Life’s Essentials
for a Better Tomorrow
We are ONE Gas
ONE Gas, Inc. is a stand-alone, 100 percent regulated natural gas utility, trading on the
New York Stock Exchange under the symbol “OGS,” and listed in the S&P MidCap 400
Index. ONE Gas is the successor to the company founded in 1906 as Oklahoma Natural Gas
Company. On January 31, 2014, ONE Gas was spun out of ONEOK, Inc. (NYSE: OKE) and now
operates as an independent natural gas distribution company focusing on delivering natural
gas safely and reliably to more than 2.1 million customers.
ONE Gas is headquartered in Tulsa, Okla.
Our Mission: Why We Exist
We deliver natural gas for a better tomorrow.
Our Vision: What We Want to Be
To be a premier natural gas distribution company,
creating exceptional value for our stakeholders.
Our Core Values
Safety: We are committed to operating safely and in
an environmentally responsible manner.
Inclusion and Diversity: We embrace and promote
diversity; every employee makes a difference and
contributes to our success.
Ethics: We adhere 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.
1
2.1
MILLION
CUSTOMERS
Oklahoma Natural Gas
Kansas Gas Service
Texas Gas Service
100%
REGULATED
Serving Residential, Commercial,
Transportation, Wholesale
and Industrial Customers
THIRD
LARGEST
Publicly Traded Natural Gas
Distribution Utility in the
United States
2
3
Financial
O V E R V IE W
2014 Summary
In our first year as a stand-alone
company, we reported net income
of $109.8 million, or $2.07 per
diluted share, and spent $297 million
in capital investments to maintain
the safety and reliability of our
systems and the high service
standards our customers expect,
while supporting growth in our
service territories.
Investments in our system led
to new rates throughout our
service territories resulting in solid
performance for 2014. Residential
customer growth in major
metropolitan areas also positively
impacted our results. Additionally,
we benefited from incremental
compressed natural gas (CNG)
revenue, as volumes increased
47 percent year over year.
Our first full-year operating costs
reflect expenses related to our
successful separation from
ONEOK and “stand-up costs”
required to establish our own
technology platform – completed
on time and under budget, and
our own insurance program.
4
We are committed to our
100 percent regulated strategy.
As a natural gas utility, we
are focused on safety through
investments in our system
and the creation of value for
all stakeholders – employees,
customers, investors
and communities.
Years Ended December 31, 2014 and 2013 (unaudited)
2014
2013
% Change
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
Total Employees, End of Period
Common Stock
$
$
$
$
$
$
$
$
$
$
109,790
2.10
2.07
0.84
826,957
166.3
379.8
10,615
9,965
99,195
10.7%
1.90
1.90
–
813,008
164.2
370.1
11,036
9,970
10.5%
9.0%
–
1.7%
1.3%
2.6%
-3.8%
–
2,127,501
2,113,912
0.6%
3,300
–
–
Market Value Per Share – Year End
$
41.22
Average Shares of Common Stock (thousands)
Basic
Diluted
52,364
52,946
52,319
52,319
Significant Scale
High Percent of Residential Customers
83%
16%
1%
Net Sales
Margin*
2014
Customer
Count*
2014
–
–
–
1.2%
92%
7%
1%
Residential • Commercial / Industrial • Other
* Excludes transportation
Oklahoma
Kansas
Texas
Fixed Charges**
Sales Customers
Average Annual Heating
Degree Days – Normal
86%
3,317
Weather Normalization***
100%
53%
4,860
100%
Average Total:
71%
–
89%
71%
1,788
62%
** Fixed percentage of total net margin on natural gas sales
*** Percent of customers who are in jurisdictions with weather normalization adjustment mechanisms
5
To My Fellow Shareholders and Employees:
At ONE Gas, 2014 was a year
of firsts. As a new stand-alone,
publicly traded company, it was
the first year we were able to
devote our full efforts to becoming
a premier natural gas distribution
company – one that is committed
to creating exceptional value for
our stakeholders.
We had a major challenge in
year one to completely separate
ourselves from our predecessor,
ONEOK. Rather than spending the
next few years relying on ONEOK
for information technology services
through transition agreements,
we made it our goal to dedicate
the capital dollars and the hours
necessary to stand on our own
in the first year. Not only was this
accomplished, but we did it with
time to spare and on budget. This
was vital for us to move forward
on a stand-alone basis, so we can
fully concentrate our resources on
the future of our business.
Our company operates
approximately 42,500 miles
of pipeline and other natural
gas distribution facilities. The
separation from ONEOK has
enabled us to get back to our
roots as a regulated natural
gas distribution business. This
increased focus has made a
major impact, as our 2014
Our company operates approximately
42,500 miles of pipeline and other
natural gas distribution facilities.
This year was a first for me as
well – my first year as the Chief
Executive Officer. I’ve been
asked frequently how it felt to
step into this role, and I have to
say, it’s been rejuvenating. In
numerous employee meetings,
their questions and comments
demonstrate a shared passion
for our business and our
customers. Our employees’
enthusiasm has shown me the
power of people, and the things
we can accomplish when we
work together. It is humbling
to be in this role, and I’m truly
enjoying the opportunity and
experiences every day.
results demonstrate. We believe
that ONE Gas is well positioned
to maintain this momentum.
Natural gas is well positioned
to be competitive against other
fuel options for decades to come.
Right now, natural gas has
approximately a 3-to-1 cost
advantage compared with
electricity. We have a high-quality
product that allows people to heat
their homes, cook their meals,
dry their clothes and enjoy hot
water – life’s essentials. And that
means we are creating a better
tomorrow for our customers.
6
• Regulatory: We strive to continue
constructive relationships with
regulators that will support our
common goal of providing safe,
reliable and cost-effective natural
gas service to our customers
and the communities we serve.
• Growth: In addition to growing
by continuing to invest in our
systems, we also are seeking
opportunities to deliver natural
gas to compressed natural gas
stations and other alternatives
that would contribute to
incremental growth regulated
transport revenue.
We believe that focusing on these
priorities will guide us toward a
successful future, while providing
our customers with life’s essentials.
Pierce H. Norton II
President and Chief Executive Officer,
ONE Gas, Inc.
April 1, 2015
As we go forward, we have five
priorities that we are challenging
ourselves to execute on with the
same enthusiasm we experienced
in our first year as a new company.
These priorities include:
• Safety: Safety has always been
our top priority and is our most
important core value. ONE Gas
will always make sure that
the safety of our employees,
customers and communities
comes before everything else.
• High-performing Workforce:
It all starts with our people.
We are dedicated to attracting
and retaining the right people
for the right jobs. Our more
than 3,300 employees also will
benefit from highly engaging
employee and leadership
development programs.
• Leveraging Technology: This
is going to be a big year for
us when it comes to
implementing software and
new technologies. Our plans
include new devices for our
operations employees that
will increase efficiency and
productivity; and adding a smart
phone application that will
offer more self-service options
for our customers.
2014 Highlights
After our first full year as ONE Gas, we
are proud of all we have accomplished:
Our net income for 2014 exceeded our
initial expectations and is expected
to grow an average of 5 to 8 percent
annually between 2014 and 2019.
At the close of 2014, our stock was
trading at new highs. We delivered
a total shareholder return of
approximately 25 percent in 2014,
outperforming our peer group
average and the S&P MidCap 400
Utilities Index. Shareholder returns
reflect solid operating and financial
results and the continued growth we
believe is ahead – all of this while
maintaining our strong investment
grade credit ratings.
For our more than 2 million customers
in Oklahoma, Kansas and Texas, we
continued our tradition of providing safe,
reliable service at competitive costs.
Our total natural gas volumes
delivered increased from 2013. The
overall average number of customers
also grew by 0.6%. Our commitment
to customer service was recognized
at Oklahoma Natural Gas, which
was named a most trusted brand –
in both the Southern region and
nationally – in the 2014 Utility Trust
Brand & Customer Engagement Study
conducted by Cogent Energy Reports,
the syndicated division of Market
Strategies International.
We worked together to define the
company’s new mission, vision and
core values.
We also created a new brand
identity, including logos, and set up
our new corporate headquarters
in Tulsa, Okla. We’ve entered 2015
with confidence in our business
strategy and our employees who
will execute on our strategic goals.
7
OUR PRIMARY TOUCHPOINTS
Warm Home
Hot Water
Dry Clothes
Cooked Meals
Abundant, efficient energy at a more
competitive cost versus alternatives – that’s
what we mean by a better tomorrow.
We provide the energy that makes your house feel
like a home. We fuel the appliances that have a
significant impact on your comfort level – your life’s
essentials – a warm home, hot water, dry clothes
and home-cooked meals.
8
9
Transitioning as a New Company
In early 2014, we
began establishing our
new ONE Gas brand
with the introduction
of a new logo on our
work locations and our
vehicle fleets. After
careful consideration,
we selected a logo
we felt represents our
company’s purpose
and exhibits energy
in motion. The four
colors represent the
four primary natural gas
usage touchpoints in
the home – the range or
cooktop, clothes dryer,
furnace and water heater.
The blues transition
purposely to represent
a natural gas flame. The
yellow piece is one of
the international colors
used to symbolize safety
and also the color used
as a standard marker for
natural gas pipelines.
On January 31, 2014, ONE Gas, Inc. separated from ONEOK, Inc. in a spinoff
that created one of the largest 100 percent regulated, publicly traded natural
gas distribution companies in the United States. From day one, ONE Gas has
focused on safety, reliability and investing in our systems, while maintaining a
conservative financial position.
10
We also are working to provide
better self-service options for
our customers.
As an independent company,
ONE Gas provides more
transparency to both regulators
and shareholders. This helps
us better collaborate with our
regulatory agencies to achieve
our common goals, while also
attracting a focused investor
base that recognizes the stability
and growth offered by ONE Gas.
A Better Tomorrow by . . .
RENEWING OUR FOCUS
As a part of ONEOK, we were
always focused on the safety
and reliability of our distribution
system, providing value and
stability to investors and fair
rates for customers. Now as
ONE Gas, we are able to put that
focus and commitment out front
as a stand-alone company – one
that operates to deliver natural
gas for a better tomorrow.
We invest the majority of capital
expenditures in system integrity
and maintenance to ensure we
can continue to provide customers
with the safe and reliable service
they expect from us. We are
growing by adding new meters,
main extensions and volumes from
transport revenues, such as CNG.
Many metropolitan areas in
our service territories have
Our success is your success, and being
able to completely focus on our regulated
distribution business gives us the ability
to deliver on our strategy.
Our diverse workforce shows up
every day with this strategy top
of mind. We know who our
customers are because we live
in the same neighborhoods and
volunteer in our communities.
We also understand that our
investors trust and expect us to
provide a fair return because a
majority of our employees are
shareholders themselves.
Our success is your success, and
being able to completely focus on
our regulated distribution business
gives us the ability to deliver on
our business strategy.
experienced growth over the past
several years, and we are seeing
the benefits of that growth.
We are improving efficiencies
by leveraging technology in
our operations.
In 2015, we will implement several
new technologies, allowing our
systems to communicate better
with each other, eliminating manual
and duplicative paperwork for our
field personnel and increasing the
productivity of our resources.
We are already taking advantage of
asset investment planning tools and
management systems to assist us in
long-range planning.
11
A Better Tomorrow by . . .
FOLLOWING OUR STRATEGIC MAP
To understand what our better
tomorrow looks like, you first have
to understand why we exist. Our
company’s mission – to deliver
natural gas for a better tomorrow –
is why our 3,300 employees get
up every day and go to work for
our customers and shareholders.
For us, a better tomorrow is
providing customers with lower
energy costs compared with other
energy alternatives and a clean
fuel source, while delivering value
to shareholders.
Executing on Our Strategy
We will accomplish these things
by following a strategic map
that will help every employee
understand where we are going
as a company and how they fit
into our plan to get there.
Our five strategic themes will be
our driving force over the next
several years as we challenge
ourselves to progress into the
future. These themes will be top
of mind for every decision we
make and every goal we want
to accomplish.
Five Strategic Themes –
ONE Gas Business Essentials
Just as our customers rely on
our product and reliable service
to provide the energy for the
life essentials of their home
or business, we also rely on
business essentials to run
our company.
Safety and Environment – Our
number one commitment is to
safety. Through a 100 percent
compliance goal, a risk-based
approach to asset replacement
and continuous improvement,
we will continue to increase the
safety and reliability of our system.
High-performing Workforce – The
foundation of our strategic map
is our largest company asset,
employees. We will continue to
attract, select, develop and retain
the talent with the necessary
skills it takes to run this business.
Additionally, we must be diligent
when it comes to developing
employees and leaders, and
promote an inclusive and diverse
workforce that is enthusiastic and
willing to change when necessary.
Leveraging Technology – We will
increase operational efficiency
through new technology and
the use of data for analytics and
decision making – all focused on
improving customer service.
Regulatory – Our goal is to
provide reasonable rates for
our customers by lowering our
operating costs to sustainable
levels and focusing on
transparency and collaboration
with our regulatory agencies,
while also creating value for
our investors.
Growth – In addition to investing
in our systems, we expect to
grow by adding both customers
and volume to our systems. We
are equipped to grow our volume
through non-traditional, regulated
means, such as combined heat
and power, distributed generation
and CNG development adding to
incremental transport revenues.
Additionally, population growth in
many of our major metropolitan
areas is leading to increased
customer growth.
12
OUR SERVICE TERRITORIES
OKLAHOMA CITY
TULSA
Oklahoma Natural Gas
853,000
Customers
Largest in Oklahoma
Natural Gas Distributor
87%
Market Share
81%
Metropolitan Customers
TOPEKA
WICHITA
KANSAS CITY
Kansas Gas Service
634,000
Customers
Largest in Kansas
Natural Gas Distributor
72%
Market Share
58%
Metropolitan Customers
EL PASO
AUSTIN
Texas Gas Service
640,000
Customers
Third Largest in Texas
Natural Gas Distributor
14%
Market Share
75%
Metropolitan Customers
13
A Better Tomorrow by . . .
VALUING SAFETY
Keeping Everybody and
Everything Safe for Today . . .
and Tomorrow
Tomorrow’s successes will be
determined in large part – as were
our past successes – by our
commitment to safety, our number
one core value.
Whether it is the safety of our
employees, customers or the
public, or the integrity of our
assets (including more than
42,500 miles of pipeline), every
day ONE Gas employees focus
on the demands of running our
natural gas system safely
and reliably.
We take pride in our dedication
to safety and to providing an
environmentally responsible
product with the most reliable
service possible. This requires
continual awareness on the part
of our employees and prudent,
ongoing investments in our pipeline
system and our other facilities.
Areas of focus include occupational
safety, employees’ health, safety
and reliability of our distribution
and transmission pipelines, and
protecting the environment.
While we are very proud of our
safety record, we know there is
always room for improvement.
Here are a few of our year one
accomplishments:
• Aging asset replacement is part
of our ongoing capital budget,
and in 2014, ONE Gas retired
or replaced approximately
475 miles of distribution and
transmission facilities.
• Our employees have one of the
best driving records among
our peer companies. For the
most recent reporting period,
the company ranked in the top
quartile of American Gas
Association member companies.
• A safe driving recognition
program rewards safe drivers
of the company’s 1,900
vehicles with an opportunity
to earn incentives for safe
driving behaviors.
• We achieved a reduction in
injuries of 15 percent in 2014
compared with 2013.
• A peer-review safety process
and employee training were
used to promote consistent,
steady improvement in our
workplace safety record.
Whether it’s the well-being of our
employees . . . or the integrity of a
two-inch distribution pipeline that
runs through a neighborhood . . .
safety is our priority.
That applies to all of our 2 million
customers, the public and our
employees, which is why at
ONE Gas, safety is not a program
but a value deeply entrenched
in our culture and our operations
365 days a year.
Protecting Our Environment
Efforts to reduce greenhouse gas emissions from ONE Gas’ operations
continue year-in and year-out, and we’re proud of our accomplishments.
Among our efforts, we are accelerating the replacement of aging
infrastructure, which lowers methane emissions from our pipelines. We
also use environmentally friendly processes to enable us to work on our
pipelines, either during pipeline replacement or during pipeline extensions,
to minimize natural gas emissions.
14
Leak surveys and inspections
are an important part of
not only our regulatory
requirements but also our
system integrity program.
15
In 2014 alone, our employees
drove more than 28 million miles
in company vehicles – equivalent
to 58 round trips to the moon!
Ensuring that we are operating our
fleets in the safest possible way is
a top priority. Our Environmental,
Safety and Health team has adopted
the Smith System®, which provides
easy-to-follow tips for safe driving.
16
A Better Tomorrow by . . .
IMPROVING SAFETY
1,032 Employees
Recognized as a part of the ONE Gas Driver Recognition Program.
This fortifies our safe driving effort. It is based on the information provided
through a 12-second video recording created by a G-force event in any one of
our more than 1,900 company vehicles.
Preventable Vehicle Incident Rate (PVIR) was
2.03 incidents per million miles driven.
AGA PVIR Quartile Data
4th Q.
3rd
2nd
1st
4th Q.
3rd
2nd
1st
3.58
2009
2.73
2010
2.35
2011
1.77
2012
2.24
2.03
2013
2014
Total Recordable Incident Rate (TRIR) was
2.45 incidents per 200,000 work hours.
AGA TRIR Quartile Data
6.34
2009
5.36
2010
4.28
2011
3.62
2012
2.98
2013
2.45
2014
The American Gas Association (AGA) represents local energy companies
that deliver clean natural gas throughout the U.S.
17
A Better Tomorrow by . . .
GIVING BACK TO COMMUNITIES
ONE Gas Foundation Established – Creating a better tomorrow for the communities
where we live and work.
Mission: To invest in programs that enhance quality of life and economic well-being in
the communities where ONE Gas operates and where our employees work and live.
Optimize Impact
Give Hope
Strengthen Communities
GUIDING PRINCIPLES
2014
36
approved requests for grants
by the ONE Gas Foundation.
$50,000 GRANT AWARDED TO HABITAT FOR HUMANITY
for a SuperBlitz project, which helped eight families build
eight new homes in two weeks in the spring. More than
130 employees also volunteered during construction.
1,826 employees, retirees and directors
pledged $706,000 to United Way
agencies in 2014, all matched dollar for dollar
totaling more than $1.4 million.
447
MATCHING GRANTS
AWARDED
based on contributions from
employees, retirees and directors
totaling more than $105,000.
36
Public school foundations
received grants.
275 EMPLOYEES + 3,267 HOURS
Volunteered time and talent for
various events and organizations.
Share The Warmth grants were made in each state where we operate. Share The Warmth is a partnership
with The Salvation Army that provides financial assistance for energy bills to families in need.
18
A Better Tomorrow through . . .
EFFICIENCY
The Energy-Efficiency Program in Oklahoma and the Conservation Program in the Austin
area both have rebate programs aimed at encouraging customers, contractors and builders to
purchase and install energy-efficient, environmentally friendly natural gas appliances.
Oklahoma Natural Gas
43,000 Rebates Totaling $7.4 Million – 24% Increase from 2013
Residential, Small Commercial Customers and Builders
43%
Natural Gas Furnace
29%
Clothes Dryer
13%
New Homes Program
2,035
2014 Range Rebate Participants
for New Program
Texas Gas Service – Austin
14,104 Rebates Worth $2.1 Million to Austin-area Customers
293
New Residential Homes
1,834
Natural Gas Appliances
810
Tankless Water Heater Units
Built with natural gas dryer stub-outs and
26 existing homeowners received a new
$300 stub-out rebate in 2014 – the first
year it was offered.
19
Our
BOARD OF DIRECTORS
From left to right:
Pattye L. Moore
Chairman,
Red Robin Gourmet Burgers
Pierce H. Norton II
President and
Chief Executive Officer,
ONE Gas, Inc.
Michael G. Hutchinson
Retired Partner,
Deloitte & Touche
Executive Team
Pierce H. Norton II, 55
President and Chief Executive Officer
Curtis L. Dinan, 47
Senior Vice President,
Chief Financial Officer and Treasurer
Joseph L. McCormick, 55
Senior Vice President, General Counsel
and Assistant Secretary
Caron A. Lawhorn, 54
Senior Vice President, Commercial
Robert S. McAnnally, 51
Senior Vice President, Operations
Rhonda L. Mayhan, 49
Vice President, Human Resources
Andrew J. Ziola, 45
Vice President, Investor Relations and
Public Affairs
Douglas H. Yaeger
Retired Chairman, President
and Chief Executive Officer,
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 Officer,
Duke Energy Americas
20
10-K
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, 2014.
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, 2014, was $1.9 billion.
On February 6, 2015, we had 51,145,396 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 21, 2015, are
incorporated by reference in Part III.
ONE Gas, Inc.
2014 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
14
25
25
25
25
26
27
28
43
45
80
80
80
80
81
81
82
82
83
87
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
Exchange Act
FERC
GAAP
GRIP
GSRS
Heating Degree Day or HDD
IASB
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
Annual Cost Adjustment
Allowance for funds used during construction
Annual Report on Form 10-K for the year ended December 31, 2014
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
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 Accounting Standards Board
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
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
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 in each jurisdiction
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
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 postretirement benefits, tax-related assets and liabilities and
other assets and liabilities primarily associated with providing natural gas distribution service in Oklahoma, Kansas and Texas.
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, Inc. 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 has not retained 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 comprised of ONEOK’s former natural gas
distribution business and are the successor to the company founded in 1906 as Oklahoma Natural Gas Company. Our company
was incorporated under the laws of the state of Oklahoma on August 30, 2013. 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 87 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 objective is focused on operating our systems in a safe, reliable and environmentally sensitive manner, growing
our business responsibly, while delivering quality customer service, which enables us to - over time - generate a competitive
total return for our shareholders and maintain our financial stability. We intend to accomplish this objective by executing on
the strategies listed below:
•
•
•
Focus on Safety - We are committed to pursuing a zero-incident safety culture with a focus on mitigating risk and
eliminating incidents that may harm our employees, contractors, the public or the environment. Comparing 2014 with
2009, we have experienced steady improvement across several key safety metrics, including a 61 percent reduction in
our total recordable incident rate and a 43 percent reduction in our preventable vehicle incident rate. In addition, a
significant portion of our capital spending is focused on the safety, reliability and efficiency of our natural gas
distribution system.
Increase Our Achieved ROE - We continually seek to improve our achieved ROE through improved operational
performance and regulatory mechanisms. For 2014, our achieved ROE was 7.6 percent across all of our service
territories. 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 lower and/or reduce the
rate of increase in operating expenses.
Focus on Our Credit Metrics and Our Balanced Approach to Capital Management - 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 employees, customers, 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 will lead to further growth of 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. As a result of overall trends in the natural gas and energy industries, we believe that 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. We remain committed to staying 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.
REGULATORY OVERVIEW
We are subject to the regulations and oversight of the state and local regulatory agencies 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.
6
Generally, a utility’s 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 a utility makes investments or incurs 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 certain expenses. Under this
mechanism, we have a targeted ROE of between 10 percent and 11 percent. If our achieved ROE is below 10 percent, our base
rates are increased upon OCC approval to an amount necessary to restore the ROE to 10.5 percent. If our achieved ROE
exceeds 11 percent, the portion of the earnings above 11 percent is shared with our customers, who receive the benefit of 75
percent of the earnings above 11 percent. We receive the benefit of the remaining 25 percent. Other regulatory mechanisms in
Oklahoma include the following:
•
Purchased Gas Adjustment Clause (PGA) - 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.
• Temperature Adjustment Clause (TAC) - The TAC is designed to reduce customers’ bills for the additional volumes
used when the actual heating degree days exceed the normalized heating degree days and to increase the 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 gas
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 million each year
from natural gas sales customers to fund the program, which provides education, heating system check-ups and
appliance rebates 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 $14.73 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 $30.28. For the year ended December 31, 2014, approximately 86 percent of
Oklahoma Natural Gas’ net margin from its sales customers was recovered from fixed charges. At December 31, 2014,
70 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 $20.12 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 $35.32. All of Oklahoma Natural Gas’ Large
Commercial and Industrial, or LCI, customers are on a fixed monthly service charge of $81.02. At December 31,
2014, 73 percent of Oklahoma Natural Gas’ commercial and industrial customers are on either SCI Rate Choice “B”
or LCI.
• 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. In 2014, Oklahoma Natural Gas collected approximately $0.8 million from the
surcharge to fund the program.
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:
7
• 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 customers’ prospective bills for the
additional volumes used when the actual heating degree days exceed the normalized heating degree days and to
increase the customers’ prospective 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 built
into its rates and its actual property tax costs 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 Postretirement 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 postretirement 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 (i.e., pipeline safety projects and 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, 2014,
approximately 54 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, each of which includes between two and 34 cities or
jurisdictions. 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 - In two 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 return, taxes and depreciation on the annual
net investment increase. 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 18 percent of its customers, Texas Gas Service makes an annual
COSA filing. 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 revenues. One COSA has no cap
on the amount of the increase. Four of the COSAs have no cap on increases related to investment; but, have caps
ranging from 3.5 percent to 5 percent or the change in the Consumer Price Index for expense increases. One COSA
caps all increases at the increase in the Consumer Price Index. A full rate case may be filed when desired by Texas
Gas Service or the regulator, but is not required.
• EPARR Filings - In the El Paso service area, comprising 38 percent of its customers, Texas Gas Service makes an
annual rate review filing. 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.
• WNA Clause - Texas Gas Service employs WNA clauses in eight of its services areas, comprising approximately 62
percent of its customers. In one of the service areas without WNA, which comprises approximately 38 percent of its
customers, Texas Gas Service recovers 88 percent of net margin from fixed charges, making revenues in this service
area less weather sensitive. WNA is designed to reduce customers’ bills for the additional volumes used when the
actual heating degree days exceed the normalized heating degree days and to increase 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 revenues
8
•
•
•
recovered through the COG with the actual natural gas supply costs and any over or under recovery is refunded or
recovered, as applicable, in the subsequent year.
Pension and Other Postretirement Benefits - Texas Gas Service is authorized by statute to defer pension and other
postretirement 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 accrue a rate of return for
regulatory accounting purposes, 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 37 percent of total customers. Texas Gas Service collects approximately $2 million per year from
customers to fund the program, which provides energy audits, weatherization and appliance rebates to promote energy
efficiency.
The average fixed monthly residential customer charge for Texas Gas Service is $14.39, and for the year ended December 31,
2014, approximately 71 percent of Texas Gas Service’s net margin from its sales customers was recovered from fixed charges.
MARKET CONDITIONS AND SEASONALITY
Supply - We purchased 180 Bcf and 189 Bcf of natural gas supply in 2014 and 2013, respectively. The decrease in 2014
resulted primarily from additional supply requirements due to colder temperatures in 2013. 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, natural gas marketers and natural gas 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.
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.
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. As of December 31, 2014, we had 52.3 Bcf of natural gas storage
capacity under lease with remaining terms ranging from one to five years and maximum allowable daily withdrawal capacity of
approximately 1.4 Bcf. This storage capacity allows us to purchase natural gas during the off peak season and store it for use in
9
the winter periods. Approximately 26 percent of our winter natural gas supply needs for our sales customers are expected to be
supplied from storage.
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 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.
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, 2014.
(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, 2014.
(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.
11.94¢
34.99
11.21
3.1x
12.21¢
35.79
9.97
3.6x
9.63¢
28.22
10.73
2.6x
$
$
$
$
$
$
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, 2014, we supply 114 fueling
stations, 31 of which we operate. Of the 83 remaining stations, we provide supply to 37 retail and 46 private CNG stations.
We transported 2.0 million Dth to CNG stations in 2014, which represents an increase of 47 percent compared with 2013.
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.
10
ENVIRONMENTAL AND SAFETY MATTERS
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 at our facilities. 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.
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. The Pipeline Safety
Improvement Act requires pipeline companies operating high-pressure 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 on 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 all 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 Comprehensive Environmental Response, Compensation and Liability Act, 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.
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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.
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
release of natural gas during pipeline and facility maintenance and operations.
Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See discussion
of our regulatory initiatives in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
EMPLOYEES
We employed approximately 3,300 people at January 30, 2015, 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, 2015:
The United Steelworkers
International Brotherhood of Electrical Workers (IBEW)
Union
Approximate
Employees
400
300
Contract Expires
October 28, 2016
June 30, 2017
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EXECUTIVE OFFICERS
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 and Position
Pierce H. Norton II
Age*
54
2014 to present
Business Experience in Past Five Years
President, Chief Executive Officer and Director
President, Chief Executive Officer and Director
2013 to 2014
2012
2011
Executive Vice President, Commercial, ONEOK and ONEOK
Partners
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
47
2014 to present
Senior Vice President, Chief Financial Officer and Treasurer
Senior Vice President, Chief Financial Officer
and Treasurer
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
Joseph L. McCormick
55
2014 to present
Senior Vice President, General Counsel and Assistant
Secretary
Senior Vice President, General Counsel and
Assistant Secretary
2008 to 2014
Vice President and Associate General Counsel, ONEOK and
ONEOK Partners
Caron A. Lawhorn
53
2014 to present
Senior Vice President, Commercial
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
Gregory A. Phillips
51
2014 to present
Senior Vice President, Operations
Senior Vice President, Operations
* As of January 1, 2015
2013 to 2014
Senior Vice President, Operations, Natural Gas Distribution,
ONEOK
2011 to 2012
President, Oklahoma Natural Gas, ONEOK
2008 to 2011
President, Texas Gas Service, ONEOK
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
(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, 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.
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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
Unfavorable economic and market conditions could affect adversely our earnings.
Weakening economic activity in our markets could result in a loss of existing customers, fewer new customers, especially in
newly constructed homes, or a decline in energy consumption, any of which could affect adversely 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 affect adversely 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 affect adversely 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 affect adversely 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.
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 agencies 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
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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. Rate cases also involve a risk of rate reduction, because once rates
have been filed, they are subject to challenge for their reasonableness 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 from 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 affect adversely 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.
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 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.
We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs is dependent on
regulatory action.
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, financing,
affiliate transactions, customer service and 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.
Our business is subject to competition that could affect adversely 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
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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 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 affect adversely 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. 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 affect adversely our cost of and ability to access capital.
Our ability to obtain adequate and cost-effective financing depends in part on our credit ratings. A negative change in our
ratings by our rating agencies could affect adversely 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 affect adversely 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
16
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 affect adversely 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 affect adversely 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 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 affect adversely our business, 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
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, 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.
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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 affect adversely 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 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 pipeline expansion or infrastructure development projects, which
may delay or prevent us from serving our customers or expanding our business.
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. 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 affect adversely 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.
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At December 31, 2014, 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 affect adversely 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 affect adversely 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
could affect adversely our cash flows. Any of these events may cause us to increase debt, conserve cash, affect adversely our
ability to make capital expenditures to grow the business or other discretionary uses of cash, and could affect adversely 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 affect adversely 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.
19
The cost of providing pension and other postretirement 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 postretirement welfare plans for certain employees. Liabilities related to
employee and retiree benefit plans following our separation from ONEOK generally were assigned based on the individual’s
last employment, so each individual who retired from ONEOK while providing service to the natural gas distribution segment
or was assigned to ONE Gas following our separation had his or her benefit plan liabilities assigned to ONE Gas. Employee
and retiree benefit liabilities relating to all other personnel not meeting one of the two criteria above remained the liability of
ONEOK. Assets in the benefit plans were assigned in accordance with the applicable rules and regulations associated with the
division of a single plan into separate plans.
Our defined benefit plans are closed to new participants, and our other postretirement welfare plans only subsidize costs for
providing postretirement medical benefits for certain grandfathered participants. 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 postretirement 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 yields may have a material adverse effect on the value of our
pension and other postretirement benefit plan assets. In these circumstances, additional cash contributions to our pension and
other postretirement 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
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 affect
adversely our earnings 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
20
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 affect
adversely 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, and this may subject our business to
increased risks. Any future cyber security attacks that affect our distribution facilities, our customers or any financial data
could have a material adverse effect on our businesses. In addition, cyber attacks on our 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 affect adversely 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, 2015, approximately 700 of our estimated 3,300 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
affect adversely 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
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 affect adversely 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 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 IASB, which
are currently in effect for most other countries in the world. Unlike GAAP, IFRS does not provide currently an industry
21
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.
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, 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 are based on variable rates of interest. The
interest rates on those borrowings will vary depending on a fluctuating base rate or a rate based off of LIBOR at our selection.
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 may be unable to achieve some or all of the benefits that we expect to achieve from our separation from ONEOK.
We may be unable to achieve the full strategic and financial benefits that we expect will result from our separation from
ONEOK or such benefits may be delayed or may not occur at all. For example, there can be no assurance that analysts and
investors will regard our corporate structure as clearer and simpler than the ONEOK corporate structure prior to the separation
or place a greater value on our company as a stand-alone company than on our business as a part of ONEOK. In addition, we
may not be able to allocate capital more efficiently or attract a more focused investor base.
We were recently separated from ONEOK, our former parent company, and, therefore, we have limited operating history as
a separate, publicly traded company.
The historical financial information prior to our separation from ONEOK included in this Annual Report does not necessarily
reflect the financial condition, results of operations or cash flows that we would have achieved as a separate, publicly traded
company during those periods primarily as a result of the following factors:
•
•
Prior to the separation our business was operated by ONEOK as part of its broader corporate organization, rather
than as a separate, publicly traded company. ONEOK or one of its affiliates performed various corporate functions
for us, including, but not limited to, information technology, accounts payable, cash management, treasury, tax
administration, legal, regulatory, certain governance functions (including compliance with the Sarbanes-Oxley Act of
2002, Dodd-Frank Wall Street Reform and the Consumer Protection Act of 2010), and internal audit and external
reporting. Our historical financial results prior to the separation reflect allocations of corporate expenses from
ONEOK for these and similar functions. These allocations may be inconsistent with what our expenses would have
been as a separate, publicly traded company.
Prior to the separation we shared economies of scope and scale in costs, employees and vendor relationships with
ONEOK. While we entered into a short-term transition agreement that will govern certain commercial and other
relationships among us and ONEOK, those contractual arrangements may not capture the benefits our business
historically received. The loss of these benefits of scope and scale may have an adverse effect on our business,
22
•
results of operations, financial condition and liquidity.
Prior to the separation, ONEOK incurred separation costs for professional services, including financial advisors,
legal, accounting, information technology, human resources and other business consultants. ONEOK did not
allocate these separation costs to us. Subsequent to the separation, we have incurred additional expenses as a result
of being a stand-alone publicly traded company. Under the terms of the Separation and Distribution Agreement
between us and ONEOK, we are responsible for all costs and expenses that we incur as a stand-alone company after
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
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.
The ownership by our executive officers and some of our directors of shares of common stock of ONEOK and limited
partnership units of ONEOK Partners and the service of certain of our directors on the boards of ONEOK and ONEOK
Partners may create, or may create the appearance of, conflicts of interest.
Because of their current or former positions with ONEOK, substantially all of our executive officers, including our chief
executive officer, and some of our nonemployee directors, own shares of ONEOK common stock and limited partnership units
of ONEOK Partners. Accordingly, immediately following ONEOK’s distribution of all of the shares of our outstanding
common stock to ONEOK shareholders, these officers and nonemployee directors owned, and may continue to own, shares of
both ONEOK and our common stock. The individual holdings of common stock and limited partnership units may be
significant for some of these persons compared with these persons’ total assets. Certain of our directors, who currently
comprise a minority of the overall composition of our board, also serve on the boards of ONEOK and/or ONEOK Partners.
Ownership by our directors and officers of common stock of ONEOK and limited partnership units of ONEOK Partners and
board service on the ONEOK and/or ONEOK Partners boards may create, or may create the appearance of, conflicts of interest
when these directors and officers are faced with decisions that could have different implications for ONEOK and ONEOK
Partners than the decisions do for us.
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
23
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.
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 are important for a new public company and 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.
24
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
We own approximately 19,000 miles of pipeline and other natural gas distribution facilities in Oklahoma; approximately 13,500
miles of pipeline and other natural gas distribution facilities in Kansas; and approximately 10,000 miles of pipeline and other
natural gas distribution facilities in Texas. We lease approximately 1.2 million square feet of office space and other facilities
for our operations. In addition, we have 52.3 Bcf of natural gas storage capacity under lease, with maximum allowable daily
withdrawal capacity of approximately 1.4 Bcf/d.
ITEM 3.
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.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
25
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
Year Ended
December 31, 2014*
High
Low
Dividends
First Quarter
Second Quarter
Third Quarter
$
$
$
35.80 $
37.98 $
37.77 $
Fourth Quarter
*Our common stock began regular-way trading on February 3, 2014.
$
44.19 $
31.53 $
34.25 $
34.00 $
34.03 $
—
0.28
0.28
0.28
At February 6, 2015, there were 15,197 holders of record of our 52,145,396 outstanding shares of common stock.
In January 2015, we declared a dividend of $0.30 per share ($1.20 per share on an annualized basis), payable on March 2,
2015, to shareholders of record as of February 20, 2015.
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 2014 totaled 35,324, and
compensation expense related to the Employee Stock Award Program was $2.5 million.
The total number of shares of our common stock available 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.
26
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth ONE Gas selected financial data for each of the periods indicated:
2014
Years Ended December 31,
2012
(Millions of dollars except per share data)
2011
2013
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
$
$
$
$
$
$
$
$
$
$
1,818.9
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
—
$
$
$
$
$
$
$
$
$
1,621.3
751.8
199.7
86.8
3,285.5
912.4
1.9
1.66
1.66
—
2010
1,817.4
754.9
225.6
106.4
3,095.1
756.4
2.2
2.03
2.03
—
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.
27
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 utility. 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 71 percent
and 69 percent of our natural gas sales net margin in 2014 and 2013, 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, which 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 is thus contingent on a number of factors, including: (1) regulatory outcomes, which dictate the
returns we are authorized to earn and the rates we are allowed to charge for our service; (2) the performance of the financial
markets, which influences the rates of return authorized by our regulators; (3) the consumption of natural gas, which impacts
the amount of our net margin derived from the variable component of our rates; (4) our operating performance, which impacts
our operating expenses; and (5) 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 safety 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, we are unable to predict the impact that new regulatory requirements will have on
our operating expenses or the level of our capital expenditures. Although we believe our regulators will continue to allow
recovery of such expenditures in the future, we cannot be assured of that outcome.
RECENT DEVELOPMENTS
Distribution - 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 to allow 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 postretirement 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 the 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’ 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, Inc. 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.
28
In December 2013, we entered into a $700 million revolving credit agreement, which became effective upon the separation.
Dividend - In 2014, we paid dividends totaling $0.84 per share ($0.28 per share in each of our second, third and fourth
quarters) on our common stock. In January 2015, a dividend of $0.30 per share ($1.20 per share on an annualized basis) was
declared for shareholders of record on February 20, 2015, payable March 2, 2015.
REGULATORY ACTIVITIES
Oklahoma - In October 2013, Oklahoma Natural Gas, together with the Public Utility Division of the OCC, filed a joint
application to postpone its 2014 rate case. The joint stipulation and settlement agreement in support of this application was
approved by the OCC in January 2014. As a result, Oklahoma Natural Gas filed a PBRC application on March 14, 2014, and
will file a rate case in 2015 based on a test year consisting of the 12 months ending March 31, 2015. The March 2014, PBRC
filing demonstrated that Oklahoma Natural Gas was earning below the range of allowable return on equity. 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.
In June 2013, the OCC approved the extension of a portfolio of conservation and energy-efficiency programs and authorized
recovery of costs and performance incentives through 2016, as well as adjustments to rebate amounts and targets that were
requested by Oklahoma Natural Gas. The agreement allows Oklahoma Natural Gas to pursue key energy-efficiency programs
and earn up to approximately $1.2 million annually, if program objectives are achieved.
In July 2012, a joint stipulation settling Oklahoma Natural Gas’ annual PBRC filing was approved by the OCC. The settlement
granted a $9.5 million rate increase and modified Oklahoma Natural Gas’ PBRC tariff. The modified tariff narrows the range
of allowed ROE to a range of 10.0 percent to 11.0 percent from our previous range of 9.75 percent to 11.25 percent, increases
the ROE reflected in any rate increase resulting from a revenue deficiency to 10.5 percent from 10.25 percent, and reduces the
number of allowed pro forma adjustments that can be proposed by Oklahoma Natural Gas.
Kansas - In August 2014, Kansas Gas Service submitted an application to the KCC requesting an increase in base rates of
approximately $3.5 million related to its GSRS. This surcharge 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. On November 25, 2014, the KCC approved an increase of $3.5 million, which became effective on
December 1, 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 postretirement benefit costs used to calculate Kansas Gas Service’s Pension and Other
Postretirement 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.
In August 2013, Kansas Gas Service filed an application to increase the GSRS by $1.5 million. The KCC approved the final
ruling that became effective December 1, 2013.
29
In October 2012, Kansas Gas Service, the staff of the KCC and the Citizens’ Utility Ratepayer Board filed a joint motion to
approve a stipulated settlement agreement granting a $28 million increase in base rates and an $18 million reduction in amounts
currently recovered through surcharges, effectively increasing its annual revenues by a net amount of $10 million. The KCC
approved this settlement in December 2012, and the new rates were effective January 2013.
In September 2012, the KCC denied Kansas Gas Service’s application to implement an infrastructure-replacement program that
would have allowed Kansas Gas Service to accelerate the rate at which it is replacing cast-iron pipe. Costs incurred by Kansas
Gas Service to replace cast-iron pipe are eligible for the GSRS.
The KCC approved an application from Kansas Gas Service to increase the GSRS by an additional $2.9 million, effective
January 2012.
Texas - GRIP is a capital-recovery mechanism that allows for an interim rate adjustment providing recovery of and a return on
incremental capital investments made between rate cases. Texas Gas Service filed requests for interim rate relief under the
GRIP statute with the City of Austin, Texas, and surrounding communities in February 2015, for approximately $3.7 million. If
approved by the cities, new rates will become effective in April 2015.
In March 2014, Texas Gas Service and the City of El Paso agreed to enter into an annual rate review mechanism called the
EPARR in lieu of a filing under the GRIP statute with the City of El Paso. Texas Gas Service filed under the GRIP statute for
other cities in the El Paso service area. The EPARR provides for a streamlined review of Texas Gas Service’s revenue
requirement based upon an agreed upon capital structure and return on equity. In April 2014, Texas Gas Service filed under the
EPARR for an increase in revenues in the City of El Paso, and under the GRIP statute for the remainder of the El Paso service
area. In July 2014, the City of El Paso approved an annual increase in revenues of $3.5 million, resulting from the EPARR
filing. The GRIP filing for the remainder of the El Paso service area was approved with an increase in revenues of $0.6
million.
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 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.
Texas Gas Service filed requests for interim rate relief under the GRIP statute with the cities of Austin, Texas, and surrounding
communities in February 2012 and with El Paso, Texas, in April 2012 for approximately $3.5 million and $1.9 million,
respectively. In May 2012, the City of Austin approved the requested increase. In July 2012, the City of El Paso approved an
increase of $1.3 million.
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
$4.0 million, $4.2 million and $10.1 million associated with these filings were approved in 2014, 2013 and 2012, respectively.
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 2014 or 2012.
30
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,
2013
2012
2014
Variances
2014 vs. 2013
Increase (Decrease)
Variances
2013 vs. 2012
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
$
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
$
$
$
1,252.0
88.8
620.2
720.6
35.8
756.4
410.5
130.2
215.7
272.0
$
$
$
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 % $
306.5
9.9
256.7
59.7
(3.1)
56.6
37.4
14.6
4.6
20.1
24 %
11 %
41 %
8 %
(9)%
7 %
9 %
11 %
2 %
7 %
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,
2013
2012
2014
Variances
2014 vs. 2013
Increase (Decrease)
Variances
2013 vs. 2012
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
569.7
112.9
5.6
688.2
102.3
790.5
$
$
564.5
111.5
5.6
681.6
98.7
780.3
$
$
523.4
103.8
4.6
631.8
88.8
720.6
$
$
5.2
1.4
—
6.6
3.6
10.2
1% $
1%
—%
1%
4%
1% $
41.1
7.7
1.0
49.8
9.9
59.7
8%
7%
22%
8%
11%
8%
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,
2013
2012
2014
Variances
2014 vs. 2013
Increase (Decrease)
Variances
2013 vs. 2012
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
490.4
197.8
688.2
$
$
470.6
211.0
681.6
$
$
439.3
192.5
631.8
$
$
19.8
(13.2)
6.6
4 % $
(6)%
1 % $
31.3
18.5
49.8
7%
10%
8%
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
31
•
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 postretirement benefit costs
resulting from an annual change in the estimated discount rate.
Depreciation and amortization expense decreased due to a decrease in the amortization associated with the ad-valorem
surcharge rider in Kansas and the expiration of the take-or-pay rider in Oklahoma, and a decrease associated with the settlement
agreement approved by the KCC in 2013 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 offset
partially by increased depreciation from our capital expenditures.
2013 vs. 2012 - Net margin increased $56.6 million due primarily to the following:
•
•
•
an increase of $36.8 million from new rates in all three states;
an increase of $12.5 million due to higher sales volumes due primarily to colder-than-normal weather in all three
states compared with warmer than normal weather in 2012; and
an increase of $5.9 million from higher transportation volumes due primarily to higher demand from weather-sensitive
customers in Kansas.
Operating costs increased $37.4 million due primarily to the following:
•
•
•
•
an increase of $14.3 million in employee-related expense, primarily pension cost increases resulting from an annual
change in the estimated discount rate;
an increase of $10.1 million in share-based compensation related to share-based compensation awards granted to our
direct employees and general and administrative personnel of ONEOK providing services on our behalf due to the
appreciation of ONEOK’s share price in 2013;
an increase of $7.0 million in ad valorem tax expense primarily as a result of an increase in the level of ad valorem tax
expense recovered in base rates, which is offset in net margin. For Kansas Gas Service, actual ad valorem taxes
incurred that differ from the level of ad valorem taxes recovered currently in base rates are deferred and recovered or
refunded through the ATSR; and
an increase of $2.9 million in bad debt expense.
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
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 increased $5.0 million for 2014, compared with 2013, primarily as a result of an increase in information
technology hardware and software. Capital expenditures increased $20.1 million for 2013, compared with 2012, primarily as a
result of extending service to new areas. Our capital expenditures are expected to be approximately $300 million for 2015.
32
Selected Operating Information - The following tables set forth certain selected operating information for the periods
indicated:
(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
Commercial and industrial
Wholesale and public authority
Transportation
Total customers
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
(in thousands)
2013
2012
Increase (Decrease)
Average Number of Customers
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Years Ended
December 31,
Variances
2013 vs. 2012
Residential
770
577
72
—
5
50
—
6
597
33
3
1
1,944
155
3
12
764
577
71
—
5
50
—
6
591
33
3
1
1,932
154
3
12
847
633
634
2,114
840
633
628
2,101
6
1
—
—
7
—
—
—
—
—
6
—
—
—
6
12
1
—
—
13
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
Years Ended December 31,
2013
2012
2014
125,337
38,555
2,454
166,346
213,456
379,802
122,855
36,956
4,403
164,214
205,915
370,129
103,799
31,459
6,135
141,393
199,408
340,801
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. Residential and commercial and industrial natural gas sales volumes increased
for 2013, compared with 2012, due primarily to colder temperatures in 2013. 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.
Years Ended
December 31,
2014
2013
Heating Degree Days
Actual
Normal
Actual
Normal
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
33
3,848
5,246
1,942
3,317
4,860
1,793
(3)%
(1)%
(12)%
112%
107%
96%
116%
108%
108%
Years Ended
December 31,
2013
2012
Heating Degree Days
Actual
Normal
Actual
Normal
2013 vs
2012
Actual
Variance
2013
2012
Actual as a percent of
Normal
Oklahoma
Kansas
Texas
3,848
5,246
1,942
3,317
4,860
1,793
2,721
3,796
1,492
3,334
4,801
1,789
41%
38%
30%
116%
108%
108%
82%
79%
83%
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, 2008, for years 1999-2008, 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
• HDDs, which are used primarily in the weather normalization billing calculations for each service area of Texas, are
weighted using 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
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.
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 cash from operations, the retained proceeds from our private
placement of senior notes in January 2014 and our commercial paper program. 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 entered into the ONE Gas Credit Agreement, which is a $700 million unsecured revolving credit facility that became
effective upon our separation from ONEOK. In July 2014, we entered into a commercial paper program to support our
working capital requirements and general corporate needs.
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
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
34
ratings. A downgrade of our investment-grade rating would increase our future cost of borrowing and affect adversely our
available liquidity.
Short-term Financing - We entered into the ONE Gas Credit Agreement, which is scheduled to expire in January 2019. 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, 2014, our total debt-to-
capital ratio was 41 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.
In July 2014, we entered into 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, 2014, we had issued $42.0 million in the form of commercial paper, $1.0 million in letters of credit
outstanding and had approximately $11.9 million of cash and cash equivalents. At December 31, 2014, we had no borrowings
and $657.0 million of credit available under the ONE Gas Credit Agreement. The weighted-average interest rate on our
commercial paper was 0.32 percent at December 31, 2014.
Debt Issuance - In January 2014, we completed a private placement of 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 from the private placement 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.
In connection with the issuance of our privately placed senior notes, we entered into a registration rights agreement, pursuant to
which we were obligated to use our commercially reasonable efforts to file with the SEC and cause to become effective a
registration statement with respect to an offer to exchange each series of our privately placed senior notes for new notes via a
noncash exchange, with terms substantially identical in all material respects to each such series of our privately placed senior
notes. Our registration statement, as amended, was declared effective by the SEC on September 5, 2014. We completed the
noncash exchange of our privately placed senior notes for our registered Senior Notes in October 2014.
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
35
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.
Treasury Shares - In February 2015, our Board of Directors authorized us to purchase treasury shares to be used to offset
shares issued under our employee and non-employee director equity compensation, dividend reinvestment and employee stock
purchase plans. The 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 may purchase, and we can terminate or limit the program at any time.
Credit Ratings - Our credit ratings as of January 31, 2015 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, 2014, our total capitalization structure is 41 percent debt to 59 percent equity.
Pension and Other Postretirement Benefit Plans - Information about our pension and other postretirement 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,
2014
2013
2012
Variances
2014 vs. 2013
Variances
2013 vs. 2012
Increase
(Decrease)
Increase
(Decrease)
(Millions of dollars)
$
$
246.6
(297.1)
59.2
8.7
3.2
11.9
$
$
154.2
(290.7)
135.7
(0.8)
4.0
3.2
$
$
196.6
(270.6)
73.5
(0.5)
4.5
4.0
$
$
92.4 $
(6.4)
(76.5)
9.5
(0.8)
8.7 $
(42.4)
(20.1)
62.2
(0.3)
(0.5)
(0.8)
36
Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. 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.
2014 vs. 2013 - Cash flows from 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.
2013 vs. 2012 - Cash flows from operating activities decreased in 2013, compared to 2012, 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 - 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.
2013 vs. 2012 - Cash used in investing activities increased for 2013, compared to 2012, due primarily to capital expenditures
for pipeline replacements.
Financing Cash Flows - 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.
2013 vs. 2012 - The changes in cash flows from financing activities is the result of our participation in ONEOK’s cash
management program and distributions to ONEOK.
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 at our facilities. 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 2014, 2013 and 2012. We do not expect to incur material expenditures for
these matters in the future.
37
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. The Pipeline Safety
Improvement Act requires pipeline companies operating high-pressure 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.
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
release of natural gas during pipeline and facility maintenance and operations.
38
Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See discussion
of 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 sections entitled “Environmental and Safety
Matters” and “Environmental Matters” in Item 1 and Note 14 of the Notes to Financial Statements in this Annual Report,
respectively. 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 2014, 2013 and 2012. We do not expect to
incur material expenditures for these matters in the future.
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.
The following summary sets forth what our management considers to be our most critical 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 the Annual Audited
Financial Statements included elsewhere 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 2014 and 2013, utilized a qualitative assessment and did not result in any impairment indicators.
Subsequent to July 1, 2014, 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
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
39
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 the Annual Audited Financial Statements for our goodwill disclosure.
Pension and Other Postretirement Benefits - We have defined benefit retirement plans covering certain full-time employees.
We also sponsor welfare plans that provide other postretirement medical and life insurance benefits to certain 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
postretirement 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
postretirement plan obligations of approximately $1.1 billion, and sponsored pension and other postretirement 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, certain employees participated in similar defined benefit pension plans and other postretirement 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 postretirement expenses were allocated to us based on plan participants who directly supported our operations. These
pension and other postretirement 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 included in this Annual Report for discussion of ONEOK’s allocation methodology.
An actuarial consultant calculates the expense related to our plans, and the Plans, and uses statistical and other factors that
attempt 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. As of 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. See Note 12 of the Notes to Financial Statements in this Annual Report for additional information.
During 2014, we recorded net periodic benefit costs of $27.1 million and $5.9 million related to our pension plans and other
postretirement benefit plans, respectively. We estimate that in 2015, we will record $39.7 million and $6.7 million related to
pension plans and other postretirement benefit plans, respectively, prior to regulatory deferrals.
The following table sets forth the weighted-average assumptions used to determine our estimated 2015 net periodic benefit cost
related to our defined pension and other postretirement benefit plans, and sensitivity to changes with respect to these
assumptions:
Discount rate
Expected long-term return on plan assets
Rate Used
Cost
Sensitivity (a)
Obligation
Sensitivity (b)
(Millions of dollars)
4.25% $
7.75% $
4.3
2.4
$
$
41.6
—
(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.
40
Assumed health care cost-trend rates have a significant effect on the amounts reported for our other postretirement 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 postretirement benefit obligation
One Percentage
Point Increase
One Percentage
Point Decrease
(Millions of dollars)
$
$
1.5
6.9
$
$
(1.4)
(6.7)
During 2014, we contributed approximately $0.9 million and approximately $9.2 million to our pension plans and other
postretirement benefit plans, respectively. In 2015, we expect to contribute approximately $0.9 million and approximately $3.9
million to our defined benefit pension plans and other postretirement 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 2014, 2013 and 2012. 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 the Annual Audited Financial Statements included elsewhere in this Annual
Report for additional discussion of contingencies.
CONTRACTUAL OBLIGATIONS
The following table sets forth our contractual obligations at December 31, 2014:
Contractual Obligations
(Millions of dollars)
2015
2016
2017
2018
2019
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
$
$
42.0
—
45.1
192.4
199.4
4.8
4.7
488.4
$
$
— $
—
45.1
176.5
4.1
7.2
4.5
237.4
$
— $
—
45.1
142.8
4.1
6.5
4.3
202.8
$
— $
—
45.1
100.7
4.1
5.9
4.0
159.8
$
— $
— $
300.0
39.4
44.7
4.1
5.3
3.4
396.9
901.3
688.1
44.4
3.0
—
10.4
$ 1,647.2
42.0
1,201.3
907.9
701.5
218.8
29.7
31.3
$ 3,132.5
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.
41
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 postretirement benefit plans for 2015. 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.
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;
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 supply;
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;
42
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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 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;
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;
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;
our ability to operate effectively as a separate, publicly traded company; 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 interest rates or commodity
prices 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.
43
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.
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, 2014 and
2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014 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, 2014, 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 2014 and 2013). 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 19, 2015
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 (Note 7)
Basic
Diluted
Average shares (thousands)
Basic
Diluted
Dividends declared per share of stock
See accompanying Notes to Financial Statements.
Years Ended December 31,
2013
(Thousands of dollars, except per share amounts)
2014
2012
$
$
1,818,906
991,949
826,957
$
1,689,952
876,944
813,008
1,376,649
620,260
756,389
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
$
$
$
363,120
130,150
47,405
540,675
215,714
3,664
(2,225)
(60,793)
156,360
(59,851)
96,509
1.84
1.84
52,319
52,319
— $
52,319
52,319
—
$
$
$
$
46
Years Ended December 31,
2013
2012
2014
(Thousands of dollars)
$
99,195
$
109,790
(1,781)
(1,781)
108,009
$
—
—
99,195
$
96,509
—
—
96,509
ONE Gas, Inc.
STATEMENTS OF COMPREHENSIVE INCOME
Net income
Other comprehensive income (loss), net of tax
Change in pension and other postretirement benefit plans liability, net of tax of
$1,244, $0, 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 (Note 10)
Current assets
Cash and cash equivalents
Accounts receivable, net
Income tax receivable
Natural gas in storage
Regulatory assets (Note 9)
Other current assets
Total current assets
Goodwill and other assets
Regulatory assets (Note 9)
Goodwill
Other assets
Total goodwill and other assets
Total assets
See accompanying Notes to Financial Statements.
December 31, December 31,
2014
2013
(Thousands of dollars)
$
$
4,850,201
1,556,481
3,293,720
4,534,074
1,489,216
3,044,858
11,943
326,749
43,800
185,300
50,193
49,516
667,501
3,171
356,988
—
166,128
21,657
54,240
602,184
478,723
157,953
51,313
687,989
4,649,210
$
23,822
157,953
17,658
199,433
3,846,475
$
48
ONE Gas, Inc.
BALANCE SHEETS
(Continued)
Equity and Liabilities
Equity and long-term debt
Common stock, $0.01 par value:
authorized 250,000,000 shares; issued and outstanding 52,083,859 shares at December 31,
2014; authorized 1,000 shares, issued and outstanding 100 shares at December 31, 2013
Paid-in capital
Retained earnings
Accumulated other comprehensive income (loss)
Owner’s net investment
Total equity
Long-term debt, excluding current maturities
Long-term line of credit with ONEOK
Total equity and long-term debt
Current liabilities
Current maturities of long-term debt
Notes payable
Short-term note payable to ONEOK
Affiliate payable
Accounts payable
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 (Note 14)
Total liabilities and equity
See accompanying Notes to Financial Statements.
December 31, December 31,
2014
2013
(Thousands of dollars)
$
$
521
1,758,796
39,894
(5,174)
—
1,794,037
1,201,311
—
2,995,348
—
—
—
—
1,239,023
1,239,023
1,318
1,027,631
2,267,972
6
42,000
—
—
159,064
44,742
26,019
60,003
32,467
28,132
392,433
894,585
287,779
79,065
1,261,429
6
—
444,960
22,403
169,500
32,426
4,791
57,360
17,796
19,835
769,077
743,452
—
65,974
809,426
$
4,649,210
$
3,846,475
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:
$
109,790
$
99,195
$
96,509
2014
Years Ended December 31,
2013
(Thousands of dollars)
2012
125,722
49,935
7,613
7,195
23,044
(43,800)
(19,172)
(47,125)
—
(6,881)
12,316
21,228
2,643
30,067
(10,102)
(15,810)
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
$
21,066
44,603
$
— $
$
— $
144,758
62,205
—
5,460
(102,142)
—
(63,139)
(46,567)
(8,140)
37,241
2,449
(5,443)
(727)
29,436
—
(378)
154,208
(292,080)
1,327
(290,753)
150,851
—
—
—
—
—
—
—
(206)
(14,969)
135,676
(869)
4,040
3,171
$
61,366
— $
$
— $
$
67
130,150
59,491
—
2,528
10,016
—
30,154
(47,658)
(7,229)
(3,950)
174
(4,511)
(1,254)
(59,338)
—
(8,495)
196,587
(272,014)
1,462
(270,552)
58,692
—
—
—
115,235
—
—
—
(330)
(100,067)
73,530
(435)
4,475
4,040
—
60,793
—
360
Depreciation and amortization
Deferred income taxes
Share-based compensation expense
Provision for doubtful accounts
Changes in assets and liabilities:
Accounts receivable
Income tax receivable
Natural gas in storage
Asset removal costs
Affiliate payable
Accounts payable
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
Issuance of debt, net of discounts
Long-term debt financing costs
Borrowings on long-term line of credit with ONEOK
Cash payment to ONEOK upon separation
Issuance of common stock
Dividends paid
Repayment of long-term debt
Distributions to ONEOK
Cash provided by 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 paid for income taxes
Cash paid to ONEOK for income taxes
See accompanying Notes to Financial Statements.
$
$
$
$
$
51
ONE Gas, Inc.
STATEMENTS OF EQUITY
January 1, 2012
Net Income
Distributions to ONEOK
December 31, 2012
Net Income
Distributions to ONEOK
Common stock issued
December 31, 2013
Net income
Other comprehensive loss
Net transfers from ONEOK (Note 2)
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
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 $
— $
—
—
—
—
—
—
—
—
—
—
—
520
1
—
521 $
— $
—
—
—
—
—
—
—
—
—
—
1,749,078
(520)
9,614
624
1,758,796 $
—
—
—
—
—
—
—
—
84,214
—
—
—
—
—
(44,320)
39,894
52
Owner’s Net
Investment
Accumulated
Other
Comprehensive
Income (Loss)
(Thousands of dollars)
Total Equity
$
$
1,158,355 $
96,509
(100,067)
1,154,797
99,195
(14,969)
—
1,239,023
25,576
—
484,479
(1,749,078)
—
—
—
— $
— $
—
—
—
—
—
—
—
—
(1,781)
(3,393)
—
—
—
—
(5,174) $
1,158,355
96,509
(100,067)
1,154,797
99,195
(14,969)
—
1,239,023
109,790
(1,781)
481,086
—
—
9,615
(43,696)
1,794,037
ONE Gas, Inc.
STATEMENTS OF EQUITY
(Continued)
January 1, 2012
Net Income
Distributions to ONEOK
December 31, 2012
Net Income
Distributions to ONEOK
Common stock issued
December 31, 2013
Net income
Other comprehensive loss
Net transfers from ONEOK (Note 2)
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
See accompanying Notes to Financial Statements.
53
ONE Gas, Inc.
NOTES TO FINANCIAL STATEMENTS
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations - ONE Gas, Inc. was a wholly owned subsidiary of ONEOK as of December 31,
2013. We are comprised of ONEOK’s 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. Transactions with ONEOK’s other operating businesses, which generally settled
monthly, are shown as accounts receivable-affiliate or accounts payable-affiliate in periods prior to the separation.
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 and 2012, 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 balance sheet at December 31, 2014, consists of the balances of ONE Gas, while at December 31, 2013, it
consists of the balances of ONE Gas and ONE Gas Predecessor.
• 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 Statements of Cash Flows for the year ended December 31, 2013 and 2012, consist entirely of the results of ONE
Gas Predecessor.
• Our Statements 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 Statements of Equity for the years ended December 31, 2013 and 2012,
consist 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
54
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
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 disclosures of 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. Prior to our separation, we participated in ONEOK’s cash management
program rather than maintaining significant cash equivalent balances. Amounts due to ONEOK resulting from the cash
management program were recorded as a short-term note payable to ONEOK. See Note 2 for additional information on the
cash management program.
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, 2014 and 2013, were $141.7 million and $143.7
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
55
mechanisms. At December 31, 2014 and 2013, our allowance for doubtful accounts was $4.0 million and $3.3 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.
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 $27.5 million and $16.6 million at
December 31, 2014 and 2013, 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 more discussion of 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 disclosures of our property, plant and equipment.
56
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, 2014 and 2013, respectively. Our goodwill impairment analysis performed in
2014, 2013 and 2012, utilized a qualitative assessment and did not result in any impairment indicators. Subsequent to July 1,
2014, 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
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 2014, 2013 or 2012.
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 our regulatory asset and liability disclosures.
Pension and Other Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time
employees. We also sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees
who retire with at least five years of service. Our actuarial consultant calculates the expense and liability related to these plans
and uses statistical and other factors that attempt 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 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 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 postretirement expenses were allocated to us based on plan participants who directly
supported our operations. These pension and other postretirement benefit costs included amounts associated with vested
participants who are no longer employees.
57
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 Plans. Accordingly, our balance sheets prior to the separation do not reflect any assets or
liabilities related to the Plans. See Note 12 for additional information regarding pension and other postretirement employee
benefit plans.
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, 2014 and 2013.
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, 2014 and 2013.
See Note 13 for additional discussion of 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
58
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 discussion of 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.
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 2014, 2013 and 2012, we had no single external customer from which we received 10 percent or more of our gross revenues.
Recently Issued Accounting Standards Update - 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 International Financial
Reporting Standards. We are evaluating the impact of this recently issued guidance, which is required to be adopted for our
quarterly and annual reports beginning with the first quarter 2017.
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 separation, 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 postretirement 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 provides 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
59
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, ONE Gas, Inc.
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.
Reorganization Adjustments - 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 postretirement 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 postretirement benefits
Other assets
Long-term line of credit with ONEOK
Short-term note payable to ONEOK
Pension and other postretirement 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
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 postretirement 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
60
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 and $12.4 million during
2013 and 2012, respectively. 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
postretirement health and welfare plans was $52.1 million and $43.4 million during 2013 and 2012, respectively, which is net
of amounts deferred through regulatory mechanisms of $1.8 million and $4.1 million during 2013 and 2012, respectively. Cost
related to pension and other postretirement 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 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
Years Ended December 31,
2013
2012
(Thousands of dollars)
$
226,582
$
135,650
177,526
29,955
36,078
6,940
(5,073)
60,930
532,938
$
165,798
24,994
24,059
6,033
(2,668)
60,305
414,171
$
Employee labor and benefit costs capitalized totaled $49.3 million and $46.1 million for 2013 and 2012, respectively. In
addition, we recorded regulated utility revenue from ONEOK and its subsidiaries. These amounts were immaterial for the
periods presented.
Following the separation, we and ONEOK are still providing services to each other under the Transition Services Agreement,
but these services are now considered third-party transactions. The remaining related party transactions prior to the separation
were not material in 2014.
Cash Management - Prior to the separation, we participated in 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. The centralized cash management program
provided that funds in excess of the daily needs of the operating divisions and subsidiaries were concentrated, consolidated or
otherwise made available for use by other wholly owned entities of ONEOK. Under this cash management program,
depending on whether a participating division or subsidiary had short-term cash requirements or cash surpluses, ONEOK
provided cash to its respective divisions or subsidiaries or the divisions or subsidiaries provided cash to ONEOK. The amounts
receivable, or due, under this program were due on demand. Activities under this program were reflected in the balance sheets
as short-term note payable to ONEOK.
Principal under this note payable bears interest based on ONEOK’s weighted-average cost of short-term debt, plus a utilization
fee of 50 basis points, calculated monthly. The weighted-average interest rates for this note payable were 0.92 percent and 0.96
percent for 2013 and 2012, respectively. Changes in this note payable represented any funding required from ONEOK for
working capital or capital expenditures and after giving effect to the transfers to ONEOK from our cash flows from operations.
61
We had no affiliate receivables as of December 31, 2014. Affiliate receivables were not material as of December 31, 2013, and
are included in accounts receivable on our balance sheets.
Long-Term Line of Credit with ONEOK - Prior to the separation, we had a $1.1 billion long-term line of credit with
ONEOK. The weighted-average interest rate on the amounts outstanding for the year was 5.79 percent and 6.43 percent in
2013 and 2012, respectively. 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 amount utilized on the long-term line of credit
was adjusted annually with an offset to owner’s net investment to adjust our debt-to-capital ratio to a level consistent with
ONEOK’s debt-to-capital ratio.
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 amounts outstanding under the note payable and long-term line of credit.
Agreements with ONEOK after the Separation - 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 addition to the Separation and Distribution Agreement (which contains many of the key provisions
related to our separation from ONEOK and the distribution of our shares of common stock to ONEOK shareholders), these
agreements include:
• Transition Services Agreement;
• Tax Matters Agreement; and
• Employee Matters Agreement.
3.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE
ONE Gas Credit Agreement - In December 2013, we entered into the ONE Gas Credit Agreement, which became effective
upon our separation from ONEOK on January 31, 2014, and is scheduled to expire on January 31, 2019. 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, 2014, our total debt-to-
capital ratio was 41 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 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.
In July 2014, we entered into 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, 2014, we
had $42.0 million of commercial paper and $1.0 million in letters of credit issued under the ONE Gas Credit Agreement, with
62
no borrowings and $657.0 million of remaining credit available under the ONE Gas Credit Agreement. The weighted-average
interest rate on our commercial paper was 0.32 percent at December 31, 2014.
4.
LONG-TERM DEBT
Senior notes issuance - In January 2014, we completed a private placement of 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 from the private placement 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.
In connection with the issuance of our Senior Notes, we entered into a registration rights agreement, pursuant to which we were
obligated to use our commercially reasonable efforts to file with the SEC and cause to become effective a registration statement
with respect to an offer to exchange each series of Senior Notes for new notes, with terms substantially identical in all material
respects to such series of our Senior Notes. Our registration statement, as amended, was declared effective by the SEC on
September 5, 2014. We completed the noncash exchange of our Senior Notes for our registered senior notes in October 2014.
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, 2014, 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, 2014, we had approximately 197.9 million shares of authorized common stock available for
issuance.
Treasury Shares - In February 2015, our Board of Directors authorized us to purchase treasury shares to be used to offset
shares issued under our employee and non-employee director equity compensation, dividend reinvestment and employee stock
purchase plans. The 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 will purchase, and we can terminate or limit the program at any time. We may hold the purchased
shares as treasury shares and will account for them using the cost method.
Dividends - Dividends paid totaled $43.7 million in 2014. The following table sets forth the dividends per share declared and
paid on our common stock for the periods indicated:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Total
2014
—
0.28
0.28
0.28
0.84
$
$
$
$
$
Additionally, a dividend of $0.30 per share ($1.20 per share on an annualized basis) was declared in January 2015, payable in
the first quarter 2015.
63
6.
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following table sets forth the balance in accumulated other comprehensive income (loss) for the period indicated:
January 1, 2014
Transfers in upon separation
Pension and other postretirement 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
Accumulated Other
Comprehensive
Income (Loss)
$
$
—
(3,393)
(2,096)
315
(1,781)
(5,174)
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
(Loss) Components
Year Ended December 31, 2014
(Thousands of dollars)
Affected Line Item in the
Statements of Income
Pension and other postretirement benefit plan obligations (a)
Amortization of net loss
Amortization of unrecognized prior service cost
Regulatory adjustments (b)
Total reclassifications for the period
$
$
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 detail of our net periodic benefit cost.
(b) Regulatory adjustments represent pension and other postretirement benefit costs expected to be recovered through rates and are deferred
as part of our regulatory assets. See Note 9 for additional disclosures of 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, 2014
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
$
$
109,790
52,364
$
2.10
—
109,790
582
52,946
$
2.07
64
Year Ended December 31, 2013
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
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
$
$
$
$
99,195
52,319
$
1.90
—
99,195
—
52,319
$
1.90
Year Ended December 31, 2012
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
96,509
52,319
$
1.84
—
96,509
—
52,319
$
1.84
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, 2014, we held purchased natural gas call options for the heating season ending
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. At December 31, 2013, we held purchased natural gas call options for the heating season ended March 2014, with
total notional amounts of 26.6 Bcf, for which we paid premiums of $8.6 million, and had a fair value of $8.7 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 purchase 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.
The short-term notes payable were due upon demand and, therefore, the carrying amounts approximate fair value and are
classified as Level 1. The estimated fair value and book value of our long-term debt, including current maturities, was $1.3
billion and $1.2 billion, respectively, at December 31, 2014. The estimated fair value of our Senior Notes was determined
using quoted market prices, and are considered Level 2.
The estimated fair value and book value of our long-term line of credit with ONEOK at December 31, 2013, was $1.2 billion
and $1.0 billion, respectively. The estimated fair value of our long-term line of credit with ONEOK was valued using the
income approach by discounting the future payments and are considered Level 3. Significant unobservable inputs include the
discount rate, which we estimated using a rate at which we could have borrowed at each measurement date.
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, 2014
Under-recovered purchased-gas costs
Pension and other postretirement 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.
Under-recovered purchased-gas costs
Pension and other postretirement benefit costs
Reacquired debt costs
Other
Total regulatory assets, net of amortization
Accumulated removal costs (a)
Over-recovered purchased-gas costs
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
13 years
1 to 24 years
up to 50 years
1 year
1 year
1 year
Remaining
Recovery Period
1 year
See Note 12
14 years
1 to 25 years
up to 50 years
1 year
Current
Noncurrent
(Thousands of dollars)
— $
$
$ 28,712
18,108
812
2,561
50,193
—
(16,516)
(13,055)
(2,896)
(32,467)
466,684
9,730
2,309
478,723
(15,451)
—
—
—
(15,451)
Total
28,712
484,792
10,542
4,870
528,916
(15,451)
(16,516)
(13,055)
(2,896)
(47,918)
$ 17,726
$
463,272
$ 480,998
December 31, 2013
Current
Noncurrent
(Thousands of dollars)
— $
$
$ 12,393
298
812
8,154
21,657
—
(17,796)
(17,796)
3,861
$
9,556
10,541
3,725
23,822
(21,375)
—
(21,375)
2,447
$
$
Total
12,393
9,854
11,353
11,879
45,479
(21,375)
(17,796)
(39,171)
6,308
Regulatory assets on our balance sheets, as authorized by the various regulatory commissions, 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 commissions 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.
Unrecovered purchased-gas costs represents the 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, 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 $6.4 million for the year ended December
31, 2014. 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.
Recovery through rates resulted in amortization of regulatory assets of approximately $18.3 million for the year ended December
31, 2012.
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.
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
$
$
$
2014
2013
(Thousands of dollars)
3,909,881
450,810
418,157
71,353
4,850,201
(1,556,481)
3,293,720
3,703,593
430,042
326,004
74,435
4,534,074
(1,489,216)
3,044,858
$
We compute depreciation expense for distribution operations by applying composite, straight-line rates approved by various
regulatory agencies. The average depreciation rates for our property are set forth in the following table for the periods
indicated:
2014
2.0% - 3.0%
Years Ended December 31,
2013
2.0% - 3.0%
2012
2.0% - 3.0%
We recorded capitalized interest of $2.5 million, $1.3 million and $1.3 million for the years ended December 31, 2014, 2013
and 2012, respectively. We incurred liabilities for construction work in process that had not been paid at December 31, 2014,
2013 and 2012 of $7.0 million, $10.5 million and $12.0 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 year ending December 31, 2014.
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,
2014, we had approximately 1.3 million shares available for issuance under the ECP, which reflect shares issued and estimated
67
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
nonmanagement 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 $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 and 2012 totaled $9.7
million and $4.8 million, respectively, which is net of $6.1 million and $3.0 million of tax benefits, respectively. Compensation
costs capitalized for employees were not material for 2014, 2013 and 2012.
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. No dividends accrue prior to vesting on the restricted stock units granted that replaced the awards granted by
ONEOK in 2012. Restricted stock unit awards granted in 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
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
cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled,
68
regardless of when, if ever, the market condition is satisfied. No dividends accrue prior to vesting on performance stock units
granted to replace awards granted by ONEOK in 2012. The new performance stock unit awards granted in 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. 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. Compensation expense is recognized on a straight-line basis over the period of the
award. The compensation expense on these awards will only be adjusted for changes in forfeitures.
Restricted Stock Unit Award Activity
As of December 31, 2014, there was $2.8 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, 2013
Released to participants prior to separation
Cancelled and replaced upon separation
Granted
Released to participants
Forfeited
Nonvested December 31, 2014
Weighted-average grant date fair value (per share)
Fair value of shares granted (thousands of dollars)
Performance Stock Unit Award Activity
ONE Gas Plan
ONEOK Plans
Number of
Shares
Weighted-
Average Price
Number of
Shares
Weighted-
Average Price
— $
— $
$
246,683
94,865
$
(7,217) $
(8,601) $
$
325,730
—
—
19.71
33.19
19.85
25.76
23.47
137,670
$
(66,960) $
(70,710) $
— $
— $
— $
— $
2014
2013
2012
$
$
33.19
3,149
$
$
47.36
1,323
$
$
34.57
28.50
40.31
—
—
—
—
36.60
2,046
As of December 31, 2014, there was $4.9 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 2014, 2013 and 2012 grants at the grant date:
ONE Gas Plan
ONEOK Plans
Number of
Units
Weighted-
Average Price
Number of
Units
Weighted-
Average Price
Nonvested December 31, 2013
Released to participants prior to separation
Cancelled and replaced upon separation
Granted
Forfeited
Nonvested December 31, 2014
— $
— $
$
739,521
$
124,015
(15,585) $
$
847,951
—
—
14.57
35.98
19.15
17.62
264,537
$
(128,458) $
(136,079) $
— $
— $
— $
Volatility
Dividend yield
Risk-free interest rate
2014
18.40% (a)
3.37%
0.67%
2013
22.27%
3.04%
0.42%
(b)
2012
27.00%
2.86%
0.38%
(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.
40.45
34.68
45.90
—
—
—
(b)
69
Weighted-average grant date fair value (per share)
Fair value of shares granted (thousands of dollars)
Employee Stock Purchase Plan
2014
2013
2012
$
$
35.98
4,462
$
$
52.30
2,926
$
$
42.39
4,286
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 36 percent of employees participated in the plan in 2014 and
purchased 51,418 shares at $32.29. Compensation expense, before taxes, was $0.4 million in 2014. 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 and $0.8 million for 2013 and 2012, respectively.
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. Shares issued to employees under this program during 2014 totaled
35,324, and compensation expense, before taxes, related to the Employee Stock Award Program was $2.5 million.
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 and $1.2 million for 2013 and 2012,
respectively.
12.
EMPLOYEE BENEFIT PLANS
Retirement and Other Postretirement Benefit Plans
Prior to separation, certain employees participated in the Plans sponsored by ONEOK. We accounted for the 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. These defined benefit pension and other postretirement 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 in 2014 was $27.1 million. Pension expense charged to us by ONEOK for employees directly supporting our
operations totaled $35.0 million and $22.8 million for 2013 and 2012, respectively.
Other Postretirement Benefit Plans - We sponsor health and welfare plans that provide postretirement medical and life
insurance benefits to certain employees who retire with at least five years of service. The postretirement 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 postretirement benefit expense in 2014 was $5.9 million.
Other postretirement benefit expense charged to us by ONEOK for employees directly supporting our operations totaled $12.3
million and $16.6 million for 2013 and 2012, respectively.
70
Actuarial Assumptions - 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 postretirement plans
Expected long-term return on plan assets
Compensation increase rate
Years Ended December 31,
2013
4.25%
4.00%
8.25%
2014
5.25%
5.00%
7.75%
2012
5.00%
5.00%
8.25%
3.20% - 3.80%
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. As of 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 postretirement 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 postretirement 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 postretirement costs. Differences, if any, between the expense and the amount recovered
through rates would be reflected in earnings, net of authorized deferrals. The KCC has authorized Kansas Gas Service’s
recovery of defined benefit pension and other postretirement benefit costs in excess of the amounts included in rates over a
period of 5 years.
We historically have recovered defined benefit pension and other postretirement benefit costs through rates. We believe it is
probable that regulators will continue to include the net periodic pension and other postretirement benefit costs in our cost of
service.
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
postretirement 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
postretirement plan obligations of approximately $1.1 billion, and sponsored defined benefit pension and other postretirement
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.
71
The following table sets forth our defined benefit pension and other postretirement benefit plans, benefit obligations and fair
value of plan assets for the periods indicated:
Changes in Benefit Obligation
Benefit obligation, beginning of period
Service cost
Interest cost
Plan participants’ contributions
Actuarial loss
Benefits paid
Benefit obligation, end of period
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 Postretirement
Benefits
Year Ended December 31, 2014
(Thousands of dollars)
$
863,620
$
11,620
43,791
—
159,275
(50,135)
1,028,171
840,699
53,907
925
—
(50,135)
845,396
(182,775) $
(907) $
(181,868)
(182,775) $
$
$
$
239,171
3,468
11,605
2,642
14,998
(14,196)
257,688
147,237
6,912
9,182
2,642
(14,196)
151,777
(105,911)
—
(105,911)
(105,911)
The accumulated benefit obligation for our defined benefit pension plans was $970.7 million at December 31, 2014.
There are no plan assets expected to be withdrawn and returned to us in 2015.
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 postretirement 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
Pension Benefits
Other Postretirement
Benefits
Year Ended December 31, 2014
(Thousands of dollars)
11,620
$
43,791
(59,862)
549
30,200
773
27,071
$
3,468
11,605
(11,393)
(1,760)
3,969
—
5,889
$
$
72
Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income
(loss) related to our defined benefit pension benefits and other postretirement benefits for the period indicated:
Pension Benefits
Other Postretirement
Benefits
Year Ended December 31, 2014
(Thousands of dollars)
Net loss arising during the period
Amortization of loss
Deferred income taxes
Total recognized in other comprehensive income (loss)
$
$
(3,543) $
518
1,244
(1,781) $
—
—
—
—
The table 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 period 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
Pension Benefits
Other Postretirement
Benefits
December 31, 2014
(Thousands of dollars)
(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 2015
(Thousands of dollars)
Prior service credit (cost)
Actuarial net loss
$
$
266
44,219
$
$
(1,760)
6,040
Pension Benefits
Other Postretirement
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
Rate to which the cost-trend rate is assumed to decline
(the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
2014
4.00% - 7.75%
4.00% - 5.00%
2022
73
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 postretirement benefit obligation
One Percentage
One Percentage
Point Increase
Point Decrease
(Thousands of dollars)
$
$
484
6,903
$
$
(463)
(6,675)
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.
74
The following tables set forth our pension benefits and other postretirement benefits plan assets by fair value category as of the
measurement date:
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 respective market sector 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 Postretirement 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 respective market sector 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:
January 1, 2014
Net realized and unrealized gains (losses)
Settlements
December 31, 2014
Pension Benefits
December 31, 2014
Insurance
Contracts
Other
Investments
Total
(Thousands of dollars)
63,454
$
73,590
$
3,446
(7,023)
(15,676)
—
59,877
$
57,914
$
$
$
137,044
(12,230)
(7,023)
117,791
75
Contributions - During 2014, we contributed $0.9 million to our defined benefit pension plans and we contributed $9.2 million
to our other postretirement benefit plans. In 2015, we expect to contribute $0.9 million to our defined benefit pension plans and
expect to contribute $3.9 million to our other postretirement benefit plans.
Pension and Other Postretirement Benefit Payments - Benefit payments for our defined benefit pension and other
postretirement benefit plans for the period ended December 31, 2014 were $50.1 million and $14.2 million, respectively. The
following table sets forth the pension benefits and other postretirement benefits payments expected to be paid in 2015-2024:
Benefits to be paid in:
(Thousands of dollars)
Pension
Benefits
Other Postretirement
Benefits
2015
2016
2017
2018
2019
2020 through 2024
$
$
$
$
$
$
51,253
52,366
53,622
55,068
56,236
301,502
$
$
$
$
$
$
13,611
14,283
15,084
15,776
16,398
88,596
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31,
2014, 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 $9.7 million in 2014. 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 and $8.4 million in 2013 and 2012, respectively for ONEOK’s matching contributions to this plan.
Profit-Sharing Plan - We have a profit-sharing plan for all nonbargaining unit employees hired after December 31, 2004, and
employees covered by the IBEW collective bargaining agreement hired after June 30, 2010, and employees covered by USW
collective bargaining agreement hired after December 15, 2011. Nonbargaining unit employees who were employed prior to
January 1, 2005, employees covered by the IBEW collective bargaining agreement employed prior to July 1, 2010, and
employees covered by the United Steelworker collective bargaining agreement employed prior to December 16, 2011, were
given a one-time opportunity to make an irrevocable election to participate in the profit-sharing plan and not accrue any
additional benefits under ONEOK’s defined benefit pension plan after December 31, 2004, and June 30, 2010, respectively.
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 $4.0 million in 2014.
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 and $2.1 million in 2013
and 2012, respectively.
Employee Deferred Compensation Plan - Our Nonqualified Deferred Compensation Plan provides select employees, as
approved by our Board of Directors, 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 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 and 2012.
76
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
2014
Years Ended December 31,
2013
(Thousands of dollars)
2012
$
$
17,006
1,397
18,403
42,024
7,911
49,935
68,338
$
$
— $
67
67
53,562
8,643
62,205
62,272
$
—
360
360
51,481
8,010
59,491
59,851
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,
2013
(Thousands of dollars)
$
161,467
$
2014
178,128
35%
35%
62,345
6,051
(58)
68,338
$
56,513
5,661
98
62,272
$
2012
156,360
35%
54,726
5,423
(298)
59,851
Prior to separation, 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
77
December 31,
2014
2013
(Thousands of dollars)
$
$
128,715
8,144
5,655
142,514
820,853
16,177
193,159
1,030,189
887,675
$
$
—
40,125
8,249
48,374
750,305
4,695
2,563
757,563
709,189
At December 31, 2014, we had income taxes receivable of $43.8 million. We had no income taxes payable or receivable at
December 31, 2013.
In accordance with the Tax Matters Agreement, a cash settlement of $3.8 million is expected from ONEOK related to both the
filing of ONEOK’s income tax return for the calendar year ended December 31, 2013 and for the January 1, 2014, through
January 31, 2014 period. Our net deferred tax liabilities were adjusted to reflect this settlement.
The net operating loss of $8.1 million expires in 2035. We expect to utilize all of the net operating loss prior to its expiration
date.
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 2014 and $4.8 million in each
of 2013 and 2012. The following table sets forth our operating lease payments for the periods indicated:
Operating Leases
(Millions of dollars)
2015
2016
2017
2018
2019
Thereafter
Total
$
$
4.7
4.5
4.3
4.0
3.4
10.4
31.3
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 2014, 2013 and 2012. We do not expect to incur material expenditures for
these matters in the future.
78
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. The Pipeline Safety
Improvement Act requires pipeline companies operating high-pressure 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, 2014
Revenues
Net margin
Operating income
Net income
Earnings per share
Basic
Diluted
Year Ended December 31, 2013
Revenues
Net margin
Operating income
Net income
Earnings per share
Basic and diluted
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$
$
$
$
$
$
$
$
$
$
$
766,178
259,836
109,353
59,076
1.13
1.13
First
Quarter
635,933
251,674
101,838
53,492
1.02
$
$
$
$
$
$
$
$
$
$
$
(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
Second
Quarter
Third
Quarter
(Thousands of dollars)
311,608
178,447
39,307
14,951
0.29
$
$
$
$
$
219,725
159,233
14,189
434
0.01
$
$
$
$
$
$
$
$
$
$
$
514,368
224,176
70,010
36,607
0.70
0.69
Fourth
Quarter
522,686
223,654
65,014
30,318
0.58
79
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, 2014.
The effectiveness of our internal control over financial reporting as of December 31, 2014, 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, 2014, 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 2015 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 2015 definitive Proxy Statement and is
incorporated herein by this reference.
80
Code of Ethics
Information concerning the code of ethics, or code of business conduct, is set forth in our 2015 definitive Proxy Statement and
is incorporated herein by this reference.
Nominating Procedures
Information concerning the nominating procedures is set forth in our 2015 definitive Proxy Statement and is incorporated
herein by this reference.
The Audit Committee
Information concerning the Audit Committee is set forth in our 2015 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 2015 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 2015 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 2015 definitive Proxy Statement and is
incorporated herein by this reference.
The Executive Committee
Information concerning the Executive Committee is set forth in our 2015 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 2015 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 2015 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 2015 definitive Proxy Statement and is
incorporated herein by this reference.
81
Equity Compensation Plan Information
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2014:
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)
— $
— $
— $
—
— (2)
—
—
3,474,486
3,474,486
Plan Category
Equity compensation plans approved
by security holders
Equity compensation plans not
approved by security holders (1)
Total
(1) Includes shares granted under our Employee Stock Purchase Plan and Employee Stock Award Program, 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 these plans, see Note 12 of the Notes to Financial Statements in this Annual Report. Column (c) includes 648,391,
89,681 and 2,736,414 shares available for future issuance under our Employee Stock Purchase Plan, Employee Stock Award Program and Equity
Compensation Plan, respectively.
(2) 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 $41.22, 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 2015 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 2015 definitive Proxy Statement and is
incorporated herein by this reference.
82
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, 2014, 2013 and 2012
Statements of Comprehensive Income for the years ended
December 31, 2014, 2013 and 2012
Balance Sheets as of December 31, 2014 and 2013
48-49
Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012
50
Statements of Equity for the years ended December 31, 2014, 2013 and 2012
51-52
Notes to Financial Statements
53-78
(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)).
83
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)).
84
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
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)).
Form of 2012 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.17 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (File No. 1-36108)).
Form of 2012 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.18 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 25, 2014 (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)).
10.23
Form of 2015 Performance Unit Award Agreement.
10.24
Form of 2015 Restricted Unit Award Agreement.
12.1
21.1
23.1
31.1
31.2
32.1
32.2
Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2014, 2013, 2012,
2011 and 2010.
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)).
85
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, 2014, 2013 and 2012; (iii) Statements of
Comprehensive Income for the years ended December 31, 2014, 2013 and 2012; (iv) Balance Sheets for the years ended
December 31, 2014 and 2013; (v) Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012; (vi)
Statements of Equity for the years ended December 31, 2014, 2013 and 2012; 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.
86
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 19, 2015
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 19th day of February 2015.
/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
87
Connect
www.onegas.com
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 filings.
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 Plan &
Dividend Reinvestment Plan
ONE Gas’ Direct Stock Purchase and Dividend
Reinvestment Plan provide 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 21, 2015 – 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
Lindsey Sprague,
Senior Investor Relations Analyst
P: 1-918-947-7671
E: lindsey.sprague@onegas.com
15 East Fifth Street, Tulsa, OK 74103
918-947-7000 • www.onegas.com