regulatory
mechanisms in Kansas include the following:
• COGR and ACA - These mechanisms allow Kansas Gas Service to recover the actual cost of the natural gas it sells to
its customers. The COGR includes a monthly estimate of the cost Kansas Gas Service incurs in transporting, storing
and purchasing natural gas supply for its sales customers, the ACA and other charges and credits. The ACA is an
annual component of the COGR that compares the cost of gas recovered through the COGR for the preceding year
with the actual natural gas supply costs and the fuel-related portion of bad debts for the same period. Any over- or
under-recovery is reflected in the subsequent year’s COGR.
• WNA Clause - This mechanism allows Kansas Gas Service to accrue the variation in net margin due to abnormal
weather occurring from November through March. WNA is designed to reduce the delivery charge component of
customers’ bills for the additional volumes used when the actual heating degree days exceed the normalized heating
degree days and to increase the delivery charge component of customers’ bills for the reduction in volumes used when
actual heating degrees days are less than the normal heating degree days. Once a year, the amount of the adjustment is
determined and is then applied to customers’ bills over the subsequent 12-month period.
• ATSR - This rider allows Kansas Gas Service to recover the difference each year between the property tax costs
included in its base rates and its actual property tax costs incurred without having to file a rate case. The amount of
the adjustment is determined annually and recovered over the subsequent 12 months as a change in the delivery-
charge component of customers’ bills.
Pension and Other Postemployment Benefits Trackers - These trackers allow Kansas Gas Service to track and defer
for recovery in its next rate case the difference between the pension and other postemployment benefit costs included
in base rates and actual expense as determined in accordance with GAAP.
•
• GSRS - This surcharge allows Kansas Gas Service to file for a rate adjustment providing a recovery of and return on
qualifying infrastructure investments, such as expenditures necessary to meet state and federal pipeline safety
requirements and government-required relocation projects incurred, each year between rate case filings. However, rate
adjustment filings cannot increase a monthly charge more than $0.40 per residential customer over the most recent
GSRS filing. After five annual filings, Kansas Gas Service is required to file a rate case or cease collection of the
surcharge.
The fixed monthly residential customer charge for Kansas Gas Service is $15.35. For the year ended December 31, 2015,
approximately 55 percent of Kansas Gas Service’s net margin from its sales customers was recovered from fixed charges.
Kansas experiences the highest heating degree days of all of our service territories, which brings a level of stability to net
margin even though a significant portion is based on usage.
Texas - Texas Gas Service has grouped its customers into 10 service areas. These service areas are further divided into the
incorporated cities and the unincorporated areas, referred to as the environs. The incorporated cities in the service areas have
original jurisdiction, with the RRC having appellate authority, and the RRC has original jurisdiction for the environs. Periodic
rate cases are filed with the cities or the RRC, as needed, to give Texas Gas Service the opportunity to earn its authorized ROE.
Other regulatory mechanisms and constructs in Texas include the following:
• GRIP Statute - For the incorporated cities in three service areas and the environs for four service areas, comprising 44
percent of Texas Gas Service’s customers, Texas Gas Service makes an annual filing under the GRIP statute, which
allows it to recover taxes and depreciation and to earn a return on the annual net increase in investment for the service
area. After five annual GRIP filings, Texas Gas Service is required to file a full rate case. A full rate case may be filed
at shorter intervals if desired by either Texas Gas Service or the regulator.
• COSA Filings - In six service areas, comprising 17 percent of its customers, Texas Gas Service makes an annual
COSA filing for the incorporated cities. COSA tariffs permit Texas Gas Service to recover return, taxes and
depreciation on the annual increases in net investment, as well as annual increases or decreases in certain expenses and
8
revenues. Five of the COSAs have a cap of 3.5 percent to 5 percent on all or a portion of the increase. A full rate case
may be filed when desired by Texas Gas Service or the regulator, but is not required.
• EPARR Filings - In the EPSA, comprising 35 percent of its customers, Texas Gas Service makes an annual rate review
filing for the incorporated cities. The annual rate review tariff permits Texas Gas Service to recover return, taxes and
depreciation on the annual increases in net investment, as well as annual increases or decreases in certain expenses and
revenues. There is no cap on the amount of the increase, but the request is subject to review and possible adjustment
by the regulator. Upon notice, a full rate case may be filed by Texas Gas Service or the regulator, but is not required.
In November 2015, Texas Gas Service notified the cities in the EPSA that it would be filing a full rate case in 2016.
• WNA Clause - Texas Gas Service employs WNA clauses in eight of its service areas, comprising 62 percent of its
customers. In one of the service areas without WNA, which comprises 38 percent of its customers, Texas Gas Service
recovers 88 percent of its delivery charge from fixed charges, making revenues in this service area less weather
sensitive. WNA is designed to reduce the delivery charge component of customers’ bills for the additional volumes
used when the actual heating degree days exceed the normalized heating degree days and to increase the margin
component of customers’ bills for the reduction in volumes used when actual heating degree days are less than the
normal heating degree days. The WNA is in effect from September through May.
• COG Clause - In all service areas, Texas Gas Service recovers 100 percent of its gas costs, including interest on
natural gas in storage and the natural gas cost component of bad debts, via a COG mechanism, subject to a limitation
of 5 percent on lost-and-unaccounted-for natural gas. The COG is reconciled annually to compare the gas costs
recovered through the COG with the actual natural gas supply costs. Any over- or under-recovery is refunded or
recovered, as applicable, in the subsequent year.
Pension and Other Postemployment Benefits - Texas Gas Service is authorized by statute to defer pension and other
postemployment benefit costs that exceed the amount recovered in base rates, and to seek recovery of the deferred
costs in a future rate case.
Pipeline-Integrity Testing Riders - Texas Gas Service recovers approximately 90 percent of its pipeline-integrity
testing expenses via riders, COSAs and the EPARR filing, with the remainder included in base rates.
Safety-Related Plant Replacements - Texas Gas Service is authorized by RRC rule to defer interest cost, taxes and
depreciation expense on safety-related plant replacements from the time the replacements are in service until the plant
is reflected in base rates, and to seek recovery of those accrued amounts in a future rate proceeding.
•
•
•
• Energy Conservation Program - Texas Gas Service has an Energy Conservation Program in its Central Texas service
area, comprising 34 percent of total customers. Texas Gas Service collects approximately $3 million per year from
customers to fund the program, which provides energy audits, weatherization and appliance rebates to promote energy
conservation.
The average fixed monthly residential customer charge for Texas Gas Service is $15.41, and for the year ended December 31,
2015, approximately 72 percent of Texas Gas Service’s net margin from its sales customers was recovered from fixed charges.
MARKET CONDITIONS AND SEASONALITY
Supply - We purchased 157 Bcf and 180 Bcf of natural gas supply in 2015 and 2014, respectively. The decrease in 2015
resulted primarily from lower supply requirements due to warmer temperatures as compared with 2014. Our natural gas supply
portfolio consists of long-term, seasonal and short-term contracts from a diverse group of suppliers. We award these contracts
through competitive-bidding processes to ensure reliable and competitively priced natural gas supply. We acquire our natural
gas supply from natural gas processors, marketers and producers.
An objective of our supply-sourcing strategy is to provide value to our customers through reliable, competitively priced and
flexible natural gas supply and transportation from multiple production areas and suppliers. This strategy is designed to
mitigate the impact on our supply from physical interruption, financial difficulties of a single supplier, natural disasters and
other unforeseen force majeure events, as well as to ensure these resources are reliable and flexible to meet the variations of
customer demands.
We do not anticipate problems with securing natural gas supply to satisfy customer demand; however, if supply shortages were
to occur, we have curtailment tariff provisions in place that allow us to reduce or discontinue natural gas service to large
industrial users and to request that residential and commercial customers reduce their natural gas requirements to an amount
essential for public health and safety. In addition, during times of critical supply disruptions, curtailments of deliveries to
customers with firm contracts may be made in accordance with guidelines established by appropriate federal, state and local
regulatory agencies.
9
Natural gas supply requirements are affected by weather conditions. In addition, economic conditions impact the requirements
of our commercial and industrial customers. Natural gas usage per residential customer may decline as customers change their
consumption patterns in response to a variety of factors, including:
• more volatile and higher natural gas prices;
•
customers’ improving the energy efficiency of existing homes by replacing doors and windows, adding insulation, and
replacing appliances with more efficient appliances;
• more energy-efficient construction; and
•
fuel switching from natural gas to electricity.
In each jurisdiction in which we operate, changes in customer-usage profiles are considered in the periodic redesign of our
rates.
As of December 31, 2015, we had 50.4 Bcf of natural gas storage capacity under lease with remaining terms ranging from one
to ten years and maximum allowable daily withdrawal capacity of approximately 1.3 Bcf. This storage capacity allows us to
purchase natural gas during the off-peak season and store it for use in the winter periods. This storage is also needed to assure
the reliability of gas deliveries during peak demands for natural gas. Approximately 25 percent of our winter natural gas supply
needs for our sales customers is expected to be supplied from storage.
In managing our natural gas supply portfolios, we partially mitigate price volatility using a combination of financial derivatives
and natural gas in storage. We have natural gas financial hedging programs that have been authorized by the regulatory
authorities in each state in which we do business. We do not utilize financial derivatives for speculative purposes, nor do we
have trading operations associated with our business.
Demand - See discussion below under “Seasonality,” “Competition” and “Compressed Natural Gas” for factors affecting
demand for our services.
Seasonality - Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural
gas requirements are for heating. Accordingly, the volume of natural gas sales is higher normally during the months of
November through March than in other months of the year. The impact on our margins resulting from weather temperatures
that are above or below normal is offset partially through our TAC and WNA mechanisms. See discussion above under
“Regulatory Overview.”
Competition - We encounter competition based on customers’ preference for natural gas, compared with other energy
alternatives and their comparative prices. We compete to supply energy for space and water heating, cooking, clothes drying
and other general energy needs. Significant energy usage competition occurs between natural gas and electricity in the
residential and small commercial markets. Customers and builders typically make the decision on the type of equipment, and
therefore the energy source, at initial installation, generally locking in the chosen energy source for the life of the equipment.
Changes in the competitive position of natural gas relative to electricity and other energy alternatives have the potential to
cause a decline in consumption of natural gas or in the number of natural gas customers.
The Department of Energy issued a statement of policy that it will use full fuel-cycle measures of energy use and emissions
when evaluating energy-conservation standards for appliances. In addition, the EPA has determined that source energy is the
most equitable unit for evaluating energy consumption. Assessing energy efficiency in terms of a full fuel-cycle or source-
energy analysis, which takes all energy use into account, including transmission, delivery and production losses, in addition to
energy consumed at the site, highlights the high overall efficiency of natural gas in residential and commercial uses compared
with electricity.
10
The below table contains data related to the cost of our delivered gas relative to electricity based on current market conditions:
Natural Gas vs. Electricity
Oklahoma
Kansas
Texas
Average retail price of electricity / kWh(1)
Natural gas price equivalent of electricity / Dth(1)
ONE Gas delivered cost of natural gas / Dth(2)
Natural gas advantage ratio(3)
(1) Source: United States Energy Information Agency, www.eia.gov, for the eleven-month period ended November 30, 2015.
(2) Represents the average delivered cost of natural gas to a residential customer, including the cost of the natural gas supplied, fixed customer charge, delivery
charges and charges for riders, surcharges and other regulatory mechanisms associated with the services we provide, for the year ended December 31, 2015.
(3) Calculated as the ratio of the natural gas price equivalent per dekatherm of the average retail price of electricity per kilowatt hour to the ONE Gas delivered
average cost of natural gas per dekatherm.
11.67¢
34.20
10.39
3.3x
12.31¢
36.08
9.98
3.6x
10.09¢
29.57
9.29
3.2x
$
$
$
$
$
$
We are subject to competition from other pipelines for our large industrial and commercial customers, and this competition has
and may continue to impact margins. Under our transportation tariffs, qualifying industrial and commercial customers are able
to purchase their natural gas needs from the supplier of their choice and have us transport it for a fee. A portion of the
transportation services that we provide are at negotiated rates that are below the maximum approved transportation tariff rates.
Reduced-rate transportation service may be negotiated when a competitive pipeline is in close proximity or another viable
energy option is available to the customer. Increased competition could potentially lower these rates.
Compressed Natural Gas (CNG) - In meeting increased interest in CNG for motor vehicle transportation, particularly from fleet
operators, we have been developing an incremental source of transportation revenue by supplying natural gas to CNG fueling
stations. The benefits of these programs are increased natural gas load, which could help mitigate future residential rate
increases, enhanced competitive position and increased customer satisfaction. As of December 31, 2015, we supply 129
fueling stations, 30 of which we operate. Of the 99 remaining stations, we provide supply to 56 retail and 43 private CNG
stations. We transported 2.3 million Dth to CNG stations in 2015, which represents an increase of 14 percent compared with
2014.
We will continue to support industry efforts to encourage development of more vehicle options by car and truck manufacturers,
to support third-party investment in CNG fueling stations and to continue tax incentives for CNG. We continue to deploy a
minimum amount of capital to connect CNG stations and allow the free market to build and operate the stations.
ENVIRONMENTAL AND SAFETY MATTERS
See Note 14 of the Notes to Financial Statements and Management’s Discussion and Analysis of Financial Condition and
Results of Operations in this Annual Report for information regarding environmental and safety matters.
EMPLOYEES
We employed approximately 3,400 people at January 29, 2016, including approximately 700 people at Kansas Gas Service who
are subject to collective bargaining agreements. The following table sets forth our contracts with collective bargaining units at
February 1, 2016:
The United Steelworkers
International Brotherhood of Electrical Workers (IBEW)
Union
Approximate
Employees
400
300
Contract Expires
October 28, 2016
June 30, 2017
11
EXECUTIVE OFFICERS OF THE REGISTRANT
All executive officers are elected annually by our Board of Directors and each serves until such person resigns, is removed or is
otherwise disqualified to serve or until such officer’s successor is duly elected. Our executive officers listed below include the
officers who have been designated by our Board of Directors as our Section 16 executive officers.
Name
Pierce H. Norton II
Age*
55
2014 to present
Business Experience in Past Five Years
President, Chief Executive Officer and Director
2013 to 2014
Executive Vice President, Commercial, ONEOK and ONEOK
Partners
2012
2011
Executive Vice President and Chief Operating Officer,
ONEOK and ONEOK Partners
Chief Operating Officer, ONEOK
2009 to 2011
President, ONEOK Distribution Companies, ONEOK
Curtis L. Dinan
48
2014 to present
Senior Vice President, Chief Financial Officer and Treasurer
Joseph L. McCormick
2011 to 2014
Senior Vice President, Natural Gas, ONEOK Partners
2007 to 2011
Senior Vice President, Chief Financial Officer and Treasurer,
ONEOK and ONEOK Partners
2007 to 2011
Board of Directors, ONEOK Partners
56
2014 to present
Senior Vice President, General Counsel and Assistant
Secretary
2008 to 2014
Vice President and Associate General Counsel, ONEOK and
ONEOK Partners
Caron A. Lawhorn
54
2014 to present
Senior Vice President, Commercial
2013 to 2014
Senior Vice President, Commercial, Natural Gas Distribution,
ONEOK
2011 to 2012
President, ONEOK Distribution Companies, ONEOK
2009 to 2011
Senior Vice President, Corporate Planning and Development,
ONEOK and ONEOK Partners
Robert S. McAnnally
52
2015 to present
Senior Vice President, Operations
2012 to 2015
Senior Vice President, Marketing and Customer Service,
Alabama Gas Corporation, a subsidiary of The Laclede
Group, Inc.
2009 to 2012
Vice President, External Affairs, Energen Corporation
Mark A. Bender
51
2015 to present
Senior Vice President, Administration and Chief Information
Officer
2014 to 2015
Vice President and Chief Information Officer
* As of January 1, 2016
2012 to 2014
Vice President of Information Technology Operations,
Chesapeake Energy Corporation
2010 to 2012
Chief Information Officer, Oral Roberts University
No family relationship exists between any of the executive officers, nor is there any arrangement or understanding between any
executive officer and any other person pursuant to which the officer was selected.
INFORMATION AVAILABLE ON OUR WEBSITE
We make available, free of charge, on our website (www.onegas.com) copies of our Annual Report, Quarterly Reports on Form
10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15
12
(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the
Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the
SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Certificate of Incorporation,
bylaws and the written charters of our Audit Committee, Executive Compensation Committee, Corporate Governance
Committee and Executive Committee are also available on our website, and we will provide copies of these documents upon
request. Our website and any contents thereof are not incorporated by reference into this report.
We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of
Regulation S-T.
ITEM 1A.
RISK FACTORS
Our investors should consider the following risks that could affect us and our business. Although we have tried to discuss key
factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any
time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors
should carefully consider the following discussion of risks and the other information included or incorporated by reference in
this Annual Report, including “Forward-Looking Statements,” which are included in Item 7, “Management’s Discussion and
Analysis of Financial Condition and Results of Operations.”
RISK FACTORS INHERENT IN OUR BUSINESS
Regulatory actions could impact our ability to earn a reasonable rate of return on our invested capital and to recover fully
our operating costs.
In addition to regulation by other governmental authorities, we are subject to regulation by the OCC, KCC, RRC and various
municipalities in Texas. These authorities set the rates that we charge our customers for our services. There can be no
assurance that we will be able to obtain rate increases or that our authorized rates of return will continue at the current levels.
We monitor and compare the rates of return we achieve with our allowed rates of return and initiate general and specific rate
proceedings as needed. If a regulatory agency were to prohibit us from setting rates that allow for the timely recovery of our
costs and a reasonable return by significantly lowering our allowed return or adversely altering our cost allocation, rate design
or other tariff provisions, modifying or eliminating cost trackers, prohibiting recovery of regulatory assets or disallowing
portions of our expenses, then our earnings could be impacted adversely. Regulatory proceedings also involve a risk of rate
reduction, because once a proceeding has been filed, it is subject to challenge by various interveners.
Further, accounting principles that govern our company permit certain assets that result from the regulatory process to be
recorded on our Balance Sheets that could not be recorded under GAAP for nonregulated entities. We consider factors such as
rate orders from regulators, previous rate orders for substantially similar costs, written approval from the regulators and
analysis of recoverability by internal and external legal counsel to determine the probability of future recovery of these assets.
If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time,
which would also adversely affect our results of operations and cash flows. Regulatory authorities also review whether our
natural gas costs are prudent and can adjust the amount of our natural gas costs that we pass through to our customers. If any
of our natural gas costs were disallowed, our results of operations and cash flows would also be affected adversely.
In the normal course of business in the regulatory environment, assets are placed in service before regulatory action is taken,
such as filing a rate case or for interim recovery under a capital tracking mechanism that could result in an adjustment of our
returns. Once we make a regulatory filing, regulatory bodies have the authority to suspend implementation of the new rates
while studying the filing. Because of this process, we may suffer the negative financial effects of having placed in service
assets that do not initially earn our authorized rate of return or may not be allowed recovery on such expenditures at all.
The profitability of our operations is dependent on our ability to recover timely the costs related to providing natural gas
service to our customers. However, we are unable to predict the impact that new regulatory requirements will have on our
operating expenses or the level of capital expenditures and we cannot assure you that our regulators will continue to allow
recovery of such expenditures in the future. Changes in the regulatory environment applicable to our business could impair our
ability to recover costs absorbed historically by our customers, and impact adversely our results of operations, financial
condition and cash flows.
We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs is dependent on
regulatory action.
13
We are subject to comprehensive regulation by several state and municipal utility regulatory agencies, which significantly
influences our operating environment and our ability to recover our costs from utility customers. The utility regulatory
authorities in Oklahoma, Kansas and Texas regulate many aspects of our utility operations, including organization, safety,
financing, affiliate transactions, customer service and the terms of service to customers, including the rates that we can charge
customers. The profitability of our operations is dependent on our ability to pass through costs related to providing natural gas
to our customers by filing periodic rate cases. The regulatory environment applicable to our operations could impair our ability
to recover costs historically absorbed by our customers.
We are unable to predict the impact that the future regulatory activities of these agencies will have on our operations. Changes
in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition and
results of operations. Further, the results of our operations could be impacted adversely if our authorized cost-recovery
mechanisms do not function as anticipated.
We are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely
affect our financial condition, results of operations and cash flows.
In the normal course of business, we are involved in legal or administrative proceedings before various courts and
governmental bodies with respect to general claims, rates, environmental issues, gas cost prudence reviews and other matters.
Adverse decisions regarding these matters, to the extent they require us to make payments in excess of amounts provided for in
our financial statements, or to the extent they are not covered by insurance, could adversely affect our financial condition,
results of operations and cash flows.
Unfavorable economic and market conditions could adversely affect our earnings.
Weakening economic activity in our markets could result in a loss of existing customers, fewer new customers, especially in
newly constructed homes and other buildings, or a decline in energy consumption, any of which could adversely affect our
revenues or restrict our future growth. It may become more difficult for customers to pay their natural gas bills, leading to slow
collections and higher-than-normal levels of accounts receivable, which in turn could increase our financing requirements and
bad debt expense. The foregoing could adversely affect our business, financial condition, results of operations and cash flows.
Increases in the wholesale price of natural gas could reduce our earnings, increase our working capital requirements and
impact adversely our customer base.
The supply and demand balance in natural gas markets could cause an increase in the price of natural gas. Recently, the
increased production in the U.S. of natural gas from shale formations has put downward pressure on the wholesale cost of
natural gas; however, restrictions or regulations on shale natural gas production, increased demand from natural gas fueled
electric power generation or natural gas exports could cause natural gas prices to increase. Additionally, the CFTC under the
2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has regulatory authority of the over-the-counter derivatives
markets. Regulations affecting derivatives could increase the price of our natural gas supply.
An increase in the price of natural gas could cause us to experience a significant increase in short-term debt because we must
pay suppliers for natural gas when purchased, and can be significantly in advance of when such costs may be recovered through
the collection of customer bills, which could adversely affect our financial condition and cash flows.
Further, the volatility of natural gas prices may impact adversely our customers’ perception of natural gas. Natural gas costs
are passed through to the customers of our LDCs based on the actual cost of the natural gas purchased by the particular LDC.
Substantial fluctuations in natural gas prices can occur from year to year and sustained periods of high natural gas prices or of
pronounced natural gas price volatility may lead to customers selecting other energy alternatives, such as electricity, and to
increased scrutiny of the prudency of our natural gas procurement strategies and practices by our regulators. It may also cause
new home developers, builders and new customers to select alternative sources of energy. Additionally, high natural gas prices
may cause customers to conserve more and may also impact adversely our accounts receivable collections, resulting in higher
bad debt expense. The occurrence of any of the foregoing could adversely affect our business, financial condition, results of
operations and cash flows, as well as our future growth opportunities.
In addition, customer demand for natural gas may decrease due to technological advancements that increase the efficiency of
and decrease energy consumption of appliances and equipment powered by natural gas.
14
Our risk-management policies and procedures may not be effective, and employees may violate our risk-management
policies.
We have implemented a set of policies and procedures that involve both our senior management and the Audit Committee of
our Board of Directors to assist us in managing risks associated with our business. These risk-management policies and
procedures are intended to align strategies, processes, people, information technology and business knowledge so that risk is
managed throughout the organization. However, as conditions change and become more complex, current risk measures may
fail to assess adequately the relevant risk due to changes in the market and the presence of risks previously unknown to us.
Additionally, if employees fail to adhere to our policies and procedures or if our policies and procedures are not effective,
potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended.
Ineffective risk-management policies and procedures or violation of risk-management policies and procedures could have an
adverse effect on our earnings, financial condition and cash flows.
Our business is subject to competition that could adversely affect our results of operations.
The natural gas distribution business is competitive, and we face competition from other companies that supply energy,
including electric companies, propane dealers, renewable energy providers and coal companies in relation to sources of energy
for electric power plants, as well as nuclear energy. Significant competitive factors include efficiency, quality and reliability of
the services we provide and price.
The most significant product competition occurs between natural gas and electricity in the residential and small commercial
markets. Natural gas competes with electricity for water and space heating, cooking, clothes drying and other general energy
needs. Increases in the price of natural gas or decreases in the price of other energy sources could impact adversely our
competitive position by decreasing the price benefits of natural gas to the consumer. Customers and builders typically make
the decision on the type of equipment at initial installation and use the chosen energy source for the life of the equipment.
Changes in the competitive position of natural gas relative to electricity and other energy products have the potential to cause a
decline in consumption or in the number of natural gas customers.
Consumer or government-mandated conservation efforts, higher natural gas costs or decreases in the price of other energy
sources also may encourage decreases in natural gas consumption and allow competition from alternative energy sources for
applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired
equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also
based on efficiency, performance, reliability, safety and other nonprice factors. Technological improvements in other energy
sources and events that impair the public perception of the nonprice attributes of natural gas could erode our competitive
advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and
cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive
sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product,
thereby reducing our ability to make capital expenditures and otherwise grow our business and affecting adversely our financial
condition, results of operations and cash flows.
Our business activities are concentrated in three states.
We provide natural gas distribution services to customers in Oklahoma, Kansas and Texas. Changes in the regional economies,
politics, regulations and weather patterns of these states could impact adversely the growth opportunities available to us and the
usage patterns and financial condition of our customers. This could adversely affect our financial condition, results of
operations and cash flows.
The availability of adequate natural gas pipeline transportation and storage capacity and natural gas supply may decrease
and impair our ability to meet customers’ natural gas requirements and reduce our earnings.
In order to meet customers’ natural gas demands, we must obtain sufficient natural gas supplies, pipeline transportation and
storage capacity from third parties. If we are unable to obtain these, our ability to meet our customers’ natural gas requirements
could be impaired and our financial condition and results of operations may be impacted adversely. A significant disruption to
or reduction in natural gas supply, pipeline capacity or storage capacity due to events including, but not limited to, operational
failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of
war, or legislative or regulatory actions, could reduce our normal supply of natural gas and thereby reduce our earnings.
A downgrade in our credit ratings could adversely affect our cost of and ability to access capital.
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Our ability to obtain adequate and cost-effective financing depends in part on our credit ratings. A reduction in our ratings by
our rating agencies could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. Such a
downgrade could further limit our access to public and private credit markets and increase the costs of borrowing under
available credit lines. Should our credit ratings be downgraded, it could limit our ability to obtain additional financing in the
future for working capital, capital expenditures and acquisitions. An increase in borrowing costs without the ability to recover
these higher costs in the rates charged to our customers could adversely affect our results of operations and cash flows by
limiting our ability to earn our allowed rate of return.
We are subject to new and existing laws and regulations that may require significant expenditures or significant increases
in operating costs or result in significant fines or penalties for noncompliance.
Our business and operations are subject to regulation by a number of federal agencies, including FERC, DOT, OSHA, EPA,
CFTC and various regulatory agencies in Oklahoma, Kansas and Texas, and we are subject to numerous federal and state laws
and regulations. Future changes to laws, regulations and policies may impair our ability to compete for business or to recover
costs and may increase the cost of our operations. Furthermore, because the language in some laws and regulations is not
prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of
regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures
affecting our operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under
the Natural Gas Act of 1938, as amended, to impose penalties for current violations of up to $1 million per day for each
violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent
noncompliance could also increase. Our failure to comply with applicable regulations could result in a material adverse effect
on our business, financial condition, results of operations and cash flows.
We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these
regulations could adversely affect our financial results.
The workplaces associated with our facilities are subject to the requirements of DOT and OSHA, and comparable state statutes
that regulate the protection of the health and safety of workers. The failure to comply with DOT, OSHA and state requirements
or general industry standards, including keeping adequate records or preventing occupational exposure to regulated substances,
could expose us to civil or criminal liability, enforcement actions, and regulatory fines and penalties and could have a material
adverse effect on our business, financial condition, results of operations and cash flows.
We are subject to environmental regulations, which could adversely affect our operations or financial results.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental
authorities relating to environmental and health and safety matters, including those legal requirements that govern discharges of
substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of
contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to
employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated
with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.
The failure to comply with these laws, regulations and other requirements, or the discovery of presently unknown
environmental conditions, could expose us to civil or criminal liability, enforcement actions and regulatory fines and penalties
and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We also own or retain liability for certain environmental conditions at 12 former manufactured natural gas sites in Kansas, and
expenses related to these sites could adversely affect our business, results of operations and cash flows. A number of
environmental issues may exist with respect to manufactured gas plants. With the trend toward stricter standards, greater
regulation and more extensive permit requirements for the types of assets operated by us that are subject to environmental
regulation, our environmental expenditures could increase in the future, and such expenditures may not be fully covered by
insurance or recoverable in rates from our customers, which could adversely affect our financial condition, results of operations
and cash flows.
We are subject to pipeline safety and system integrity laws and regulations that may require significant expenditures,
significant increases in operating costs or, in the case of noncompliance, substantial fines.
We are subject to the Pipeline Safety Improvement Act, which requires companies like us that operate high-pressure pipelines
to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated
high-consequence areas. Further, the Pipeline Safety, Regulatory Certainty and Job Creation Act increased the maximum
penalties for violating federal pipeline safety regulations and directed the DOT and Secretary of Transportation to conduct
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further review or studies on issues that may or may not be material to us. Compliance with existing or new laws and
regulations may result in increased capital, operating and other costs which may not be recoverable in rates from our customers
or may impact materially our competitive position relative to other energy providers. Failure to comply with such laws and
regulations may result in fines, penalties or injunctive measures that would not be recoverable from customers in rates and
could result in a material adverse effect on our financial condition, results of operations and cash flows. The failure to comply
with these laws, regulations and other requirements could expose us to civil or criminal liability, enforcement actions, and
regulatory fines and penalties and could have a material adverse effect on our business, financial condition, results of
operations and cash flows.
Climate change, carbon neutral or energy-efficiency legislation or regulations could increase our operating costs or restrict
our market opportunities, affecting adversely our growth, cash flows and results of operations.
The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate
change, including greenhouse gas emissions, such as carbon dioxide. Such laws or regulations could impose costs tied to
carbon emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They
could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or
result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond
to new mandates. The focus on climate change could impact adversely the reputation of fossil fuel products or services. The
occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to other energy sources,
increase our costs and the prices we charge to customers, reduce the demand for natural gas or cause fuel switching to other
energy sources, and impact the competitive position of natural gas and the ability to serve new or existing customers, affecting
adversely our business, results of operations and cash flows.
We are subject to physical and financial risks associated with climate change.
There is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates
physical and financial risk. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.
For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be
affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any
changes. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues and
cash flows. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to
increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have
an impact on our revenues and cash flows by affecting natural gas prices. Severe weather impacts our operating territories
primarily through thunderstorms, tornados and snow or ice storms. To the extent the frequency of extreme weather events
increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or
recover all the costs related to mitigating these physical risks. To the extent financial markets view climate change and
emissions of greenhouse gases as a financial risk, this could adversely affect our ability to access capital markets or cause us to
receive less favorable terms and conditions in future financings. Our business could be affected by the potential for lawsuits
related to or against greenhouse gas emitters based on the claimed connection between greenhouse gas emissions and climate
change, which could impact adversely our business, results of operations and cash flows.
Demand for natural gas is highly weather sensitive and seasonal, and weather conditions may cause our earnings to vary
from year to year.
Our earnings can vary from year to year, depending in part on weather conditions, which directly influence the volume of
natural gas delivered to customers. Natural gas sales to residential and commercial customers are seasonal, as a substantial
portion of their natural gas requirements are for heating during the winter months. Warmer-than-normal weather can reduce
our utility margins as customer consumption declines. We have implemented weather normalization mechanisms for our sales
to customers in Oklahoma, Kansas and portions of Texas, which are designed to limit our earnings sensitivity to weather.
Weather normalization mechanisms allow us to increase customer billings to offset lower natural gas usage when weather is
warmer than normal and decrease customer billings to offset higher natural gas usage when weather is colder than normal. If
our rates and tariffs are modified to curtail such weather protection programs, then we would be exposed to additional risk
associated with weather. As a result of occurrences of the foregoing, our results of operations and cash flows could vary and be
impacted adversely.
We may not be able to complete necessary or desirable expansion or infrastructure development projects, which may delay
or prevent us from serving our customers or expanding our business.
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In order to serve new customers or expand our service to existing customers, we may need to maintain, expand or upgrade our
distribution and/or transmission infrastructure, including laying new distribution lines. Various factors may prevent or delay us
from completing such projects or make completion more costly, such as the inability to obtain required approval from local,
state and/or federal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing,
competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements
relating to construction or other material components of an infrastructure development project. As a result, we may not be able
to serve adequately existing customers or support customer growth, which would impact adversely our business, stakeholder
perception, financial condition, results of operations and cash flows.
We may pursue acquisitions, divestitures and other strategic opportunities, the success of which may impact adversely our
results of operations, cash flows and financial condition.
As part of our strategic objectives, we may pursue acquisitions to complement or expand our business, as well as divestures and
other strategic opportunities. We may not be able to successfully negotiate, finance or receive regulatory approval for future
acquisitions or integrate the acquired businesses with our existing business and services. These efforts may also distract our
management and employees from day-to-day operations and require substantial commitments of time and resources. Future
acquisitions could result in potentially dilutive issuances of equity securities, a decrease in our liquidity as a result of our using
a significant portion of our available cash or borrowing capacity to finance the acquisition, the incurrence of debt, contingent
liabilities and amortization expenses and substantial goodwill. The effects of these strategic decisions may have long-term
implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes may
adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved
by regulators) to the detriment of the company. We may be affected materially and adversely if we are unable to integrate
successfully businesses that we acquire.
An impairment of goodwill and long-lived assets could reduce our earnings.
At December 31, 2015, we had approximately $158 million of goodwill recorded on our balance sheet. Goodwill is recorded
when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net
assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating
that goodwill might be impaired. Long-lived assets with finite useful lives are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that impairment is
indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on our equity and
balance sheet leverage as measured by debt to total capitalization, which could impact adversely our financial condition and
results of operations.
We may be unable to access capital or our cost of capital may increase significantly.
Our ability to obtain adequate and cost-effective financing is dependent upon the liquidity of the financial markets, in addition
to our financial condition and credit ratings. Disruptions in the capital and credit markets could adversely affect our ability to
access short-term and long-term capital. Access to funds under our ONE Gas Credit Agreement will be dependent on the
ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding
commitments if they experience shortages of capital and liquidity. Disruptions and volatility in the global credit markets could
cause the interest rate we pay on our ONE Gas Credit Agreement, which is based on LIBOR, to increase. This could result in
higher interest rates on future financings, and could impact the liquidity of the lenders under our ONE Gas Credit Agreement,
potentially impairing their ability to meet their funding commitments to us. Disruptions in the capital and credit markets as a
result of uncertainty, changing or increased regulation or failures of significant financial institutions could adversely affect our
access to capital needed for our business. The inability to access adequate capital or an increase in the cost of capital may
require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate our
dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our
ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and
increase our costs of borrowing.
Changes in federal and state fiscal, tax and monetary policy could increase significantly our costs or decrease our cash
flows.
Changes in federal and state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary
pressures on the costs of goods, services and labor. This could increase our expenses and capital spending and decrease our
cash flows if we are not able to recover or recover timely such increased costs from our customers. This series of events may
increase our rates to customers and thus may impact adversely customer billings and customer growth. Changes in tax rules
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could adversely affect our cash flows. Any of these events may cause us to increase debt, conserve cash, adversely affect our
ability to make capital expenditures to grow the business or other discretionary uses of cash, and could adversely affect our
cash flows.
Federal, state and local jurisdictions may challenge our tax return positions.
The preparation of our federal and state tax return filings may require significant judgments, use of estimates and the
interpretation and application of complex tax laws. Significant judgment also is required in assessing the timing and amounts
of deductible and taxable items. Despite management’s expectation that our tax return positions will be fully supportable,
certain positions may be challenged successfully by federal, state and local jurisdictions.
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding
obligations in the event of a default on our part.
The terms of our debt agreements contain cross-default provisions, which provide that we will be in default under such
agreements in the event of certain defaults under other debt agreements. Accordingly, should an event of default occur under
any of those agreements, we would face the prospect of being in default under all of our debt agreements, obliged in such
instance to satisfy all of our outstanding indebtedness simultaneously. In such an event, we may not be able to obtain
alternative financing or, if we are able to obtain such financing, we may not be able to obtain it on terms acceptable to us,
which would adversely affect our ability to implement our business plan, have flexibility in planning for, or reacting to,
changes in our business, make capital expenditures and finance our operations.
The cost of providing pension and other postemployment health care benefits to eligible employees and qualified retirees is
subject to changes in pension fund values and changing demographics and may increase. In addition, the passage of the
Patient Protection and Affordable Care Act in 2010 could increase the cost of health care benefits for our employees.
Further, the costs to us of providing such benefits and related funding requirements are subject to the continued and timely
recovery of such costs through our rates.
We have defined benefit pension plans and other postemployment welfare plans for certain employees. Our defined benefit and
other postemployment welfare plans are closed to new participants. Our other postemployment welfare plans only subsidize
costs for providing postemployment medical benefits. The cost of providing these benefits to eligible current and former
employees is subject to changes in the market value of our pension and other postemployment benefit plan assets, changing
demographics, including longer life expectancy of plan participants and their beneficiaries, and changes in health care costs.
Any sustained declines in equity markets and reductions in bond values may have a material adverse effect on the value of our
pension and other postemployment benefit plan assets. In these circumstances, additional cash contributions to our pension and
other postemployment benefit plans may be required, which could have a material adverse impact on our financial condition
and cash flows.
In addition, the costs of providing health care benefits to our employees could increase over the next five to ten years due in
large part to the Patient Protection and Affordable Care Act of 2010. The future costs of compliance with its provisions are
difficult to measure at this time. Also, our costs of providing such benefits and related funding requirements could also
increase materially in the future, depending on the timing of the recovery, if any, of such costs through our rates, which could
impact adversely our financial condition and cash flows.
Our business is subject to operational hazards and unforeseen interruptions that could affect materially and adversely our
business and for which we may not be insured adequately.
We are subject to all of the risks and hazards typically associated with the natural gas distribution business. Operating risks
include, but are not limited to, leaks, pipeline ruptures and the breakdown or failure of equipment or processes. Other
operational hazards and unforeseen interruptions include adverse weather conditions, accidents, explosions, fires, the collision
of equipment with our pipeline facilities (for example, this may occur if a third-party were to perform excavation or
construction work near our facilities) and catastrophic events, such as tornados, hurricanes, earthquakes, floods or other similar
events beyond our control. It is also possible that our facilities could be direct targets or indirect casualties of an act of
terrorism, including cyber attacks. A casualty occurrence might result in injury or loss of life, extensive property damage or
environmental damage caused to or by employees, customers, contractors, vendors and other third parties. The location of
pipeline facilities near populated areas, including residential areas, commercial business centers and industrial gathering places,
could increase the level of damages resulting from these risks. Liabilities incurred and interruptions to the operations of our
pipelines or other facilities caused by such an event could reduce revenues generated by us and increase expenses, which could
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have a material adverse effect on our financial condition, results of operations and cash flows. Additionally, our regulators may
not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would
adversely affect our earnings and cash flows.
Unanticipated events or a combination of events, failure in resources needed to respond to events, or slow or inadequate
response to events may have an adverse impact on our financial condition, results of operations and cash flows.
While we have general liability and property insurance currently in place in amounts that we consider appropriate based on our
assessment of business risk and best practices in our industry and in general business, such policies are subject to certain limits
and deductibles. Further, we are not fully insured against all risks inherent in our business. As a result of market conditions,
premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance
may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew
existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all.
The insurance proceeds received for any loss of, or any damage to, any of our facilities or to third parties may not be sufficient
to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner. The
occurrence of any of the foregoing could have a material adverse effect on our financial condition, results of operations and
cash flows.
A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely
affect our financial results.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of
our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results
could be affected adversely. Our financial results could also be affected adversely if an employee causes our operational
systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems.
In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee
tampering or manipulation of those systems will result in losses that are difficult to detect.
Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business.
We use computer programs to help run our financial and operations organizations, including an enterprise resource planning
system that integrates data and reporting activities across our company. The use of technological programs, systems and tools
may subject our business to increased risks. Any future cyber security attacks that affect our distribution facilities, our
customers, our suppliers and third party service providers or any financial data could have a material adverse effect on our
businesses. In addition, cyber attacks on our company, customer and employee data may result in a financial loss and may
impact adversely our reputation. Third-party systems on which we rely could also suffer operational system failure.
The foregoing events could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject
us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability, and our
business, financial condition and results of operations could be affected adversely.
Our business could be affected adversely by strikes or work stoppages by our unionized employees.
At February 1, 2016, approximately 700 of our estimated 3,400 employees were represented by collective-bargaining units
under collective-bargaining agreements. We are involved periodically in discussions with collective-bargaining units
representing some of our employees to negotiate or renegotiate labor agreements. We cannot predict the results of these
negotiations, including whether any failure to reach new agreements will have a negative effect on our business, financial
condition and results of operations or whether we will be able to reach any agreement with the collective-bargaining units. Any
failure to reach agreement on new labor contracts might result in a work stoppage. Any future work stoppage could, depending
on the operations and the length of the work stoppage, have a material adverse effect on our financial condition and results of
operations.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could
adversely affect operations and cash flows. Further, we may be unable to attract and retain professional and technical
employees, which could impact adversely our earnings.
Our operations require skilled and experienced workers with proficiency in multiple tasks. In recent years, a shortage of
workers trained in various skills associated with the natural gas distribution business has caused us to conduct certain
operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs. This shortage
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of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain
areas, combined with the difficulty of attracting new workers to the natural gas distribution industry. This shortage of skilled
labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an
adverse impact on labor productivity and costs and our ability to meet the needs of our customers in the event there is an
increase in the demand for our products and services, which could adversely affect our business and cash flows.
Our ability to implement our business strategy and serve our customers is dependent upon our ability to employ talented
professionals and attract and retain a skilled, high-performing workforce. We are subject to the risk that we will not be able to
effectively replace or transfer the knowledge and expertise of retiring employees. Without a skilled workforce, our ability to
provide quality service to our customers and meet our regulatory requirements will be challenged, and this could impact
adversely our business, financial condition, results of operations and cash flows.
Changes in accounting standards may impact adversely our financial condition and results of operations.
The SEC is considering whether issuers in the United States should be required to prepare financial statements in accordance
with IFRS instead of the current GAAP. IFRS is a comprehensive set of accounting standards promulgated by the International
Accounting Standards Board, which are currently in effect for most other countries in the world. Unlike GAAP, IFRS does not
provide currently an industry accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current
state, we may be precluded from applying certain regulatory accounting principles, including the recognition of certain
regulatory assets and regulatory liabilities. The potential issues associated with rate-regulated accounting, along with other
potential changes associated with the adoption of IFRS, may impact adversely our reported financial condition and results of
operations should adoption of IFRS be required.
Additionally, we are subject to additional changes in GAAP, SEC regulations and other interpretations of financial reporting
requirements for public utilities. We neither have control over the impact these changes may have on our financial condition or
results of operations nor the timing of such changes.
Our financing arrangements subject us to various restrictions that could limit our operating flexibility.
The covenants in the indenture governing our Senior Notes and our ONE Gas Credit Agreement restrict our ability to create or
permit certain liens, to consolidate or merge or to convey, transfer or lease substantially all of our properties and assets.
The ONE Gas Credit Agreement includes a requirement that our debt to total capital ratio may not exceed 70 percent as of the
end of any calendar quarter. Events beyond our control could impair our ability to satisfy this requirement. As long as our
indebtedness remains outstanding, these restrictive covenants could impair our ability to expand or pursue our growth strategy.
In addition, the breach of any covenants or any payment obligations in any of these debt agreements will result in an event of
default under the applicable debt instrument. If there were an event of default under one of our debt agreements, the holders of
the defaulted debt may have the ability to cause all amounts outstanding with respect to that debt to be due and payable, subject
to applicable grace periods. This could trigger cross-defaults under our other debt agreements, including our Senior Notes.
Forced repayment of some or all of our indebtedness would reduce our available cash and have an adverse impact on our
financial condition and results of operations.
Some of our debt, including borrowings under our ONE Gas Credit Agreement and our commercial paper program, is
based on variable rates of interest, which could result in higher interest expenses in the event of an increase in interest
rates.
In the future, we could be exposed to fluctuations in variable interest rates. This increases our exposure to fluctuations in
market interest rates. Amounts borrowed under the ONE Gas Credit Agreement and commercial paper program are based on
variable rates of interest. If these rates rise, the interest rate on this debt will also increase. Therefore, an increase in these rates
may increase our interest payment obligations and have a negative effect on our cash flows and financial position.
RISKS RELATING TO THE SEPARATION
We are responsible for certain contingent and other liabilities related to the historical natural gas distribution business of
ONEOK, as well as a portion of any contingent corporate liabilities of ONEOK that do not relate to either the natural gas
distribution business or ONEOK’s remaining businesses.
Under the Separation and Distribution Agreement between us and ONEOK, we assumed and are responsible for certain
contingent and other corporate liabilities related to the historical natural gas distribution business of ONEOK (including
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associated costs and expenses, whether arising prior to, at, or after our separation). In addition, under the Separation and
Distribution Agreement we are also responsible for a portion of any contingent corporate liabilities of ONEOK that do not
relate to either our business or the business of ONEOK following the separation (for example, liabilities associated with certain
corporate activities not specifically attributable to either business). If we are required to indemnify ONEOK or are otherwise
liable for these liabilities, they may have a material adverse effect on our financial condition, results of operations and cash
flows.
Third parties may seek to hold us responsible for liabilities of ONEOK that we did not assume in our agreements.
Third parties may seek to hold us responsible for retained liabilities of ONEOK. Under our agreements with ONEOK,
ONEOK has agreed to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are
significant and we are ultimately held liable for them, we cannot assure that we will be able to recover the full amount of our
losses from ONEOK.
Our prior and continuing relationship with ONEOK exposes us to risks attributable to businesses of ONEOK.
ONEOK is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating
to the business of ONEOK. Any claims made against us that are properly attributable to ONEOK in accordance with these
arrangements require us to exercise our rights under our agreements with ONEOK to obtain payment from ONEOK. We are
exposed to the risk that, in these circumstances, ONEOK cannot, or will not, make the required payment.
If the distribution, together with certain related transactions, were to fail to qualify as a tax-free transaction for U.S. federal
income tax purposes under Sections 355, 368(a)(1)(D) and other related provisions of the Code, then ONEOK and/or its
shareholders could incur significant U.S. federal income tax liabilities, and we could incur significant indemnity
obligations.
ONEOK received an IRS Ruling to the effect that the distribution, together with certain related transactions, qualified as tax-
free to ONEOK, us and the ONEOK shareholders under Sections 355, 368(a)(1)(D) and other related provisions of the Code.
ONEOK also received an opinion of Skadden, Arps, Slate, Meagher & Flom LLP, tax counsel to ONEOK, which opinion relies
on the continued validity of the IRS Ruling, with respect to certain issues relating to the tax-free nature of the transactions that
were not addressed in or covered by the IRS Ruling.
The IRS Ruling and the tax opinion rely upon certain assumptions, as well as statements, representations and certain
undertakings made by our officers and the officers of ONEOK regarding the past and future conduct of the companies’
respective businesses and other matters. If any of those statements, representations or assumptions are incorrect or untrue in
any material respect or any of those undertakings are not complied with, the conclusions reached in the IRS Ruling or the
opinion could be affected adversely, and ONEOK and/or its shareholders could be subject to significant tax liabilities.
Notwithstanding the IRS Ruling and opinion of tax counsel, the IRS could determine on audit that the distribution, together
with certain related transactions, was taxable if it determines that any of these statements, representations, assumptions, or
undertakings were not correct or have been violated or if it disagrees with the conclusions in the opinion that were not covered
by the IRS Ruling, or for other reasons, including as a result of certain significant changes in the stock ownership of ONEOK
or us after the distribution.
If the distribution were subsequently determined, for whatever reason, not to qualify as a transaction that is tax-free for U.S.
federal income tax purposes under Sections 355, 368(a)(1)(D), and other related provisions of the Code, ONEOK and/or the
holders of ONEOK common stock immediately prior to the distribution could incur significant tax liabilities, and, in certain
circumstances as described further under "Certain Relationships and Related Transactions, and Director Independence - Tax
Matters Agreement," we will be required to indemnify ONEOK, its subsidiaries, and certain related persons for taxes and
related expenses resulting from the distribution, which could be material. Any such indemnity obligation could have a
materially adverse impact on our financial condition.
To preserve the tax-free treatment to ONEOK and/or its shareholders of the distribution and certain related transactions, we
may not be able to engage in certain transactions.
To preserve the tax-free treatment to ONEOK and/or its shareholders of the distribution and certain related transactions, we are
restricted, under the Tax Matters Agreement between us and ONEOK, from taking any action that prevents such transactions
from being tax-free for U.S. federal, state and local income tax purposes. These restrictions may limit our ability to pursue
certain strategic transactions or engage in other transactions, including using our common stock to make acquisitions and in
connection with equity capital market transactions that might increase the value of our business.
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RISKS RELATING TO OUR COMMON STOCK
Provisions in our certificate of incorporation, our bylaws, Oklahoma law and certain of the agreements into which we have
entered as part of the separation may prevent or delay an acquisition of our company, which could decrease the trading
price of our common stock.
Our certificate of incorporation, bylaws and Oklahoma law contain provisions that are intended to deter coercive takeover
practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the raider and to encourage
prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions
include, among others:
•
•
•
•
a board of directors that is divided into three classes with staggered terms;
rules regarding how shareholders may present proposals or nominate directors for election at shareholder
meetings;
the right of our board of directors to issue preferred stock without shareholder approval; and
limitations on the right of shareholders to remove directors.
Oklahoma law also imposes some restrictions on mergers and other business combinations between us and any holder of 15
percent or more of our outstanding common stock.
We believe these provisions protect our shareholders from coercive or otherwise potentially unfair takeover tactics by requiring
potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any
acquisition proposal. These provisions are not intended to make our company immune from takeovers. However, these
provisions apply even if the offer may be considered beneficial by some shareholders and could delay or prevent an acquisition
that our board of directors determines is not in the best interests of our company and our shareholders.
Our ability to pay dividends on our common stock will depend on our ability to generate sufficient positive earnings and
cash flows.
Our ability to pay dividends in the future will depend upon, among other things, our future earnings, cash flows and restrictive
covenants, if any, under future credit agreements to which we may be a party. Our cash available for dividends will principally
be generated from our operations. Because the cash we generate from operations will fluctuate from quarter to quarter, we may
not be able to maintain future dividends at the levels we expect or at all. Our ability to pay dividends depends primarily on
cash flows, including cash flows from changes in working capital, and not solely on profitability, which is affected by noncash
items. As a result, we may pay dividends during periods when we record net losses and may be unable to pay cash dividends
during periods when we record net income.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
PROPERTIES
The following table sets forth the approximate number of service lines, pipeline and other natural gas distribution properties as
of December 31, 2015:
Properties (miles)
Distribution
Transmission
Total properties
OK
KS
TX
Total
18,300
700
19,000
12,000
1,500
13,500
10,100
800
10,900
40,400
3,000
43,400
We lease approximately 0.5 million square feet of office space and other facilities for our operations. In addition, we have 50.4
Bcf of natural gas storage capacity under lease, with maximum allowable daily withdrawal capacity of approximately 1.3 Bcf/
d.
23
ITEM 3.
LEGAL PROCEEDINGS
See Note 14 of the Notes to Financial Statements in this Annual Report for information regarding legal proceedings.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
24
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION, HOLDERS AND DIVIDENDS
Our common stock is listed on the NYSE under the trading symbol “OGS.” The following table sets forth the high and low
closing prices of our common stock for the period indicated:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
First Quarter
Second Quarter
Third Quarter
$
$
$
$
$
$
$
Year Ended
December 31, 2015
High
Low
Dividends
46.11 $
44.33 $
45.56 $
51.34 $
39.38 $
41.41 $
41.70 $
45.18 $
Year Ended
December 31, 2014*
High
Low
Dividends
35.80 $
37.98 $
37.77 $
31.53 $
34.25 $
34.00 $
34.03 $
0.30
0.30
0.30
0.30
—
0.28
0.28
0.28
Fourth Quarter
*Our common stock began regular-way trading on February 3, 2014.
$
44.19 $
At February 5, 2016, there were 14,944 registered shareholders of the Company’s common stock.
In January 2016, we declared a dividend of $0.35 per share ($1.40 per share on an annualized basis), payable on March 11,
2016, to shareholders of record as of February 26, 2016.
Employee Stock Award Program
Under the Employee Stock Award Program, we have issued, for no monetary consideration, one share of our common stock to
all eligible employees when the per-share closing price of our common stock on the NYSE closes for the first time at or above
each $1.00 increment above $34. Shares issued to employees under this program during 2015 totaled 23,506, and
compensation expense related to the Employee Stock Award Program was $1.1 million.
The total number of shares of our common stock authorized for issuance under this program is 125,000. The shares issued
under this program have not been registered under the Securities Act, in reliance upon the position taken by the SEC (see
Release No. 6188, dated February 1, 1980) that the issuance of shares to employees pursuant to a program of this kind does not
require registration under the Securities Act. See Note 11 of the Notes to Financial Statements in this Annual Report for
additional information.
25
Performance Graph
The following performance graph compares the performance of our common stock with the S&P MidCap 400 Index, the Dow
Jones Industrial Average and a ONE Gas Peer Group during the period beginning February 3, 2014, and ending on December
31, 2015. February 3, 2014 was the first day of “regular way” trading for ONE Gas on the NYSE. This graph assumes a $100
investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid
on such investments throughout the period.
Value of $100 Investment Assuming Reinvestment of Dividends at February 3, 2014, and
at the End of Every Quarter Through December 31, 2015, among ONE Gas, Inc., the S&P
MidCap 400 Utilities Index, the S&P MidCap 400 Index, the Dow Jones Industrial Average
and the ONE Gas Peer Group
$160
$140
$120
$100
$80
ONE Gas, Inc.
S&P MidCap 400 Index
ONE Gas Peer Group 1
S&P MidCap 400 Utilities Index
Dow Jones Industrial Average
Cumulative Total Return
As of Each Quarter Ending
3/31/2014
6/30/2014
9/30/2014 12/31/2014 3/31/2015
6/30/2015
9/30/2015 12/31/2015
ONE Gas, Inc.
S&P MidCap 400 Utilities Index
S&P MidCap 400 Index
$
$
$
106.84 $
113.12 $
103.41 $
125.39 $
132.43 $
131.32 $
140.81 $
156.83
107.49 $
115.89 $
105.54 $
118.29 $
112.20 $
104.63 $
107.00 $
111.26
109.21 $
113.93 $
109.38 $
116.32 $
122.50 $
121.19 $
110.89 $
113.78
$
107.54 $
Dow Jones Industrial Average
ONE Gas Peer Group1
1 The ONE Gas peer group used in this graph is the same peer group that will be used in determining our level of performance under our 2015 performance
units at the end of the three-year performance period and is comprised of the following companies: AGL Resources Inc.; Atmos Energy Corporation; Avista
Corporation; The Laclede Group, Inc.; New Jersey Resources Corporation; Northwest Natural Gas Company; Piedmont Natural Gas Company, Inc.; Questar
Corporation; South Jersey Industries, Inc.; Southwest Gas Corp.; Vectren Corporation and WGL Holdings, Inc.
112.66 $
110.59 $
123.53 $
110.28 $
118.56 $
126.30 $
114.69 $
118.52 $
107.04 $
118.91 $
116.31 $
127.05 $
107.44 $
118.77
137.63
$
26
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for each of the periods indicated:
2015
Years Ended December 31,
2013
(Millions of dollars except per share data)
2012
2014
Revenues
Net margin
Operating income
Net income
Total assets
Long-term line of credit with ONEOK
Long-term debt, including current maturities
Basic earnings per share
Diluted earnings per share
Dividends declared per common share
$
$
$
$
$
$
$
$
$
$
1,547.7
841.7
239.1
119.0
4,644.4
1,201.3
2.26
2.24
1.20
$
$
$
$
$
— $
$
$
$
$
1,818.9
827.0
225.3
109.8
4,649.2
$
$
$
$
$
— $
$
$
$
1,201.3
2.10
2.07
0.84
$
$
$
$
$
$
$
$
$
1,690.0
813.0
220.3
99.2
3,846.5
1,027.6
1.3
1.90
1.90
—
$
$
$
$
$
$
$
$
$
1,376.6
756.4
215.7
96.5
3,491.3
1,027.6
1.5
1.84
1.84
—
2011
1,621.3
751.8
199.7
86.8
3,285.5
912.4
1.9
1.66
1.66
—
Prior to 2014, historical basic and diluted earnings per share for the periods presented were calculated based on the number of
shares distributed to ONEOK shareholders on separation plus any shares associated with fully vested stock awards that had not
been issued and considered outstanding as of the beginning of each period prior to the separation. See Note 1 of the Notes to
Financial Statements in this Annual Report for additional information on earnings per share.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with our audited financial statements and Notes to
Financial Statements in this Annual Report.
EXECUTIVE SUMMARY
We are a 100 percent regulated natural gas distribution company. As such, our regulators determine the rates we are allowed to
charge for our service based on our revenue requirements needed to achieve our authorized rates of return. We earn revenues
from the delivery of natural gas, but do not earn a profit on the natural gas that we deliver, as those costs are passed through to
our customers at cost. The primary components of our revenue requirements are the amount of capital invested in our business,
which is also known as rate base, our allowed rate of return on our capital investments and our recoverable operating expenses,
including depreciation and income taxes. Our rates have both a fixed and a variable component, with approximately 73 percent
and 71 percent of our natural gas sales net margin in 2015 and 2014, respectively, derived from fixed monthly charges to our
customers. The variable component of our rates is dependent on the consumption of natural gas, which is impacted primarily
by the weather and, to a lesser extent, economic activity. While we have weather normalization mechanisms in most
jurisdictions that adjust customers’ bills when the actual heating degree days differ from normalized heating degree days, these
mechanisms are in place for only a portion of the year and do not offset all fluctuations in usage resulting from weather
variability. Accordingly, the weather can have either a positive or negative impact on our financial performance.
Our financial performance, therefore, is contingent on a number of factors, including: (1) regulatory outcomes, which
determine the returns we are authorized to earn and the rates we are allowed to charge for our service; (2) the consumption of
natural gas, which impacts the amount of our net margin derived from the variable component of our rates; (3) our operating
performance, which impacts our operating expenses; and (4) the perceived value of natural gas relative to other energy sources,
particularly electricity, which influences our customers’ choice of natural gas to provide a portion of their energy needs.
We are subject to regulatory requirements for pipeline integrity and environmental compliance. These requirements impact our
operating expenses and the level of capital expenditures required for compliance. Historically, our regulators have allowed
recovery of these expenditures. However, because integrity and environmental regulation is changing constantly, our capital
and operating expenditures to comply will change, as well. Although we believe our regulators will continue to allow recovery
of such expenditures in the future, we will continue to make these expenditures with no assurance about if, or over what period,
we will be permitted to recover them.
27
RECENT DEVELOPMENTS
In January 2016, a dividend of $0.35 per share ($1.40 per share on an annualized basis) was declared for shareholders of record
on February 26, 2016, payable March 11, 2016.
REGULATORY ACTIVITIES
Oklahoma - In July 2015, Oklahoma Natural Gas filed a request with the OCC for an increase in base rates, reflecting system
investments and operating costs necessary to maintain the safety and reliability of its natural gas distribution system. In
January 2016, the OCC approved a joint stipulation and settlement agreement reached in November 2015 to allow an increase
in revenue of $29,995,000. We also recorded a regulatory asset of $2.4 million to recover certain information technology costs
incurred as a result of our separation from ONEOK in 2014, which will be recovered over four years. The agreement set
Oklahoma Natural Gas’ authorized return on equity at 9.5 percent, which represents the midpoint of the allowed range of 9.0 to
10.0 percent and a rate base of approximately $1.2 billion. The agreement includes the continuation, with certain
modifications, of the Performance Based Rate Change tariff that was established in 2009.
In March 2015, Oklahoma Natural Gas filed its energy-efficiency program true-up application for its 2014 program year,
requesting a utility incentive of $1.2 million. In July 2015, the Public Utility Division of the OCC and all other parties entered
into a joint stipulation approving the filing. A hearing on merits was held in July 2015, with the Administrative Law Judge
recommending the approval of the joint stipulation. The joint stipulation was approved by the OCC in December 2015.
Oklahoma Natural Gas filed a PBRC application in March 2014. In June 2014, a joint stipulation and settlement agreement
associated with our PBRC filing was reached and contained an increase in base rates of approximately $13.7 million, and an
energy-efficiency program true-up and a utility incentive adjustment of $0.9 million. In August 2014, the settlement was
approved by the OCC.
Kansas - Kansas Gas Service is expected to file a rate case in 2016 based on a 2015 test year, with new rates effective January
2017.
In August 2015, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.4 million
related to its GSRS. GSRS is a capital-recovery mechanism that allows for rate adjustment, providing recovery of and a return
on incremental safety-related and government-mandated capital investments made between rate cases. In November 2015, the
KCC approved the $2.4 million increase effective December 2015.
In August 2014, Kansas Gas Service submitted an application to the KCC requesting an increase in rates of approximately $3.5
million related to its GSRS. In November 2014, the KCC approved an increase of $3.5 million, which became effective on
December 2014.
In December 2013, the KCC approved a settlement agreement between ONEOK, the staff of the KCC, and the Citizens’ Utility
Ratepayer Board for the separation from ONEOK of our Kansas Gas Service natural gas distribution business. Among other
things, the terms of the settlement agreement include the following:
• Kansas Gas Service shall not change its base rates prior to January 1, 2017. The time limitation on filing a general
rate case to change base rates does not preclude Kansas Gas Service from changing rates or tariffs to recover
appropriate costs under its current approved riders and tariffs, including its COGR, ACA, WNA, ATSR and GSRS
tariffs;
• Kansas Gas Service agreed to expense certain costs associated with ONEOK’s acquisition of Kansas Gas Service in
1997 that were previously recorded as a regulatory asset and were being amortized and recovered in rates over a 40-
year period. As such, we recorded a noncash charge to income of approximately $10.2 million in the fourth quarter of
2013;
• The level of pension and other postemployment benefit costs used to calculate Kansas Gas Service’s Pension and
Other Postemployment Benefit Trackers was adjusted to $13.6 million from $16.6 million, with a corresponding
reduction to revenues; and
• A one-time contribution to 501(c)(3) organizations of $1.2 million to provide financial assistance for weatherization of
housing for low income natural gas customers of Kansas Gas Service that was accrued in the fourth quarter of 2013.
The agreement authorized the transfer of ONEOK’s existing Kansas natural gas distribution assets, certificates of convenience
and necessity, franchises and tariffs to us.
28
Texas - In December 2015, Texas Gas Service filed a rate case requesting an increase in revenues of $3.1 million for its
Galveston and South Jefferson County service areas. Texas Gas Service filed this rate case directly with the incorporated cities,
and the RRC for the unincorporated areas. If approved by the cities and the RRC, the new rates will become effective in June
2016.
In March 2014, Texas Gas Service and the City of El Paso agreed to enter into an annual rate review mechanism called the
EPARR. The EPARR provides for a streamlined review of Texas Gas Service’s revenue requirement on an annual basis, and is
in lieu of a filing under the GRIP statute. Texas Gas Service continued to file under the GRIP statute for other incorporated
cities in the EPSA until early 2015, when the other incorporated cities in the EPSA adopted the EPARR mechanism. GRIP is a
capital-recovery mechanism that allows for a rate adjustment providing recovery of and a return on incremental capital
investments made between rate cases.
In March 2015, Texas Gas Service filed under the EPARR, requesting an increase in revenues of $9.4 million in the City of El
Paso and surrounding incorporated cities in the EPSA. The filing included a request to include a payroll adjustment which
would increase revenues by an additional $1.8 million, for a total increase in revenues of $11.2 million. In August 2015, Texas
Gas Service and the incorporated cities in the EPSA reached an agreement on a rate increase of $8.0 million to take effect in
August 2015. In April 2015, Texas Gas Service filed with the RRC under the GRIP statute, requesting an increase of $0.4
million in revenues for the unincorporated areas of the EPSA. The RRC approved the filing in July 2015. In November 2015,
Texas Gas Service notified the EPSA that it would be filing a full rate case in lieu of the EPARR in 2016.
Texas Gas Service filed requests for interim rate relief under the GRIP statute with the City of Austin, Texas, and surrounding
communities in February 2014 for approximately $5.2 million. The city councils approved the requested increase effective
May 2014. Texas Gas Service received approval for rate relief under the GRIP statute with the City of Austin, Texas, and
surrounding communities in May 2015, for approximately $3.7 million. The new rates became effective in June 2015.
Texas Gas Service filed requests for interim rate relief under the GRIP statute with the cities of Austin, Texas, and surrounding
communities in February 2013 and with El Paso, Texas, in April 2013 for approximately $4.1 million and $4.9 million,
respectively. In May 2013, the City of Austin approved the requested increase. In July 2013, the City of El Paso denied Texas
Gas Service’s GRIP request, which Texas Gas Service appealed to the RRC. In September 2013, the RRC approved Texas Gas
Service’s requested increase.
In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and cost-of-service adjustments in
various other Texas jurisdictions to address investments in rate base and changes in expense. Annual rate increases totaling
$4.8 million, $4.0 million and $4.2 million associated with these filings were approved in 2015, 2014 and 2013, respectively.
Texas Gas Service expects to file a rate case in the Central Texas jurisdiction, which includes the city of Austin, in 2016.
General - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets. Should
recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for recognition and accordingly,
a writeoff of regulatory assets and stranded costs may be required. In 2013, as part of the KCC settlement for the separation of
our Kansas Gas Service assets from ONEOK, we expensed $10.2 million for the remaining balance of certain costs associated
with ONEOK’s acquisition of Kansas Gas Service in 1997. There were no writeoffs of regulatory assets resulting from the
failure to meet the criteria for capitalization during 2015 and 2014.
29
Selected Financial Results - The following table sets forth certain selected financial results for our operations for the periods
indicated:
Financial Results
Natural gas sales
Transportation revenues
Cost of natural gas
Net margin, excluding other revenues
Other revenues
Net margin
Operating costs
Depreciation and amortization
Operating income
Capital expenditures
Years Ended December 31,
2014
2013
2015
Variances
2015 vs. 2014
Increase (Decrease)
Variances
2014 vs. 2013
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
$
1,417.9
98.8
706.0
810.7
31.0
841.7
469.6
133.0
239.1
294.3
$
$
$
1,680.1
102.3
991.9
790.5
36.5
827.0
476.0
125.7
225.3
297.1
$
$
$
1,558.5
98.7
876.9
780.3
32.7
813.0
447.9
144.8
220.3
292.1
$
$
$
(262.2)
(3.5)
(285.9)
20.2
(5.5)
14.7
(6.4)
7.3
13.8
(2.8)
(16)% $
(3)%
(29)%
3 %
(15)%
2 %
(1)%
6 %
6 % $
(1)% $
121.6
3.6
115.0
10.2
3.8
14.0
28.1
(19.1)
5.0
5.0
8 %
4 %
13 %
1 %
12 %
2 %
6 %
(13)%
2 %
2 %
The following table sets forth our net margin, excluding other revenues, by type of customer, for the periods indicated:
Net Margin, Excluding Other Revenues
Natural gas sales
Residential
Commercial and industrial
Wholesale and public authority
Net margin on natural gas sales
Transportation revenues
Net margin, excluding other revenues
Years Ended December 31,
2014
2013
2015
Variances
2015 vs. 2014
Increase (Decrease)
Variances
2014 vs. 2013
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
589.8
115.6
6.5
711.9
98.8
810.7
$
$
569.7
112.9
5.6
688.2
102.3
790.5
$
$
564.5
111.5
5.6
681.6
98.7
780.3
$
$
20.1
2.7
0.9
23.7
(3.5)
20.2
4 % $
2 %
16 %
3 %
(3)%
3 % $
5.2
1.4
—
6.6
3.6
10.2
1%
1%
—%
1%
4%
1%
Our net margin on natural gas sales is comprised of two components, fixed and variable margin. Fixed margin reflects the
portion of our net margin attributable to the monthly fixed customer charge component of our rates, which does not fluctuate
based on customer usage in each period. Variable margin reflects the portion of our net margin that fluctuates with the volumes
delivered and billed. We believe that the combination of the significant residential component of our customer base, the fixed
charge component of our sales margin and our regulatory rate mechanisms in place result in a stable cash flow profile. The
following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:
Net Margin on Natural Gas Sales
Net margin on natural gas sales
Fixed margin
Variable margin
Net margin on natural gas sales
Years Ended December 31,
2014
2013
2015
Variances
2015 vs. 2014
Increase (Decrease)
Variances
2014 vs. 2013
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
519.2
192.7
711.9
$
$
490.4
197.8
688.2
$
$
470.6
211.0
681.6
$
$
28.8
(5.1)
23.7
6 % $
(3)%
3 % $
19.8
(13.2)
6.6
4 %
(6)%
1 %
2015 vs. 2014 - Net margin increased $14.7 million due primarily to the following:
•
•
•
•
an increase of $27.5 million from new rates, primarily in Texas and Oklahoma; and
an increase of $4.8 million in residential sales due primarily to customer growth in Oklahoma and Texas; offset
partially by
a decrease of $6.0 million due to lower line extension revenue, from commercial and industrial customers, and other
revenues;
a decrease of $4.8 million due to lower sales volumes, net of weather normalization, primarily due to warmer weather
in 2015;
30
•
•
a decrease of $3.7 million in rider and surcharge recoveries due to a lower ad-valorem surcharge in Kansas and the
expiration of the rider associated with the recovery of take-or-pay settlements in Oklahoma, both of which are offset
by lower regulatory amortization in depreciation and amortization expense; and
a decrease of $3.1 million due primarily to lower transportation volumes from weather-sensitive customers primarily
in Kansas.
Operating costs decreased $6.4 million due primarily to the following:
•
•
•
•
•
•
•
a decrease of $6.8 million in information technology services associated with our separation from ONEOK;
a decrease of $6.0 million in outside services costs due primarily to operational efficiencies;
a decrease of $4.1 million in legal and worker’s compensation expense;
a decrease of $2.7 million in bad debt expense primarily due to warmer weather in Kansas;
a decrease of $1.4 million in fleet-related expenses due primarily to lower fuel costs; and
a decrease of $0.9 million in ad valorem taxes; offset partially by
an increase of $16.3 million in employee-related costs due primarily to increases of $9.3 million in higher labor costs
due to an increase in our number of employees and $7.0 million in benefit costs, which includes the impact of the
changes in our discount rate for pension and other postemployment benefit costs compared with the prior year.
Depreciation and amortization expense increased $7.3 million due primarily to an increase in depreciation of $12.1 million
from capital expenditures being placed in service, offset partially by a decrease in the amortization of the ad valorem surcharge
in Kansas and the take-or-pay rider in Oklahoma of $3.6 million.
2014 vs. 2013 - Net margin increased $14.0 million due primarily to the following:
•
•
•
•
•
•
an increase of $16.8 million from new rates, primarily in Texas and Oklahoma;
an increase of $5.6 million in residential sales due primarily to customer growth;
an increase of $4.7 million from higher volumes due primarily to weather-sensitive transportation customers; and
an increase of $2.8 million in CNG revenue and higher line extension revenue from commercial and industrial
customers in Oklahoma; offset partially by
a decrease of $12.8 million in rider and surcharge recoveries due to a lower ad-valorem surcharge in Kansas and the
expiration of the rider associated with the recovery of take-or-pay settlements in Oklahoma, both of which are offset
by lower regulatory amortization in depreciation and amortization expense; and
a decrease of $3.7 million due primarily to warmer weather in all three states compared with colder-than-normal
weather in 2013, net of weather normalization.
Operating costs increased $28.1 million due primarily to the following:
•
•
•
•
•
an increase of $13.0 million in outside service costs related primarily to $6.8 million of costs associated with our
separation from ONEOK and $3.7 million in pipeline maintenance activities;
an increase of $12.6 million in insurance, information technology and rent expenses;
an increase of $11.0 million in employee-related expenses resulting from higher labor and compensation costs; and
an increase of $1.7 million in bad debt expense; offset partially by
a decrease of $8.0 million in benefit costs related primarily to lower pension and other postemployment benefit costs
resulting from an annual change in the estimated discount rate.
Depreciation and amortization expense increased due primarily to the settlement agreement approved by the KCC authorizing
the separation of the Kansas Gas Service assets from ONEOK to us, whereby Kansas Gas Service agreed to expense a $10.2
million regulatory asset related to a transaction cost recovery and an increase in the amortization of amounts previously
deferred for ad valorem taxes, which is offset in net margin.
Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, automated meter reading,
extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements,
government-mandated relocation of pipelines, fleet and facilities, and information technology hardware and software. It is our
practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations.
Capital expenditures decreased $2.8 million for 2015, compared with 2014, due primarily to reduced spending on information
technology hardware and software in 2014 related to our separation from ONEOK. Capital expenditures increased $5.0 million
for 2014, compared with 2013, primarily as a result of an increase in spending on information technology hardware and
software related to our separation from ONEOK. Our capital expenditures are expected to be approximately $305.0 million for
2016.
31
Commercial and industrial
Wholesale and public authority
Transportation
Total customers
Volumes (MMcf)
Natural gas sales
Residential
Commercial and industrial
Wholesale and public authority
Total volumes sold
Transportation
Total volumes delivered
Selected Operating Information - The following tables set forth certain selected operating information for the periods
indicated:
(in thousands)
2015
2014
Increase (Decrease)
Average Number of Customers
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Years Ended
December 31,
Variances
2015 vs. 2014
Residential
783
579
Commercial and industrial
Wholesale and public authority
Transportation
Total customers
73
—
5
50
—
6
606
34
3
1
1,968
157
3
12
776
578
72
—
5
50
—
6
601
34
4
1
1,955
156
4
12
861
635
644
2,140
853
634
640
2,127
7
1
—
—
8
1
—
—
—
1
5
—
(1)
—
4
13
1
(1)
—
13
(in thousands)
2014
2013
Increase (Decrease)
Average Number of Customers
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Years Ended
December 31,
Variances
2014 vs. 2013
Residential
776
578
72
—
5
50
—
6
601
34
4
1
1,955
156
4
12
770
577
72
—
5
50
—
6
597
33
3
1
1,944
155
3
12
853
634
640
2,127
847
633
634
2,114
6
—
—
—
6
1
—
—
—
1
4
1
1
—
6
11
1
1
—
13
Years Ended December 31,
2014
2013
2015
115,477
35,943
2,615
154,035
204,763
358,798
125,337
38,555
2,454
166,346
213,456
379,802
122,855
36,956
4,403
164,214
205,915
370,129
Total volumes delivered decreased for 2015, compared with 2014, due primarily to warmer temperatures in 2015. Residential
and commercial and industrial natural gas sales volumes increased for 2014, compared with 2013, due primarily to colder
temperatures in the first quarter of 2014. The impacts on margins for the periods presented were mitigated largely by weather-
normalization mechanisms.
Wholesale sales represent contracted natural gas volumes that exceed the needs of our residential, commercial and industrial
customer base and are available for sale to other parties. The impact to net margin from changes in volumes associated with
these customers is minimal.
32
Years Ended
December 31,
2015
2014
Heating Degree Days
Actual
Normal
Actual
Normal
Oklahoma
Kansas
Texas
3,135
4,264
1,715
3,317
4,860
1,785
3,720
5,179
1,716
3,317
4,860
1,788
Years Ended
December 31,
2014
2013
Heating Degree Days
Actual
Normal
Actual
Normal
2015 vs
2014
Actual
Variance
(16)%
(18)%
— %
2015
2014
Actual as a percent of
Normal
95%
88%
96%
112%
107%
96%
2014 vs
2013
Actual
Variance
2014
2013
Actual as a percent of
Normal
Oklahoma
Kansas
Texas
3,720
5,179
1,716
3,317
4,860
1,788
3,848
5,246
1,942
3,317
4,860
1,793
(3)%
(1)%
(12)%
112%
107%
96%
116%
108%
108%
Normal HDDs are established through rate proceedings in each of our rate jurisdictions for use primarily in weather
normalization billing calculations. Normal HDDs disclosed above are based on:
•
•
•
10-year weighted average HDDs as of December 31, 2014, for years 2005-2014, as calculated using 11 weather
stations across Oklahoma and weighted on average customer count for Oklahoma;
30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as
calculated using 13 weather stations across Kansas and weighted on HDDs by weather station and customers for
Kansas; and
a rolling 10-year average of actual natural gas distribution sales volumes by service area for Texas.
Actual HDDs are based on quarter-to-date and year-to-date, weighted average of:
•
•
•
11 weather stations and customers by month for Oklahoma;
13 weather stations and customers by month for Kansas; and
9 weather stations and natural gas distribution sales volumes by service area for Texas.
CONTINGENCIES
We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results
of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters,
individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not
have a material adverse effect on our results of operations, financial position or cash flows. See Note 14 of the Notes to
Financial Statements in this Annual Report for information with respect to legal proceedings.
LIQUIDITY AND CAPITAL RESOURCES
General - From the date of the separation, we have funded operating expenses, working capital requirements, including
purchases of natural gas and capital expenditures primarily with operating cash flows and commercial paper. Prior to the
separation, we relied primarily on operating cash flow and participation in ONEOK’s cash management program for our
liquidity and capital resource requirements.
We believe that the combination of the significant residential component of our customer base, the fixed-charge component of
our natural gas sales net margin and our regulatory rate mechanisms that we have in place result in a stable cash flow profile.
Because the energy consumption of residential customers is less volatile compared with commercial and industrial customers,
our business historically has generated stable and predictable net margin and cash flows. Additionally, we have several
regulatory rate mechanisms in place to reduce the lag in earning a return on our capital expenditures. We anticipate that our
33
cash flow generated from operations and our expected short- and long-term financing arrangements will enable us to maintain
our current and planned level of operations and provide us flexibility to finance our infrastructure investments.
Our ability to access capital markets for debt and equity financing under reasonable terms depends on market conditions and
our financial condition and credit ratings. We believe that stronger credit ratings will provide a significant advantage to our
business. By maintaining a conservative financial profile and stable revenue base, we believe that we will be able to maintain
an investment-grade credit rating, which we believe will provide us access to diverse sources of capital at more favorable rates
in order to finance our infrastructure investments. Credit rating agencies perform independent analyses when assigning credit
ratings.
Short-term Financing - The ONE Gas Credit Agreement, which is scheduled to expire in January 2019, contains certain
financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-
capital ratio of no more than 70 percent at the end of any calendar quarter. The ONE Gas Credit Agreement also contains
customary affirmative and negative covenants, including covenants relating to liens, indebtedness of subsidiaries, investments,
changes in the nature of business, fundamental changes, transactions with affiliates, burdensome agreements, and use of
proceeds. In the event of a breach of certain covenants by ONE Gas, amounts outstanding under the ONE Gas Credit
Agreement may become due and payable immediately. At December 31, 2015, our total debt-to-capital ratio was 40 percent,
and we were in compliance with all covenants under the ONE Gas Credit Agreement.
The ONE Gas Credit Agreement includes a $50 million sublimit for the issuance of standby letters of credit and also features an
option to request an increase in the size of the facility to an aggregate of $1.2 billion from $700 million, upon satisfaction of
customary conditions, including receipt of commitments from new lenders or increased commitments from existing lenders.
Borrowings made under the facility are available for general corporate purposes. The ONE Gas Credit Agreement contains
provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating.
Based on our current credit ratings, borrowings, if any, will accrue interest at LIBOR plus 79.5 basis points, and the annual
facility fee is 8 basis points.
We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The
ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the
obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.
We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of
$700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary but may not exceed
270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest
factor.
The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the
commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement.
At December 31, 2015, we had issued $12.5 million in the form of commercial paper, $1.0 million in letters of credit
outstanding and had approximately $2.4 million of cash and cash equivalents. At December 31, 2015, we had no borrowings
and $686.5 million of credit available under the ONE Gas Credit Agreement. The weighted-average interest rate on our
commercial paper was 0.7 percent at December 31, 2015.
Debt Issuance - In January 2014, we issued senior notes, consisting of $300 million of 2.07 percent senior notes due 2019,
$300 million of 3.61 percent senior notes due 2024 and $600 million of 4.658 percent senior notes due 2044 (collectively, our
“Senior Notes”). The net proceeds were approximately $1.19 billion and were used to fund a one-time cash payment to
ONEOK of approximately $1.13 billion as part of the separation. The remaining portion of the net proceeds was retained in
order to provide sufficient financial flexibility and to support working capital requirements and capital expenditures.
The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100
million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of
the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.
We may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date, starting one month, three
months, and six months, respectively, before their maturity dates. Prior to these dates, we may redeem these Senior Notes, in
whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole
premium. The redemption price will never be less than 100 percent of the principal amount of the respective Senior Notes plus
34
accrued and unpaid interest to the redemption date. Our Senior Notes are senior unsecured obligations, ranking equally in right
of payment with all of our existing and future unsecured senior indebtedness.
Credit Ratings - Our credit ratings as of January 31, 2016 were:
Rating Agency
Moody’s
S&P
Rating
A2
A-
Outlook
Stable
Stable
Our commercial paper is currently rated Prime-1 by Moody’s and A-2 by S&P. We intend to maintain strong credit metrics
while we pursue a balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe
will be competitive with our peer group.
Capitalization structure - As of December 31, 2015, our total capitalization structure was 40 percent debt to 60 percent equity.
Pension and Other Postemployment Benefit Plans - Information about our pension and other postemployment benefits plans,
including anticipated contributions, is included under Note 12 of the Notes to Financial Statements in this Annual Report.
CASH FLOW ANALYSIS
Prior to the separation, we utilized ONEOK’s centralized cash management program that concentrated the cash assets of its
operating divisions and subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of
borrowing, transaction costs and bank fees. Under this cash management program, depending on whether we had a short-term
cash surplus or cash requirement, we provided cash to ONEOK or ONEOK provided cash to us when necessary. Subsequent to
the separation, we maintain separate cash accounts from ONEOK, and our interest expense is related only to our borrowings.
We use the indirect method to prepare our Statements of Cash Flows. Under this method, we reconcile net income to cash
flows provided by operating activities by adjusting net income for those items that impact net income but may not result in
actual cash receipts or payments and changes in our assets and liabilities not classified as investing or financing activities
during the period. Items that impact net income but may not result in actual cash receipts or payments include, but are not
limited to, depreciation and amortization, deferred income taxes, share-based compensation expense and provision for doubtful
accounts.
The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods
indicated:
Total cash provided by (used in):
Operating activities
Investing activities
Financing activities
Change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Years Ended December 31,
2015
2014
2013
Variances
2015 vs. 2014
Variances
2014 vs. 2013
Increase
(Decrease)
Increase
(Decrease)
(Millions of dollars)
$
$
394.2
(294.3)
(109.4)
(9.5)
11.9
2.4
$
$
246.6
(297.1)
59.2
8.7
3.2
11.9
$
$
154.2
(290.7)
135.7
(0.8)
4.0
3.2
$
$
147.6 $
2.8
(168.6)
(18.2)
8.7
(9.5) $
92.4
(6.4)
(76.5)
9.5
(0.8)
8.7
Operating Cash Flows - Changes in cash flows from operating activities, before changes in operating assets and liabilities, are
due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information.
Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions,
changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows.
Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.
2015 vs. 2014 - Cash flows from operating assets and liabilities in our operating activities increased in 2015, compared to 2014,
due primarily to the collection of trade receivables, tax receivables, payment of trade payables and the recovery of natural gas
35
purchase costs, including natural gas in storage, through our purchased-gas cost adjustment mechanisms, which were impacted
by warmer weather and lower natural gas costs. The timing of cash collections from customers and payments to vendors and
suppliers vary from period to period in the normal course of business and directly impact our cash flows from operations. In
addition, our changes in income taxes receivable were impacted by an extension of the IRS rules for bonus depreciation.
2014 vs. 2013 - Cash flows from operating assets and liabilities in our operating activities increased in 2014, compared to 2013,
due primarily to the collection of trade receivables, payment of trade payables and the recovery of natural gas purchase costs
through our purchased-gas cost adjustment mechanisms. The timing of cash collections from customers and payments to
vendors and suppliers vary from period to period in the normal course of business and directly impact our cash flows from
operations.
Investing Cash Flows - 2015 vs. 2014 - Cash used in investing activities decreased for 2015, compared to 2014, due primarily
to capital expenditures for information technology hardware and software associated with our separation from ONEOK.
2014 vs. 2013 - Cash used in investing activities increased for 2014, compared to 2013, due primarily to capital expenditures
for information technology hardware and software associated with our separation from ONEOK.
Financing Cash Flows - 2015 vs. 2014 - Cash used in financing activities increased for 2015, compared with 2014, due
primarily to an increase in the dividend rate of two cents, an additional quarter of dividends paid in 2015, a decrease in our
outstanding notes payable, and purchases of treasury stock used to offset shares issued under our equity compensation and
employee stock purchase plans.
2014 vs. 2013 - Cash used in financing activities decreased for 2014, compared with 2013 due primarily to the $1.19 billion
debt issuance and $1.13 billion cash payment to ONEOK in connection with our separation from ONEOK in 2014, compared
with our participation in ONEOK’s cash management program and our distributions to ONEOK in 2013.
ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS
Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or
regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to,
those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes,
wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations
require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other
approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or
interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other
regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected
capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new
regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased
compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas.
These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws
and regulations. A consent agreement with the KDHE governs all work at these sites. The terms of the consent agreement
allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis.
Remediation involves typically the management of contaminated soils and may involve removal of structures and monitoring
and/or remediation of groundwater.
We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites according to plans approved
by KDHE. Regulatory closure has been achieved at three of the sites. We have begun site assessment at the remaining site
where no active remediation has occurred.
Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in
relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had
no material effects on earnings or cash flows during 2015, 2014 and 2013. A number of environmental issues may exist with
respect to manufactured gas plants. With the trend toward stricter standards, greater regulation and more extensive permit
requirements for the types of assets operated by us that are subject to environmental regulation, our environmental expenditures
could increase in the future, and such expenditures may not be fully covered by insurance or recoverable in rates from our
customers, and those costs may adversely affect our financial condition, results of operations and cash flows.
36
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations
require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline
segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012,
the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for
violating federal pipeline safety regulations and directs the DOT and the Secretary of Transportation to conduct further review
or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:
•
•
•
an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current
high-consequence areas;
a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum
allowable operating pressures; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence
areas.
The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline
safety regulations are unknown.
Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations promulgated
thereunder, impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States.
Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may
be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or
maintaining permits and approvals for sources of air emissions. We do not expect that these expenditures will have a material
impact on our respective results of operations, financial position or cash flows. The Clean Water Act imposes substantial
potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by
such discharge.
Federal, state and regional initiatives to measure and regulate greenhouse gas emissions are underway. We monitor relevant
federal and state legislation to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting
Rule requires annual greenhouse gas emissions reporting as carbon dioxide equivalents from affected facilities and for the
natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own
emissions. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material
impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in
the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may
institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has
been enacted that assesses any costs, fees or expenses on any of these emissions.
CERCLA - The federal CERCLA, also commonly known as Superfund, imposes strict, joint and several liability, without
regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) that caused and/or
contributed to the release of a hazardous substance into the environment. These persons include, but are not limited to, the
owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the
hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the
hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. We
do not expect that our responsibilities under CERCLA will have a material impact on our respective results of operations,
financial position or cash flows.
Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration issued
updated pipeline security guidelines in April 2012. Our pipeline facilities have been reviewed according to the current
guidelines and no material changes have been required to date.
Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of
our operations on the environment. These strategies include: (1) developing and maintaining an accurate greenhouse gas
emissions inventory according to current rules issued by the EPA; (2) improving the efficiency of our various pipelines; (3)
following developing technologies for emission control; and (4) utilizing practices to reduce the loss of methane from our
facilities such as vintage pipe replacement which not only improves system integrity but also helps lower emissions.
We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on
maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the
37
release of natural gas during pipeline and facility maintenance and operations. Additionally, the EPA is currently developing a
methane emissions partnership program expected to be finalized in 2016.
Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional
information regarding our regulatory initiatives in Management’s Discussion and Analysis of Financial Condition and Results
of Operations.
Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 14
of the Notes to Financial Statements in this Annual Report. We cannot assure that existing environmental statutes and
regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional
regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on
our business, financial condition and results of operations. Our expenditures for environmental evaluation, mitigation,
remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash
flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2015,
2014 and 2013. We do not expect to incur material expenditures for these matters in the future.
IMPACT OF NEW ACCOUNTING ST
Information about the impact of new accounting standards is included in Note 1 of the Notes to Financial Statements in this
Annual Report.
ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The preparation of our financial statements and related disclosures in accordance with GAAP requires us to make estimates and
assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets
and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and
assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these
estimates and assumptions are reasonable, actual results could differ from our estimates. See our Risk Factors and/or Forward-
Looking Statements for factors which could impact our estimates.
The following summary sets forth what we consider to be our most critical estimates and accounting policies. Our critical
accounting policies are defined as those estimates and policies most important to the portrayal of our financial condition and
results of operations and that require management’s most difficult, subjective or complex judgment, particularly because of the
need to make estimates concerning the impact of inherently uncertain matters.
Regulation - Our operations are subject to regulation with respect to rates, service, maintenance of accounting records and
various other matters by the respective regulatory authorities in the states in which we operate. We account for the financial
effects of the ratemaking and accounting practices and policies of the various regulatory commissions in our financial
statements. We record regulatory assets for costs that have been deferred for which future recovery through customer rates is
considered probable and regulatory liabilities when it is probable that revenues will be reduced for amounts that will be
credited to customers through the ratemaking process. As a result, certain costs that would normally be expensed under GAAP
are capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Discontinuing the
application of this method of accounting for regulatory assets and liabilities could significantly increase our operating expenses,
as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income. Further,
regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized
are based upon historical experience and our understanding of the regulations. The impact of regulation on our operations may
be affected by decisions of the regulatory authorities or the issuance of new regulations.
For further discussion of regulatory assets and liabilities, see Note 9 of the Notes to Financial Statements in this Annual Report.
Impairment of Goodwill - We assess our goodwill for impairment at least annually as of July 1. Our goodwill impairment
analysis performed in 2015 and 2014, utilized a qualitative assessment and did not result in any impairment indicators.
Subsequent to July 1, 2015, no event has occurred indicating that the fair value is less than the carrying value.
As part of our goodwill impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and
market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that our
fair value is less than our carrying amount. If further testing is necessary, we perform a two-step impairment test for goodwill.
In the first step, an initial assessment is made by comparing our fair value with our book value, including goodwill. If the fair
value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the
38
impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible
and intangible net assets from the fair value determined in step one of the assessment. If the carrying value of the goodwill
exceeds the implied fair value of the goodwill, we will record an impairment charge.
To estimate our fair value, we use two generally accepted valuation approaches, an income approach and a market approach,
using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash
flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount
rates. Under the market approach, we apply acquisition multiples to forecasted cash flows. The acquisition multiples used are
consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows over a
period of years.
Our impairment tests require the use of assumptions and estimates, such as industry economic factors and the profitability of
future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and
estimates change due to new information, we may be exposed to future impairment charges.
See Note 1 of the Notes to Financial Statements in this Annual Report for further discussion of goodwill.
Pension and Other Postemployment Benefits - We have defined benefit retirement plans covering eligible full-time
employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible
employees who retire with at least five years of service. In connection with the separation from ONEOK, we entered into an
Employee Matters Agreement with ONEOK, which provides that our employees no longer participate in benefit plans
sponsored or maintained by ONEOK as of the separation date. Effective January 1, 2014, the ONEOK defined benefit pension
plans and other postemployment benefit plans transferred assets and obligations related to those employees transferring to ONE
Gas and vested participants who are no longer employees to the new ONE Gas plans. As a result, we recorded sponsored
pension and other postemployment plan obligations of approximately $1.1 billion, and sponsored pension and other
postemployment plan assets of approximately $1.0 billion. Additionally, as a result of the transfer of unrecognized losses from
ONEOK, our regulatory assets and deferred income taxes increased $331 million and $86 million, respectively.
Prior to the separation, eligible employees participated in similar defined benefit pension plans and other postemployment
health and welfare plans (the Plans) sponsored by ONEOK. We accounted for these plans as multiemployer benefit plans.
Accordingly, we did not record an asset or liability to recognize the funded status of the Plans. We recognized a liability only
for any required contributions to the Plans that were accrued and unpaid at the balance sheet date. The related pension and
other postemployment expenses were allocated to us based on plan participants who directly supported our operations. These
pension and other postemployment benefit costs included amounts associated with vested participants who are no longer
employees. As described in Note 2 of the Notes to Financial Statements in this Annual Report, prior to 2014, ONEOK also
charged us for the allocated cost of certain employees of ONEOK who provided general and administrative services on our
behalf. ONEOK included an allocation of the benefit costs associated with these ONEOK employees based upon its allocation
methodology, not necessarily specific to the employees providing general and administrative services on our behalf. See Note
2 of the Notes to Financial Statements in this Annual Report for discussion of ONEOK’s allocation methodology.
To calculate the expense and liabilities related to our plans, we utilize an outside actuarial consultant, which uses statistical and
other factors to anticipate future events. These factors include assumptions about the discount rate, expected return on plan
assets, rate of future compensation increases, age and employment periods. In determining the projected benefit costs,
assumptions can change from period to period and may result in material changes in the costs we recognize.
In October 2015, plan amendments were approved to merge our frozen cash-balance defined benefit pension plan covering
certain Texas Gas Service employees with our defined benefit pension plan covering certain eligible employees. In addition,
we announced to eligible pre-65 participants in our postemployment medical plan a change from a self-insured
postemployment medical plan to a plan providing participants an annual benefit that will allow them to select coverage on a
healthcare exchange. As a result, we remeasured the respective plan assets and benefit obligations, effective October 1, 2015,
which resulted in a reduction in benefit obligations of our postemployment benefit plan of $11.9 million at December 31, 2015.
Net periodic benefit cost for the plans in 2015 was reduced by $3.4 million. See Note 12 of the Notes to Financial Statements
in this Annual Report for additional information.
During 2015, we recorded net periodic benefit costs of $38.0 million and $5.0 million related to our pension plans and other
postemployment benefit plans, respectively, prior to regulatory deferrals. We estimate that in 2016, we will record $32.0 million
and $1.7 million related to pension plans and other postemployment benefit plans, respectively, prior to regulatory deferrals.
39
The following table sets forth the weighted-average assumptions used to determine our estimated 2016 net periodic benefit cost
related to our defined pension and other postemployment benefit plans, and sensitivity to changes with respect to these
assumptions:
Discount rate
Expected long-term return on plan assets (c)
Rate Used
Cost
Sensitivity (a)
Obligation
Sensitivity (b)
(Millions of dollars)
4.75% $
7.75%/8.0% $
3.7
2.3
$
$
37.3
—
(a) Approximate impact a quarter percentage point decrease in the assumed rate would have on net periodic pension costs.
(b) Approximate impact a quarter percentage point decrease in the assumed rate would have on defined benefit pension obligation.
(c) Expected long-term rate of return on plan assets for pension and other postemployment benefits are 7.75 percent and 8.0 percent, respectively.
Assumed health care cost-trend rates have a significant effect on the amounts reported for our other postemployment benefit
plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
Effect on total of service and interest cost
Effect on other postemployment benefit obligation
One Percentage
Point Increase
One Percentage
Point Decrease
(Millions of dollars)
$
$
0.8
3.6
$
$
(0.7)
(3.8)
During 2015, we contributed approximately $14.1 million to our other postemployment benefit plans. In 2016, we expect to
contribute approximately $0.9 million and approximately $5.8 million to our defined benefit pension plan and other
postemployment benefit plans, respectively.
Revenue Recognition - For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We
recognize revenues upon the delivery of natural gas commodity or services rendered to customers. Revenues are accrued for
natural gas delivered and services rendered to customers, but not yet billed, based on estimates from the last meter-reading date
to month end (accrued unbilled revenue). The billing cycles for customers do not necessarily coincide with the accounting
periods used for financial reporting purposes. We accrue unbilled revenues for natural gas that has been delivered but not yet
billed at the end of an accounting period. Accrued unbilled revenue is based on a percentage estimate of amounts unbilled each
month, which is dependent upon a number of factors, some of which require management’s judgment. These factors include
customer consumption patterns and the impact of weather on usage.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and
environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered and an amount can be reasonably estimated. We expense legal fees as incurred
and base our legal liability estimates on currently available facts and our assessments of the ultimate outcome or resolution.
Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion
of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets
when their receipt is deemed probable. Our expenditures for environmental evaluation, mitigation, remediation and
compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures
related to environmental matters had no material effect on earnings or cash flows for 2015, 2014 and 2013. Actual results may
differ from our estimates resulting in an impact, positive or negative, on earnings.
See Note 14 of the Notes to Financial Statements in this Annual Report for additional discussion of contingencies.
40
CONTRACTUAL OBLIGATIONS
The following table sets forth our contractual obligations at December 31, 2015:
Contractual Obligations
(Millions of dollars)
2016
2017
2018
2019
2020
Thereafter
Total
Commercial paper
Long-term debt, including current maturities
Interest payments on debt
Firm transportation and storage capacity contracts
Natural gas purchase commitments
Employee benefit plans
Operating leases
Total
$
$
12.5
—
45.1
178.2
158.1
6.7
4.6
405.2
$
$
— $
—
45.1
148.0
5.0
4.4
4.5
207.0
$
— $
—
45.1
109.4
2.0
4.5
4.2
165.2
$
— $
300.0
39.4
61.3
1.5
25.5
3.5
431.2
$
— $
— $
—
38.9
58.2
0.9
37.5
3.3
138.8
901.3
649.2
54.2
1.5
—
7.0
$ 1,613.2
12.5
1,201.3
862.8
609.3
169.0
78.6
27.1
$ 2,960.6
Commercial paper - Commercial paper includes short-term notes payable with maturities that may vary but may not exceed
270 days from the date of issue.
Long-term debt and interest payments on debt - Long-term debt includes our three debt issuances at their due dates. Interest
payments on debt are calculated by multiplying our long-term debt by the respective coupon rates.
Firm transportation and storage contracts - We are party to fixed-price contracts providing us with firm transportation and
storage capacity. The commitments associated with these contracts are recoverable through our purchased-gas cost
mechanisms as allowed by the applicable regulatory authority.
Natural gas purchase commitments - We are party to fixed-price and variable-price contracts for the purchase of natural gas.
Future variable-price natural gas purchase commitments are estimated based on market price information. Actual future
variable-price purchase commitments may vary depending on market prices at the time of delivery. As market information
changes daily and is potentially volatile, these values may change significantly. The commitments associated with these
contracts are recoverable through our purchased-gas cost mechanisms as allowed by the applicable regulatory authority.
Employee benefit plans - Employee benefit plans include our anticipated contribution to maintain the minimum required
funding level for our pension and other postemployment benefit plans. See Note 12 of the Notes to Financial Statements in this
Annual Report for discussion of employee benefit plans.
Operating leases - Our operating leases include leases for office space, facilities and information technology hardware and
software.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Annual Report are forward-looking statements within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our
anticipated financial performance, liquidity, management’s plans and objectives for our future operations, our business
prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-
looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of
1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially
from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or
assumed future results of our operations and other statements contained or incorporated in this Annual Report identified by
words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,”
“guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” and other words and terms of similar meaning.
41
One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Annual
Report. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements
to be materially different from any future results, performance or achievements expressed or implied by forward-looking
statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions
and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual
results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
our ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment
and regulatory assets in our regulated rates;
our ability to manage our operations and maintenance costs;
changes in regulation, including the application of market rates by state and local agencies;
the economic climate and, particularly, its effect on the natural gas requirements of our residential and
commercial industrial customers;
competition from alternative forms of energy, including, but not limited to, solar power, wind power, geothermal
energy and biofuels;
conservation efforts of our customers;
variations in weather, including seasonal effects on demand, the occurrence of storms and disasters, and climate
change;
indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to
borrow additional funds and/or place us at competitive disadvantage compared with competitors;
our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including
decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of
existing supply and transportation arrangements that are not replaced with contracts with similar terms and pricing;
the mechanical integrity of facilities operated;
operational hazards and unforeseen operational interruptions;
adverse labor relations;
the effectiveness of our strategies to reduce earnings lag, margin protection strategies and risk mitigation strategies;
our ability to generate sufficient cash flows to meet all of our cash needs;
changes in the financial markets during the periods covered by the forward-looking statements, particularly those
affecting the availability of capital and our ability to refinance existing debt and fund investments and acquisitions;
actions of rating agencies, including the ratings of debt, general corporate ratings and changes in the rating agencies’
ratings criteria;
changes in inflation and interest rates;
our ability to purchase and sell assets at attractive prices and on other attractive terms;
our ability to recover the costs of natural gas purchased for our customers;
impact of potential impairment charges;
volatility and changes in markets for natural gas;
possible loss of LDC franchises or other adverse effects caused by the actions of municipalities;
payment and performance by counterparties and customers as contracted and when due;
changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;
changes in law resulting from new federal or state energy legislation;
changes in environmental, safety, tax and other laws to which we and our subsidiaries are subject;
advances in technology;
population growth rates and changes in the demographic patterns of the markets we serve;
acts of nature and the potential effects of threatened or actual terrorism, including cyber attacks or breaches of
technology systems and war;
the sufficiency of insurance coverage to cover losses;
the effects of our strategies to reduce tax payments;
the effects of litigation and regulatory investigations, proceedings, including our rate cases, or inquiries;
changes in accounting standards and corporate governance;
discovery of material weaknesses in our internal controls;
our ability to attract and retain talented management and directors;
the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by
various factors, including our credit ratings and general economic conditions;
declines in the market prices of debt and equity securities and resulting funding requirements for our defined benefit
pension plans;
the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as
a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or
divestiture;
42
•
•
the final resolutions or outcomes with respect to our contingent and other corporate liabilities related to the natural gas
distribution business and any related actions for indemnification made pursuant to the Separation and Distribution
Agreement; and
the costs associated with increased regulation and enhanced disclosure and corporate governance requirements
pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those
expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future
results. These and other risks are described in greater detail in Item 1A, Risk Factors, in this Annual Report. All forward-
looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors.
Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement
whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our exposure to market risk discussed below includes forward-looking statements. Our views on market risk are not
necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may
occur since actual gains and losses will differ from those estimated based on actual fluctuations in commodity prices or interest
rates and the timing of transactions.
Commodity Price Risk
Our commodity price risk, driven primarily by fluctuations in the price of natural gas, is mitigated by our purchased-gas cost
adjustment mechanisms. We use derivative instruments to economically hedge the cost of anticipated natural gas purchases
during the winter heating months to protect our customers from upward market price volatility of natural gas. Additionally, we
inject natural gas into storage during the summer months and withdraw the natural gas during the winter heating season. Gains
or losses associated with these derivative instruments and storage activities are included in, and recoverable through our
purchased-gas cost adjustment mechanisms, which are subject to review by regulatory authorities.
Interest-Rate Risk
We are exposed to interest-rate risk primarily associated with new debt financing needed to fund capital requirements,
including future contractual obligations and maturities of long-term and short-term debt. We expect to manage interest-rate risk
on future borrowings through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps
may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be
used to convert the fixed rates of long-term borrowings into short-term variable rates.
Counterparty Credit Risk
We assess the creditworthiness of our customers. Those customers who do not meet minimum standards are required to
provide security, including deposits and other forms of collateral, when appropriate. With more than 2 million customers
across three states, we are not exposed materially to a concentration of credit risk. We maintain a provision for doubtful
accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit
environment and other information. In most jurisdictions, we are able to recover natural gas costs related to uncollectible
accounts through our purchased-gas cost adjustment mechanisms.
43
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44
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of ONE Gas, Inc.:
In our opinion, the accompanying balance sheets and the related statements of income, comprehensive income, equity and cash
flows present fairly in all material respects, the financial position of ONE Gas, Inc. (the Company) at December 31, 2015 and
2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015 in
conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial
reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our
responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting
based on our audits (which were integrated audits in 2015 and 2014). We conducted our audits in accordance with the standards
of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our
audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
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 (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) 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 (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 18, 2016
45
ONE Gas, Inc.
STATEMENTS OF INCOME
Revenues
Cost of natural gas
Net margin
Operating expenses
Operations and maintenance
Depreciation and amortization
General taxes
Total operating expenses
Operating income
Other income
Other expense
Interest expense
Income before income taxes
Income taxes
Net income
Earnings per share
Basic
Diluted
Average shares (thousands)
Basic
Diluted
Dividends declared per share of stock
See accompanying Notes to Financial Statements.
Years Ended December 31,
2014
(Thousands of dollars, except per share amounts)
2013
2015
$
$
1,547,692
705,959
841,733
$
1,818,906
991,949
826,957
1,689,952
876,944
813,008
414,476
133,023
55,105
602,604
239,129
263
(2,813)
(44,570)
192,009
(72,979)
119,030
2.26
2.24
52,578
53,254
1.20
$
$
$
$
420,686
125,722
55,255
601,663
225,294
1,625
(2,949)
(45,842)
178,128
(68,338)
109,790
2.10
2.07
52,364
52,946
0.84
$
$
$
$
393,072
144,758
54,830
592,660
220,348
6,165
(3,680)
(61,366)
161,467
(62,272)
99,195
1.90
1.90
52,319
52,319
—
$
$
$
$
46
Years Ended December 31,
2014
2013
2015
(Thousands of dollars)
$
109,790
$
119,030
773
773
119,803
$
(1,781)
(1,781)
108,009
$
99,195
—
—
99,195
ONE Gas, Inc.
STATEMENTS OF COMPREHENSIVE INCOME
Net income
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plans liability, net of tax of
$(483), $1,244, and $0, respectively
Total other comprehensive income (loss), net of tax
Comprehensive income
See accompanying Notes to Financial Statements.
$
$
47
ONE Gas, Inc.
BALANCE SHEETS
Assets
Property, plant and equipment
Property, plant and equipment
Accumulated depreciation and amortization
Net property, plant and equipment
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Income tax receivable
Natural gas in storage
Regulatory assets
Other current assets
Total current assets
Goodwill and other assets
Regulatory assets
Goodwill
Other assets
Total goodwill and other assets
Total assets
See accompanying Notes to Financial Statements.
December 31, December 31,
2015
2014
(Thousands of dollars)
$
$
5,132,682
1,620,771
3,511,911
4,850,201
1,556,481
3,293,720
2,433
216,343
33,325
38,877
142,153
32,925
16,789
482,845
11,943
326,749
27,511
43,800
185,300
50,193
22,005
667,501
435,863
157,953
55,838
649,654
4,644,410
$
478,723
157,953
51,313
687,989
4,649,210
$
48
ONE Gas, Inc.
BALANCE SHEETS
(Continued)
Equity and Liabilities
Equity and long-term debt
Common stock, $0.01 par value:
December 31, December 31,
2015
2014
(Thousands of dollars)
authorized 250,000,000 shares; issued 52,598,005 shares and outstanding 52,259,224 shares at
December 31, 2015; authorized 250,000,000 shares, issued and outstanding 52,083,859 shares at
December 31, 2014
$
Paid-in capital
Retained earnings
Accumulated other comprehensive income (loss)
Treasury stock, at cost: 338,781 shares at December 31, 2015 and no shares at December 31, 2014
Total equity
Long-term debt, excluding current maturities
Total equity and long-term debt
Current liabilities
Current maturities of long-term debt
Notes payable
Accounts payable
Accrued interest
Accrued taxes other than income
Accrued liabilities
Customer deposits
Regulatory liabilities
Other current liabilities
Total current liabilities
Deferred credits and other liabilities
Deferred income taxes
Employee benefit obligations
Other deferred credits
Total deferred credits and other liabilities
Commitments and contingencies
Total liabilities and equity
See accompanying Notes to Financial Statements.
$
526
1,764,875
95,046
(4,401)
(14,491)
1,841,555
1,201,305
3,042,860
521
1,758,796
39,894
(5,174)
—
1,794,037
1,201,311
2,995,348
7
12,500
107,482
18,873
37,249
31,470
60,325
24,615
11,700
304,221
6
42,000
159,064
18,872
44,742
26,019
60,003
32,467
9,260
392,433
951,785
272,309
73,235
1,297,329
894,585
287,779
79,065
1,261,429
$
4,644,410
$
4,649,210
49
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50
ONE Gas, Inc.
STATEMENTS OF CASH FLOWS
Operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
119,030
$
109,790
$
99,195
2015
Years Ended December 31,
2014
(Thousands of dollars)
2013
Depreciation and amortization
Deferred income taxes
Share-based compensation expense
Provision for doubtful accounts
Changes in assets and liabilities:
Accounts receivable
Materials and supplies
Income tax receivable
Natural gas in storage
Asset removal costs
Affiliate payable
Accounts payable
Accrued interest
Accrued taxes other than income
Accrued liabilities
Customer deposits
Regulatory assets and liabilities
Employee benefit obligation
Other assets and liabilities
Cash provided by operating activities
Investing activities
Capital expenditures
Proceeds from sale of assets
Cash used in investing activities
Financing activities
Settlement of short-term notes payable to ONEOK, net
Borrowings on notes payable, net
Repurchase of common stock
Issuance of debt, net of discounts
Long-term debt financing costs
Cash payment to ONEOK upon separation
Issuance of common stock
Dividends paid
Repayment of long-term debt
Distributions to ONEOK
Cash provided by (used in) financing activities
Change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized
Cash paid to ONEOK for interest, net of amounts capitalized
Cash (received) paid for income taxes, net
Cash paid to ONEOK for income taxes
See accompanying Notes to Financial Statements.
$
$
$
$
$
51
133,023
63,789
9,187
4,520
105,886
(5,814)
4,923
43,147
(51,608)
—
(59,635)
1
(7,493)
5,451
322
50,658
(15,033)
(6,147)
394,207
(294,320)
—
(294,320)
—
(29,500)
(24,122)
—
—
—
7,051
(62,826)
—
—
(109,397)
(9,510)
11,943
2,433
125,722
49,935
7,613
7,195
23,044
10,868
(43,800)
(19,172)
(47,125)
—
(6,881)
18,743
12,316
21,228
2,643
30,067
(10,102)
(45,421)
246,663
(297,103)
—
(297,103)
—
42,000
—
1,199,994
(11,087)
(1,130,000)
2,001
(43,696)
—
—
59,212
8,772
3,171
11,943
$
$
42,980
$
— $
(5,423) $
— $
21,066
44,603
$
— $
$
— $
144,758
62,205
—
5,460
(102,142)
(1,668)
—
(63,139)
(46,567)
(8,140)
37,241
(1)
2,449
(5,443)
(727)
29,436
—
1,291
154,208
(292,080)
1,327
(290,753)
150,851
—
—
—
—
—
—
—
(206)
(14,969)
135,676
(869)
4,040
3,171
—
61,366
—
67
ONE Gas, Inc.
STATEMENTS OF EQUITY
January 1, 2013
Net income
Distributions to ONEOK
Common stock issued
December 31, 2013
Net income
Other comprehensive loss
Net transfers from ONEOK
Reclassification of Owner’s net investment to paid-in capital
Issuance of common stock at the separation
Common stock issued
Common stock dividends - $0.84 per share
December 31, 2014
Net income
Other comprehensive income
Repurchase of common stock
Common stock issued
Common stock dividends - $1.20 per share
December 31, 2015
See accompanying Notes to Financial Statements.
Common
Stock Issued
(Shares)
Common
Stock
Paid-in
Capital
(Thousands of dollars)
Retained
Earnings
— $
—
—
100
100
—
—
—
—
51,941,136
142,623
—
52,083,859
—
—
—
514,146
—
52,598,005 $
— $
—
—
—
—
—
—
—
—
520
1
—
521
—
—
—
5
—
526 $
— $
—
—
—
—
—
—
—
1,749,078
(520)
9,614
624
1,758,796
—
—
—
5,027
1,052
1,764,875 $
—
—
—
—
—
84,214
—
—
—
—
—
(44,320)
39,894
119,030
—
—
—
(63,878)
95,046
52
ONE Gas, Inc.
STATEMENTS OF EQUITY
(Continued)
Treasury
Stock
Owner’s Net
Investment
Accumulated
Other
Comprehensive
Income (Loss)
(Thousands of dollars)
Total Equity
January 1, 2013
Net income
Distributions to ONEOK
Common stock issued
December 31, 2013
Net income
Other comprehensive loss
Net transfers from ONEOK
Reclassification of Owner’s net investment to paid-in capital
Issuance of common stock at the separation
Common stock issued
Common stock dividends - $0.84 per share
December 31, 2014
Net income
Other comprehensive income
Repurchase of common stock
Common stock issued
Common stock dividends - $1.20 per share
December 31, 2015
See accompanying Notes to Financial Statements.
$
$
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(24,122)
9,631
—
(14,491) $
1,154,797 $
99,195
(14,969)
—
1,239,023
25,576
—
484,479
(1,749,078)
—
—
—
—
—
—
—
—
—
— $
— $
—
—
—
—
—
(1,781)
(3,393)
—
—
—
—
(5,174)
—
773
—
—
—
(4,401) $
1,154,797
99,195
(14,969)
—
1,239,023
109,790
(1,781)
481,086
—
—
9,615
(43,696)
1,794,037
119,030
773
(24,122)
14,663
(62,826)
1,841,555
53
ONE Gas, Inc.
NOTES TO FINANCIAL STATEMENTS
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations - Prior to January 31, 2014, ONE Gas was a wholly owned subsidiary of ONEOK
and comprised its former natural gas distribution business. On January 8, 2014, ONEOK’s board of directors approved the
distribution of all the shares of our common stock to holders of ONEOK common stock. On January 31, 2014, we became an
independent, publicly traded company as a result of a distribution by ONEOK of our common stock to ONEOK’s shareholders.
Our common stock began trading “regular-way” under the ticker symbol “OGS” on the NYSE on February 3, 2014.
We provide natural gas distribution services to more than 2 million customers through our divisions in Oklahoma, Kansas and
Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential,
commercial, industrial and transportation customers in all three states. In addition, we also provide natural gas distribution
services to wholesale and public authority customers.
Basis of Presentation - Prior to our separation from ONEOK, our financial statements were derived from ONEOK’s financial
statements, which included its natural gas distribution business as if we, for accounting purposes, had been a separate company
for all periods presented. The assets and liabilities in the financial statements have been reflected on a historical basis. The
financial statements for periods prior to the separation also include expense allocations for certain corporate functions
historically performed by ONEOK, including allocations of general corporate expenses related to executive oversight,
accounting, treasury, tax, legal, information technology and other services. We believe our assumptions underlying the
financial statements, including the assumptions regarding the allocation of general corporate expenses from ONEOK, are
reasonable. However, the financial statements may not include all of the actual expenses that would have been incurred by us
and may not reflect our results of operations, financial position and cash flows had we been a separate publicly traded company
during the periods presented prior to the separation.
Because the operations of the natural gas distribution business within ONEOK were conducted through separate divisions,
ONEOK’s net investment in us, excluding the long-term line of credit with ONEOK, is shown as owner’s net investment in lieu
of equity in the financial statements prior to the separation. Transactions between ONEOK and us that were not part of the
long-term line of credit with ONEOK or the short-term note payable to ONEOK have been identified in the Statements of
Equity as a net transfer from ONEOK.
All financial information presented after the separation represents the results of operations, financial position and cash flows of
ONE Gas. Accordingly:
• Our Statements of Income and Comprehensive Income for the year ended December 31, 2014, consist of the results of
ONE Gas for the eleven months ended December 31, 2014, and the results of ONE Gas Predecessor for the one month
ended January 31, 2014. Our Statements of Income and Comprehensive Income for the year ended December 31,
2013, consist entirely of the results of ONE Gas Predecessor. Our net income for the period prior to January 31, 2014,
was recorded to owner’s net investment.
• Our Statement of Cash Flows for the year ended December 31, 2014, consists of the results of ONE Gas for the eleven
months ended December 31, 2014, and the results of ONE Gas Predecessor for the one month ended January 31, 2014.
Our Statement of Cash Flows for the year ended December 31, 2013, consists entirely of the results of ONE Gas
Predecessor.
• Our Statement of Equity for the year ended December 31, 2014, consists of both the activity for ONE Gas Predecessor
prior to January 31, 2014, and the activity for ONE Gas completed in connection with, and subsequent to, the
separation on January 31, 2014. Our Statement of Equity for the year ended December 31, 2013, consists entirely of
the results of ONE Gas Predecessor.
The financial statements include the accounts of the natural gas distribution business as set forth in “Organization and Nature of
Operations” above. All significant balances and transactions between our divisions have been eliminated.
Use of Estimates - The preparation of our financial statements and related disclosures in accordance with GAAP requires us to
make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the
reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial
statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting
period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and
liabilities, provisions for doubtful accounts receivable, unbilled revenues for natural gas delivered but for which meters have
54
not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any
deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.
We evaluate these estimates on an ongoing basis using historical experience and other methods we consider reasonable based
on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our
financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give
rise to the revision become known.
Fair Value Measurements - We define fair value as the price that would be received from the sale of an asset or the transfer of
a liability in an orderly transaction between market participants at the measurement date. We use the market and income
approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are
executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant
would price the net risk exposure at the measurement date.
Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or
disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the
hierarchy are described below:
• Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;
• Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly
or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or
corroborated by observable market data; and
• Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These
unobservable inputs are developed based on the best information available and may include our own internal data.
We recognize transfers into and out of the levels as of the end of each reporting period.
Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires
management’s judgment regarding the degree to which market data is observable or corroborated by observable market data.
We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest
level input that is significant to the fair value measurement in its entirety. See Note 8 for additional information regarding our
fair value measurements.
Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash
and have original maturities of three months or less.
Revenue Recognition - For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We
recognize revenues upon the delivery of the natural gas commodity or services rendered to customers. The billing cycles for
customers do not necessarily coincide with the accounting periods used for financial reporting purposes. Revenues are accrued
for natural gas delivered and services rendered to customers, but not yet billed. Accrued unbilled revenue is based on a
percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require
management’s judgment. These factors include customer consumption patterns and the impact of weather on usage. The
amounts of accrued unbilled natural gas sales revenues at December 31, 2015 and 2014, were $109.6 million and $141.7
million, respectively.
Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for natural gas sold or
services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our customers. Those customers
who do not meet minimum standards are required to provide security, including deposits and other forms of collateral, when
appropriate. With more than 2 million customers across three states, we are not exposed materially to a concentration of credit
risk. We maintain an allowance for doubtful accounts based upon factors surrounding the credit risk of customers, historical
trends, consideration of the current credit environment and other information. In Oklahoma, Kansas and most jurisdictions we
serve in Texas, we are able to recover natural gas costs related to doubtful accounts through purchased-gas cost adjustment
mechanisms. At December 31, 2015 and 2014, our allowance for doubtful accounts was $3.5 million and $4.0 million,
respectively.
Inventories - Natural gas in storage is maintained on the basis of weighted-average cost. Natural gas inventories that are
injected into storage are recorded in inventory based on actual purchase costs, including storage and transportation costs.
Natural gas inventories that are withdrawn from storage are accounted for in our purchased-gas cost adjustment mechanisms at
the weighted-average inventory cost.
55
Materials and supplies inventories, which are included in other current assets on our Balance Sheets, are stated at the lower of
weighted-average cost or net realizable value. Our materials and supplies inventories totaled $33.3 million and $27.5 million at
December 31, 2015 and 2014, respectively.
Derivatives and Risk Management Activities - We record all derivative instruments at fair value, with the exception of
normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value
of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so,
the reason for holding it, or if regulatory rulings require a different accounting treatment.
If certain conditions are met, we may elect to designate a derivative instrument as a hedge of exposure to changes in fair values
or cash flows.
The table below summarizes the various ways in which we account for our derivative instruments and the impact on our
financial statements:
Accounting Treatment
Balance Sheet
Income Statement
Recognition and Measurement
Normal purchases and
normal sales
Mark-to-market
- Fair value not recorded
- Change in fair value not recognized in earnings
- Recorded at fair value
- Change in fair value recognized in, and
recoverable through, the purchased-gas cost
adjustment mechanisms
We have not elected to designate any of our derivative instruments as hedges. Gains or losses associated with the fair value of
commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost
adjustment mechanisms.
See Note 8 for additional information regarding our fair value measurements and hedging activities using derivatives.
Property, Plant and Equipment - Our properties are stated at cost, which includes direct construction costs such as direct
labor, materials, burden and AFUDC. Generally, the cost of our property retired or sold, plus removal costs, less salvage, is
charged to accumulated depreciation. Gains and losses from sales or retirement of an entire operating unit or system of our
properties are recognized in income. Maintenance and repairs are charged directly to expense.
AFUDC represents the cost of borrowed funds used to finance construction activities. We capitalize interest costs during the
construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense.
Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, we apply composite
depreciation rates to functional groups of property having similar economic circumstances. We periodically conduct
depreciation studies to assess the economic lives of our assets. These depreciation studies are completed as a part of our rate
proceedings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are effective.
Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial
position, results of operations or cash flows.
Property, plant and equipment on our Balance Sheets includes construction work in process for capital projects that have not yet
been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when
they are substantially complete and ready for their intended use.
See Note 10 for additional information regarding our property, plant and equipment.
Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually as of July 1. Total
goodwill was $158.0 million at December 31, 2015 and 2014, respectively. Our goodwill impairment analysis performed in
2015, 2014 and 2013, utilized a qualitative assessment and did not result in any impairment indicators. Subsequent to July 1,
2015, no event has occurred indicating that it is more likely that not that our fair value is less than our carrying value of our net
assets.
As part of our goodwill impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and
market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that our
56
fair value is less than our carrying amount. If further testing is necessary, we perform a two-step impairment test for goodwill.
In the first step, an initial assessment is made by comparing our fair value with our book value, including goodwill. If the fair
value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the
impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible
and intangible net assets from the fair value determined in step one of the assessment. If the carrying value of the goodwill
exceeds the implied fair value of the goodwill, we will record an impairment charge.
To estimate our fair value, we use two generally accepted valuation approaches, an income approach and a market approach,
using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash
flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount
rates. Under the market approach, we apply acquisition multiples to forecasted cash flows. The acquisition multiples used are
consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows over a
period of years.
We assess our long-lived assets for impairment whenever events or changes in circumstances indicate that an asset’s carrying
amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the
undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is
indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived
asset. We determined that there were no asset impairments in 2015, 2014 or 2013.
Regulation - We are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various
municipalities in Texas. We follow the accounting and reporting guidance for regulated operations. During the ratemaking
process, regulatory authorities set the framework for what we can charge customers for our services and establish the manner
that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the
amounts through rates over time, as opposed to expensing such costs as incurred. Examples include weather normalization,
unrecovered purchased-gas costs, pension and postemployment benefit costs and ad valorem taxes. This allows us to stabilize
rates over time rather than passing such costs on to the customer for immediate recovery. Actions by regulatory authorities
could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount
deferred is recorded as income or expense at the time of the regulatory action. A write-off of regulatory assets and costs not
recovered may be required if all or a portion of the regulated operations have rates that are no longer:
•
•
•
established by independent regulators;
designed to recover the specific entity’s costs of providing regulated services; and
set at levels that will recover our costs when considering the demand and competition for our services.
See Note 9 for additional information regarding our regulatory assets and liabilities disclosures.
Pension and Other Postemployment Employee Benefits - We have defined benefit retirement plans covering eligible
employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible
employees who retire with at least five years of service. To calculate the costs and liabilities related to our plans, we utilize an
outside actuarial consultant, which uses statistical and other factors to anticipate future events. These factors include
assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and mortality
and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to
period and may result in material changes in the cost and liabilities we recognize.
Prior to the separation, certain employees participated in pension and other postemployment employee benefit plans sponsored
by ONEOK. We accounted for these plans as multiemployer benefit plans. Accordingly, we did not record an asset or liability
to recognize the funded status of these plans. We recognized a liability only for any required contributions to those plans that
were accrued and unpaid at the balance sheet date. The related pension and other postemployment expenses were allocated to
us based on plan participants who directly supported our operations. These pension and other postemployment benefit costs
included amounts associated with vested participants who are no longer employees.
Prior to the separation, certain benefit costs associated with employees who directly supported our operations were determined
based on a specific employee basis. We were also allocated benefit costs associated with employees of ONEOK that provided
general corporate services. These amounts were charged to us by ONEOK as described in Note 2. Prior to the separation, we
were not the plan sponsor for the ONEOK pension and other postemployment benefit plans. Accordingly, our balance sheets
prior to the separation do not reflect any assets or liabilities related to these plans. See Note 12 for additional information
regarding pension and other postemployment employee benefit plans.
57
Income Taxes - Deferred income taxes are recorded for the difference between the financial statement and income tax basis of
assets and liabilities and carryforward items, based on income tax laws and rates existing at the time the temporary differences
are expected to reverse. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated
by the OCC, KCC, RRC and various municipalities in Texas, if, as a result of an action by a regulator, it is probable that the
effect of the change in tax rates will be recovered from or returned to customers through future rates. We continue to amortize
previously deferred investment tax credits for ratemaking purposes over the periods prescribed by our regulators.
A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from
the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future
taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation
allowance is required. Such evidence can include our current financial position, our results of operations, both actual and
forecasted, the reversal of deferred tax liabilities, as well as the current and forecasted business economics of our industry. We
had no valuation allowance at December 31, 2015 and 2014.
We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and
measurement of a tax position that is taken or expected to be taken in a tax return. We reflect penalties and interest as part of
income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition
threshold and measurement attribute. There were no material uncertain tax positions at December 31, 2015 and 2014.
See Note 13 for additional information regarding income taxes.
Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-
lived assets that result from the acquisition, construction, development and/or normal use of the asset. Certain long-lived assets
that comprise our natural gas distribution systems, primarily our pipeline assets, are subject to agreements or regulations that
give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon
the discontinued use of the natural gas distribution system. We recognize the fair value of a liability for an asset retirement
obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate
reasonably the fair value of the asset retirement obligations for portions of our assets because the settlement dates are
indeterminable given our expected continued use of the assets with proper maintenance. We expect our natural gas distribution
systems will continue in operation as long as natural gas supply and demand for natural gas distribution service exists. Based
on the widespread use of natural gas for heating and cooking activities by residential and commercial customers in our service
areas, management expects supply and demand to exist for the foreseeable future.
In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain
regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization.
These removal costs collected through our rates include costs attributable to legal and nonlegal removal obligations; however,
the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory
liability for financial reporting purposes. Historically, with the exception of the regulatory authority in Kansas, the regulatory
authorities that have jurisdiction over our regulated operations have not required us to quantify or disclose this amount; rather,
these costs are addressed prospectively in depreciation rates and are set in each general rate order. We have made an estimate
of our regulatory liability using current rates since the last general rate order in each of our jurisdictions; however, for financial
reporting purposes, significant uncertainty exists regarding the future disposition of this regulatory liability, pending, among
other issues, clarification of regulatory intent. We continue to monitor the regulatory requirements, and the liability may be
adjusted as more information is obtained. We record the estimated asset removal obligation in noncurrent liabilities in other
deferred credits on our Balance Sheets. To the extent this estimated liability is adjusted, such amounts will be reclassified
between accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on
earnings.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and
environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred
and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution.
Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion
of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets
when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or
negative, on earnings. See Note 14 for additional information regarding contingencies.
Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate
forfeiture rates based on historical forfeitures under our share-based payment plans.
58
Prior to the separation, ONEOK charged us for compensation expense related to stock-based compensation awards granted to
our employees that directly supported our operations. Share-based compensation was also a component of allocated amounts
charged to us by ONEOK for general and administrative personnel providing services on our behalf.
Earnings per share - Basic EPS is based on net income and is calculated based upon the daily weighted-average number of
common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have
not yet been issued as common stock. Diluted EPS includes the above, plus unvested stock awards granted under our
compensation plans, but only to the extent these instruments dilute earnings per share.
Segments - We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential,
commercial, industrial and transportation customers. We define reportable business segments as components of an organization
for which discrete financial information is available and operating results are evaluated on a regular basis by the chief operating
decision maker (CODM) in order to assess performance and allocate resources. Our CODM is our Chief Executive Officer
(CEO). Characteristics of our organization that were relied upon in making this determination include the similar nature of
services we provide, the functional alignment of our organizational structure, and the reports that are regularly reviewed by the
CODM for the purpose of assessing performance and allocating resources. Our management is functionally aligned and
centralized, with performance evaluated based upon results of the entire distribution business. Capital allocation decisions are
driven by asset integrity management and operating efficiency, not geographic location.
We evaluate performance based principally on operating income. Affiliate sales are recorded on the same basis as sales to
unaffiliated customers and are discussed in further detail in Note 2. Net margin is comprised of total revenues less cost of
natural gas. Cost of natural gas includes commodity purchases, fuel, storage and transportation costs and does not include an
allocation of general operating costs or depreciation and amortization.
In 2015, 2014 and 2013, we had no single external customer from which we received 10 percent or more of our gross revenues.
Treasury Stock - We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are
recorded as reductions in equity in our Balance Sheets. We record the reissuance of treasury stock at our weighted average cost
of treasury shares recorded in equity in our Balance Sheets.
Recently Issued Accounting Standards Update - In October 2015, the FASB issued ASU 2015-17, “Balance Sheet
Classification of Deferred Taxes,” to simplify reporting of deferred taxes. The new guidance requires all deferred tax assets
and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This guidance is
required to be adopted for our interim and annual reports for periods beginning after December 15, 2016, but early adoption is
permitted. We have adopted this guidance early to simplify our financial reporting process, have applied it prospectively for
the period beginning October 1, 2015, and it did not have a material impact on our financial statements. Prior periods were not
retrospectively adjusted.
In August 2015, the FASB issued ASU 2015-15, “Interest-Imputation of Interest (Subtopic 835-30),” which specifically
addresses the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We
do not expect this issued guidance, which will be adopted concurrently with ASU 2015-03, to have a material impact on our
financial statements.
In April 2015, the FASB issued ASU 2015-03, “Interest-Imputation of Interest,” which requires that debt issuance costs related
to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt
liability. We do not expect this issued guidance, which is required to be adopted for our interim and annual reports for periods
beginning after December 15, 2015, to have a material impact on our financial statements.
In April 2015, the FASB issued ASU 2015-05, “Intangibles-Goodwill and Other-Internal-Use Software,” which helps entities
evaluate the accounting for fees paid by a customer in a cloud computing arrangement. We do not expect this issued guidance,
which is required to be adopted for our interim and annual reports for periods beginning after December 15, 2015, to have a
material impact on our financial statements.
In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which clarifies and converges the
revenue recognition principles under GAAP and IFRS. In July 2015, FASB delayed the effective date of ASU 2014-09 for one
year. We are evaluating the impact of this recently issued guidance, which is required to be adopted for our interim and annual
reports beginning with the first quarter 2018.
59
2.
SEPARATION & RELATED-PARTY TRANSACTIONS
Distribution - On January 8, 2014, ONEOK’s board of directors approved the distribution of our common stock to holders of
ONEOK common stock.
In order for ONEOK to effect the distribution, we requested, and the SEC declared effective, our Registration Statement on
Form 10 on January 10, 2014. ONEOK transferred all of the assets and liabilities primarily related to its natural gas
distribution business to us. Assets and liabilities included accounts receivable and payable, natural gas in storage, regulatory
assets and liabilities, pipeline and other natural gas distribution facilities, customer deposits, employee-related assets and
liabilities, including amounts attributable to pension and other postemployment benefits, tax-related assets and liabilities and
other assets and liabilities primarily associated with providing natural gas distribution service in Oklahoma, Kansas and Texas.
Cash and certain corporate assets, such as office space in the corporate headquarters and certain IT hardware and software,
were not transferred to us; however, a Transition Services Agreement between ONEOK and us provided access to such
corporate assets as necessary to operate our business for a period of time to enable us to obtain the applicable corporate assets.
Immediately prior to the contribution of the natural gas distribution business to us, ONEOK contributed to the capital of the
natural gas distribution business all of the amounts outstanding on the natural gas distribution business’ short-term note payable
to and long-term line of credit with ONEOK. We received approximately $1.19 billion of cash from a private placement of
senior notes, which were later exchanged for registered notes, then used a portion of those proceeds to fund a cash payment of
approximately $1.13 billion to ONEOK. Effective January 31, 2014, the number of our authorized shares increased to 250
million shares of common stock and 50 million of preferred stock. On January 31, 2014, ONEOK distributed one share of our
common stock for every four shares of ONEOK common stock held by ONEOK shareholders of record as of the close of
business on January 21, 2014, the record date of the distribution. At the close of business on January 31, 2014, we became an
independent, publicly traded company as a result of the distribution.
Reorganization Adjustments - We entered into the Separation and Distribution Agreement and several other agreements with
ONEOK to effect the separation and provide a framework for our relationships with ONEOK after the distribution. These
agreements govern the relationship between ONEOK and us subsequent to the completion of the distribution, and provide for
the allocation among ONEOK and us of the assets, liabilities and obligations (including employee benefits and tax-related
assets and liabilities) relating to the natural gas distribution business attributable to periods prior to, at and after the distribution.
In accordance with the terms of the Separation and Distribution Agreement, ONEOK contributed the assets and liabilities of its
natural gas distribution business to us. The noncash contributions below represent ONEOK assets and liabilities attributable to
pension and other postemployment employee benefits, general corporate assets and liabilities and related deferred taxes not
included previously in the ONE Gas Predecessor balance sheet, but the costs for which were included in ONE Gas
Predecessor’s results of operations. The table below also includes the contribution of the short-term note payable to and long-
term line of credit with ONEOK previously included in ONE Gas Predecessor balance sheets. The assets and liabilities below
were recorded at historical cost as the reorganization was among entities under common control. Net transfers from ONEOK
included:
(Thousands of dollars)
Property, plant and equipment, net
Regulatory assets, pension and other postemployment benefits
Other assets
Long-term line of credit with ONEOK
Short-term note payable to ONEOK
Pension and other postemployment benefits - liabilities
Other liabilities
Deferred taxes
Accumulated other comprehensive loss
Net contribution of assets (liabilities)
Less: Cash paid to ONEOK
Net transfers from ONEOK
$
$
$
21,459
331,148
80,700
1,027,631
397,857
(123,800)
(34,404)
(86,112)
(3,393)
1,611,086
1,130,000
481,086
Affiliate Transactions - Prior to our separation, we had certain transactions with ONEOK and its subsidiaries. We purchased a
portion of our natural gas supply and natural gas transportation and storage services from ONEOK and its affiliates. These
60
contracts were awarded through a competitive-bidding process, and the costs were recoverable through our purchased-gas cost
adjustment mechanisms.
Prior to our separation, the Statements of Income included expense allocations for certain corporate functions historically
performed by ONEOK and allocated to its natural gas distribution business, including allocations of general corporate expenses
related to executive oversight, accounting, treasury, tax, legal, information technology and facilities maintenance. Where costs
were incurred specifically on our behalf, the costs were billed directly to us by ONEOK. In other situations, the costs were
allocated to us through a variety of methods, depending upon the nature of the expenses. For example, a service that applied
equally to all employees of ONEOK was allocated based upon the number of employees in each ONEOK affiliate. An expense
benefiting us but having no direct basis for allocation was allocated by the modified Distrigas method, a method using a
combination of ratios that include gross plant and investment, operating income and payroll expense. It is not practicable to
determine what these general overhead costs would be on a stand-alone basis. These allocations included the following costs:
Corporate Services - These represent costs for certain employees of ONEOK who provided general and administrative services
on our behalf. These charges were either directly identifiable or allocated based upon usage factors for our operations. In
addition, we received other allocated costs for our share of general corporate expenses of ONEOK, which were determined
based on our relative use of the service or, if there was no direct basis for allocation, were allocated by the modified Distrigas
method. All of these costs are reflected in operations and maintenance and depreciation expense in the Statements of Income.
Benefit Plans and Incentives - These represent benefit costs and other incentives, including group health and welfare benefits,
pension plans, other postemployment benefit plans and employee stock-based compensation plans. Costs associated with
incentive and stock-based compensation plans were determined on a specific identification basis for certain employees who
directly supported our operations. All other employee benefit costs historically were allocated using a percentage factor
derived from a ratio of benefit costs to salary costs for ONEOK’s employees. These expenses are included in operations and
maintenance expenses in the Statements of Income.
Total compensation cost, which included costs for both employees who directly supported our operations and allocations for
corporate services, charged to us by ONEOK related to share-based payment plans was $15.5 million during 2013.
Compensation costs charged to us by ONEOK in 2014 were not material. See Note 11 for additional information regarding
share-based payments. Total cost charged to us by ONEOK related to pension and other postemployment health and welfare
plans was $52.1 million during 2013, which is net of amounts deferred through regulatory mechanisms of $1.8 million during
2013. Cost related to pension and other postemployment health and welfare plans which was charged to us by ONEOK in 2014
was not material. See Note 12 for additional information regarding employee benefit plans.
Interest Expense - ONEOK utilized a centralized approach to cash management and the financing of its businesses. Cash
receipts and cash expenditures for costs and expenses from our operations were transferred to or from ONEOK on a regular
basis and recorded as increases or decreases in the balance due in short-term note payable to ONEOK under an unsecured
promissory note we had in place with ONEOK. The amounts outstanding under the long-term line of credit with ONEOK and
the short-term note payable to ONEOK accrued interest based on ONEOK’s weighted-average cost of long-term and short-term
debt, respectively.
The weighted average interest rate on amounts outstanding under the long-term line of credit with ONEOK was 5.79 percent in
2013. The interest rate on the revolver was reset each year based on ONEOK’s outstanding debt plus an adjustment of 50 basis
points for ONEOK’s cost to administer the program.
The weighted-average interest rate for the short-term notes payable to ONEOK was 0.92 percent for 2013. Principal under
these notes payable beared interest based on ONEOK’s weighted-average cost of short-term debt, plus a utilization fee of 50
basis points, calculated monthly.
61
The following table shows ONEOK’s and its subsidiaries’ transactions with us included in the Statements of Income for the
periods indicated:
Cost of natural gas
Operations and maintenance
Direct employee labor and benefit costs
Allocated employee labor and benefit costs
Charges for general and administrative services
Depreciation and amortization
Other (income)/expense, net
Interest expense
Total
Year Ended December 31,
2013
(Thousands of dollars)
$
$
226,582
177,526
29,955
36,078
6,940
(5,073)
60,930
532,938
Employee labor and benefit costs capitalized totaled $49.3 million for 2013. In addition, we recorded regulated utility revenue
from ONEOK and its subsidiaries. This amount was immaterial for the period presented.
The remaining related party transactions prior to the separation were not material in 2014.
3.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE
ONE Gas Credit Agreement - The ONE Gas Credit Agreement contains certain financial, operational and legal covenants.
Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the
end of any calendar quarter. The ONE Gas Credit Agreement also contains customary affirmative and negative covenants,
including covenants relating to liens, indebtedness of subsidiaries, investments, changes in the nature of business, fundamental
changes, transactions with affiliates, burdensome agreements, and use of proceeds. In the event of a breach of certain
covenants by ONE Gas, amounts outstanding under the ONE Gas Credit Agreement may become due and payable immediately.
At December 31, 2015, our total debt-to-capital ratio was 40 percent and we were in compliance with all covenants under the
ONE Gas Credit Agreement.
The ONE Gas Credit Agreement includes a $50 million sublimit for the issuance of standby letters of credit and also features an
option to request an increase in the size of the facility to an aggregate of $1.2 billion from $700 million by either commitments
from new lenders or increased commitments from existing lenders. Borrowings made under the facility are available for
general corporate purposes. The ONE Gas Credit Agreement contains provisions for an applicable margin rate and an annual
facility fee, both of which adjust with changes in our credit rating. Based on our current credit ratings, borrowings, if any, will
accrue interest at LIBOR plus 79.5 basis points, and the annual facility fee is 8 basis points.
We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of
$700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary but may not exceed
270 days from the date of issue. The commercial paper notes are sold generally at par less a discount representing an interest
factor.
The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the
commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. At December 31, 2015, we
had $12.5 million of commercial paper and $1.0 million in letters of credit issued under the ONE Gas Credit Agreement, with
no borrowings and $686.5 million of remaining credit available under the ONE Gas Credit Agreement. The weighted-average
interest rate on our commercial paper was 0.70 percent and 0.32 percent at December 31, 2015 and 2014, respectively.
4.
LONG-TERM DEBT
Senior notes issuance - In January 2014, we issued senior notes, consisting of $300 million of 2.07 percent senior notes due
2019, $300 million of 3.61 percent senior notes due 2024 and $600 million of 4.658 percent senior notes due 2044
(collectively, our “Senior Notes”). The net proceeds were approximately $1.19 billion and were used to fund a one-time cash
62
payment to ONEOK of approximately $1.13 billion as part of the separation. The remaining portion of the net proceeds was
retained in order to provide sufficient financial flexibility and to support working capital requirements and capital expenditures.
The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100
million or more. Such events of default would entitle the trustee or the holders of 25 percent in the aggregate principal amount
of the outstanding Senior Notes to declare those senior notes immediately due and payable in full.
We may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date, starting one month, three
months, and six months, respectively, before their maturity dates. Prior to these dates, we may redeem these Senior Notes, in
whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole
premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued
and unpaid interest to the redemption date. Our Senior Notes are senior unsecured obligations, ranking equally in right of
payment with all of our existing and future unsecured senior indebtedness.
5.
EQUITY
Preferred Stock - At December 31, 2015, we have 50 million, $0.01 par value, authorized shares of preferred stock available.
We have not issued or established any classes or series of shares of preferred stock.
Common Stock - At December 31, 2015, we had approximately 197.4 million shares of authorized common stock available for
issuance.
Treasury Shares - We purchase treasury shares to be used to offset shares issued under our employee and non-employee
director equity compensation and employee stock purchase plans. Our Board of Directors established an annual limit of $20
million of treasury stock purchases, exclusive of funds received through the dividend reinvestment and employee stock
purchase plans. Stock purchases may be made in the open market or in private transactions at times, and in amounts that we
deem appropriate. There is no guarantee as to the exact number of shares that we purchase, and we can terminate or limit the
program at any time. We hold the purchased shares as treasury shares and account for them using the cost method.
Dividends Declared - In January 2016, a dividend of $0.35 per share ($1.40 per share on an annualized basis) was declared for
shareholders of record on February 26, 2016, payable March 11, 2016.
63
6.
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following table sets forth the balance in accumulated other comprehensive income (loss) for the period indicated:
Accumulated Other
Comprehensive
Income (Loss)
(Thousands of dollars)
—
$
January 1, 2014
Transfers in upon separation
Pension and other postemployment benefit plans obligations
Other comprehensive income (loss) before reclassification, net of tax of $1,442
Amounts reclassified from accumulated other comprehensive income (loss), net of tax of $(198)
Other comprehensive income (loss)
December 31, 2014
Pension and other postemployment benefit plans obligations
Other comprehensive income (loss) before reclassification, net of tax of $(130)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax of $(353)
Other comprehensive income (loss)
December 31, 2015
$
(3,393)
(2,096)
315
(1,781)
(5,174)
209
564
773
(4,401)
The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) on our
Statements of Income for the period indicated:
Details about Accumulated Other Comprehensive Income
Year Ended December 31,
Affected Line Item in the
(Loss) Components
2015
2014
Statements of Income
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss
Amortization of unrecognized prior service cost
Regulatory adjustments (b)
Total reclassifications for the period
(Thousands of dollars)
$
$
47,494
(1,962)
45,532
(44,615)
917
(353)
564
$
$
34,169
(1,211)
32,958
(32,445)
513 Income before income taxes
(198) Income tax expense
315 Net income
(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See
Note 12 for additional information regarding our net periodic benefit cost.
(b) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred
as part of our regulatory assets. See Note 9 for additional information regarding our regulatory assets and liabilities.
7.
EARNINGS PER SHARE
The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:
Year Ended December 31, 2015
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
Basic EPS Calculation
Net income available for common stock
Diluted EPS Calculation
Effect of dilutive securities
Net income available for common stock and common stock equivalents
$
$
119,030
52,578
$
2.26
—
119,030
676
53,254
$
2.24
64
Basic EPS Calculation
Net income available for common stock
Diluted EPS Calculation
Effect of dilutive securities
Net income available for common stock and common stock equivalents
Basic EPS Calculation
Net income available for common stock
Diluted EPS Calculation
Effect of dilutive securities
Net income available for common stock and common stock equivalents
$
$
$
$
Year Ended December 31, 2014
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
109,790
52,364
$
2.10
—
109,790
582
52,946
$
2.07
Year Ended December 31, 2013
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
99,195
52,319
$
1.90
—
99,195
—
52,319
$
1.90
On January 31, 2014, 51,941,236 shares of our common stock were distributed to ONEOK shareholders in conjunction with the
separation. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding,
we have assumed this amount and any shares associated with fully vested stock awards that have not been issued to be
outstanding as of the beginning of each period prior to the separation presented in the calculation of weighted-average shares.
8.
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS
Derivative Instruments - At December 31, 2015, we held purchased natural gas call options for the heating season ending
March 2016, with total notional amounts of 17.0 Bcf, for which we paid premiums of $5.8 million, and had a fair value of $0.4
million. At December 31, 2014, we held purchased natural gas call options for the heating season ended March 2015, with
total notional amounts of 16.0 Bcf, for which we paid premiums of $6.4 million, and had a fair value of $0.1 million. The
premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in current
regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.
Additionally, changes in fair value associated with these contracts are deferred as part of our unrecovered purchased-gas costs
in our Balance Sheets. Our natural gas call options are classified as Level 1 as fair value amounts are based on unadjusted
quoted prices in active markets including NYMEX-settled prices. There were no transfers between levels for the periods
presented.
Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts
payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of
bank and money market accounts, and are classified as Level 1.
Short-term notes payable and commercial paper are due upon demand and, therefore, the carrying amounts approximate fair
value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $1.2 billion at both
December 31, 2015 and 2014. The estimated fair value of our long-term debt, including current maturities, was $1.2
billion and $1.3 billion at December 31, 2015 and 2014, respectively. The estimated fair value of our Senior Notes was
determined using quoted market prices, and are considered Level 2.
65
9.
REGULATORY ASSETS AND LIABILITIES
The table below presents a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
December 31, 2015
Under-recovered purchased-gas costs
Pension and other postemployment benefit costs
Weather normalization
Reacquired debt costs
Other
Total regulatory assets, net of amortization
Accumulated removal costs (a)
Over-recovered purchased-gas costs
Ad valorem tax
Total regulatory liabilities
Net regulatory assets and liabilities
(a) Included in other deferred credits in our Balance Sheets.
Under-recovered purchased-gas costs
Pension and other postemployment benefit costs
Reacquired debt costs
Other
Total regulatory assets, net of amortization
Accumulated removal costs (a)
Weather normalization
Over-recovered purchased-gas costs
Ad valorem tax
Total regulatory liabilities
Net regulatory assets and liabilities
(a) Included in other deferred credits in our Balance Sheets.
Remaining
Recovery Period
1 year
See Note 12
1 year
12 years
1 to 23 years
up to 50 years
1 year
1 year
Remaining
Recovery Period
1 year
See Note 12
13 years
1 to 24 years
up to 50 years
1 year
1 year
1 year
Current
Noncurrent
(Thousands of dollars)
— $
$
$ 13,336
15,670
2,198
812
909
32,925
—
(22,884)
(1,731)
(24,615)
425,175
—
8,919
1,769
435,863
(9,032)
—
—
(9,032)
Total
13,336
440,845
2,198
9,731
2,678
468,788
(9,032)
(22,884)
(1,731)
(33,647)
$
8,310
$
426,831
$ 435,141
December 31, 2014
Current
Noncurrent
(Thousands of dollars)
— $
$
Total
$ 28,712
18,108
812
2,561
50,193
—
(16,516)
(13,055)
(2,896)
(32,467)
$ 17,726
466,684
9,730
2,309
478,723
(15,451)
—
—
—
(15,451)
463,272
$
28,712
484,792
10,542
4,870
528,916
(15,451)
(16,516)
(13,055)
(2,896)
(47,918)
$ 480,998
Regulatory assets on our Balance Sheets, as authorized by the various regulatory authorities, are probable of recovery. Base
rates are designed to provide a recovery of cost during the period rates are in effect but do not generally provide for a return on
investment for amounts we have deferred as regulatory assets. All of our regulatory assets recoverable through base rates are
subject to review by the respective regulatory authorities during future rate proceedings. We are not aware of any evidence that
these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such
costs, consistent with our historical recoveries.
Purchased-gas costs represent the natural gas costs that have been over- or under-recovered from customers through the
purchased-gas cost adjustment mechanisms, and includes natural gas utilized in our operations and premiums paid and any cash
settlements received from our purchased natural gas call options.
We amortize reacquired debt costs in accordance with the accounting guidelines prescribed by the OCC and KCC.
In December 2013, the KCC approved a settlement agreement between ONEOK, the staff of the KCC, and the Citizens’ Utility
Ratepayer Board that authorized the transfer of ONEOK’s Kansas Gas Service natural gas distribution assets to us. As a result,
Kansas Gas Service expensed certain transition costs associated with ONEOK’s acquisition of Kansas Gas Service in 1997 that
previously had been recorded as a regulatory asset and amortized and recovered in rates over a 40-year period. As such, we
recorded a noncash charge to income of approximately $10.2 million before taxes during 2013 in depreciation and
amortization.
66
Weather normalization represents revenue over- or under-recovered through the weather normalization adjustment rider in
Kansas. This amount is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an
adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.
Ad valorem tax represents an increase or decrease in Kansas Gas Service’s taxes above or below the amount approved in a rate
case. This amount is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an
adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.
Recovery through rates resulted in amortization of regulatory assets of approximately $1.6 million and $6.4 million for the years
ended December 31, 2015 and 2014, respectively. Amortization of regulatory assets of approximately $32.0 million for the year
ended December 31, 2013, included amounts recovered through rates totaling $21.8 million and $10.2 million related to certain
transition costs as described above.
We collect, through our rates, the estimated costs of removal on certain regulated properties through depreciation expense, with
a corresponding credit to accumulated depreciation and amortization. These removal costs are nonlegal obligations; however,
the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory
liability. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our
jurisdictions. We record the estimated nonlegal asset removal obligation in noncurrent liabilities in other deferred credits on
our Balance Sheets.
In January 2016, as a result of our rate case in Oklahoma, we recorded a regulatory asset of $2.4 million to recover certain
information technology costs incurred as a result of our separation from ONEOK in 2014, which will be recovered over four
years.
10.
PROPERTY, PLANT AND EQUIPMENT
The following table sets forth our property, plant and equipment by property type, for the periods indicated:
December 31, December 31,
Natural gas distribution pipelines and related equipment
Natural gas transmission pipelines and related equipment
General plant and other
Construction work in process
Property, plant and equipment
Accumulated depreciation and amortization
Net property, plant and equipment
$
$
$
2015
2014
(Thousands of dollars)
4,114,090
462,654
498,906
57,032
5,132,682
(1,620,771)
3,511,911
3,909,881
450,810
418,157
71,353
4,850,201
(1,556,481)
3,293,720
$
We compute depreciation expense for distribution operations by applying composite, straight-line rates approved by various
regulatory authorities. The average depreciation rates for our property are set forth in the following table for the periods
indicated:
2015
2.0% - 3.0%
Years Ended December 31,
2014
2.0% - 3.0%
2013
2.0% - 3.0%
We recorded capitalized interest of $2.6 million, $2.5 million and $1.3 million for the years ended December 31, 2015, 2014
and 2013, respectively. We incurred liabilities for construction work in process that had not been paid at December 31, 2015,
2014 and 2013 of $15.0 million, $7.0 million and $10.5 million, respectively. Such amounts are not included in capital
expenditures on the Statements of Cash Flows.
Amounts recorded for regulatory accounting purposes that were not reflected in our financial statements were not material for
the years ended December 31, 2015 and 2014.
67
11.
SHARE-BASED PAYMENTS
The ONE Gas Equity Compensation Plan (ECP or ONE Gas Plan) provides for the granting of stock-based compensation,
including incentive stock options, nonstatutory stock options, stock bonus awards, restricted stock awards, restricted stock unit
awards, performance stock awards and performance unit awards to eligible employees and the granting of stock awards to
nonemployee directors. We have reserved 2.8 million shares of common stock for issuance under the ECP. At December 31,
2015, we had approximately 1.4 million shares available for issuance under the ECP, which reflect shares issued and estimated
shares expected to be issued upon vesting of outstanding awards granted under the plan, less forfeitures. The plan allows for
the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code section 409A requirements.
Prior to our separation, certain employees assigned to us in the separation participated in ONEOK’s share-based awards plans
(ONEOK Plans). The ONEOK Plans provided for ONEOK common stock based awards to both employees and ONEOK’s
nonemployee directors. The plans permitted the granting of various types of awards including, but not limited to, performance
stock units and restricted stock units. Awards could be granted for no consideration other than prior and future services or
based on certain financial performance targets. In connection with the separation, awards granted by ONEOK in 2012 and
2013 were cancelled and replaced with awards of ONE Gas shares. The number of restricted stock units held by a ONE Gas
participant was multiplied by a ratio of 2.04 which was determined by the ONEOK volume-weighted average share price of
$68.22 on January 31, 2014, and the ONE Gas volume-weighted average share price of $33.50 on February 3, 2014, rounded to
the nearest whole share.
The same ratio of 2.04 was used to convert the outstanding performance stock units awarded by ONEOK prior to the separation
into awards for ONE Gas shares. A pre-distribution payout factor was applied to each grant based on ONEOK’s total
shareholder return performance compared with its peer group for the number of days lapsed from the date of the grant to
January 31, 2014, and these awards were frozen or “banked” and are not subject to an additional payout factor. The remaining
units from each grant will continue to be at-risk based on our performance and the relative total shareholder return of our peer
group.
No incremental cost was recorded in our financial statements upon cancellation and replacement of the 2012 and 2013
restricted stock units and performance stock units because the previous awards were cancelled and replaced pursuant to anti-
dilution provisions of the ONEOK Plans and the fair value of the awards immediately following the cancellation and
replacement was not higher than the fair value of the awards immediately before the cancellation and replacement.
We were charged by ONEOK for share-based compensation expense related to employees that directly supported our
operations. ONEOK also charged us for the allocated costs of certain employees of ONEOK (including stock-based
compensation) who provided general and administrative services on our behalf. Information included in this note is limited to
share-based compensation associated with employees in 2014, and employees that directly supported our operations as part of
ONEOK prior to our separation. See Note 2 for total costs charged to us by ONEOK.
Compensation cost expensed for our share-based payment plans was $5.7 million, net of tax benefits of $3.5 million, for 2015,
and $7.0 million, net of tax benefits of $4.4 million for 2014. Compensation cost charged to us for employees directly
supporting our operations by ONEOK for 2013 totaled $9.7 million, respectively, which is net of $6.1 million of tax benefits.
Restricted Stock Unit Awards - We have granted restricted stock unit awards to key employees that vest over a service period
of generally three years and entitle the grantee to receive shares of our common stock. The awards granted that replaced
awards granted by ONEOK in 2012 vested, and 2013 will vest, consistent with their original vesting dates in 2015 and 2016,
respectively. Restricted stock unit awards granted in 2015 and 2014 and that replaced awards granted by ONEOK in 2013
accrue dividend equivalents in the form of additional restricted stock units prior to vesting. Restricted stock unit awards are
measured at fair value as if they were vested and issued on the grant date, reduced by expected dividend payments for awards
that do not accrue dividends and adjusted for estimated forfeitures. Compensation expense is recognized on a straight-line
basis over the vesting period of the award. A forfeiture rate of 3 percent per year based on historical forfeitures under our
share-based payment plans is used.
Performance Stock Unit Awards - We have granted performance stock unit awards to key employees. The shares of common
stock underlying the performance stock units vest at the expiration of a service period of generally three years if certain
performance criteria are met by us as determined by the Executive Compensation Committee of the Board of Directors. The
awards granted that replaced awards granted by ONEOK in 2012 vested, and 2013 will vest, consistent with their original
vesting dates in 2015 and 2016, respectively, if certain performance criteria are met by us for the at-risk portion of the awards
as described above. Upon vesting, a holder of performance stock units is entitled to receive a number of shares of common
68
stock equal to a percentage (0 percent to 200 percent) of the performance stock units granted, based on our total shareholder
return over the vesting period, compared with the total shareholder return of a peer group of other utilities over the same period.
If paid, the outstanding performance stock unit awards entitle the grantee to receive shares of our common stock. The
outstanding performance stock unit awards are equity awards with a market-based condition, which results in the compensation
expense for these awards being recognized on a straight-line basis over the requisite service period, provided that the requisite
service period is fulfilled, regardless of when, if ever, the market condition is satisfied. The new performance stock unit awards
granted in 2015 and 2014 and the grants that replaced awards granted by ONEOK in 2013 accrue dividend equivalents in the
form of additional performance stock units prior to vesting. The fair value of these performance stock units was estimated on
the grant date based on a Monte Carlo model. The compensation expense on these awards will only be adjusted for changes in
forfeitures. A forfeiture rate of 3 percent per year based on historical forfeitures under our and, prior to the separation,
ONEOK’s share-based payment plans was used.
Restricted Stock Unit Award Activity
As of December 31, 2015, there was $3.2 million of total unrecognized compensation costs related to the nonvested restricted
stock unit awards, which is expected to be recognized over a weighted-average period of 1.8 years. The following tables set
forth activity and various statistics for restricted stock unit awards outstanding under the respective plans for the period
indicated:
Nonvested December 31, 2014
Granted
Vested
Forfeited
Nonvested December 31, 2015
Weighted-average grant date fair value (per share)
Fair value of shares granted (thousands of dollars)
Performance Stock Unit Award Activity
Number of
Shares
Weighted-
Average Price
$
325,730
$
75,880
(162,280) $
(8,072) $
$
231,258
2015
2014
2013
$
$
41.40
3,141
$
$
33.19
3,149
$
$
23.47
41.40
18.32
34.42
32.59
47.36
1,323
As of December 31, 2015, there was $4.7 million of total unrecognized compensation cost related to the nonvested
performance stock unit awards, which is expected to be recognized over a weighted-average period of 1.7 years. The following
tables set forth activity and various statistics related to our performance stock unit awards and the assumptions used by us, and
ONEOK prior to 2014, in the valuations of the 2015, 2014 and 2013 grants at the grant date:
Nonvested December 31, 2014
Granted
Vested
Forfeited
Nonvested December 31, 2015
Volatility
Dividend yield
Risk-free interest rate
Number of
Units
Weighted-
Average Price
$
847,951
100,860
$
(502,474) $
(7,087) $
$
439,250
2015
15.90% (a)
2.90%
1.10%
2014
18.40%
3.37%
0.67%
(a)
2013
22.27%
3.04%
0.42%
17.62
44.48
14.33
30.22
27.35
(b)
(a) - Volatility based on historical volatility over three years using daily stock price observations of our peer utilities.
(b) - Volatility based on historical volatility over three years using daily ONEOK stock price observations.
69
Weighted-average grant date fair value (per share)
Fair value of shares granted (thousands of dollars)
Employee Stock Purchase Plan
2015
2014
2013
$
$
44.48
4,486
$
$
35.98
4,462
$
$
52.30
2,926
We have reserved a total of 0.7 million shares of common stock for issuance under our Employee Stock Purchase Plan (the
ESPP). Subject to certain exclusions, all employees who work at least 20 hours per week are eligible to participate in the ESPP.
Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to
terms and limitations of the plan. The purchase price of the stock is 85 percent of the lower of the average market price of our
common stock on the grant date or exercise date. Approximately 40 percent and 36 percent of employees participated in the
plan in 2015 and 2014, respectively, and purchased 51,092 shares at $36.15 in 2015 and 51,418 shares at $32.29 in 2014.
Compensation expense, before taxes, was $1.3 million and $0.4 million in 2015 and 2014, respectively. All eligible employees
of ONEOK were eligible to participate in a similar ESPP plan, but enrollment of our employees in that plan was terminated
upon the separation. Compensation expense, before tax, charged to us by ONEOK for employees who directly supported our
operations was $2.7 million for 2013.
Employee Stock Award Program
Under the program, each time the per-share closing price of our common stock on the NYSE closed for the first time at or
above each $1.00 increment above its previous historical high closing price, we issued, for no monetary consideration, one
share of our common stock to all eligible employees. The total number of shares of our common stock authorized for issuance
under this program is 125,000. Shares issued to employees under this program during 2015 and 2014 totaled 23,506 and
35,324, and compensation expense, before taxes, related to the Employee Stock Award Program was $1.1 million and $2.5
million for 2015 and 2014, respectively. Compensation expense, before taxes, charged to us by ONEOK related to a similar
program to ours that was administered by ONEOK for employees who directly supported our operations was $4.2 million for
2013.
12.
EMPLOYEE BENEFIT PLANS
Retirement and Other Postemployment Benefit Plans
Prior to separation, certain employees participated in the Plans sponsored by ONEOK. We accounted for the Plans as
multiemployer benefit plans. These defined benefit pension and other postemployment benefit costs included amounts
associated with vested participants who are no longer employees. As described in Note 2, prior to 2014, ONEOK also charged
us for the allocated cost of certain employees of ONEOK who provided general and administrative services on our behalf.
ONEOK included an allocation of the benefit costs associated with these ONEOK employees based upon its allocation
methodology, not necessarily specific to the employees providing general and administrative services on our behalf.
Retirement Plans - We have a defined benefit pension plan covering nonbargaining-unit employees hired before January 1,
2005, and certain bargaining-unit employees hired before December 15, 2011. Nonbargaining unit employees hired after
December 31, 2004; employees represented by Local No. 304 of the International Brotherhood of Electrical Workers (IBEW)
hired on or after July 1, 2010; employees represented by the United Steelworkers hired on or after December 15, 2011; and
employees who accepted a one-time opportunity to opt out of the defined benefit pension plan are covered by a profit-sharing
plan. Certain employees of the Texas Gas Services division were entitled to benefits under a frozen cash-balance pension plan.
In addition, we have a supplemental executive retirement plan for the benefit of certain officers. No new participants in the
supplemental executive retirement plan have been approved since 2005, and it was formally closed to new participants as of
January 1, 2014. We fund our defined benefit pension costs at a level needed to maintain or exceed the minimum funding
levels required by the Employee Retirement Income Security Act of 1974, as amended, and the Pension Protection Act of 2006.
Pension expense was $38.0 million and $27.1 million in 2015 and 2014, respectively, prior to regulatory deferrals. Pension
expense charged to us by ONEOK for employees directly supporting our operations totaled $35.0 million for 2013, prior to
regulatory deferrals.
Other Postemployment Benefit Plans - We sponsor health and welfare plans that provide postemployment medical and life
insurance benefits to certain employees who retire with at least five years of service. The postemployment medical plan is
contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other
cost-sharing features such as deductibles and coinsurance. Other postemployment benefit expense was $5.0 million and $5.9
70
million in 2015 and 2014, respectively, prior to regulatory deferrals. Other postemployment benefit expense charged to us by
ONEOK for employees directly supporting our operations totaled $12.3 million for 2013, prior to regulatory deferrals.
Plan Amendments - In October 2015, plan amendments were approved to merge our frozen cash-balance defined benefit
pension plan covering certain Texas Gas Service employees with our defined benefit pension plan covering certain eligible
employees. In addition, we announced to eligible pre-65 participants in our postemployment medical plans a change from a
self-insured postemployment medical plan to a plan providing participants an annual benefit that will allow them to select
coverage on a healthcare exchange. As a result, we remeasured the respective plan assets and benefit obligations, effective
October 1, 2015, which resulted in a reduction in benefit obligations of our postemployment benefit plan of $11.9 million. Net
periodic benefit cost for the plans in 2015 was reduced by $3.4 million.
Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit
obligations for pension and postemployment benefits for the periods indicated:
Discount rate
Compensation increase rate
December 31,
2015
4.75%
3.35% - 3.40%
2014
4.25%
3.30% - 3.50%
The following table sets forth the weighted-average assumptions used by us, and ONEOK prior to 2014, to determine the
periodic benefit costs for the periods indicated:
Discount rate - pension plans
Discount rate - other postemployment plans
Expected long-term return on plan assets
Compensation increase rate
Nine Months Ended
September 30,
2015
4.25%
4.25%
7.75%
3.30% - 3.50%
Three Months Ended
December 31,
2015
4.75%
4.75%
7.75%
3.30% - 3.50%
Years Ended December 31,
2014
5.25%
5.00%
7.75%
2013
4.25%
4.00%
8.25%
3.35% - 3.50% 3.45% - 3.50%
We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and
economic growth models. At December 31, 2014, we updated our assumed mortality rates to incorporate the new set of
mortality tables issued by the Society of Actuaries in October 2014.
We determine our discount rates annually. We estimate our discount rate based upon a comparison of the expected cash flows
associated with our future payments under our defined benefit pension and other postemployment obligations to a hypothetical
bond portfolio created using high-quality bonds that closely match expected cash flows. Bond portfolios are developed by
selecting a bond for each of the next 60 years based on the maturity dates of the bonds. Bonds selected to be included in the
portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue
size, yield outliers and other filtering criteria to remove unsuitable bonds.
Regulatory Treatment - The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and
other postemployment benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service,
respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for
defined benefit pension and other postemployment costs. Differences, if any, between the expense and the amount recovered
through rates would be reflected in earnings, net of authorized deferrals.
We historically have recovered defined benefit pension and other postemployment benefit costs through rates. We believe it is
probable that regulators will continue to include the net periodic pension and other postemployment benefit costs in our cost of
service.
71
Obligations and Funded Status - In connection with the separation from ONEOK, we entered into an Employee Matters
Agreement with ONEOK, which provides that our employees no longer participate in benefit plans sponsored or maintained by
ONEOK as of the separation date. Effective January 1, 2014, the ONEOK defined benefit pension plans and other
postemployment benefit plans transferred assets and obligations related to those employees transferring to ONE Gas and vested
participants who are no longer employees to the new ONE Gas plans. As a result, we recorded sponsored pension and other
postemployment plan obligations of approximately $1.1 billion, and sponsored defined benefit pension and other
postemployment plan assets of approximately $1.0 billion, which are reflected below as our balances at the beginning of the
period. Additionally, as a result of the transfer of unrecognized losses from ONEOK, our regulatory assets and deferred income
taxes increased $331 million and $86 million, respectively.
The following table sets forth our defined benefit pension and other postemployment benefit plans, benefit obligations and fair
value of plan assets for the periods indicated:
Benefit obligation, end of period
985,624
1,028,171
Changes in Benefit Obligation
Benefit obligation, beginning of period
Service cost
Interest cost
Plan participants’ contributions
Actuarial loss (gain)
Benefits paid
Plan amendment
Change in Plan Assets
Fair value of plan assets, beginning of period
Actual return on plan assets
Employer contributions
Plan participants’ contributions
Benefits paid
Fair value of assets, end of period
Balance at December 31
Current liabilities
Noncurrent liabilities
Balance at December 31
Pension Benefits
Other Postemployment Benefits
December 31,
December 31,
2015
2014
2015
2014
(Thousands of dollars)
$
1,028,171
$
863,620
$
257,688
$
239,171
13,660
43,542
—
(47,607)
(52,142)
—
11,620
43,791
—
159,275
(50,135)
—
845,396
(9,026)
933
—
(52,142)
785,161
840,699
53,907
925
—
(50,135)
845,396
3,257
10,628
2,915
(19,702)
(14,632)
(11,901)
228,253
151,777
1,335
14,100
2,915
(14,632)
155,495
3,468
11,605
2,642
14,998
(14,196)
—
257,688
147,237
6,912
9,182
2,642
(14,196)
151,777
$
$
$
(200,463) $
(182,775) $
(72,758) $
(105,911)
(912) $
(907) $
— $
—
(199,551)
(181,868)
(72,758)
(200,463) $
(182,775) $
(72,758) $
(105,911)
(105,911)
The accumulated benefit obligation for our defined benefit pension plans was $934.3 million and $970.7 million at December
31, 2015 and 2014, respectively.
There are no plan assets expected to be withdrawn and returned to us in 2016.
72
Components of Net Periodic Benefit Cost - The following table sets forth the components of net periodic benefit cost for our
defined benefit pension and other postemployment benefit plans for the period indicated:
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on assets
Amortization of unrecognized prior service cost
Amortization of net loss
Settlements
Net periodic benefit cost
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on assets
Amortization of unrecognized prior service cost
Amortization of net loss
Net periodic benefit cost
Pension Benefits
Year Ended December 31,
2015
2014
(Thousands of dollars)
13,660
$
43,542
(61,769)
266
42,226
27
37,952
$
Other Postemployment Benefits
Year Ended December 31,
2015
2014
(Thousands of dollars)
3,257
$
10,628
(11,892)
(2,228)
5,268
5,033
$
11,620
43,791
(59,862)
549
30,200
773
27,071
3,468
11,605
(11,393)
(1,760)
3,969
5,889
$
$
$
$
Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income
(loss) related to our defined benefit pension benefits for the period indicated:
Pension Benefits
Year Ended December 31,
2015
2014
(Thousands of dollars)
Net gain (loss) arising during the period
Amortization of loss
Deferred income taxes
Total recognized in other comprehensive income (loss)
$
$
$
339
917
(483)
773
$
(3,543)
518
1,244
(1,781)
There were no amounts recognized in other comprehensive income (loss) related to our other postemployment benefits for the
periods presented.
73
The tables below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as
components of net periodic benefit expense for the periods indicated:
Prior service credit (cost)
Accumulated loss
Accumulated other comprehensive loss
before regulatory assets
Regulatory asset for regulated entities
Accumulated other comprehensive loss
after regulatory assets
Deferred income taxes
Accumulated other comprehensive loss,
net of tax
Prior service credit (cost)
Accumulated loss
Accumulated other comprehensive loss
before regulatory assets
Regulatory asset for regulated entities
Accumulated other comprehensive loss
after regulatory assets
Deferred income taxes
Accumulated other comprehensive loss,
net of tax
Pension Benefits
December 31,
2015
2014
(Thousands of dollars)
— $
(407,798)
(407,798)
400,625
(7,173)
2,772
(4,401) $
Other Postemployment Benefits
December 31,
2015
2014
(Thousands of dollars)
14,010
$
(50,447)
(36,437)
36,437
—
—
— $
(266)
(426,862)
(427,128)
418,699
(8,429)
3,255
(5,174)
4,337
(64,861)
(60,524)
60,524
—
—
—
$
$
$
$
The following tables set forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets
expected to be recognized as components of net periodic benefit expense in the next fiscal year:
Amounts to be recognized in 2016
(Thousands of dollars)
Prior service credit (cost)
Actuarial net loss
$
$
— $
35,542
$
(3,633)
4,608
Pension Benefits
Other Postemployment
Benefits
Health Care Cost Trend Rates - The following table sets forth the assumed health care cost-trend rates for the periods
indicated:
Health care cost-trend rate assumed for next year
4.00% - 7.50%
4.00% - 7.75%
Rate to which the cost-trend rate is assumed to decline
(the ultimate trend rate)
4.00% - 5.00%
4.00% - 5.00%
Year that the rate reaches the ultimate trend rate
2022
2022
2015
2014
74
Assumed health care cost-trend rates have a significant effect on the amounts reported for our health care plans. A one
percentage point change in assumed health care cost-trend rates would have the following effects:
Effect on total of service and interest cost
Effect on other postemployment benefit obligation
One Percentage
One Percentage
Point Increase
Point Decrease
(Thousands of dollars)
$
$
263
3,655
$
$
(266)
(3,752)
Plan Assets - Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize
long-term fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the
plan’s current and projected financial obligations. To achieve this strategy, we have established a liability-driven investment
strategy to change the allocations as the plan reaches certain funded status. The plan’s investments include a diverse blend of
various domestic and international equities, investment-grade debt securities which mirror the cash flows of our liability,
insurance contracts and alternative investments. The current target allocation for the assets of our defined benefit pension plan
is as follows:
U.S. large-cap equities
Investment-grade bonds
Developed foreign large-cap equities
Alternative investments
Mid-cap equities
Emerging markets equities
Small-cap equities
Total
37.4%
30.0%
10.6%
7.7%
5.6%
5.0%
3.7%
100%
As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed
above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the
exception of indexing purposes, are prohibited from owning our stock.
The following tables set forth our pension benefits and other postemployment benefits plan assets by fair value category as of
the measurement date:
Pension Benefits
December 31, 2015
Asset Category
Level 1
Level 2
Level 3
Total
(Thousands of dollars)
Investments:
Equity securities (a)
Government obligations
Corporate obligations (b)
Cash and money market funds (c)
Insurance contracts and group annuity contracts
Other investments (d)
Total assets
$
405,935 $
62,150 $
— $
—
—
5,429
—
2,884
44,651
139,396
10,279
—
—
—
—
—
56,465
57,972
468,085
44,651
139,396
15,708
56,465
60,856
$
414,248 $
256,476 $
114,437 $
785,161
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category represents alternative investments such as hedge funds and other financial instruments.
75
Pension Benefits
December 31, 2014
Asset Category
Level 1
Level 2
Level 3
Total
(Thousands of dollars)
Investments:
Equity securities (a)
Government obligations
Corporate obligations (b)
Cash and money market funds (c)
Insurance contracts and group annuity contracts
Other investments (d)
Total assets
$
439,165 $
66,766 $
— $
—
—
4,152
—
—
47,769
153,412
16,341
—
—
—
—
—
59,877
57,914
505,931
47,769
153,412
20,493
59,877
57,914
$
443,317 $
284,288 $
117,791 $
845,396
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category represents alternative investments such as hedge funds.
Other Postemployment Benefits
December 31, 2015
Asset Category
Level 1
Level 2
Level 3
Total
(Thousands of dollars)
Investments:
Equity securities (a)
Government obligations
Corporate obligations (b)
Cash and money market funds (c)
Insurance contracts and group annuity contracts
Other investments (d)
Total assets
$
54,560 $
7,498 $
— $
62,058
—
—
233
—
4
64
200
13,322
79,531
—
—
—
—
—
83
64
200
13,555
79,531
87
$
54,797 $
100,615 $
83 $
155,495
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category represents alternative investments such as hedge funds.
76
Other Postemployment Benefits
December 31, 2014
Asset Category
Level 1
Level 2
Level 3
Total
(Thousands of dollars)
Investments:
Equity securities (a)
Government obligations
Corporate obligations (b)
Cash and money market funds (c)
Insurance contracts and group annuity contracts
Other investments (d)
Total assets
$
49,553 $
12,589 $
— $
62,142
—
—
964
—
—
78
251
5,894
82,353
—
—
—
—
—
95
78
251
6,858
82,353
95
$
50,517 $
101,165 $
95 $
151,777
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category represents alternative investments such as hedge funds.
The following table sets forth the reconciliation of Level 3 fair value measurements of our pension plans for the periods
indicated:
January 1, 2014
Net realized and unrealized gains (losses)
Settlements
December 31, 2014
Net realized and unrealized gains
Settlements
December 31, 2015
Pension Benefits
Insurance
Contracts
Other
Investments
Total
(Thousands of dollars)
63,454
$
73,590
$
3,446
(7,023)
(15,676)
—
59,877
$
57,914
$
2,188
(5,600)
58
—
137,044
(12,230)
(7,023)
117,791
2,246
(5,600)
56,465
$
57,972
$
114,437
$
$
$
Contributions - During 2015, we contributed $0.9 million to our defined benefit pension plans and we contributed $14.1
million to our other postemployment benefit plans. In 2016, we expect to contribute $0.9 million to our defined benefit pension
plans and expect to contribute $5.8 million to our other postemployment benefit plans.
77
Pension and Other Postemployment Benefit Payments - Benefit payments for our defined benefit pension and other
postemployment benefit plans for the period ended December 31, 2015 were $52.1 million and $14.6 million, respectively.
The following table sets forth the pension benefits and other postemployment benefits payments expected to be paid in
2016-2025:
Benefits to be paid in:
(Thousands of dollars)
Pension
Benefits
Other Postemployment
Benefits
2016
2017
2018
2019
2020
2021 through 2025
$
$
$
$
$
$
53,359
54,710
56,201
57,238
58,901
311,194
$
$
$
$
$
$
14,116
13,875
14,435
14,956
15,406
81,175
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31,
2015, and include estimated future employee service.
Other Employee Benefit Plans
401(k) Plan - We have a 401(k) Plan which covers all full-time employees, and employee contributions are discretionary. We
match 100 percent of each participant’s eligible contribution up to 6 percent of each participant’s eligible compensation, subject
to certain limits. Our contributions made to the plan were $10.2 million and $9.7 million 2015 and 2014, respectively. Prior to
our separation, ONEOK maintained a similar 401(k) Plan and compensation expense charged to us for employees who directly
supported our operations by ONEOK totaled $8.3 million in 2013 for ONEOK’s matching contributions to this plan.
Profit-Sharing Plan - We have a profit-sharing plan for all employees that do not participate in our defined benefit pension
plan. We plan to make a contribution to the profit-sharing plan each quarter equal to 1 percent of each participant’s eligible
compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year.
Employee contributions are not allowed under the plan. Our contributions made to the plan were $6.5 million and $4.0 million
in 2015 and 2014, respectively. ONEOK maintained a similar Profit-Sharing Plan and compensation expense associated with
ONEOK’s contributions made to the plan for employees who directly supported our operations prior to the separation were
$1.6 million in 2013.
Employee Deferred Compensation Plan - Our Nonqualified Deferred Compensation Plan provides select employees with the
option to defer portions of their compensation and provides nonqualified deferred compensation benefits that are not available
due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws.
Contributions made to the plan were not material in 2015 and 2014. ONEOK maintained a similar plan and contributions made
to the plan for employees who directly supported our operations prior to the separation were not material in 2013.
78
13.
INCOME TAXES
The following table sets forth our provision for income taxes for the periods indicated:
Current income tax provision
Federal
State
Total current income tax provision
Deferred income tax provision
Federal
State
Total deferred income tax provision
Total provision for income taxes
2015
Years Ended December 31,
2014
(Thousands of dollars)
2013
$
$
7,135
2,055
9,190
56,440
7,349
63,789
72,979
$
$
17,006
1,397
18,403
42,024
7,911
49,935
68,338
$
$
—
67
67
53,562
8,643
62,205
62,272
The following table is a reconciliation of our income tax provision for the periods indicated:
Income before income taxes
Federal statutory income tax rate
Provision for federal income taxes
State income taxes, net of federal tax benefit
Other, net
Total provision for income taxes
$
$
Years Ended December 31,
2014
(Thousands of dollars)
$
178,128
$
2015
192,009
35%
35%
67,203
6,114
(338)
72,979
$
62,345
6,051
(58)
68,338
$
2013
161,467
35%
56,513
5,661
98
62,272
Prior to our separation from ONEOK, our operations were included in the consolidated federal and state income tax returns of
ONEOK. Our income tax provision was calculated on a separate return basis. Accordingly, we recognized deferred tax assets
and liabilities for the difference between the financial statement and income tax basis of assets and liabilities and carry-forward
items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse as if we had
been a corporation for federal and state income tax purposes. In addition, ONEOK managed its tax position based upon the tax
attributes of the consolidated group. Certain attributes may not be available to use if we had been operating as an independent
company.
The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax
assets and liabilities for the periods indicated:
Deferred tax assets
Employee benefits and other accrued liabilities
Net operating loss
Other
Total deferred tax assets
Deferred tax liabilities
Excess of tax over book depreciation
Purchased-gas cost adjustment
Other regulatory assets and liabilities, net
Total deferred tax liabilities
Net deferred tax liabilities
79
December 31,
2015
2014
(Thousands of dollars)
$
$
110,148
—
7,848
117,996
897,667
3,999
168,115
1,069,781
951,785
$
$
128,715
8,144
5,655
142,514
820,853
16,177
193,159
1,030,189
887,675
At December 31, 2015 and 2014, we had income taxes receivable of $38.9 million and $43.8 million, respectively.
Prior to our separation from ONEOK, we were included in the ONEOK income tax returns for all applicable years. We file
income tax returns in the United States federal jurisdiction as well as in the states where we have operations. In 2015, we filed
our initial United States consolidated federal tax return for the period February 1, 2014 through December 31, 2014.
We have adopted ASU 2015-17, “Balance Sheet Classification of Deferred Taxes,” early to simplify our financial reporting
process and have applied it prospectively for the period beginning October 1, 2015. Prior periods were not retrospectively
adjusted.
14.
COMMITMENTS AND CONTINGENCIES
Commitments - Operating leases represent future minimum lease payments under noncancelable leases covering office space,
facilities and information technology hardware and software. Rental expense was $5.0 million in each of 2015 and 2014 and
$4.8 million in 2013. The following table sets forth our operating lease payments for the periods indicated:
Operating Leases
(Millions of dollars)
2016
2017
2018
2019
2020
Thereafter
Total
$
$
4.6
4.5
4.2
3.5
3.3
7.0
27.1
Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or
regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to,
those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes,
wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations
require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other
approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or
interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other
regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected
capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new
regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased
compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas.
These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws
and regulations. A consent agreement with the KDHE governs all work at these sites. The terms of the consent agreement
allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis.
Remediation involves typically the management of contaminated soils and may involve removal of structures and monitoring
and/or remediation of groundwater.
We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites according to plans approved
by KDHE. Regulatory closure has been achieved at three of the sites. We have begun site assessment at the remaining site
where no active remediation has occurred.
Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in
relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had
no material effects on earnings or cash flows during 2015, 2014 and 2013. A number of environmental issues may exist with
respect to manufactured gas plants. With the trend toward stricter standards, greater regulation and more extensive permit
requirements for the types of assets operated by us that are subject to environmental regulation, our environmental expenditures
could increase in the future, and such expenditures may not be fully covered by insurance or recoverable in rates from our
customers, and those costs may adversely affect our financial condition, results of operations and cash flows.
80
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations
require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline
segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012,
the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for
violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or
studies on issues that may or may not be material to us. These issues include but are not limited to the following:
•
•
•
an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current
high-consequence areas;
a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable
operating pressures; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence
areas.
The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline
safety regulations are unknown.
Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our
operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible
losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final
outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.
15.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Year Ended December 31, 2015
Revenues
Net margin
Operating income
Net income
Earnings per share
Basic
Diluted
Year Ended December 31, 2014
Revenues
Net margin
Operating income
Net income
Earnings per share
Basic
Diluted
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$
$
$
$
$
$
$
$
$
$
$
$
676,531
262,978
109,005
60,381
1.15
1.13
First
Quarter
766,178
259,836
109,353
59,076
1.13
1.13
$
$
$
$
$
$
$
$
$
$
$
$
(Thousands of dollars)
256,786
176,837
31,270
12,076
0.23
0.23
$
$
$
$
$
$
225,226
170,502
24,951
7,371
0.14
0.14
Second
Quarter
Third
Quarter
(Thousands of dollars)
296,838
176,493
26,812
9,454
0.18
0.18
$
$
$
$
$
$
241,522
166,452
19,119
4,653
0.09
0.09
$
$
$
$
$
$
$
$
$
$
$
$
389,149
231,416
73,903
39,202
0.75
0.74
Fourth
Quarter
514,368
224,176
70,010
36,607
0.70
0.69
81
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9.
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have
concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on
the evaluation of the controls and procedures required by Rule 13a-15(b) of the Exchange Act.
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). Under the supervision and with the participation of our management, including our
Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial
reporting based on the framework in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management
concluded that our internal control over financial reporting was effective as of December 31, 2015.
The effectiveness of our internal control over financial reporting as of December 31, 2015, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their reports which are included
herein (Item 8).
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2015, 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
Directors of the Registrant
Information concerning our directors is set forth in our 2016 definitive Proxy Statement and is incorporated herein by this
reference.
Executive Officers of the Registrant
Information concerning our executive officers is included in Part I, Item 1, Business, of this Annual Report.
Compliance with Section 16(a) of the Exchange Act
Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2016 definitive Proxy Statement and is
incorporated herein by this reference.
82
Code of Ethics
Information concerning the code of ethics, or code of business conduct, is set forth in our 2016 definitive Proxy Statement and
is incorporated herein by this reference.
Nominating Procedures
Information concerning the nominating procedures is set forth in our 2016 definitive Proxy Statement and is incorporated
herein by this reference.
The Audit Committee
Information concerning the Audit Committee is set forth in our 2016 definitive Proxy Statement and is incorporated herein by
this reference.
The Audit Committee Financial Experts
Information concerning the Audit Committee Financial Experts is set forth in our 2016 definitive Proxy Statement and is
incorporated herein by this reference.
The Executive Compensation Committee
Information concerning the Executive Compensation Committee is set forth in our 2016 definitive Proxy Statement and is
incorporated herein by this reference.
The Corporate Governance Committee
Information concerning the Corporate Governance Committee is set forth in our 2016 definitive Proxy Statement and is
incorporated herein by this reference.
The Executive Committee
Information concerning the Executive Committee is set forth in our 2016 definitive Proxy Statement and is incorporated herein
by this reference.
Committee Charters
The full text of our Audit Committee charter, Executive Compensation Committee charter, Corporate Governance Committee
charter and Executive Committee charter are published on and may be printed from our website at www.onegas.com and are
also available from our corporate secretary upon request.
ITEM 11.
EXECUTIVE COMPENSATION
Information on executive compensation is set forth in our 2016 definitive Proxy Statement and is incorporated herein by this
reference.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners
Information concerning the ownership of certain beneficial owners is set forth in our 2016 definitive Proxy Statement and is
incorporated herein by this reference.
Security Ownership of Management
Information on security ownership of directors and officers is set forth in our 2016 definitive Proxy Statement and is
incorporated herein by this reference.
83
Equity Compensation Plan Information
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2015:
Number of Securities Issued
Upon Exercise of Outstanding
Options, 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 in
Column (a))
(c)
— $
— $
— $
— (3)
—
—
2,191,002
612,410
2,803,412
Plan Category
Equity compensation plans approved
by security holders (1)
Equity compensation plans not
approved by security holders (2)
Total
(1) Includes restricted stock incentive units and performance-unit awards granted under our Equity Compensation Plan and our Nonqualified Deferred
Compensation Plan for Nonemployee Directors. For a brief description of the material features of this plan, see Note 12 of the Notes to Financial Statements
in this Annual Report.
(2) Includes shares granted under our Employee Stock Purchase Plan and Employee Stock Award Program. For a brief description of the material features of
these plans, see Note 11 of the Notes to Financial Statements in this Annual Report. Column (c) includes 546,234 and 66,176 shares available for future
issuance under our Employee Stock Purchase Plan and Employee Stock Award Program, respectively.
(3) Compensation deferred into our common stock under our Employee Non-Qualified Deferred Compensation Plan and Deferred Compensation Plan for
Nonemployee Directors is distributed to participants at fair market value on the date of distribution. The price used for these plans to calculate the weighted-
average exercise price in the table is $50.17, which represents the year-end closing price of our common stock on the NYSE.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Information on certain relationships and related transactions and director independence is set forth in our 2016 definitive Proxy
Statement and is incorporated herein by this reference.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information on the principal accountant’s fees and services is set forth in our 2016 definitive Proxy Statement and is
incorporated herein by this reference.
84
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV.
(1) Financial Statements
Page No.
45
46
47
Report of Independent Registered Public Accounting Firm
Statements of Income for the years ended December 31, 2015, 2014 and 2013
Statements of Comprehensive Income for the years ended
December 31, 2015, 2014 and 2013
Balance Sheets as of December 31, 2015 and 2014
48-49
Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013
51
Statements of Equity for the years ended December 31, 2015, 2014 and 2013
52-53
Notes to Financial Statements
54-81
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(2) Financial Statements Schedules
All schedules have been omitted because of the absence of conditions under which they are required.
(3) Exhibits
2.1
3.1
3.2
4.1
4.2
4.3
Separation and Distribution Agreement, dated as of January 14, 2014, by and between ONE Gas, Inc. and
ONEOK, Inc. (incorporated by reference to Exhibit 2.1 to ONE Gas, Inc.’s Current Report on Form 8-K
filed on January 15, 2014 (File No. 1-36108)).
Amended and Restated Certificate of Incorporation of ONE Gas, Inc., dated January 31, 2014 (incorporated
by reference to Exhibit 4.5 to ONE Gas, Inc.’s Registration Statement on Form S-8 filed on January 31,
2014 (File No. 333-193690)).
Amended and Restated By-Laws of ONE Gas, Inc. (incorporated by reference to Exhibit 4.6
to ONE Gas, Inc.’s Registration Statement on Form S-8 filed on January 31, 2014 (File No. 333-193690)).
Form of Common Stock Certificate (incorporated by reference to Exhibit 4.2 to ONE Gas, Inc.’s
Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).
Indenture, dated January 27, 2014, between ONE Gas, Inc. and U.S. Bank National Association, as trustee
(incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on
January 30, 2014 (File No. 1-36108)).
Supplemental Indenture No. 1, dated January 27, 2014, between ONE Gas, Inc. and U.S. Bank National
Association, as trustee (incorporated by reference to Exhibit 10.2 to ONE Gas, Inc.’s
Current Report on Form 8-K filed on January 30, 2014 (File No. 1-36108)).
85
4.4
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
Registration Rights Agreement, dated January 27, 2014, among Morgan Stanley & Co. LLC, J.P. Morgan
Securities LLC and RBS Securities Inc., as representatives of the several initial purchasers named therein
(incorporated by reference to Exhibit 10.3 to ONE Gas, Inc.’s Current Report on Form 8-K filed on
January 30, 2014 (File No. 1-36108)).
Tax Matters Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc.
(incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January
15, 2014 (File No. 1-36108)).
Transition Services Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc.
(incorporated by reference to Exhibit 10.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January
15, 2014 (File No. 1-36108)).
Employee Matters Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc.
(incorporated by reference to Exhibit 10.3 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January
15, 2014 (File No. 1-36108)).
Form of ONE Gas, Inc. Indemnification Agreement between ONE Gas, Inc. and ONE Gas, Inc. officers and
directors (incorporated by reference to Exhibit 10.5 to ONE Gas, Inc.’s Registration Statement on Form
10 filed on October 1, 2013 (File No. 1-36108)).
ONE Gas, Inc. Annual Officer Incentive Plan (incorporated by reference to Exhibit 10.6 to ONE Gas, Inc.’s
Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).
ONE Gas, Inc. Pre-2005 Nonqualified Deferred Compensation Plan (incorporated by reference
to Exhibit 10.7 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December
23, 2013 (File No. 1-36108)).
ONE Gas, Inc. Employee Nonqualified Deferred Compensation Plan (incorporated by reference
to Exhibit 10.8 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December
23, 2013 (File No. 1-36108)).
ONE Gas, Inc. Pre-2005 Supplemental Executive Retirement Plan (incorporated by reference to
Exhibit 10.9 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December
23, 2013 (File No. 1-36108)).
ONE Gas, Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit
10.10 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013
(File No. 1-36108)).
Credit Agreement, dated as of December 20, 2013, among ONE Gas, Inc., Bank of America, N.A.,
as administrative agent, swingline lender and a letter of credit issuer, and the other lenders and letter of credit
issuers parties thereto (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Current Report on Form
8-K filed on December 23, 2013 (File No. 1-13643)).
ONE Gas, Inc. Officer Change in Control Severance Plan (incorporated by reference to
Exhibit 10.12 to ONE Gas, Inc.’s Registration Statement filed on Form 10, Amendment No. 2 filed on
December 23, 2013 (File No. 1-36108)).
ONE Gas, Inc. Equity Compensation Plan (incorporated by reference to Exhibit 10.13 to ONE
Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No.
1-36108)).
Form of 2014 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.13 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).
86
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
12.1
21.1
23.1
31.1
31.2
32.1
32.2
Form of 2014 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.14 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).
Form of 2013 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.15 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).
Form of 2013 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.16 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).
ONE Gas, Inc. Equity Compensation Plan (incorporated by reference to Appendix A to ONE Gas, Inc.’s
Definitive Proxy Statement on Schedule 14A filed on April 1, 2015 (File No. 1-36108)).
ONE Gas, Inc. Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.16 to ONE Gas,
Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No.
1-36108)).
ONE Gas, Inc. Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to
Exhibit 10.1 to ONE Gas, Inc. Current Report on Form 8-K filed on February 24, 2014 (File No. 1-36108)).
ONE Gas, Inc. 401(k) Plan of ONE Gas Employees and Former ONE Gas Employees effective as of January
1, 2014 (incorporated by reference to Exhibit 4.4 to ONE Gas, Inc.’s Registration Statement on Form S-8
filed on January 31, 2014 (File No. 333-193690)).
Form of Commercial Paper Dealer Agreement (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s
Current Report on Form 8-K filed on September 10, 2014 (File No. 1-36108)).
Form of 2015 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.2 to ONE Gas,
Inc.’s Quarterly Report on Form 10-Q filed on April 30, 2015 (File 1-36108)).
Form of 2015 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.3 to ONE Gas,
Inc.’s Quarterly Report on Form 10-Q filed on April 30, 2015 (File 1-36108)).
Form of 2016 Performance Unit Award Agreement.
Form of 2016 Restricted Unit Award Agreement.
Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2015, 2014, 2013,
2012 and 2011.
Subsidiaries of ONE Gas, Inc.
Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.
Certification of Pierce H. Norton II pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Pierce H. Norton II pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
Certification of Curtis L. Dinan pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
87
101.INS
XBRL Instance Document.
101.SCH
XBRL Schema Document.
101.CAL
XBRL Calculation Linkbase Document.
101.LAB
XBRL Label Linkbase Document.
101. PRE
XBRL Presentation Linkbase Document.
101.DEF
XBRL Extension Definition Linkbase Document.
Attached as Exhibit 101 to this Annual Report are the following XBRL-related documents: (i) Document and Entity
Information; (ii) Statements of Income for the years ended December 31, 2015, 2014 and 2013; (iii) Statements of
Comprehensive Income for the years ended December 31, 2015, 2014 and 2013; (iv) Balance Sheets for the years ended
December 31, 2015 and 2014; (v) Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013; (vi)
Statements of Equity for the years ended December 31, 2015, 2014 and 2013; and (vii) Notes to Financial Statements.
We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report.
88
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Date: February 18, 2016
ONE Gas, Inc.
Registrant
By:
/s/ Curtis L. Dinan
Curtis L. Dinan
Senior Vice President,
Chief Financial Officer and Treasurer
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on this 18th day of February 2016.
/s/ John W. Gibson
John W. Gibson
Chairman of the Board
/s/ Curtis L. Dinan
Curtis L. Dinan
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Accounting Officer)
/s/ Michael G. Hutchinson
Michael G. Hutchinson
Director
/s/ Eduardo A. Rodriguez
Eduardo A. Rodriguez
Director
/s/ Pierce H. Norton II
Pierce H. Norton II
President, Chief Executive Officer and
Director
/s/ Robert B. Evans
Robert B. Evans
Director
/s/ Pattye L. Moore
Pattye L. Moore
Director
/s/ Douglas H. Yaeger
Douglas H. Yaeger
Director
89
Forward-looking Statements
Statements contained in this annual report that include company
expectations or predictions should be considered forward-looking
statements that are covered by the safe harbor provisions of the
Securities Act of 1933 and the Securities Exchange Act of 1934,
as amended.
It is important to note that the actual results could differ materially
from those projected in such forward-looking statements.
For additional information that could cause actual results to differ
materially from such forward-looking statements, refer to ONE Gas’
Securities and Exchange Commission fi lings.
Shareholder Information
Wells Fargo Shareowner Services
P.O. Box 64874
St. Paul, MN 55164-0856
P: 1-855-217-6403
P: (Outside U.S.) 1-651-450-4064
TDD number: 1-651-450-4144
www.shareowneronline.com
Direct Stock Purchase & Dividend Reinvestment Plan
ONE Gas’ Direct Stock Purchase and Dividend Reinvestment Plan
provides new investors and current shareholders a convenient way to
purchase ONE Gas common stock without paying processing fees or
service charges and to reinvest cash dividends. For more information
or to enroll in the plan, call Wells Fargo at 1-855-217-6403. The
Prospectus is also available at www.onegas.com.
Annual Meeting Details
First Place Tower
15 East Fifth Street
Tulsa, OK 74103
May 26, 2016 – 9 a.m. CDT
Auditors
PricewaterhouseCoopers LLP
Two Warren Place
6120 South Yale Avenue, Suite 1850
Tulsa, OK 74136
Corporate Headquarters
First Place Tower
15 East Fifth Street
Tulsa, OK 74103
Credit Ratings
Moody’s: A2 (Stable)
Standard & Poor’s: A- (Stable)
Investor Relations
ONE Gas Investor Relations
Department
P.O. Box 21049
Tulsa, OK 74121
P: 1-855-496-0200
E: IR@onegas.com
Andrew Ziola, Vice President,
Investor Relations and Public Affairs
P: 1-918-947-7163
E: andrew.ziola@onegas.com
Board of Directors
From left to right:
Douglas H. Yaeger
Retired Chairman, President and Chief Executive Offi cer, Laclede Gas Company
John W. Gibson
Chairman, ONE Gas, Inc.
Eduardo A. Rodriguez
President, Strategic Communications Consulting Group
Robert B. Evans
Retired President and Chief Executive Offi cer, Duke Energy Americas
Pattye L. Moore
Chairman, Red Robin Gourmet Burgers
Pierce H. Norton II
President and Chief Executive Offi cer, ONE Gas, Inc.
Michael G. Hutchinson
Retired Partner, Deloitte & Touche
Executive Team
Joseph L. McCormick, 56
Senior Vice President, General
Counsel and Assistant Secretary
Caron A. Lawhorn, 55
Senior Vice President, Commercial
Robert S. McAnnally, 52
Senior Vice President, Operations
Mark A. Bender, 51
Senior Vice President,
Administration,
Chief Information Offi cer
Andrew J. Ziola, 46
Vice President,
Investor Relations and
Public Aff airs
Pierce H. Norton II, 56
President and Chief
Executive Offi cer
Curtis L. Dinan, 48
Senior Vice President,
Chief Financial Offi cer
and Treasurer
16
FPO
15 East Fifth Street, Tulsa, OK 74103
918-947-7000 • www.onegas.com