Resilient and Reliable Energy
For a Better Tomorrow
Annual Report 2020
ABOUT ONE GAS
ONE Gas, Inc. is a 100-percent regulated natural gas utility and trades on the New York Stock Exchange under the symbol
“OGS.” ONE Gas is included in the S&P MidCap 400 Index and is one of the largest natural gas utilities in the United States.
We provide natural gas distribution services to approximately 2.2 million customers in Kansas, Oklahoma and Texas. We are
headquartered in Tulsa, Oklahoma.
OUR DIVISIONS INCLUDE:
72% market share,
the largest in Kansas.
88% market share,
the largest in Oklahoma.
13% market share,
the third largest in Texas.
Our largest natural gas distribution markets by customer count
are Kansas City, Wichita and Topeka; Oklahoma City and
Tulsa; and Austin and El Paso. These seven metropolitan areas
account for 70 percent of our customers. We primarily serve
residential, commercial and transportation customers in all
three states.
MISSION
Our mission is to deliver natural gas for a better tomorrow.
VISION
Our vision is to be a premier natural gas distribution company,
creating exceptional value for our stakeholders.
CORE VALUES
SAFETY
We are committed to operating safely and in an
environmentally responsible manner.
ETHICS
We are accountable to the highest ethical standards
and are committed to compliance. Honesty, trust
and integrity matter.
INCLUSION & DIVERSITY
We embrace an inclusive and diverse culture that
encourages collaboration. Every employee makes a
difference and contributes to our success.
SERVICE
We provide exceptional service and make
continuous improvements in our pursuit
of excellence.
VALUE
We create value for all stakeholders, including
our customers, employees, investors and
communities.
2020 HIGHLIGHTS
Earnings per share
$3.68
$3.51
compared with
in 2019
Net income
increased to
$196
million
compared with
$187 million
in 2019
$512
million
70%
in capital investments;
for system integrity
and reliability
470
miles
of distribution
mains, service
lines and
transmission lines
replaced
in 2020
Approximately
26,400
new meters
$3.2
million
in ONE Gas Foundation
grants and
community giving
ONE Gas Annual Report 2
Resilient and Reliable Energy
FOR A BETTER
To Our Fellow Shareholders:
In 2020, our mission to deliver natural gas for a better
tomorrow guided our business strategy and daily operations
during an unprecedented year of challenges in our country
and our communities. As the homes of our customers
transitioned to places of work, schooling and much more,
we continued delivering affordable natural gas through our
resilient and reliable systems bringing comfort and stability
in the face of uncertainty.
As part of our safety culture, we closely monitored data
relative to the coronavirus, took numerous safety precautions
and continued delivering natural gas safely and reliably to
customers while protecting our employees and supporting
our communities.
Adversity continued into 2021 as our employees and our
customers endured some of the coldest, most extreme
weather ever seen in our service areas. Due to the intensity
and duration of this winter storm, we experienced
unforeseeable and unprecedented circumstances across our
service area, including the coldest day recorded in over a
century, rolling electric brownouts and countless water main
breaks. For seven long days, our employees worked through
these adverse conditions and collectively, with our customers’
help, we kept the gas flowing to meet the most basic need of
our customers — keeping them warm.
Our culture and our core values continue to lead us every day
– including through these challenging events. We’d like to
express our gratitude for our employees’ teamwork, resiliency
and responsiveness as we dealt with back-to-back 100-year
events between this historic winter storm and a pandemic.
Our response is a testament to the culture of this company.
2020 Performance at a Glance
As one of the largest publicly traded natural gas
distribution companies, our focused business model offers a
clear mission, vision, strategy and values-driven culture that
enables us to deliver a reliable and affordable energy choice
to more than 2.2 million customers each day.
In 2020, net income increased to $196 million compared
with $187 million in 2019. Diluted earnings per share
increased approximately five percent to $3.68. We
increased our dividends by eight percent over dividends
paid in 2019.
Capital Horizon and Clarity
Modernizing our distribution systems remains a
pivotal way we decrease emissions while maintaining
safe and reliable operations. This requires significant
capital investments and collaborative relationships
with regulators to enable us to provide the most cost-
effective, safe and reliable service to our growing
470 miles
of distribution
mains, service
lines and
transmission lines
replaced in 2020
3 ONE Gas Annual Report
$512 million
in capital investments;
70%
for system integrity
and reliability
TOMORROW
customer base. We have replaced an average of 244 miles
of vintage pipe per year since 2014. With the remaining
vintage materials left to replace, we have a 20-plus-year
runway to deploy our capital.
Our portfolio of regulatory mechanisms provides for
the timely recovery of investments. These mechanisms
support our ability to continue to invest in improving
our systems. Ninety percent of our capital investments
are included in annual regulatory filings.
In 2020, we invested $512 million, with 70 percent of
that capital investment dedicated to system integrity
and replacement projects. Replacing pipelines helps us
maintain safe and reliable operations while decreasing
leaks and emissions from our systems.
Our ongoing investment also results in new customers.
In 2020, we set approximately 26,400 new meters, an
18 percent increase over 2019 and more meters than any
previous year in our history.
Safe Operations
Safety doesn’t just happen. It’s driven by our 3,700 employees
who have committed to a culture of zero harm. Success is
reliant on continuous education and training, real-time
reporting and shared responsibility so that our employees
know what is expected to keep themselves, their co-workers,
our customers and communities safe.
Our safety efforts are overseen by our Environment,
Safety, Health & Compliance (ESH&C) Steering
Committee which is chaired by our COO and reports
to the CEO. Its primary purpose is to provide vision,
direction and oversight of our ESH&C programs,
processes and management systems in order to protect
our employees, customers, the environment, and the
communities we serve. It also governs the safe design
and operation of our systems and assets.
In 2020, we remained in the first quartile in all safety
metrics tracked by the American Gas Association.
In 2020, our Days Away, Restricted or Transferred
(DART) was the lowest in company history and the
lowest of all similar-sized local distribution companies
for the third year in a row.
High-Performing Workforce
To build a better tomorrow for everyone, we have
created a culture that embraces inclusion and diversity
and encourages collaboration. Our programs and
policies consider our employees’ physical, social,
emotional and financial health and help attract diverse
talent. Our CEO-chaired Inclusion and Diversity
Council and employee-led resource groups encourage
employee retention and development.
In 2020, we again had high participation in our annual
employee engagement survey, with 90 percent of
Net income increased to
$196 million
compared with
$187 million
in 2019
Earnings per share
$3.68
compared with
$3.51
in 2019
ONE Gas Annual Report 4
employees providing feedback. Employee engagement
scores were in the top quartile of Gallup’s Overall
Company Database and showed improvement for the
fourth consecutive year.
World events in 2020, including a pandemic and social
injustices, challenged us to further explore how we can
strengthen a sense of belonging – from employees and
customers to suppliers and the communities we serve. As
a leader in our industry and the communities we serve,
we are committed to listening and learning with a goal
of providing a more equitable experience for all.
Investment in the Future
Technology is a major driver of true innovation.
ONE Gas continues to invest in the development
and adoption of innovative technology that improves
operational and end-use efficiencies and allows us to
continue to provide safe, reliable, cost-effective service
while reducing our carbon footprint.
In 2020, we leveraged technology to quickly transition
more than half of our workforce to a remote working
environment in only three days due to the COVID-19
pandemic. The transition allowed our teams to
continue reliable service for our customers and reduce
risk for our employees.
We also piloted new ways to detect and reduce
emissions with mobile methane detection technology.
The technology allowed us to analyze our emissions
data at a speed and scale not previously possible. The
result was an increase in data-driven decision making
to better inform our capital investments and prioritize
pipe replacement.
In 2021 and beyond, we will continue investing in
innovative solutions that lead to more reliable and
resilient natural gas delivery systems that also lowers
greenhouse gas emissions. This includes looking at
how we can use our existing assets and technology to
expand renewable natural gas capture from agriculture,
waste-water treatment plants and landfills. We’re also
participating in research studies that explore the use of
hydrogen production and blending for use in our systems.
$3.2 million
in ONE Gas Foundation
grants and
community giving
5 ONE Gas Annual Report
5 ONE Gas Annual Report
5 ONE Gas Annual Report
In Closing
We pledge to create exceptional value for all our
stakeholders and deliver natural gas for a better
tomorrow. Although we have only been operating under
the ONE Gas name since 2014, we have been serving
customers in these communities for more than 100
years. With our mission in mind, we are committed to
continuously improve and invest in safety while caring for
our employees, our communities and the environment.
Our core values — safety, ethics, inclusion and diversity,
service and value — are the foundation for all that we do
and guide our sustainability strategy. We believe that we
share the responsibility to protect our environment and are
an important part of any energy transformation to lower
carbon emissions — offering resiliency and reliability.
ONE Gas and natural gas as a fuel choice are nimble
and responsive to change, as evident in our performance
over the past year. We’re confident natural gas will
play a critical role as the U.S. moves towards achieving
emission reduction goals and increasing the use of
renewable energy sources.
No single energy source will be the solution to support
our country’s energy needs. It will take multiple sources
to satisfy the demand for affordable, resilient and
reliable energy. For more than 100 years, the natural
gas industry has evolved through innovation to meet
customer needs. We’ll continue to implement that spirit
of innovation and leverage our resilient and sustainable
infrastructure to be part of the solution for reaching
net-zero emissions.
A better tomorrow means embracing the opportunities
presented through energy transformation and being
part of real change for our planet. We look forward to
showing you our progress on that journey.
Thank you for your support and interest in ONE Gas as
we expand our role in the energy transformation underway
and deliver on our mission for a better tomorrow.
John W. Gibson
Chairman
Chairman
ONE Gas, Inc.
Pierce H. Norton II
President and CEO
ONE Gas, Inc.
Approximately
26,400
new meters
ONE Gas Annual Report 6
ONE Gas Annual Report 6
ONE Gas Annual Report 6
Exceeded our
Environmental Protection
Agency Methane Challenge
emissions reduction
commitment for
4th year
in a row
47,292
metric tons of CO2e
displaced through
ONE Gas customer rebates
for natural gas vehicles
in 2020, which is equivalent
to removing 10,215 cars
from the road
22.1%
reduction in emissions
from a 2014 baseline.
Based on our current
replacement program, we
expect to reduce emissions
by 33% by 2024
Committed to the
ENVIRONMENT
We believe we have a shared responsibility to care for our planet and are
committed to reduce our operational emissions through four key areas:
accelerated pipeline replacement; increased public awareness and damage
prevention programs; leak prevention and repair strategies; and energy
efficiency programs.
7 ONE Gas Annual Report
Emissions Reduction from Pipeline Replacement
As % of Operational Emissions
4.0%
3.0%
2.0%
1.0%
0.0%
2015
2016
2017
2018
2019
2020
Pipeline Replacement
Average Annual Miles Est.
2021-2025
120
60
220
2020
130
44 7
2019
4
113
78
2
2018
21
111
53 5
289
233
240
2017
2016
23
22
196
192
61 1 144
43 2
131
400
470
430
430
425
390
Vintage Pipeline as Portion of
Total Pipeline Inventory (in Miles)
Unprotected Bare Steel
Vintage Plastic
Cast Iron
Protected Bare Steel
Risk-Mitigation and
Government Relocations
1,100
6,080
57,020
5,180
900
Vintage pipeline
replacement program
represents more than a
20-year investment runway.
Note: Inventory and values are based on data reported for 2020. Pipeline replacement due to future changes in state or federal
regulations is not projected in 5-year replacement estimates. *The vintage pipeline replacement program includes: wrought iron,
unprotected bare steel, protected bare steel and vintage plastic.
ONE Gas Annual Report 8
FINANCIAL OVERVIEW
We reported 2020 net income of $196 million,
or $3.68 per diluted share, compared with
$187 million, or $3.51 per diluted share, in
2019; and 2020 capital expenditures and asset
removal costs of $512 million, compared with
$465 million in 2019. Our 2020 net margin
increased by $28.1 million compared with last
year, which primarily reflects new rates in our
service territories along with an increase in net
residential customer growth.
In 2021, our diluted earnings per share
performance is expected to be within a range
of $3.68 to $3.92 per share. Our 2021 capital
expenditures and asset removal costs are
expected to be approximately $540 million.
On Jan. 19, 2021, the ONE Gas Board of
Directors increased the quarterly dividend by 4
cents per share to 58 cents per share, effective
for first quarter 2021, resulting in an annualized
dividend of $2.32 per share.
Our average annual dividend growth rate is
expected to increase 6 percent to 8 percent
between 2020 and 2025 with a targeted
dividend payout ratio of 55 percent to 65
percent of net income, all subject to board
approval.
HIGHLIGHTS
Total Revenues and Net Income
Total Revenues (thousands)
)
(
Net Income (thousands)
Earnings and Dividends
Basic
Diluted
Dividends Per Share
Margin, Volumes and Weather
Net Margin (thousands)*
Total Volumes Delivered (Bcf)
Actual Heating Degree Days
Normal Heating Degree Days
Customers and Employees
Average Number of Customers (thousands)
Employees
Common Stock
2020
2019
2018
$1,530,268
$ ,
,
$1,652,730
$ ,
,
$1,633,731
$ ,
,
$196,412
$186,749
$172,234
$3.70
$3.68
$2.16
$3.53
$3.51
$2.00
$3.27
$3.25
$1.84
$992,823
$964,756
$919,095
385.1
9,241
9,765
396.4
10,490
9,828
2,220
3,700
2,194
3,600
392.5
10,521
9,959
2,179
3,500
Market Value Per Share: Year-end Closing Price
$76.77
$93.57
$79.60
Average Shares of Common Stock, Outstanding (thousands):
Basic
Diluted
53,133
53,370
52,895
53,240
52,693
53,029
9 ONE Gas Annual Report
9 ONE Gas Annual Report
9 ONE Gas Annual Report
*See discussion of non-GAAP financial measure inside back cover.
BOARD OF DIRECTORS
Michael G. Hutchinson
Retired Partner
Deloitte & Touche
Tracy E. Hart
President and
Chief Executive Officer
Tarlton Corporation
Pierce H. Norton II
President and
Chief Executive Officer
ONE Gas, Inc.
Eduardo A. Rodriguez
President
Strategic Communication
Consulting Group
John W. Gibson
Chairman
ONE Gas, Inc.
Pattye L. Moore
Retired Board Chair and
Interim Chief Executive Officer
Red Robin Gourmet Burgers
Robert B. Evans
Retired President and
Chief Executive Officer
Duke Energy Americas
Douglas H. Yaeger
Retired Chairman, President and
Chief Executive Officer
The Laclede Group, Inc.
(Spire, Inc.)
EXECUTIVE TEAM
As of April 1, 2021
Pierce H. Norton II, 61
President and
Chief Executive Officer
Curtis L. Dinan, 53
Senior Vice President and
Chief Commercial Officer
Mark. A. Bender, 56
Senior Vice President,
Administration and
Chief Information Officer
Caron A. Lawhorn, 60
Senior Vice President and
Chief Financial Officer
Robert S. McAnnally, 57
Senior Vice President and
Chief Operating Officer
Joseph L. McCormick, 61
Senior Vice President,
General Counsel and
Assistant Secretary
Julie A. White, 50
Vice President, Communications,
Public Affairs and
Inclusion & Diversity
ONE Gas Annual Report 10
ONE Gas Annual Report 10
ONE Gas Annual Report 10
Kansas Gas Service | Oklahoma Natural Gas | Texas Gas Service
ONEGas.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020.
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:
Title of each class
Common Stock, par value $0.01 per share
Trading Symbol
OGS
Name of exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
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 ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of
Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an
emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company”
in Rule 12b-2 of the Exchange Act. (Check one) Large accelerated filer ☒
Smaller reporting company ☐
Emerging growth company ☐
Non-accelerated filer ☐
Accelerated filer ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control
over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its
audit report. ☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or
revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The aggregate market value of the equity securities held by nonaffiliates based on the closing trade price of the registrant on June 30, 2020, was $3.9 billion.
On February 22, 2021, we had 53,243,986 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 27, 2021, are
incorporated by reference in Part III.
ONE Gas, Inc.
2020 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.
Item 16.
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
Form 10-K Summary
5
11
23
24
24
24
25
26
26
50
52
92
92
92
92
93
93
94
94
95
98
99
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 subsidiaries, unless the context indicates otherwise.
2
GLOSSARY
The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
AAO
ADIT
AFUDC
Annual Report
ASC
ASU
Bcf
CDC
CERCLA
CFTC
Clean Air Act
Clean Water Act
CNG
Code
COSA
COVID-19
DOT
Dth
ECP
EDIT
EPA
EPS
ESG
ESPP
Exchange Act
FASB
FERC
GAAP
GPAC
GRIP
GSRS
Heating Degree Day or HDD
HCA(s)
IT
KCC
KDHE
kWh
LDC
LIBOR
MAOP(s)
MGP
MMcf
Moody’s
Net margin
NOL
NPRM
NYMEX
NYSE
Accounting Authority Order
Accumulated deferred income tax
Allowance for funds used during construction
Annual Report on Form 10-K for the year ended December 31, 2020
Accounting Standards Codification
Accounting Standards Update
Billion cubic feet
Centers for Disease Control and Prevention
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
Compressed natural gas
Internal Revenue Code of 1986, as amended
Cost-of-Service Adjustment
Coronavirus Disease 2019
United States Department of Transportation
Dekatherm
The ONE Gas, Inc. Amended and Restated Equity Compensation Plan (2018)
Excess accumulated deferred income taxes resulting from a change in enacted tax
rates
United States Environmental Protection Agency
Earnings per share
Environmental, social and governance
The ONE Gas, Inc. Amended and Restated Employee Stock Purchase Plan
Securities Exchange Act of 1934, as amended
Financial Accounting Standards Board
Federal Energy Regulatory Commission
Accounting principles generally accepted in the United States of America
Gas Pipeline Advisory Committee
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
High consequence area(s)
Information technology
Kansas Corporation Commission
Kansas Department of Health and Environment
Kilowatt hour
Local distribution company
London Interbank Offered Rate
Maximum allowable operating pressure(s)
Manufactured gas plant
Million cubic feet
Moody’s Investors Service, Inc.
Non-GAAP measure defined as total revenues less cost of natural gas
Net operating loss
Notice of proposed rulemaking
New York Mercantile Exchange
New York Stock Exchange
3
OCC
ONE Gas
ONE Gas 2021 Term Loan Facility
Oklahoma Corporation Commission
ONE Gas, Inc.
ONE Gas’ $2.5 billion two-year unsecured term loan facility
ONE Gas 364-day Credit Agreement
ONE Gas Credit Agreement
OSHA
PBRC
PHMSA
Pipeline Safety Improvement Act
Pipeline Safety, Regulatory Certainty and
Job Creation Act
PPE
RNG
ROE
RRC
S&P
SEC
Securities Act
Senior Notes
WNA
XBRL
ONE Gas’ $250 million 364-day revolving credit agreement, which expires on
April 6, 2021
ONE Gas’ $700 million amended and restated revolving credit agreement, which
expires on October 4, 2024
Occupational Safety and Health Administration
Performance-Based Rate Change
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
Personal protective equipment
Renewable natural gas
Return on equity calculated consistent with utility ratemaking principles in each
jurisdiction in which we operate
Railroad Commission of Texas
Standard and Poor’s Rating Services
Securities and Exchange Commission
Securities Act of 1933, as amended
ONE Gas’ registered notes consisting of $300 million of 3.61 percent senior notes
due 2024, $300 million of 2.00 percent senior notes due 2030, $600 million of
4.658 percent notes due 2044, and $400 million of 4.50 percent senior notes due
2048
Weather normalization adjustment(s)
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, Forward-Looking Statements, in this Annual Report.
4
ITEM 1.
BUSINESS
OUR BUSINESS
PART I
ONE Gas, Inc. is incorporated under the laws of the state of Oklahoma. Our common stock is listed on the NYSE under the
trading symbol “OGS,” and is included in the S&P MidCap 400 Index. We are a 100-percent regulated natural gas distribution
utility, headquartered in Tulsa, Oklahoma, and one of the largest publicly traded natural gas utilities in the United States. We
are successor to the company founded in 1906 as Oklahoma Natural Gas Company, which became ONEOK, Inc. (NYSE:
OKE) in 1980. On January 31, 2014, ONE Gas officially separated from ONEOK, Inc.
We provide natural gas distribution services to our approximately 2.2 million customers and are the largest natural gas
distributor in Oklahoma and Kansas and the third largest in Texas, in terms of customers. We primarily serve residential,
commercial and transportation 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 to approximately 88
percent, 72 percent and 13 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas, respectively.
OUR STRATEGY
Our mission is to deliver natural gas for a better tomorrow. Our vision is to be a premier natural gas distribution company,
creating exceptional value for all stakeholders. Our business strategy is focused on:
•
•
•
Safety, Compliance and Reliability - We are committed, first and foremost, to pursuing a zero-incident safety and 100-
percent compliance culture through programs, procedures, policies, guidelines and other internal controls designed to
mitigate risk and incidents that may harm our employees, contractors, customers, the public or the environment.
Additionally, a significant portion of our capital spending is focused on the safety, integrity, reliability and efficiency
of our natural gas distribution system.
Fostering a High-performing Workforce - The foundation of our Company is our employees. Our success begins with
a values-driven culture and a commitment to developing a skilled, agile, diverse and engaged workforce where every
employee understands that they can and do make a difference.
Investing in Our System - 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. In addition, as some of our service
territories continue to experience economic growth, our capital investments for new service lines and main line
extensions to serve new customers, predominately in the seven major metropolitan areas we serve, will further
contribute to our growth.
• Maintaining a Conservative Financial Profile - As we increase rate base through system investments, we are focused
on maintaining a conservative financial profile and providing our customers with reasonable rates, while providing our
shareholders with a competitive total return. We believe that maintaining strong credit ratings is prudent as we seek to
access the capital markets to fund capital expenditures and for other general corporate purposes.
•
Sustainability - We understand that our stakeholders expect us to operate a sustainable business. We are committed to
environmental stewardship, social responsibility and good corporate governance, all evaluated through the lens of our
core values of safety, ethics, diversity and inclusion, service and value. We are focused on continually improving
practices and disclosures of our ESG-related plans, programs, goals and targets. See “Available Information” for
additional information regarding our ESG-related matters.
REGULATORY OVERVIEW
We are subject to the regulations and oversight of the state and local regulatory authorities of the territories in which we
operate. Rates and charges for natural gas distribution services are established by the OCC for Oklahoma Natural Gas and by
the KCC for Kansas Gas Service. Texas Gas Service is subject to regulatory oversight by the various incorporated cities that it
serves, which have primary jurisdiction for their respective service areas. Rates in unincorporated areas of our service territory
in Texas and all appellate matters are subject to regulatory oversight by the RRC. These regulatory authorities have the
5
responsibility of ensuring that the utilities in their jurisdictions provide safe and reliable service at a reasonable cost, while
providing utility companies the opportunity to earn a fair and reasonable return on their investments.
Generally, our rates and charges are established in rate case proceedings. Regulatory authorities may also approve mechanisms
that allow for adjustments for specific costs or investments made between rate cases. Due to the nature of the regulatory
process, there is an inherent lag between the time that we make investments or incur additional costs and the setting of new
rates and/or charges to recover those investments or costs. Additionally, we are not allowed recovery of certain costs we incur.
The following provides additional detail on the regulatory mechanisms in the jurisdictions we serve.
Oklahoma - Oklahoma Natural Gas currently operates under a PBRC mechanism, which provides for streamlined annual rate
reviews between rate cases and includes adjustments for incremental capital investment and allowed expenses. Under this
mechanism, we have an authorized ROE of 9.5 percent, with a 100 basis point dead-band of 9 to 10 percent. If our achieved
ROE is below 9 percent, our base rates are increased upon OCC approval to an amount necessary to restore the ROE to 9.5
percent. If our achieved ROE exceeds 10 percent, the portion of the earnings that exceeds 10 percent is shared with our
customers, who receive the benefit of 75 percent of those earnings. We receive the benefit of the remaining 25 percent.
Oklahoma Natural Gas was required to make filings pursuant to the PBRC mechanism for the 12 months ended December 31
for each of the years 2016 through 2020. Oklahoma Natural Gas is also required to file a rate case on or before June 30, 2021,
based on a test year consisting of the twelve months ended December 31, 2020.
Kansas - Kansas Gas Service files periodic rate cases with the KCC as needed. Between rate cases, Kansas Gas Service adjusts
rates through provisions of the GSRS statute. The GSRS statute allows Kansas Gas Service to file for a rate adjustment
providing a recovery of and return on qualifying infrastructure investments incurred between rate case filings, including safety-
related investments to replace, upgrade or modernize obsolete facilities, as well as projects that enhance the integrity of pipeline
system components or extend the useful life of such assets. Eligible investments also include expenditures for relocations and
physical and cyber security. The filing cannot occur more often than once every 12 months and the rate adjustment cannot
increase the monthly charge by more than $0.80 per residential customer per month compared with the most recent GSRS
filing. After five annual filings, Kansas Gas Service is required to file a rate case or cease collection of this surcharge.
Texas - Texas Gas Service provides service to customers in five service areas. These service areas are further divided into the
incorporated cities and the unincorporated areas. Periodic rate cases are filed with the cities or the RRC, as needed. Between
rate cases, Texas Gas Service can adjust rates through annual filings pursuant to the GRIP statute or an annual COSA filing.
Annual filings under the GRIP statute allow Texas Gas Service to recover taxes and depreciation and to earn a return on the
annual net increase in investment for a service area. After the fifth anniversary of the effective date of the rate schedules from
our last rate case for a service area, 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. Texas Gas Service makes annual GRIP filings for the
incorporated cities in three of its service areas and for the unincorporated areas in all five service areas, which combined
comprise 89 percent of Texas Gas Service’s customers.
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. The COSAs have a cap of 3.25 percent to 5 percent on
the expense portion of the increase. A full rate case may be filed when desired by Texas Gas Service or the regulator but is not
required. Texas Gas Service makes an annual COSA filing for the incorporated cities in two of its service areas, comprising 11
percent of its customers.
Weather normalization - All of our service areas utilize weather normalization mechanisms. These mechanisms are designed
to reduce the delivery charge component of customers’ bills for the additional volumes used when actual HDDs exceed
normalized HDDs and to increase the delivery charge component of customers’ bills for the reduction in volumes used when
actual HDDs are less than normal HDDs. Normal HDDs are established through rate proceedings in each of our jurisdictions.
6
The following tables provide additional detail on our rate structures and the regulatory mechanisms in each of our jurisdictions:
Effective Date of
Last Action(1)
June 2020
Rate Base
(millions)(2)
$1,616
Rate of
Return(2)
7.06%
Equity
Ratio(2)
56%
Return on
Equity(2)
9.50%
Division
Jurisdiction
Oklahoma Natural Gas
Kansas Gas Service (3)
Texas Gas Service
OK
KS
Central-Gulf
West Texas
December 2020
$1,133
August 2020
June 2020
$458
$397
$128
$54
$10
Rio Grande Valley
November 2020
North Texas
November 2020
Borger / Skellytown
December 2020
Division
Jurisdiction
Interim Rate
Adjustment
Mechanism
Interim
Capital
Recovery WNA
Oklahoma Natural Gas
Kansas Gas Service (3)
Texas Gas Service
OK
KS
Central-Gulf
West Texas
PBRC
GSRS
GRIP
GRIP
Rio Grande Valley
North Texas
GRIP / COSA
GRIP / COSA
Borger / Skellytown
GRIP
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
8.60%
7.46%
7.28%
7.35%
7.55%
7.55%
N/A
59%
60%
61%
62%
62%
9.30%
9.50%
9.50%
9.50%
9.75%
9.75%
WNA Effective
Dates
November - April
January - December
September - May
September - May
September - May
September - May
September - May
Energy Efficiency /
Conservation
Program
Yes
No
Yes
No
Yes
No
No
Division
Oklahoma Natural Gas
Kansas Gas Service (3)
Texas Gas Service
Jurisdiction
OK
KS
Central-Gulf
West Texas
Rio Grande Valley
North Texas
Borger / Skellytown
Purchased Gas
Riders(4)
Yes
Bad Debt Recovery(5)
Yes
Expense
Trackers(6)
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
(1)
(2)
(3)
(4)
Effective date of last approved rate case or interim filing.
The rate base, authorized rate of return, authorized debt/equity ratio and authorized return on equity presented in this table are those from the most recent regulatory filing for each jurisdiction. These
rate bases, rates of return, debt/equity ratios and returns on equity are not necessarily indicative of current or future rate bases, rates of return, debt/equity ratios or returns on equity.
Kansas Gas Service’s most recent rate case, approved in February 2019, settled without a determination of rate base, rate of return, authorized debt/equity ratio and authorized return on equity within
the settlement. This reflects Kansas Gas Service’s estimate of rate base from that rate case adjusted for approved GSRS filings and the return on equity embedded in the pre-tax carrying charge utilized
in its GSRS filing.
Our purchased gas adjustment mechanisms allow recovery of expenses the Company incurs to purchase natural gas for our customers. These costs are passed on to customers without markup.
(5) We recover the gas cost portion of bad debts through our various purchased gas cost adjustment mechanisms.
(6)
These trackers represent cost adjustment mechanisms for costs that are subject to significant fluctuations compared to other costs, represent a large component of our cost of service and are generally
outside our control. Examples include pension and other postemployment benefits costs for Kansas Gas Service and Texas Gas Service, ad-valorem taxes in Kansas and pipeline integrity testing
expenses in Texas.
For the year ended December 31, 2020, approximately 87 percent, 55 percent, and 70 percent of net margin from sales
customers were recovered from fixed charges for Oklahoma Natural Gas, Kansas Gas Service, and Texas Gas Service,
respectively.
MARKET CONDITIONS AND SEASONALITY
Supply - We purchased 153 Bcf and 174 Bcf of natural gas supply in 2020 and 2019, respectively. Our natural gas supply
portfolio consists of contracts with varying terms from a diverse group of suppliers. We award these contracts through
competitive-bidding processes to ensure reliable and competitively priced natural gas supply. We acquire our natural gas
supply from natural gas processors, marketers and producers.
An objective of our supply-sourcing strategy is to provide value to our customers through reliable, competitively priced and
flexible natural gas supply and transportation from multiple production areas and suppliers. This strategy is designed to
7
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 that adequate supply is available to meet the variations of customer
demand.
We do not anticipate problems with securing natural gas supply to satisfy customer demand; however, if supply shortages were
to occur, we have curtailment provisions in our tariffs 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 for our sales customers are impacted by weather and economic conditions. The consumption
patterns for our customers may change from time-to-time in response to a variety of possible factors, including:
•
•
•
•
the occurrence of a significant disruption in natural gas supplies, either by itself, or accompanied by higher or lower
natural gas prices;
the availability of more energy-efficient construction methods;
fuel switching from natural gas to electricity; and
residential customers may improve upon the energy efficiency of existing homes by replacing doors and windows,
adding insulation and replacing appliances with more efficient appliances.
In each jurisdiction in which we operate, changes in customer-usage profiles are considered in the periodic redesign of our
rates.
As of December 31, 2020, we had 48.3 Bcf of natural gas storage capacity under contract with remaining terms ranging from
one to ten years and maximum allowable daily withdrawal capacity of approximately 1.3 Bcf. This storage capacity allows us
to purchase natural gas during the off-peak season and store it for use in the winter periods. This storage is also needed to
assure the reliability of gas deliveries during peak demands for natural gas. Approximately 26 percent of our winter natural gas
supply needs for our sales customers is expected to be supplied from storage.
In managing our natural gas supply portfolios, we partially mitigate price volatility using a combination of financial derivatives
and natural gas in storage. We have natural gas financial hedging programs that have been authorized by the OCC, KCC and
certain jurisdictions in Texas. We do not utilize financial derivatives for speculative purposes, nor do we have trading
operations associated with our business.
Demand - See discussion below under Seasonality, Competition and CNG 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 normally higher 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 the tables above under Regulatory Overview for
additional information.
Competition - We encounter competition based on customers’ preference for natural gas, compared with other energy
alternatives and their comparative prices. We compete primarily to supply energy for space and water heating, cooking and
clothes drying. 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 U.S. 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.
8
The table below contains data related to the cost of delivered natural gas relative to electricity:
Natural Gas vs. Electricity
Oklahoma
Kansas
Texas
Average retail price of electricity / kWh(1)
ONE Gas delivered cost of natural gas / kWh(2)
Natural gas advantage ratio(3)
(1) Source: United States Energy Information Agency, www.eia.gov, for the eleven-month period ended November 30, 2020.
(2) Represents the average delivered cost of natural gas per kWh equivalent 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, 2020.
(3) Calculated as the ratio of the ONE Gas delivered average cost of natural gas per kWh equivalent to the average retail price of electricity per kWh.
12.78¢
3.00¢
4.3x
10.09¢
2.86¢
3.5x
11.95¢
3.42¢
3.5x
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 supply from the provider of their choice and contract with us to 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.
CNG - In meeting demand for CNG for motor vehicle transportation, particularly from fleet operators who are attracted to its
lower greenhouse gas emissions and operating fuel costs relative to gasoline- or diesel-powered vehicles, we have continued to
supply natural gas to CNG fueling stations. Our strategy is to support third-party investment in CNG fueling stations. We
deploy capital to connect CNG stations built and operated by third parties to our system. As of December 31, 2020, we supply
151 fueling stations, 33 of which we operate in conjunction with our own fleets. Of the 118 remaining stations, 67 are retail
and 51 are private stations. We transported 2.6 million Dth to CNG stations in 2020, which represents a decrease of 6 percent
compared with 2019.
RNG and Hydrogen – RNG and hydrogen technologies offer potential opportunities to secure new natural gas supply sources
that could be transported on our pipeline system and reduce greenhouse gas emissions. We have begun to make investments in
RNG and hydrogen technologies and innovation, including: (1) establishing interconnection guidelines for bringing RNG into
our system, (2) working directly with developers and end-use customers to identify potential RNG projects, (3) analyzing
pipeline system integrity and gas supply implications, including sourcing opportunities, related to hydrogen use in our system,
and (4) partnering with industry groups to develop methodologies regarding hydrogen blending and utilization to allow for
intentional sharing and learning across the LDC industry.
ENVIRONMENTAL AND SAFETY MATTERS
See Note 17 of the Notes to Consolidated Financial Statements and Management’s Discussion and Analysis of Financial
Condition and Results of Operations in this Annual Report for information regarding environmental and safety matters.
EMPLOYEES
We employed approximately 3,700 people at February 1, 2021, 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, 2021:
The United Steelworkers
International Brotherhood of Electrical Workers
Union
Approximate
Employees
400
300
Contract Expires
May 31, 2022
June 30, 2021
The foundation of our Company is our employees and our success begins with a values-driven culture and commitment to
developing a skilled, agile, diverse and engaged workforce where every employee understands that they can and do make a
difference. Advancing a safe, ethical, inclusive and diverse culture creates an environment that attracts and retains the high-
performing workforce needed to successfully execute our strategy. Safety is our number one core value and the foundation of
everything we do. Our success is reliant on training and development, performance management and shared responsibility that
focuses on engagement and ensures our employees know what is expected to keep themselves, their teammates, our customers
and communities safe.
9
To build a better tomorrow for everyone, we continue to foster a culture that embraces inclusion and diversity and encourages
collaboration. Our core values include inclusion and diversity, and we believe in equity and the value and voice of every
employee. As part of our commitment, our Inclusion and Diversity Council is chaired by our Chief Executive Officer and
includes five employees serving as permanent members, with 14 employees serving as rotating members with two-year terms.
The Inclusion and Diversity Council provides governance and guidance for implementing our strategy and sharing our vision of
an inclusive and diverse workforce. To promote an inclusive and diverse workforce, we are developing training programs for
our employees. Inclusion and diversity are embedded in our selection process and our new-hire orientation, and managing bias
training is included in our leadership development program.
INFORMATION ABOUT OUR 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
Pierce H. Norton II
Caron A. Lawhorn
Age*
60
2014 to present
Business Experience in Past Five Years
President, Chief Executive Officer and Director
59
2019 to present
Senior Vice President and Chief Financial Officer
2014 to 2019
Senior Vice President, Commercial
Joseph L. McCormick
61
2014 to present
Senior Vice President, General Counsel and Assistant
Secretary
Curtis L. Dinan
53
2020 to present
Senior Vice President and Chief Commercial Officer
2019 to 2020
Senior Vice President, Commercial
2018 to 2019
Senior Vice President and Chief Financial Officer
2014 to 2018
Senior Vice President, Chief Financial Officer and Treasurer
Robert S. McAnnally
57
2020 to present
Senior Vice President and Chief Operating Officer
Mark A. Bender
Jeffrey J. Husen
* As of January 1, 2021
2015 to 2020
Senior Vice President, Operations
56
2015 to present
Senior Vice President, Administration and Chief Information
Officer
49
2018 to present Vice President, Chief Accounting Officer and Controller
2014 to 2018
Controller
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.
AVAILABLE INFORMATION
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,
which also makes these materials available on its website (www.sec.gov). Copies of our Code of Business Conduct and Ethics,
Corporate Governance Guidelines, Certificate of Incorporation, bylaws, the written charters of our Audit Committee, Executive
Compensation Committee, Corporate Governance Committee and Executive Committee and our Sustainability Report are also
available on our website, and copies of these documents are available upon request.
10
In addition to filings with the SEC and materials posted on our website, we also use social media platforms as channels of
information distribution to reach public investors. Information contained on our website and posted on or disseminated through
our social media accounts is not incorporated by reference into this report.
ITEM 1A.
RISK FACTORS
Our investors should consider the following risks that could affect us and our business. Although we believe we have discussed
the 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 Part 2, Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations.
RISK FACTORS INHERENT IN OUR BUSINESS
Operational Risks
Pandemics or other health crises could have an adverse effect on our business.
Our business and our customers could be materially and adversely affected by the risks, or the public perception of the risks,
related to a pandemic or other health crisis, such as the outbreak of COVID-19. The COVID-19 pandemic is having an
unprecedented impact on the U.S. and its economy and has created significant uncertainties about the potential adverse effect of
the pandemic on the economy, our customers, our employees and supply chain partners. These uncertainties have also resulted
in significant volatility within financial markets and a decrease in the value of equity securities, including our common stock.
International, federal, state and local public health and governmental authorities have taken extraordinary and wide-ranging
actions to contain and combat the outbreak and spread of COVID-19 across the U.S. and throughout the world, including
quarantines, “stay-at-home” orders and similar mandates for many individuals to substantially restrict daily activities and for
many businesses to curtail or cease normal operations. These recommendations and/or mandates from federal, state and local
authorities may remain in place for a prolonged period or may be reimposed in connection with a resurgence of the virus
following resumption or partial resumption of normal economic activities. These recommendations and/or mandates result in
temporary or long-term financial hardships for our residential customers and business interruptions and/or closures for our
commercial, industrial and transportation customers, all of which increases the risk of delinquencies and defaults of payments
on their accounts and may also affect our supply chain. It is possible that COVID-19 public health containment efforts will be
intensified to such an extent that we will be forced to curtail or possibly suspend certain business operations for an indefinite
period. Regulatory orders require us to continue serving our natural gas customers in default during the pandemic outbreak,
which may adversely affect our earnings, liquidity and cash flows.
Experts have observed an increase in the volume and the sophistication of cyberattacks since the beginning of the COVID-19
pandemic. Any breaches of technology systems could disrupt our operations or result in the loss or exposure of confidential or
sensitive customer, employee or Company information and adversely affect our business, financial condition and results of
operations.
As an essential business, we have implemented business continuity and emergency response plans to continue to provide
natural gas services to customers and support our operations, while taking health and safety measures such as implementing
worker distancing measures and using a remote workforce where possible. Beginning at the end of the first quarter of 2020,
remote working arrangements for our employees increased as a result of the COVID-19 pandemic, requiring enhancements and
modifications to our IT infrastructure (e.g. Internet, Virtual Private Network, remote collaboration systems, etc.), and any
failures of the technologies, including third-party service providers, that facilitate working remotely could limit our ability to
conduct ordinary operations and expose us to increased risk or impact of a cyberattack or data breach. When we begin
reintegrating our personnel back into the workplace, having a greater number of employees working from our facilities will
likely cause us to incur greater costs related to purchasing more PPE, additional facility sanitation activities and expanding
health-screening processes. Shortages in PPE may require us to revise or delay our reintegration plans. Increases in the number
of COVID-19 cases in our service areas may also result in delaying or slowing personnel reintegration.
There is no assurance that the continued spread of COVID-19 and efforts to contain the virus (including, but not limited to,
voluntary and mandatory quarantines, restrictions on travel, vaccinations, limiting gatherings of people, and reduced operations
and extended closures of many businesses and institutions) will not materially impact our business, results of operations and
financial condition.
11
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 or penalties.
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. The failure to comply with these laws,
regulations and other requirements could expose us to civil or criminal liability, enforcement actions, fines, penalties or
injunctive measures that may not be recoverable from customers in rates and could have a material adverse effect on our
business, financial condition, results of operations and cash flows, and reputation.
We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these
regulations could adversely affect our financial results or result in significant fines or penalties.
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 that may not be
recoverable through our rates and could have a material adverse effect on our business, financial condition, results of operations
and cash flows. Although we employ safety procedures in the design and operation of our facilities, there is a risk that an
accident or injury to one of our employees could occur in one of our facilities. Any accident or injury to our employees could
result in litigation, operational delays and harm to our reputation, which could negatively affect our business, operating results
and financial condition.
Our business is subject to operational hazards and unforeseen interruptions that could materially and adversely affect 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 or vehicles with our pipeline facilities (for example, this may occur if a third-party were to perform excavation or
construction work near our facilities or vehicles colliding with above-ground pipeline facilities) and catastrophic events, such as
severe weather events, hurricanes, thunderstorms, tornadoes, sustained extreme temperatures, earthquakes, floods or other
similar events beyond our control. Disruptions to the operations of natural gas producers who supply us with natural gas,
including due to the loss of power, could disrupt our ability to serve our customers. It is also possible that our facilities, or those
of our counterparties or service providers, could be direct targets or indirect casualties of an act of terrorism, including cyber-
attacks. Lapses in judgement or failure to follow protocols could lead to warranty and indemnification liabilities or catastrophic
accidents, causing property damage or personal injury. 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 adversely affect our earnings and cash flows.
Unanticipated events or a combination of events, failure in resources needed to respond to events, or slow or inadequate
response to events may have an adverse impact on our financial condition, results of operations and cash flows.
While we have general liability and property insurance currently in place in amounts that we consider appropriate based on our
assessment of business risk and best practices in our industry and in general business, such policies are subject to certain limits,
deductibles and policy exclusions. Further, we are not fully insured against all risks inherent in our business, including certain
types of catastrophic events. 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
12
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 systems or facilities or to third parties may not be
sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner.
The occurrence of any of the foregoing could have a material adverse effect on our financial condition, results of operations and
cash flows.
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 our financial condition may be adversely affected.
In order to meet customers’ natural gas demands, we rely on and must obtain sufficient natural gas supplies, pipeline
transportation and storage capacity from third parties. We must contract for reliable and adequate delivery capacity for our
distribution system, while considering the dynamics of the interstate and intrastate pipeline capacity markets, our own in-system
resources, as well as the characteristics of our customer base. If we are unable to obtain these, our ability to meet our customers’
natural gas requirements could be impaired. 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, severe weather events,
hurricanes, thunderstorms, tornadoes, sustained extreme temperatures, earthquakes, 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.
Such severe events may also cause significant reductions in our natural gas in storage, which will take time to replenish, and
cause gas restrictions or curtailment of operations and delivery of natural gas to customers including, for example, restrictions
and curtailments imposed by regulators during the recent February 2021 winter weather event. These types of events and
disruptions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow,
liquidity and prospects.
We may not be able to complete necessary or desirable expansion or infrastructure development projects, which may delay
or prevent us from serving our customers or expanding our business.
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 approvals 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
adequately serve existing customers or support customer growth, which would adversely impact our business, stakeholder
perception, financial condition, results of operations 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-management policies and
procedures are intended to align strategies, processes, people, IT 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 a material adverse
effect on our earnings, financial condition and cash flows.
Our business increasingly relies on technology, the failure of which, or the occurrence of cyber or physical security attacks
thereon, or those of third parties, may adversely affect our financial results and cash flows.
Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business.
We use computer programs to help run our financial and operations organizations, including an enterprise resource planning
system that integrates data and reporting activities across our Company. The failure of these or other similarly important
technologies, the lack of alternative technologies, or our inability to have these technologies supported, updated, expanded or
integrated into other technologies, could hinder our operations and adversely impact our financial condition and results of
operations. The use of technological programs, systems and tools may subject our business to increased risks.
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Our business is dependent upon our operational systems to process a large amount of data and complex transactions. As part of
our operations, we come into contact with sensitive information, including personally identifiable information. If any of our
financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be
adversely affected. Our financial results could also be adversely affected if an employee or third party 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 or third-
party tampering or manipulation of those systems will result in losses that are difficult to detect or mitigate.
Additionally, certain portions of our IT, customer service, resource management, pipeline and infrastructure installation and
maintenance, engineering, payroll and human resources functions that we rely on are provided by third-party vendors. Services
provided by third-parties could be disrupted due to events and circumstances beyond our control which could adversely impact
our business, financial condition, results of operations and cash flows.
Any cyber or physical security attacks, or threats of such attacks, that affect our distribution facilities, our customers, our
suppliers and third-party service providers or any financial data could disrupt normal business operations, expose sensitive
information, and/or lead to physical damages that may have a material adverse effect on our business. Physical damage due to a
cyber security incident or acts of cyber terrorism could impact services and could lead to material liabilities. As cyber or
physical security attacks become more common and sophisticated, we could be required to incur increased costs to strengthen
our systems or to obtain additional insurance coverage against potential losses. Federal and state regulatory agencies are
increasingly focused on risk related to physical security and cybersecurity in general, and specifically in critical infrastructure
sectors, including natural gas distribution. In addition, cyber or physical attacks or threats on our Company, customer and
employee data may result in a financial loss and may adversely impact our business, financial condition, results of operations
and cash flows. Third-party systems on which we rely could also suffer such attacks or operational system failure.
While we have implemented and continue to evaluate and improve policies, procedures, protective technologies, and controls to
prevent and detect cyber or physical security attacks, there is no guarantee that these efforts (or any similar efforts by third
parties on which we rely) will be effective against any particular cyber or physical attack or protect us from unauthorized access
or damage to our systems. A severe attack or security breach could adversely affect our business reputation, diminish customer
confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to
material legal claims and liability which may not be fully covered by insurance, and our business, financial condition, results of
operations and cash flows could be adversely affected.
Failure to maintain the security of personally identifiable information could adversely affect us.
In connection with our business we and our vendors, suppliers and contractors collect and retain personally identifiable
information (e.g., information of our customers, shareholders, suppliers and employees), and there is an expectation that we and
such third parties will adequately protect that information. The U.S. regulatory environment surrounding information security
and privacy is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of
confidential information pose increasingly complex compliance challenges and potentially elevate our costs. Any failure by us
to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant
penalties and liabilities for us. A significant theft, loss or fraudulent use of the personally identifiable information we maintain
or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions could
adversely impact our reputation and could result in significant costs, fines, litigation.
Our business could be adversely affected by strikes or work stoppages by our unionized employees, which may impact our
operations, cash flows and earnings.
At February 1, 2021, approximately 700 of our estimated 3,700 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, results of
operations and cash flows.
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A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could
adversely affect operations, cash flows and earnings. Further, we may be unable to attract and retain management and
professional and technical employees, which could adversely impact our operations, earnings and cash flows.
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 challenges of attracting new qualified workers to the natural gas distribution industry. This shortage of
skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have
an adverse impact on labor productivity and costs and our ability to meet the needs of our customers in the event there is an
increase in the demand for our products and services, which could adversely affect our business and cash flows.
Our ability to implement our business strategy, satisfy our regulatory requirements, and serve our customers is dependent upon
our ability to continue to recruit and employ talented management and professionals while retaining a skilled, agile, diverse and
engaged workforce. We are subject to the risk that we will not be able to effectively replace or transfer the knowledge and
expertise of retiring management or employees. Without effective succession, our ability to provide quality service to our
customers and satisfy our regulatory requirements will be challenged, and this could adversely impact our business, financial
condition, results of operations and cash flows.
We are subject to environmental regulations and failure to comply with these regulations could result in significant fines or
penalties and could adversely affect our operations or financial results.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental
authorities relating to environmental and health and safety matters, including those legal requirements that govern discharges of
substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of
contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to
employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated with
our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. The
failure to comply with these laws, regulations and other requirements, or the discovery of presently unknown environmental
conditions, could expose us to civil or criminal liability, enforcement actions and regulatory fines and penalties that may not be
recoverable through our rates and could have a material adverse effect on our business, financial condition, results of operations
and cash flows.
We also own or retain legal responsibility for certain environmental conditions at certain former MGP sites. A number of
environmental issues may exist with respect to these former MGP sites. Accordingly, future costs are dependent on the final
determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation, changing
technology and governmental regulations and could be material to our financial condition, results of operations and cash flows.
With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets
operated by us that are subject to environmental regulation, our environmental expenditures could increase in the future, and
such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, which could adversely
affect our financial condition, results of operations and cash flows.
We are subject to physical and financial risks associated with climate change, which may adversely affect our financial
results, growth, cash flows and results of operations.
There is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates
physical and financial risks. 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. To the extent climate change adversely impacts the economic health of our operating territory, it could adversely
impact customer demand or our customers’ ability to pay. 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 severe weather events, hurricanes, thunderstorms, tornadoes,
sustained extreme temperatures, earthquakes, floods or other similar events beyond our control. To the extent the frequency of
extreme weather events increases, our costs of providing service and our working capital requirements could increase. We may
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not be able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks. To the
extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could adversely affect
our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business
could be affected by the potential for lawsuits related to or against greenhouse gas emitters based on the claimed connection
between greenhouse gas emissions and climate change, which could adversely impact our business, results of operations and
cash flows.
Regulatory and Legislative Risks
Regulatory actions could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover
our invested capital, operating costs and natural gas costs.
In addition to regulation by other governmental authorities, we are subject to regulation by the OCC, KCC, RRC and various
municipalities in Texas. These authorities set the rates that we charge our customers for our services. Our ability to obtain
timely future rate increases depends on regulatory discretion. Significant events, including severe weather events, may result in
us experiencing unforeseeable and unprecedented market pricing for gas costs, as well as financing costs related to the payment
of gas costs, all or a part of which may not be recoverable through our tariffs in each state where we operate. As such, there can
be no assurance that we will be able to obtain rate increases, fully recover our natural gas costs or that our authorized rates of
return will continue at the current levels.
We monitor and compare the rates of return we achieve with our allowed rates of return and initiate general and specific rate
proceedings as needed. If a regulatory agency were to prohibit us from setting rates that allow for the timely recovery of our
costs and a reasonable return by significantly lowering our allowed return or adversely altering our cost allocation, rate design
or other tariff provisions, modifying or eliminating cost trackers, prohibiting recovery of regulatory assets or disallowing
portions of our expenses, then our earnings could be adversely impacted. Regulatory proceedings also involve a risk of rate
reduction, because once a proceeding has been filed, it is subject to challenge by various intervenors. Risks and uncertainties
relating to delays in obtaining, or failure to obtain, regulatory approvals, conditions imposed in regulatory approvals, and
determinations in regulatory investigations can also impact financial performance. In particular, the timing and amount of rate
relief can materially impact results of operations, financial condition and cash flows.
Further, accounting principles that govern our Company permit certain assets that result from the regulatory process to be
recorded on our consolidated balance sheets that could not be recorded under GAAP for nonregulated entities. We consider
factors such as rate orders from regulators, previous rate orders for substantially similar costs, written approval from the
regulators and analysis of recoverability by internal and external legal counsel to determine the probability of future recovery of
these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at
that time, which would also adversely affect our financial condition, 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. In certain instances, including in the event of significant and severe weather events, we may apply to regulators
seeking authority to timely recover extraordinary costs, and our application may not be approved. If any of our natural gas costs
or related expenses were disallowed, our results of operations and cash flows would also be adversely affected.
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 timely recover 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 give assurance that our regulators will continue to allow recovery of
such expenditures in the future. Changes in the regulatory environment applicable to our business or the imposition of
additional regulation could impair our ability to recover costs absorbed historically by our customers, and adversely impact our
results of operations, financial condition and cash flows.
We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs is dependent on
regulatory action.
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
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authorities in Oklahoma, Kansas and Texas regulate many aspects of our utility operations, including organization, safety,
financing, affiliate transactions, customer service and the terms of service to customers, including the rates that we can charge
customers.
The profitability of our operations is dependent on our ability to recover costs, including income taxes, 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 included in the rates billed to our customers. In addition, as the regulatory environment
applicable to our operations increases in complexity, the risk of inadvertent noncompliance could also increase. Our failure to
comply with applicable laws and regulations could result in the imposition of fines, penalties or other enforcement actions by
the authorities that regulate our operations that would not be recoverable in our rates.
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 and operations are subject to regulation by a number of federal agencies, including FERC, DOT, OSHA, EPA,
CFTC and various regulatory agencies in Oklahoma, Kansas and Texas, and we are subject to numerous federal and state laws
and regulations. Future changes to laws, regulations and policies may impair our ability to compete for business or to recover
costs and may increase the cost of our operations. Furthermore, because the language in some laws and regulations is not
prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of
regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures
affecting our operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under
the Natural Gas Act of 1938, as amended, to impose penalties for current violations of up to $1 million per day for each
violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent
noncompliance could also increase. The fines or penalties for noncompliance with laws and regulations may not be recoverable
through our rates. 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.
Carbon neutral, energy-efficiency or other legislation or regulations intended to address climate change could increase our
operating costs or restrict our market opportunities, adversely affecting our financial results, growth, cash flows and results
of operations.
International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit the causes of
climate change, including greenhouse gas emissions, such as carbon dioxide and methane. 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 adversely impact the reputation of fossil fuel
products or services. The occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to
other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas or cause fuel
switching to other energy sources, and impact the competitive position of natural gas and the ability to serve new or existing
customers, adversely affecting our business, results of operations and cash flows.
We are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely
affect our financial condition, results of operations and cash flows.
In the normal course of business, we are involved in legal or administrative proceedings before various courts and
governmental bodies with respect to general claims, rates, environmental issues, gas cost prudence reviews and other matters.
Adverse decisions regarding these matters, to the extent they require us to make payments in excess of amounts provided for in
our consolidated financial statements, or to the extent they are not covered by insurance, could adversely affect our financial
condition, results of operations and cash flows.
Changes in federal and state fiscal, tax and monetary policy could significantly increase our costs and 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 or may result in refunding amounts previously collected for deferred taxes to
customers on an accelerated basis. This could increase our expenses and capital spending and decrease our cash flows if we are
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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 adversely impact customer growth. Changes in tax rates could adversely affect our cash flows and may
increase the cash we pay for income taxes in the future. Changes in monetary or other policies of the federal or state
governments may adversely affect the economic climate for the United States, the regions in which we operate or particular
industries, such as ours or those of our customers. Any of these events could adversely affect our cash flows, restrict our ability
to make capital investments and may cause us to increase debt and take other actions to conserve cash.
Financial, Economic and Market Risks
Unfavorable economic and market conditions could adversely affect our financial condition, earnings and cash flows.
Weakening economic activity in our markets could result in a loss of existing customers, fewer new customers, especially in
newly constructed homes and other buildings, or a decline in energy consumption, any of which could adversely affect our
revenues or restrict our future growth. It may become more difficult for customers to pay their natural gas bills, leading to slow
collections and higher-than-normal levels of accounts receivable, which in turn could increase our financing requirements and
bad debt expense. Customers may also experience difficulties paying their natural gas bills in the instance of severe weather
events that result in higher usage and higher natural gas prices, exacerbating impacts on our ability to collect and furthering our
increasing financing requirements and bad debt expense, which could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and prospects.
We cannot predict the timing, strength, or duration of any future economic slowdowns. Fluctuations and uncertainties in the
economy make it challenging for us to accurately forecast and plan future business activities and to identify risks that may
affect our business, financial condition, results of operations and cash flows. The foregoing could adversely affect our business,
financial condition, results of operations and cash flows.
Increases in the price of natural gas could reduce our earnings, increase our working capital requirements, and adversely
impact our customer base.
Changes in supply and demand within the natural gas markets, as well as other factors, could cause an increase in the price of
natural gas. The increased production in the U.S. of natural gas from shale formations generally has put downward pressure on
the wholesale cost of natural gas in recent years; however, other factors could put upward pressure on natural gas prices,
including weather-related events, restrictions or regulations on shale natural gas production and waste water disposal, increased
demand from natural gas fueled electric power generation and increases in natural gas exports. Market conditions can also lead
to short-term price spikes in natural gas prices, such as high demand during periods of extreme cold weather or system
constraints at specific delivery locations.
Natural gas costs are passed through to our customers based on the actual cost of the natural gas we purchase and a customer’s
consumption. Regulatory authorities 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. The disallowance of or delay in recovery of our natural gas costs could
adversely affect our financial condition, results of operations and cash flows. Additionally, 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.
Further, higher and more volatile natural gas prices may adversely impact our customers’ perception of natural gas. 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 prudence 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 adversely impact our accounts receivable collections, resulting in higher bad debt
expense. The occurrence of any of the foregoing could adversely affect our business, financial condition, results of operations
and cash flows, as well as our future growth opportunities.
Our business is subject to competition that could adversely affect our results of operations.
The natural gas distribution business is competitive, and we face competition from other companies that supply energy,
including electric companies, private generation, solar energy producers, propane dealers, other renewable energy providers and
from other sources of energy for power generation, such as coal or nuclear energy. Significant competitive factors include
efficiency, quality and reliability of the services we provide and the price we charge.
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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 adversely impact 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, bans on natural gas infrastructure in new construction, higher natural
gas costs or decreases in the price of other energy sources also may encourage decreases in natural gas consumption and allow
competition from alternative energy sources for applications that have used natural gas, encouraging some customers to move
away from natural gas-powered 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, environmental and other nonprice factors.
Technological improvements in other energy sources, energy storage, conservation, efficiency 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 adversely affecting 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 adversely impact the growth opportunities available to us and the
usage patterns and financial condition of our customers. This could adversely affect our financial condition, results of
operations and cash flows.
A downgrade in our credit ratings or placing those ratings on negative outlook or watch could adversely affect our cost of
and ability to access capital.
Our ability to obtain adequate and cost-effective financing depends in part on our credit ratings. Our credit ratings are subject to
change at any time in the discretion of the applicable rating agencies. Numerous factors, including many of which are not
within our control, are considered by the rating agencies in connection with assigning credit ratings. A reduction in our ratings
by our rating agencies could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. Such a
downgrade could further limit or delay our access to public and private credit markets and increase the costs of borrowing under
available credit lines. While the current Moody’s and S&P (collectively, the Rating Agencies) issuer credit ratings for ONE Gas
are investment grade, there is no assurance that these credit ratings will not be downgraded. A downgrade of our credit ratings
may materially and adversely affect the market prices of our equity and debt securities, the interest rates at which borrowings
are made and debt securities and commercial paper are issued, and the various fees on credit facilities. This could make it
significantly more costly for us to borrow money, to issue debt securities and to raise certain other types of capital and/or
complete additional financings. Such negative credit rating actions, as well as the reasons for such actions, could materially and
adversely affect our cash flows, results of operations and financial condition and the market price of, and our ability to pay the
principal of and interest on, our debt securities. Should our credit ratings be downgraded, it could limit or delay our ability to
obtain additional financing in the future for working capital, capital expenditures and acquisitions when necessary or desirable.
In addition, our pool of investors and prospective creditors would likely decrease. An increase in borrowing costs without the
ability to recover these higher costs in the rates charged to our customers could adversely affect our results of operations,
financial condition and cash flows by limiting our ability to earn our allowed rate of return.
Moreover, most of our large suppliers and counterparties require an expected level of creditworthiness in order for them to enter
into transactions with us. If our credit ratings decline, the costs to operate our business could increase because counterparties
could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business
with us.
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
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utility margins as customer consumption declines. We have implemented WNA mechanisms for our sales to customers in
Oklahoma, Kansas and Texas, which are designed to reduce our earnings sensitivity to weather. WNA mechanisms require 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, financial condition and cash flows could vary and be impacted
adversely.
Emerging technologies may cause disruption in utility services, which may adversely affect our customer growth, earnings
and cash flows.
Commercial technologies that advance electrification and increase energy efficiency in some aspects of the economy, such as
transportation or heating, could negatively impact the demand for natural gas. We may not be able to quickly adapt to changes
resulting from rapidly advancing technologies that may result in a reduction in demand for our services. This could slow
customer growth and even cause customers to reduce or cease using natural gas which could have a material adverse effect on
our financial condition, results of operations and cash flows.
An impairment of goodwill and long-lived assets could reduce our earnings.
At December 31, 2020, we had approximately $158 million of goodwill recorded on our Consolidated 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 adversely
impact our financial condition and results of operations.
We may be unable to access capital or our cost of capital may increase significantly which may adversely affect our results
of operations, cash flows and financial condition.
Our ability to obtain adequate and cost-effective financing is dependent upon the liquidity of the financial markets, in addition
to our financial condition and credit ratings. Disruptions in the capital and credit markets could adversely affect our ability to
access short-term and long-term capital. Access to funds under our ONE Gas Credit Agreement, our commercial paper
program, our ONE Gas 364-day Credit Agreement and our ONE Gas 2021 Term Loan Facility will be dependent on the ability
of the participating banks to meet their funding commitments and any issues with lenders causing them to stop purchasing our
commercial paper. 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, our ONE Gas 2021 Term Loan Facility, our commercial paper program, and our ONE Gas 364-day 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, our ONE Gas 2021 Term Loan Facility and our ONE
Gas 364-day Credit Agreement, potentially impairing their ability to meet their funding commitments to us. Disruptions in the
capital and credit markets as a result of uncertainty, changing or increased regulation or failures of significant financial
institutions could adversely affect our access to capital needed for our business. The inability to access adequate capital or an
increase in the cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and
require us to reduce or eliminate our dividend or other discretionary uses of cash. A significant reduction in our liquidity could
cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our
access to credit markets and increase our costs of borrowing. Additionally, as we have recently entered into the ONE Gas 2021
Term Loan Facility in February 2021, our additional indebtedness may limit our ability to borrow additional funds, if needed, or
prevent us from raising the funds on commercially reasonable terms, or on terms acceptable to us, or at all.
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, which may adversely affect our results of operations, cash flows and
financial condition.
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 many or all of our debt agreements, obliged in
such instance to satisfy all of our outstanding indebtedness under many or all such agreements simultaneously. In such an event,
20
we may not be able to obtain alternative financing or, if we are able to obtain such financing, we may not be able to obtain it on
terms acceptable to us, which would adversely affect our ability to implement our business plan, have flexibility in planning for,
or reacting to, changes in our business, make capital expenditures and finance our operations.
The cost of providing pension and other postemployment health care benefits to eligible employees and qualified retirees is
subject to changes in pension fund values, changing demographics and other factors and may increase our costs. In
addition, the passage of the Patient Protection and Affordable Care Act in 2010 and the Consolidated Appropriations Act in
2021 and the potential revision, repeal and/or replacement of either of these acts 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 which may adversely affect our cash flows and
earnings.
We have defined benefit pension plans and other postemployment welfare plans for certain eligible employees. Our defined
benefit plans are closed to new participants. Our other postemployment welfare plans subsidize costs for providing
postemployment medical benefits and life insurance. The cost of providing these benefits to eligible current and former
employees is subject to changes in the market value of our pension and other postemployment benefit plan assets, changing
demographics, including longer life expectancy of plan participants and their beneficiaries, current and future legislative
changes, changes in health care costs, changes in discount rates used to calculate liability, and various actuarial calculations and
assumptions.
Any sustained declines in equity markets and reductions in bond values may have a material adverse effect on the value of our
pension and other postemployment benefit plan assets. In these circumstances, additional cash contributions to our pension and
other postemployment benefit plans may be required, which could have a material adverse impact on our financial condition
and cash flows.
In addition, the costs of providing health care benefits to our employees could increase over the next several years due in large
part to the Patient Protection and Affordable Care Act of 2010 and the Consolidated Appropriations Act in 2021, and the
potential revision, repeal and/or replacement of either of these acts. The future costs of compliance with the provisions are
difficult to measure at this time. Also, our costs of providing such benefits and related funding requirements could also
materially increase in the future, depending on the timing of the recovery, if any, of such costs through our rates, which could
adversely impact our financial condition and cash flows.
Our financing arrangements subject us to various restrictions that could limit our operating flexibility, earnings and cash
flows.
The covenants in the indenture governing our Senior Notes, our ONE Gas Credit Agreement and the ONE Gas 364-day 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 and the ONE Gas 364-day Credit Agreement include 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. The ONE Gas 364-day Credit Agreement is scheduled to mature in April 2021.
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, results of operations and cash flows.
Some of our debt, including borrowings under our ONE Gas Credit Agreement, our ONE Gas 364-day Credit Agreement
and our commercial paper program, is based on variable rates of interest, which could result in higher interest expenses in
the event of an increase in interest rates.
We are 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, the ONE Gas 364-day Credit Agreement and commercial paper
program are based on variable rates of interest. If these rates rise, the interest rate on this debt will also increase. Therefore, an
21
increase in these rates will increase our interest payment obligations and have a negative effect on our cash flows and financial
position.
Conditions in the financial markets and economic conditions generally may materially adversely affect us.
Our business is capital intensive and we rely significantly on long-term debt to fund a portion of our capital expenditures and
repay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations.
Limitations on the availability of credit and increases in interest rates or credit spreads may materially adversely affect our
businesses, cash flows, results of operations, financial condition and/or prospects, as well as our ability to meet contractual and
other commitments. In difficult credit market environments, we may find it necessary to fund our operations and capital
expenditures at a higher cost or we may be unable to raise as much funding as we need to support new or ongoing business
activities. This could cause us to reduce non-safety related capital expenditures and could increase our cost of servicing debt,
both of which could significantly reduce our short-term and long-term profitability.
Other factors can affect the availability and cost of credit for our businesses, as well as the terms of equity and debt financing,
including:
•
•
•
•
•
•
adverse changes to laws and regulations in the states in which we operate;
the overall health of the energy industry;
volatility in natural gas prices;
changes in tax law;
credit ratings downgrades; and
general economic and financial market conditions.
We are dependent on continued access to the credit and capital markets to execute our business strategy.
Our long-term debt is currently rated as “investment grade” by the Rating Agencies. We rely upon access to both short-term
and long-term credit and capital markets to satisfy our liquidity requirements. If adverse credit conditions or a downgrade in our
ratings outlook were to cause a significant limitation on our access to the private credit and public capital markets, we could see
a reduction in our liquidity. A significant reduction in our liquidity could in turn trigger a negative change in our ratings outlook
or even a reduction in our credit ratings by one or more of the credit rating agencies. Such a downgrade could further limit our
access to private credit and/or public capital markets and increase our costs of borrowing.
While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can
provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas
increases significantly or there are regulatory constraints on our ability to recover gas or financing costs. The future effects on
our business, liquidity and financial results of a deterioration of current conditions in the credit and capital markets could be
material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.
RISKS RELATING TO OUR COMMON STOCK
Provisions in our certificate of incorporation, our bylaws and Oklahoma law as well as regulatory approvals 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:
•
•
rules regarding how shareholders may present proposals or nominate directors for election at shareholder
meetings; and
the right of our Board of Directors to issue preferred stock without shareholder approval.
Oklahoma law also imposes some restrictions on mergers and other business combinations between us and any holder of 15
percent or more of our outstanding common stock.
We believe these provisions protect our shareholders from coercive or otherwise potentially unfair takeover tactics by requiring
potential acquirers to negotiate with our Board of Directors and by providing our Board of Directors with more time to assess
22
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.
Additionally, any acquisition of our Company would need to be approved by certain regulatory bodies including the OCC, KCC
and various regulators in Texas, which could delay or prevent an acquisition.
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.
GENERAL RISK FACTORS
Federal, state and local jurisdictions may challenge our tax return positions.
The preparation of our federal and state tax return filings requires 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, and in determining the amount of any reserves for potential adverse outcomes regarding tax positions that
have been taken that may be subject to challenge by taxing authorities. 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,
which could adversely impact our results of operations, cash flows and financial condition.
We may pursue acquisitions, divestitures and other strategic opportunities which, if not successful, may adversely impact
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 divestitures
and other strategic opportunities. We may not be able to successfully negotiate, finance or receive regulatory approval for
future acquisitions or integrate the acquired businesses with our existing business and services. These efforts may also distract
our management and employees from day-to-day operations and require substantial commitments of time and resources. Future
acquisitions could result in potentially dilutive issuances of equity securities, a decrease in our liquidity as a result of our using
a significant portion of our available cash or borrowing capacity to finance the acquisition, the incurrence of debt, contingent
liabilities and amortization expenses and substantial goodwill. The effects of these strategic decisions may have long-term
implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes may
adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved
by regulators) to the detriment of the Company. We may be materially and adversely affected if we are unable to successfully
integrate businesses that we acquire.
Changes in accounting standards may adversely impact our financial condition, results of operations and cash flows.
We are subject to additional changes in GAAP, SEC regulations and other interpretations of financial reporting requirements
for public utilities. We neither have control over the impact these changes may have on our financial condition or results of
operations nor the timing of such changes.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
23
ITEM 2.
PROPERTIES
The following table sets forth the approximate miles of distribution mains and transmission pipeline as of December 31, 2020:
Properties (miles)
Distribution
Transmission
Total properties
OK
19,000
700
19,700
KS
11,600
1,500
13,100
TX
Total
10,600
300
10,900
41,200
2,500
43,700
We lease approximately 400 thousand square feet of office space and other facilities for our operations. In addition, we have
48.3 Bcf of natural gas storage capacity under contract, with maximum allowable daily withdrawal capacity of approximately
1.3 Bcf.
ITEM 3.
LEGAL PROCEEDINGS
See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for information regarding legal
proceedings.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
24
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(cid:17)(cid:20)
ITEM 6.
SELECTED FINANCIAL DATA
Not applicable.
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 consolidated financial statements and
Notes to Consolidated Financial Statements in this Annual Report.
EXECUTIVE SUMMARY
We are a 100-percent regulated natural gas distribution company. As such, our regulators determine the rates we are allowed to
charge for our service based on the 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, interest expense and income taxes. Our rates have both a fixed and a variable component, with
approximately 72 percent of our natural gas sales net margin in 2020 derived from fixed monthly charges to our sales
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 WNA mechanisms that adjust sales customers’ bills when
actual HDDs differ from normalized HDDs, these mechanisms are in place for only a portion of the year, except in Kansas, and
do not offset all fluctuations in usage resulting from weather variability. Accordingly, the weather can have either a positive or
negative impact on our financial performance.
Our financial performance, therefore, is contingent on a number of factors, including: (1) our regulatory construct and
outcomes, which determine the rates we are allowed to charge for our service and the authorized rates of return on our
investments in rate base; (2) the consumption of natural gas, which impacts the amount of our net margin derived from the
variable component of our rates; (3) customer growth; (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 integrity and environmental compliance. These requirements impact our
operating expenses and the level of capital expenditures required for compliance. Historically, our regulators have allowed
recovery of these expenditures. However, because integrity and environmental regulation is changing constantly, our capital
and operating expenditures to comply are changing as well. Although we believe our regulators will continue to allow recovery
of such expenditures in the future, we will continue to make these expenditures with no assurance about if, or over what period,
we will be permitted to recover them.
RECENT DEVELOPMENTS
2021 February Winter Weather Event - A historic winter weather event in February 2021 impacted supply, market pricing and
demand for natural gas in a number of states, including our service territories of Kansas, Oklahoma, and Texas. During this
time, the governors of Kansas, Oklahoma, and Texas, each declared a state of emergency, and certain regulatory agencies
issued emergency orders that impacted the utility and natural gas industries, including statewide utilities curtailment programs
and orders requiring jurisdictional natural gas and electric utilities to do all things possible and necessary to ensure that natural
gas and electricity utility services continue to be provided to their customers. Due to the historic nature of this winter weather
event, we experienced unforeseeable and unprecedented market pricing for gas costs in our Kansas, Oklahoma, and Texas
jurisdictions, which resulted in aggregated natural gas purchases for the month of February of approximately $2.2 billion. These
purchases are generally payable at the end of March 2021.
On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility to enhance our liquidity position as part of the
financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of the 2021
winter weather event and the repayment of indebtedness.
Our purchased gas costs are recoverable through our tariffs in each state where we operate. Due to the higher level of gas
purchase costs during the 2021 winter event, we are working with regulators to extend the recovery periods of such costs in
order to lessen the immediate customer impact. In that regard, the Kansas Corporation Commission and the Railroad
Commission of Texas each authorized certain utilities, including local natural gas distribution companies, to record a regulatory
26
asset to account for the extraordinary costs associated with this winter weather event, including but not limited to gas purchase
costs and other costs related to the procurement and transportation of gas supply. We have also filed a motion with the
Oklahoma Corporation Commission to seek comparable authority in Oklahoma to record a regulatory asset to account for the
extraordinary costs, including carrying costs, associated with this winter weather event. An administrative law judge has
recommended approval of our motion by the Oklahoma Corporation Commission.
See “Regulatory Activities”, “Liquidity”, Note 2 of the Notes to the Consolidated Financial Statements and Item 1A, “Risk
Factors” in this Annual Report for additional discussion of the effects of this winter weather event on us.
COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have
implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and
communities. The following summarizes actions we have taken and the impact on our operations:
Workforce
Customers
Operations
Following the guidance of the CDC, OSHA and third-party subject matter
experts we have engaged, we have established a number of protocols to
protect our employees. For all employees, we are encouraging social
distancing and proper hygiene, and are requiring the use of masks in our
facilities. Employees who may be exhibiting symptoms or who may have
been exposed to COVID-19 are required to contact a third-party medical
consultant engaged by the Company who follows protocols specifically
developed for COVID-19 to determine whether the employee should seek
medical attention, self-isolate or can safely return to work.
Our business continuity planning and investments in IT enabled an orderly
transition to remote work for approximately 50 percent of our employees.
For those employees who continue to report to our offices and service
centers, the reduced number of employees working in these locations
provides space for social distancing. We have implemented health
screenings at all of our employee work locations, which include a self-
assessment health screening application using mobile devices and
automated thermal temperature checks at our larger facilities. We routinely
disinfect employee work locations, placing emphasis on high-touch surfaces
in common areas. For employees who continue to interact with customers,
we are providing additional PPE in accordance with CDC and OSHA
guidelines.
In addition, we have implemented a Paid Pandemic Leave Policy, increased
medical benefits for COVID-19 testing and vaccination and are reminding
employees of our benefit plans and programs for their financial, physical
and mental health and well-being.
For customers requesting service orders, we have implemented protocols to
determine whether someone in the home has been exposed to COVID-19.
Employees entering customers’ homes are provided appropriate PPE in
accordance with CDC and OSHA guidelines to protect themselves and our
customers. Customers are also asked to provide for social distancing while
our employees are in the customer’s home.
As ordered by our regulators, customer disconnects for nonpayment were
suspended from mid-March through May 20, 2020, in Oklahoma, through
May 31, 2020, in Kansas, and through December 31, 2020, in some areas of
Texas. As of December 31, 2020, we have temporarily suspended
disconnects for safety reasons across all of our jurisdictions due to the level
of COVID-19 infection. Customers who are finding it difficult to pay their
bills are being encouraged to contact us so we can work with them to
establish alternative payment arrangements and advise them of public-
assistance programs that may be available.
Although we have experienced employee absences due to our protocols for
self-isolation of employees who may be exhibiting symptoms or who may
have been exposed to or contracted the COVID-19 virus, we have
continued, and expect to continue, to execute our work in the field,
including our capital work for system integrity, pipeline replacements and
extending service to new customers. Our work going forward could be
impacted if we do not have access to the PPE needed to keep our employees
and customers safe or experience a significant increase in employee and
contractor absences.
27
Supply Chain
Regulatory
Liquidity
We are actively managing the materials, supplies and contract services
necessary for our operations. We utilize a diverse group of suppliers and
contractors and are in frequent contact with our vendors to understand their
ability to continue to provide the materials, supplies and services we
require. To date, we have not experienced significant disruption to our
supply chain and have no indication of significant disruptions in the future.
Our suppliers and contractors could be impacted if they, or the businesses
they rely on, experience a significant increase in employee absences.
Our natural gas supply portfolio consists of contracts with varying terms
from a diverse group of suppliers. We acquire our natural gas supply from
natural gas processors, marketers and producers from multiple production
areas and lease capacity from third-party natural gas storage providers. 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.
To date, we have not experienced disruption to our natural gas supply and
we do not anticipate significant disruption in the future.
We are in regular communication with our regulators to keep them apprised
of the effects COVID-19 is having on the service we provide. We have
received accounting orders in each of our jurisdictions authorizing us to
accumulate and defer for regulatory purposes certain incremental costs
incurred, including bad debt expenses, and certain lost revenues, net of
offsetting expense reductions, associated with COVID-19.
In April 2020, we entered into the ONE Gas 364-day Credit Agreement in
the amount of $250 million, which provides us an additional source of
liquidity.
At December 31, 2020, we had short-term liquidity available through our
commercial paper program, credit facilities and cash on hand totaling
$538.6 million.
In April 2020, we issued $300 million of 2.00 percent senior notes due
2030. The proceeds from the issuance were used to reduce the amount of
our outstanding commercial paper and for general corporate purposes.
We believe our investment-grade credit ratings and strong balance sheet
will enable us to access sources of liquidity that are adequate to support our
current and planned level of operations.
During the year ended December 31, 2020, impacts on our results of operations as a result of COVID-19 include but are not
limited to:
•
•
•
lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of
disconnects for nonpayment in each of our rate jurisdictions;
incremental expenses for PPE, cleaning supplies, outside services and other expenses; and
lower expenses for travel and employee training that have been restricted due to the pandemic.
Going forward, we expect continuing impacts on our revenues and expenses during the course of the pandemic. We also could
experience a possible reduction in revenues from commercial and transportation customers temporarily or permanently
impacted by the pandemic. We have received accounting orders in each of our jurisdictions authorizing us to accumulate and
defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of
offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs
and lost revenue will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial
reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be
probable of recovery. At December 31, 2020, no regulatory assets have been recorded. We continue to evaluate the impacts of
COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed
probable. Accordingly, there could be a delay in the recognition of amounts that may be approved for recovery until the
conclusion of future regulatory proceedings.
28
See “Regulatory Activities,” “Financial Results and Operating Information,” “Capital Expenditures and Asset Removal Costs,”
Note 11 and Note 17 of the Notes to Consolidated Financial Statements and Item 1A, “Risk Factors” in this Annual Report for
additional discussion of the effects of COVID-19 on us.
At-the-Market Equity Program - In February 2020, we initiated a $250 million at-the-market equity program. Proceeds from the
program are available for general corporate purposes, which may include repaying or refinancing a portion of our outstanding
indebtedness and funding working capital and capital expenditures. See “Liquidity and Capital Resources” in this Annual
Report for additional discussion.
Dividend - In January 2021, we declared a dividend of $0.58 per share ($2.32 per share on an annualized basis) for shareholders
of record as of February 19, 2021, payable on March 5, 2021.
REGULATORY ACTIVITIES
Oklahoma - On February 12, 2021, the governor of Oklahoma declared a state of emergency for all 77 counties in the state of
Oklahoma in light of expected severe weather and freezing temperatures associated with a winter weather event. The
declaration cited anticipated damage to private and public properties and utilities, including electric, gas, and water systems,
within the state of Oklahoma.
On February 16, 2021, the Oklahoma Corporation Commission approved an Emergency Order (the “OCC Order”) (i) directing
natural gas and electric utilities to prioritize deliveries of natural gas and electricity for services necessary for life, health, and
public safety, and natural gas to electric generation facilities that serve human needs customers, and (ii) directing local utilities
to communicate with their customers in order to reduce all non-essential energy consumption, and to reduce load in a safe and
reasonable manner. The OCC Order recognized that the severe weather conditions resulted in increased commodity prices for
both gas and electric utilities, along with issues relating to commodity acquisition, line pressure, and supply shortages. The
OCC Order expired on February 20, 2021.
In order to reduce the impact on customers, on February 19, 2021, Oklahoma Natural Gas filed a motion with the Oklahoma
Corporation Commission to seek the authority to record a regulatory asset to account for the extraordinary costs, including costs
associated with gas purchases, other operational costs and carrying costs, associated with this winter weather event. These costs
will be subject to a review for reasonableness and accuracy in future regulatory proceedings. On February 25, 2021, an
administrative law judge recommended for approval by the OCC an interim order granting a motion to establish a regulatory
asset. The order states that Oklahoma Natural Gas shall defer to a regulatory asset the extraordinary costs associated with this
unprecedented winter weather event, including commodity costs incorporating escalated spot and daily index prices, operational
costs and carrying costs. The order identifies that decisions related to the recovery of the deferred costs will be addressed at a
later date. The recommendation from the administrative law judge will next be considered by the OCC.
In June 2020, the OCC issued an order permitting the creation of regulatory assets and deferrals related to COVID-19. Each
utility is authorized under the OCC’s order to record as a regulatory asset increased bad debt expenses, costs associated with
expanded payment plans, waived fees, and incremental expenses that are directly related to the suspension of or delay in
disconnection of service (or the reconnection of service) beginning March 15, 2020, as a result of the governor’s executive
order declaring a state of emergency. In addition, the OCC recognizes that utilities report taking many steps to ensure the
continuity of utility service, while protecting utility personnel, customers, and the general public. Such steps include procuring
additional PPE, increasing sanitation efforts at facilities, implementing health-screening processes, and securing temporary
facilities for potential sequestration of critical operations personnel. The OCC has stated it supports the continuation of these
critical response and planning efforts and acknowledges such efforts cause incremental costs that it will allow to be deferred
and reviewed in a future rate case. The OCC’s deferral authorization does not bind the OCC to any specific treatment of these
items in any future proceeding, nor does it prohibit the OCC from considering the effect of any operational savings, or other
financial impacts that may occur as a result of COVID-19. The recovery of the regulatory assets and deferrals will be addressed
in the next rate case that is required to be filed on or before June 30, 2021.
In February 2020, Oklahoma Natural Gas filed its fourth annual PBRC application following the general rate case that was
approved in January 2016. A settlement was reached, and the OCC approved a joint stipulation in July 2020. This stipulation
includes a base rate increase of $9.7 million and an energy efficiency incentive of $2.2 million, with new rates reflecting these
changes effective in June 2020. This stipulation also includes a credit of $12.2 million associated with EDIT to be issued
through a bill credit to Oklahoma customers in the first quarter 2021.
In March 2019, Oklahoma Natural Gas filed its third annual PBRC application following the general rate case that was
approved in January 2016. This filing was made in compliance with the January 2019 OCC order settling tax issues resulting
29
from the Tax Cuts and Jobs Act of 2017. A settlement was reached, and the OCC approved a joint stipulation in August 2019.
This stipulation includes a PBRC credit of $15.6 million to be spread over a 12-month period through a bill credit to Oklahoma
customers beginning in the third quarter 2019 and a credit of $12.7 million associated with EDIT.
In March 2018, Oklahoma Natural Gas filed its second annual PBRC application following the general rate case that was
approved in January 2016. This filing was based on a calendar test year of 2017 and addressed the tax issues resulting from the
Tax Cuts and Jobs Act of 2017. In January 2019, the OCC issued an order requiring Oklahoma Natural Gas to lower base rates
by $11.3 million beginning February 2019 to reflect the lower federal corporate income tax rate and the authorized ROE of 9.5
percent prospectively and to credit customers for EDIT based upon amortization periods in compliance with the tax
normalization rules for the portions of EDIT stipulated by the Code and ten years for all other components. This order also
required the March 15, 2019, PBRC filing to include the return of all earnings above 9.5 percent occurring in the 2018 test year.
As required, PBRC filings are made annually on or before March 15, until the next general rate case, which is currently
required to be filed on or before June 30, 2021, based on a calendar 2020 test year.
Kansas - On February 14, 2021, the governor of Kansas issued a State of Disaster Emergency due to wind chill warnings and
stress on utility and natural gas providers caused by the significantly colder than normal weather from a winter weather event.
The executive order also urged Kansas citizens to conserve energy to help ensure a continued supply of natural gas and
electricity and keep their own personal costs down. The declaration also noted that due to increased energy demand and natural
gas supply constraints caused by sub-zero temperatures, utilities at the time were experiencing wholesale natural gas prices
anywhere from 10 to 100 times higher than normal.
On February 15, 2021, the KCC issued an Emergency Order (i) directing all jurisdictional natural gas and electric utilities to
coordinate efforts and take all reasonably feasible, lawful, and appropriate actions to ensure adequate delivery of natural gas
and electricity to interconnected, non-jurisdictional utilities in Kansas, (ii) requiring jurisdictional natural gas and electric
utilities to do all things possible and necessary to ensure that natural gas and electricity utility services continue to be provided
to their customers in Kansas, and (iii) allowing those electric and natural gas distribution utilities who incur extraordinary costs
to ensure their customers and other interconnected customers continue to receive utility service during this unprecedented cold
weather event to defer those costs to a regulatory asset account. Once this weather event is over, each jurisdictional utility will
be required to file a compliance report detailing the extent of such costs incurred and present a plan to minimize the financial
impacts of this event on ratepayers over a reasonable time frame. These costs will be subject to review for reasonableness and
accuracy in future regulatory proceedings. Kansas Gas Service expects to file its compliance report in the first quarter of 2021.
In August 2020, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $7.8 million
related to its GSRS. This filing incorporates the effect on the requested GSRS rate increase of a bill amending the Kansas
income tax code that eliminates public utilities regulated by the KCC from paying Kansas state income taxes beginning January
1, 2021. In September 2020, Kansas Gas Service submitted an errata to the application which modified the requested increase to
approximately $7.5 million. In November 2020, the KCC approved the increase effective December 2020.
In May 2020, a bill amending the Kansas state income tax code was signed into law that exempts public utilities regulated by
the KCC from paying Kansas state income taxes beginning January 1, 2021, and authorizes the KCC to adjust utility rates for
the elimination of Kansas state income tax beginning January 1, 2021. As a result of the enactment of this legislation, we
remeasured our ADIT. As a regulated entity, the reduction in ADIT of $81.5 million was recorded as an EDIT regulatory
liability and will be refunded to our customers. This adjustment had no material impact on our income tax expense and no
impact on our cash flows for the year ended December 31, 2020. The bill stipulates that, if requested by the utility, this EDIT
will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next
general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates to
reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the
reduction, effective January 1, 2021. See Notes 11 and 15 of the Notes to Consolidated Financial Statements in this Annual
Report for additional information.
In April 2020, Kansas Gas Service filed an application with the KCC for an AAO to accumulate and defer certain incremental
costs incurred, including bad debt expenses and lost revenues, as well as associated carrying costs, related to COVID-19
beginning March 1, 2020, for recovery in Kansas Gas Service’s next rate case filing. In July 2020, the KCC approved the
request for an AAO subject to the recommendations set forth in its Staff Report and Recommendation and clarifications sought
by Kansas Gas Service. The AAO provides notice that Kansas Gas Service may identify, track, document, accumulate, and
defer in a regulatory asset extraordinary costs (net of any cost decreases) and lost revenue, plus carrying costs, associated with
the COVID-19 pandemic. The KCC states that approval of the AAO is not a finding that tracked costs and lost revenue will be
included in future rates; rather, any determination regarding recoverability will occur in a future rate proceeding. In a separate
30
order applicable to all regulated utilities, the KCC approved the deferral of bad debt expense and late payment fees associated
with the suspension of disconnection activity and customer protection provisions. The recovery, the carrying charges and
amortization period will be determined in Kansas Gas Service’s next rate case or alternative rate recovery filing.
In August 2019, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $4.2 million
related to its GSRS. In November 2019, the KCC approved the increase effective December 2019.
In November 2018, Kansas Gas Service submitted an application to the KCC requesting approval of its contract to own, operate
and maintain the natural gas distribution system at Fort Riley, a United States Army installation, for approximately $5.8
million. The KCC approved the Company’s application in May 2019 and Kansas Gas Service and Fort Riley began preparing
for the transition. In response to the COVID-19 pandemic, Kansas Gas Service entered into an agreement dated April 1, 2020,
with the U.S. government to stay the transition period and contract performance until concerns surrounding the COVID-19
pandemic are resolved. The 10-month transition period work officially started in June 2020, with the understanding that there
may be excusable delays in the future because of new state of Kansas requirements related to COVID-19 or changes in Fort
Riley’s health protection conditions. The duration of the stay and any future excusable delays will impact the timing of the asset
acquisition.
In June 2018, Kansas Gas Service filed a request with the KCC for an increase in base rates, reflecting investments in system
improvements and changes in operating costs necessary to maintain the safety and reliability of its natural gas distribution
system, as well as addressing the tax issues resulting from the Tax Cuts and Jobs Act of 2017. In February 2019, the KCC
issued an order that included a net base rate increase of $18.6 million and a GSRS pre-tax carrying charge of approximately 9.1
percent. Kansas Gas Service was already recovering $2.9 million from customers through the GSRS, therefore, this order
represents a total base rate increase of $21.5 million. The increase in base rates reflects an amortization credit for the refund of
EDIT over a period in compliance with the tax normalization rules for the portions stipulated by the Code and five years for all
other components of EDIT. Additionally, the settlement provides for extending application of the WNA rider to small
transportation customers and the implementation of a tracker for cybersecurity expenses.
In a separate order issued by the KCC, Kansas Gas Service was required to refund to customers the amount of the regulatory
liability for the decrease in the federal corporate income tax rate in 2018 through the date on which Kansas Gas Service’s new
rates went into effect in February 2019. The total refund of $16.6 million was issued through a bill credit to Kansas customers
in the second quarter 2019.
In April 2018, a bill amending the GSRS statute was approved. Beginning January 1, 2019, the scope of projects eligible for
recovery under the statute includes safety-related investments to replace, upgrade or modernize obsolete facilities, as well as
projects that enhance the integrity of pipeline system components or extend the useful life of such assets. Safety-related
investments also include expenditures for physical and cyber security. Additionally, the cap on the monthly residential
surcharge increased to $0.80 from $0.40.
Texas - On February 12, 2021, the governor of Texas declared a state of disaster for all 254 counties in Texas in response to the
then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to
prolonged freezing temperatures, heavy snow, and freezing rain statewide.
Also, on February 12, 2021, the RRC issued an Emergency Order to temporarily implement a statewide utilities curtailment
program intended to protect residences, hospitals, schools, churches, and other human needs customers. On February 17, 2021,
the RRC extended its Emergency Order issued on February 12, 2021, to February 23, 2021.
On February 13, 2021, the RRC issued a Notice to Local Distribution Companies that acknowledged that, due to the demand
for natural gas during this winter weather event, natural gas utility LDCs may be required to pay extraordinarily high prices in
the market for natural gas and may be subjected to other extraordinary costs when responding to the event. The RRC also
encouraged natural gas utilities to continue to work to ensure that the citizens of the State of Texas are provided with safe and
reliable natural gas service. To partially defer and reduce the impact on customers for these costs that ultimately are reflected in
customer bills, the RRC authorized LDCs to record a regulatory asset to account for the extraordinary costs associated with this
winter weather event, including but not limited to gas cost and other costs related to the procurement and transportation of gas
supply. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings.
In April 2020, the RRC issued an order authorizing utilities to use a regulatory accounting mechanism and a subsequent process
through which Texas Gas Service may seek future recovery of incremental expenses resulting from the effects of COVID-19,
including bad debt and associated credit and collections costs, waived fees and other reasonable and necessary incremental
costs to address the impact of COVID-19. The timing of any recovery will be determined as we work with our regulators.
31
West Texas Service Area - In March 2020, Texas Gas Service made GRIP filings for all customers in the West Texas service
area. In June 2020, the RRC and the cities in the West Texas service area agreed to an increase of $4.7 million, and new rates
became effective in June 2020.
In March 2019, Texas Gas Service made GRIP filings for all customers in the West Texas service area. In June 2019, the RRC
and the cities in the West Texas service area agreed to an increase of $4.1 million, and new rates became effective in July 2019.
In March 2018, Texas Gas Service made GRIP filings for all customers in the West Texas service area. In June 2018, the RRC
and the cities in the West Texas service area agreed to an increase of $3.5 million, and new rates became effective in July 2018.
Central-Gulf Service Area - In February 2021, Texas Gas Service made GRIP filings for all customers in the Central-Gulf
service area, requesting an increase of $10.7 million to be effective in the third quarter of 2021.
In 2019, Texas Gas Service filed a rate case for all customers in the Central Texas and Gulf Coast service areas, seeking a rate
increase of $15.6 million and a $1.3 million credit to customers associated with EDIT, and requesting to consolidate the two
service areas into one. In August 2020, the RRC approved all terms of a settlement, including a $10.3 million increase in base
rates, as well as consolidation of the Central Texas service area and the Gulf Coast service area into a new Central-Gulf service
area. The RRC also approved an $8.5 million credit to customers associated with EDIT. The settlement included an ROE of
9.5 percent and a capital structure with equity of 59 percent and debt of 41 percent, and new rates became effective in August
2020.
In March 2019, Texas Gas Service made GRIP filings for all customers in the Central Texas service area. In June 2019, the
RRC and the cities in the Central Texas service area agreed to an increase of $5.5 million, and new rates became effective in
June 2019.
In March 2018, Texas Gas Service made GRIP filings for all customers in the Central Texas service area. In June 2018, the
RRC and the cities in the Central Texas service area agreed to an increase of $3.3 million, and new rates became effective in
July 2018.
Other Texas Service Areas - In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and
COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. Annual rate
increases associated with these filings that were approved totaled $1.8 million, $1.9 million and $1.6 million for the years ended
December 31, 2020, 2019, and 2018, respectively.
In 2018, Texas Gas Service requested a total of $11.1 million of decreases to rates for customers in its service areas due to the
reduction of the federal corporate income tax rate, and one-time refunds totaling $6.6 million for the reduction in the federal
corporate income tax rate for the period between January 1, 2018, to the dates new rates were implemented. The requests for the
decreases in rates and the one-time refunds were approved and new rates, where applicable, became effective in the second half
of 2018. Four service areas in Texas have authorized EDIT to be credited to customers annually. The timing of the return of
EDIT to customers in our remaining service area in Texas will be determined as we work with our regulators.
EDIT - The treatment of EDIT by our regulators is not expected to have a material impact on earnings, as any reduction or
credit in rates is offset by a reduction in income tax expense, which includes the amortization of the regulatory liability as a
credit in income tax expense. During the years ended December 31, 2020 and 2019, we credited income tax expense
$17.4 million and $12.8 million, respectively, for the amortization of the regulatory liability associated with EDIT that was
returned to customers. No amortization of the regulatory liability associated with EDIT returned to customers was recorded in
2018. See “Liquidity and Capital Resources - Tax Reform” and Note 15 of the Notes to Consolidated Financial Statements for
additional discussion of the Tax Cuts and Jobs Act of 2017.
OTHER
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 write-off of
regulatory assets and stranded costs may be required. There were no write-offs of regulatory assets resulting from the failure to
meet the criteria for capitalization during 2020, 2019 or 2018.
32
FINANCIAL RESULTS AND OPERATING INFORMATION
Selected Financial Results - Net income was $196.4 million, or $3.68 per diluted share, $186.7 million, or $3.51 per diluted
share, and $172.2 million, or $3.25 per diluted share, for the years ended December 31, 2020, 2019 and 2018, respectively. We
operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial and
transportation customers. We evaluate our financial performance principally on net income.
The following table sets forth certain selected financial results for our operations for the periods indicated:
Financial Results
Natural gas sales
Transportation revenues
Other revenues
Total revenues
Cost of natural gas
Net margin
Operating costs
Depreciation and amortization
Operating income
Net income
Capital expenditures and asset removal costs
Years Ended December 31,
2019
2018
2020
Variances
2020 vs. 2019
Increase (Decrease)
Variances
2019 vs. 2018
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
$
$
1,389.2
114.1
27.0
1,530.3
537.4
992.9
494.5
194.9
303.5
196.4
512.2
$
$
$
$
1,508.1
114.1
30.5
1,652.7
687.9
964.8
489.1
180.4
295.3
186.7
465.1
$
$
$
$
1,492.4
109.7
31.6
1,633.7
714.6
919.1
470.6
160.1
288.4
172.2
447.4
$
$
$
$
(118.9)
—
(3.5)
(122.4)
(150.5)
28.1
5.4
14.5
8.2
9.7
47.1
(8)% $
— %
(11)%
(7)%
(22)%
3 %
1 %
8 %
3 % $
5 % $
10 % $
15.7
4.4
(1.1)
19.0
(26.7)
45.7
18.5
20.3
6.9
14.5
17.7
1 %
4 %
(3)%
1 %
(4)%
5 %
4 %
13 %
2 %
8 %
4 %
Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our
tariffs and rates approved by the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas
sales, which are included as other revenues in our Notes to Consolidated Financial Statements.
Transportation revenues represent revenue from contracts with customers through implied contracts established by our tariffs
and rates approved by the regulatory authorities, as well as tariff-based negotiated contracts.
Other utility revenues include primarily miscellaneous service charges which represent implied contracts with customers
established by our tariffs and rates approved by the regulatory authorities and other revenues from regulatory mechanisms,
which are included in the consolidated statements of income and our Notes to Consolidated Financial Statements as other
revenues.
Non-GAAP Financial Measure - We have disclosed net margin, which is considered a non-GAAP financial measure, in our
selected financial data and selected financial results. Net margin is comprised of total revenues less cost of natural gas. Cost of
natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost
of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and
amortization. In addition, these regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis
without a profit. Therefore, although our revenues will fluctuate with the cost of natural gas that we pass-through to our
customers, net margin is not affected by fluctuations in the cost of natural gas. Accordingly, we routinely use net margin in the
analysis of our financial performance. We believe that net margin provides investors a more relevant and useful measure to
analyze our financial performance as a 100 percent regulated natural gas utility than total revenues because the change in the
cost of natural gas from period to period does not impact our operating income. As such, the following discussion and analysis
of our financial performance will reference net margin rather than total revenues and cost of natural gas individually.
33
The following table sets forth reconciliation of net margin to the most directly comparable GAAP measure for the periods
indicated:
Years Ended December 31,
2020 vs. 2019
Variances
Variances
2019 vs. 2018
Non-GAAP Reconciliation
2020
2019
2018
Increase (Decrease)
Increase (Decrease)
Total revenues
Cost of natural gas
Net margin
(Millions of dollars, except percentages)
$ 1,530.3
$ 1,652.7
$ 1,633.7
$
(122.4)
(7)% $
19.0
537.4
687.9
714.6
(150.5)
(22)%
(26.7)
$
992.9
$
964.8
$
919.1
$
28.1
3 % $
45.7
1 %
(4)%
5 %
The following table sets forth our net margin by type of customer for the periods indicated:
Net Margin
Natural gas sales
Residential
Commercial and industrial
Other
Net margin on natural gas sales
Transportation revenues
Other revenues
Net margin
Years Ended December 31,
2019
2018
2020
Variances
2020 vs. 2019
Increase (Decrease)
Variances
2019 vs. 2018
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
711.1
132.8
7.9
851.8
114.1
27.0
992.9
$
$
681.0
131.5
7.7
820.2
114.1
30.5
964.8
$
$
644.1
127.1
6.6
777.8
109.7
31.6
919.1
$
$
30.1
1.3
0.2
31.6
—
(3.5)
28.1
4 % $
1 %
3 %
4 %
— %
(11)%
3 % $
36.9
4.4
1.1
42.4
4.4
(1.1)
45.7
6 %
3 %
17 %
5 %
4 %
(3)%
5 %
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 and the effects of weather normalization. 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,
2019
2018
2020
Variances
2020 vs. 2019
Increase (Decrease)
Variances
2019 vs. 2018
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
610.3
241.5
851.8
$
$
590.2
230.0
820.2
$
$
553.9
223.9
777.8
$
$
20.1
11.5
31.6
3 % $
5 %
4 % $
36.3
6.1
42.4
7 %
3 %
5 %
2020 vs. 2019 - Net margin increased $28.1 million due primarily to the following:
•
•
•
•
•
•
•
an increase of $23.1 million from new rates;
an increase of $10.1 million in residential sales due primarily to net customer growth;
an increase of $2.1 million in rider and surcharge recoveries due to a higher ad-valorem surcharge in Kansas, which
was offset with higher regulatory amortization expense in depreciation and amortization expense; and
an increase of $1.3 million due to the beneficial impact of a retroactive CNG federal excise tax credit, offset partially
by:
a decrease of $4.3 million due to lower fees associated with collection activities and late payments primarily related to
the suspensions of disconnects for nonpayment in response to the COVID-19 pandemic in each of our rate
jurisdictions;
a decrease of $2.8 million due to lower transport volumes primarily in Kansas; and
a decrease of $0.9 million due to lower sales volumes, net of weather normalization, primarily in Kansas and
Oklahoma from warmer weather in 2020 compared with the same period in 2019. For 2020, heating degree days in
Oklahoma and Kansas were 12% and 11% lower, respectively, compared with 2019.
34
Operating costs increased $5.4 million due primarily to the following:
•
•
•
•
•
•
•
•
an increase of $6.4 million in expenses related to our response to the COVID-19 pandemic;
an increase of $5.4 million in bad debt expense;
an increase of $2.6 million in ad-valorem taxes; and
an increase of $2.1 million in insurance expense, offset partially by:
a decrease of $4.8 million in expenses for travel and employee training that have been impacted by the COVID-19
pandemic;
a decrease of $3.3 million in legal-related costs;
a decrease of $1.4 million in materials for pipeline repair and maintenance activities; and
a decrease of $1.0 million in outside service costs.
The portion of the decrease in late payment, reconnect and collection fees resulting from the suspension of disconnects for
nonpayment in response to the COVID-19 pandemic and increased bad debt expense and the net incremental expenses related
to the COVID-19 pandemic are eligible for future recovery under the regulatory orders we have received in each of our
jurisdictions. For financial reporting purposes, the amounts deferred as a regulatory asset for future recovery under the
accounting orders must be probable of recovery. At December 31, 2020, no regulatory assets have been recorded. We continue
to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial statement purposes at such
time as recovery is deemed probable.
Depreciation and amortization expense increased $14.5 million due primarily to an increase in depreciation from our capital
expenditures being placed in service and an increase in amortization of the ad-valorem surcharge rider in Kansas.
Other Factors Affecting Net Income - Other factors that affect net income include a $1.3 million decrease, compared with 2019,
in income tax expense due to a higher credit to income tax expense from the amortization of EDIT of $4.6 million, offset
partially by the increase in income before income taxes.
EDIT - The return of EDIT to our customers is not expected to have a material impact on earnings, as any reduction or credit in
rates is offset by a reduction in income tax expense. During the years ended December 31, 2020 and 2019, we credited income
tax expense $17.4 million and $12.8 million, respectively, for the amortization of the regulatory liability associated with EDIT
that was returned to customers. No amortization of the regulatory liability associated with EDIT returned to customers was
recorded in 2018. See “Liquidity and Capital Resources” and Note 11 of the Notes to Consolidated Financial Statements for
additional discussion of the Tax Cuts and Jobs Act of 2017.
Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity,
extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements,
automated meter reading, government-mandated pipeline relocations, fleet, facilities, IT assets and cybersecurity. It is our
practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations. Asset
removal costs include expenditures associated with the replacement or retirement of long-lived assets that result from the
construction, development and/or normal use of our assets, primarily our pipeline assets.
Capital expenditures and asset removal costs increased $47.1 million for 2020, compared with 2019, due primarily to increased
system integrity activities, extension of service to new areas and higher government relocation activities. Our capital
expenditures and asset removal costs are expected to be approximately $540 million for 2021, although the amount and timing
of these expenditures could be impacted by the COVID-19 pandemic. While we have not experienced a significant impact to
our capital expenditures program for the year ended December 31, 2020, our capital activity for 2021 could experience a delay
if conditions associated with COVID-19 worsen, impacting employee absences, or our supply chain for contract labor,
materials and supplies, which may cause us to suspend or curtail certain business operations for an indefinite period.
35
Selected Operating Information - The following tables set forth certain selected operating information for the periods
indicated:
(in thousands)
2020
2019
Increase (Decrease)
Average Number of Customers
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Years Ended
December 31,
Variances
2020 vs. 2019
Residential
814
589
Commercial and industrial
Other
Transportation
Total customers
75
—
6
50
—
6
641
35
3
1
2,044
160
3
13
804
584
74
—
6
50
—
6
631
35
3
1
2,019
159
3
13
895
645
680
2,220
884
640
670
2,194
10
1
—
—
11
5
—
—
—
5
10
—
—
—
10
25
1
—
—
26
(in thousands)
2019
2018
Increase (Decrease)
Average Number of Customers
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Years Ended
December 31,
Variances
2019 vs. 2018
Residential
804
584
Commercial and industrial
Other
Transportation
Total customers
74
—
6
50
—
6
631
35
3
1
2,019
159
3
13
798
583
74
—
5
50
—
6
624
35
3
1
2,005
159
3
12
884
640
670
2,194
877
639
663
2,179
6
—
—
1
7
1
—
—
—
1
7
—
—
—
7
14
—
—
1
15
The increase in the average number of customers for 2020, compared with 2019, is due primarily to the connection of new
customers resulting from the extension and expansion of our system in our service areas. For 2020, our average customer count
includes 26,400 new customer connections compared to 22,300 in 2019. Also contributing to the increase is a reduction in
disconnects for nonpayment by our customers as a result of suspensions of collection activities in response to the COVID-19
pandemic.
The following table reflects the total volumes delivered, excluding the effects of WNA mechanisms on sales volumes:
Volumes (MMcf)
Natural gas sales
Residential
Commercial and industrial
Other
Total sales volumes delivered
Transportation
Total volumes delivered
Years Ended December 31,
2019
2018
2020
121,967
36,169
2,427
160,563
224,531
385,094
128,723
40,690
2,688
172,101
224,304
396,405
128,393
40,743
2,505
171,641
220,884
392,525
Total volumes delivered decreased for 2020, compared with 2019, due primarily to warmer weather in the fourth quarter 2020.
The impact of weather on residential and commercial net margin is mitigated by WNA mechanisms in all jurisdictions.
36
The following table sets forth the HDD’s by state for the periods indicated:
Years Ended
December 31,
2020
2019
Actual
Normal
Actual
Normal
2020 vs.
2019
Actual
Variance
2020
2019
Actual as a percent of
Normal
3,253
4,408
1,580
3,264
4,722
1,779
3,716
4,971
1,803
3,264
4,791
1,773
(12)%
(11)%
(12)%
100 %
93 %
89 %
114 %
104 %
102 %
Years Ended
December 31,
2019
2018
Actual
Normal
Actual
Normal
2019 vs.
2018
Actual
Variance
2019
2018
Actual as a percent of
Normal
3,716
4,971
1,803
3,264
4,791
1,773
3,771
5,012
1,738
3,263
4,914
1,782
(1)%
(1)%
4 %
114 %
104 %
102 %
116 %
102 %
98 %
HDDs
Oklahoma
Kansas
Texas
HDDs
Oklahoma
Kansas
Texas
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:
•
•
•
Oklahoma - For years 2016-2020, 10-year weighted average HDDs as of December 31, 2014, as calculated using 11
weather stations across Oklahoma and weighted on average customer count.
Kansas - For April 2019 and forward, a 30-year rolling average for years 1988-2017 calculated using three weather
stations across Kansas and weighted on HDDs by weather station and customers. For 2017 to March 2019, 30-year
average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using
four weather stations across Kansas and weighted on HDDs by weather station and customers.
Texas - An average of HDDs authorized in our most recent rate proceeding in each service area and weighted using a
rolling 10-year average of actual natural gas distribution sales volumes by service area.
Actual HDDs are based on year-to-date, weighted average of:
•
•
•
11 weather stations and customers by month for Oklahoma;
3 weather stations and customers by month for Kansas; and
9 weather stations and natural gas distribution sales volumes by service area for Texas.
Selected financial results and operating information for 2019, compared with 2018, is described in Part II, Item 7
"Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-
K for the year ended December 31, 2019.
CONTINGENCIES
We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results
of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters,
individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not
have a material adverse effect on our results of operations, financial position or cash flows. See Note 17 of the Notes to
Consolidated Financial Statements in this Annual Report for information with respect to legal proceedings.
37
LIQUIDITY AND CAPITAL RESOURCES
General - We have relied primarily on operating cash flow and commercial paper for our liquidity and capital resource
requirements. We fund operating expenses, working capital requirements, including purchases of natural gas, and capital
expenditures primarily with cash from operations and commercial paper.
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 rate mechanisms that we have in place result in a stable cash flow profile and
historically has generated stable earnings. Additionally, we have rate mechanisms in place in our jurisdictions that reduce the
lag in earning a return on our capital expenditures and provide for recovery of certain changes in our cost of service by allowing
for adjustments to rates between rate cases. 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, our
financial condition and credit ratings. By maintaining a conservative financial profile and stable revenue base, we expect to
maintain credit ratings at a level that supports our access to diverse sources of capital at favorable rates for capital investments
and expenses.
Short-term Financing - In October 2019, we exercised a one-year extension of the ONE Gas Credit Agreement and amended
the agreement to provide that we may extend the maturity date by one year, subject to the lenders’ consent, two additional
times. The ONE Gas Credit Agreement remains a $700 million revolving unsecured credit facility and includes a $20 million
letter of credit subfacility and a $60 million swingline subfacility. We are able to request an increase in commitments of up to
an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new
lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2024, and is
available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit
and for other general corporate purposes.
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. The ONE Gas
Credit Agreement also 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, 2020, our total debt-to-
capital ratio was 47 percent, and we were in compliance with all covenants under the ONE Gas Credit Agreement.
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.
In April 2020, we entered into the ONE Gas 364-day Credit Agreement. The ONE Gas 364-day Credit Agreement is a
$250 million revolving unsecured credit facility containing various customary conditions to borrowing and affirmative,
negative and financial ratio maintenance covenants, all of which are substantially the same as those of the ONE Gas
Credit Agreement. The ONE Gas 364-day Credit Agreement also contains provisions for an applicable margin rate and a
quarterly 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 115 basis points, and the quarterly facility fee is 10 basis points.
Both the ONE Gas Credit Agreement and the ONE Gas 364-day Credit Agreement utilize LIBOR as the reference rate for
determining interest to accrue on borrowings under the respective agreements. In the event LIBOR is not available, and such
circumstances are unlikely to be temporary, our lenders for each respective agreement may establish an alternative interest rate
for the impacted loans by replacing LIBOR with one or more secured overnight financing-based rates or another alternate
benchmark rate.
At December 31, 2020, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement
or the ONE Gas 364-day Credit Agreement, with $948.8 million of combined remaining credit available to repay our
commercial paper borrowings.
38
We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of
$700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary, but may not exceed
270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest
factor. At December 31, 2020, we had $418.2 million of commercial paper outstanding.
Long-Term Debt - On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility to enhance our liquidity
position as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as
a result of the 2021 winter weather event and the repayment of indebtedness.
The ONE Gas 2021 Term Loan Facility provides for a $2.5 billion unsecured term loan facility. Proceeds of the loans under the
ONE Gas 2021 Term Loan Facility will be available for natural gas purchases as a result of the 2021 winter weather event and
the repayment of indebtedness. The ONE Gas 2021 Term Loan Facility matures two years after the loans are funded under the
ONE Gas 2021 Term Loan Facility. The loans under the ONE Gas 2021 Term Loan Facility will bear interest at a “Eurodollar
Rate” or a “Base Rate” as specified in the ONE Gas 2021 Term Loan Facility, plus a margin specified in the ONE Gas 2021
Term Loan Facility which adjusts based on our debt ratings and the outstanding amount of loans remaining under the ONE Gas
2021 Term Loan Facility. Outstanding loans or commitments under the ONE Gas 2021 Term Loan Facility are required to be
prepaid or reduced, as applicable, with the net cash proceeds received by ONE Gas or any of its subsidiaries from certain debt
and equity issuances.
The ONE Gas 2021 Term Loan Facility contains customary conditions to borrowing, and customary affirmative and negative
covenants, including a financial ratio maintenance covenant requiring us to maintain a total debt-to-capital ratio of no more than
72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent at the end of any calendar quarter
thereafter. The ONE Gas 2021 Term Loan Facility also contains various customary events of default, the occurrence of which
could result in a termination of the lenders’ commitments and the acceleration of all of our obligations thereunder.
In April 2020, ONE Gas issued $300 million of 2.00 percent senior notes due 2030. The proceeds from the issuance were used
to reduce the amount of outstanding commercial paper and for general corporate purposes.
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.
Depending on the series, we may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date,
starting three months or six months 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
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.
At December 31, 2020, our long-term debt-to-capital ratio was 41 percent.
Credit Ratings - Our credit ratings as of December 31, 2020, were:
Rating Agency
Moody’s
S&P
Rating
A2
A
Outlook
Stable
Stable
Our commercial paper was rated Prime-1 by Moody’s and A-1 by S&P as of December 31, 2020.
On February 23, 2021, our credit ratings changed as follows:
Rating Agency
Moody’s
S&P
Rating
A3
BBB+
Outlook
Negative
Negative
Also on February 23, 2021, the ratings on our commercial paper changed to Prime-2 by Moody’s and A-2 by S&P.
39
We intend to maintain credit metrics at a level that supports our 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.
At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity
distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to
$250 million. Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions
or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the
program. At December 31, 2020, we had issued and sold 179,514 shares of our common stock for $13.6 million, generating
proceeds, net of issuance costs, of $13.5 million, and had $236.4 million of equity available for issuance under the program.
Proceeds from the program are available for general corporate purposes, which may include repaying or refinancing a portion
of our outstanding indebtedness and funding working capital and capital expenditures.
Tax Reform - We have addressed the regulatory liability for EDIT resulting from the Tax Cuts and Jobs Act of 2017 in each of
our jurisdictions. Our regulatory liability for income tax rate changes represents deferral of the effects of enacted federal and
state income tax rate changes on our ADIT and other regulatory liabilities resulting from the effect of the changes in income
taxes on our rates.
In May 2020, a bill amending the Kansas state income tax code was signed into law that exempts public utilities regulated by
the KCC from paying Kansas state income taxes beginning January 1, 2021. As a result of the enactment of this legislation, we
remeasured our ADIT. As a regulated entity, the reduction in ADIT of $81.5 million was recorded as an EDIT regulatory
liability and will be refunded to our customers. This adjustment had no material impact on our income tax expense and no
impact on our cash flows for the year ended December 31, 2020. The bill stipulates that, if requested by the utility, this EDIT
will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next
general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates to
reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the
reduction, effective January 1, 2021.
Cash flows for years ended December 31, 2020 and 2019 were reduced by approximately $17.4 million and $12.8 million,
respectively, for EDIT returned to customers. No amortization of the regulatory liability associated with EDIT returned to
customers was recorded in 2018.
Pension and Other Postemployment Benefit Plans - We did not make any material contributions to our defined benefit
pension plan or other postemployment plans in 2020. During 2019, we contributed $29.2 million to our defined benefit pension
plan and $6.2 million to our other postemployment benefit plans. Information about our pension and other postemployment
benefits plans, including anticipated contributions, is included under Note 14 of the Notes to Consolidated Financial Statements
in this Annual Report.
CASH FLOW ANALYSIS
We use the indirect method to prepare our consolidated 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.
40
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,
Variances
2020
2019
2018
2020 vs. 2019
2019 vs. 2018
(Millions of dollars)
$
$
364.5
(470.4)
96.0
(9.9)
17.9
8.0
$
$
310.4
(422.9)
109.1
(3.4)
21.3
17.9
$
$
467.7
(394.5)
(66.3)
6.9
14.4
21.3
$
$
54.1 $
(47.5)
(13.1)
(6.5)
(3.4)
(9.9) $
(157.3)
(28.4)
175.4
(10.3)
6.9
(3.4)
Operating Cash Flows - Changes in cash flows from operating activities are due primarily to changes in net margin and
operating expenses discussed in Financial Results and Operating Information, the effects of tax reform discussed in Regulatory
Activities and changes in working capital. Changes in natural gas prices and demand for our services or natural gas, whether
because of general economic conditions, variations in weather not mitigated by WNAs, 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.
2020 vs. 2019 - Cash flows from operating activities were higher in 2020 compared with 2019, due primarily to working capital
changes resulting from the timing of payments for natural gas purchases.
Investing Cash Flows - 2020 vs. 2019 - Cash used in investing activities increased for 2020, compared to 2019, due primarily
to capital expenditures for increased system integrity activities and extending service to new areas.
Financing Cash Flows - 2020 vs. 2019 - Cash provided by financing activities for 2020 decreased, compared with 2019, due
primarily to proceeds from issuance of long-term debt, offset by larger repayments on notes payable.
2019 vs. 2018 - Cash flows in 2019, compared with 2018, are described in Part II, Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December
31, 2019.
ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS
COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have
implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and
communities. As ordered by our regulators, customer disconnects for nonpayment were suspended from mid-March through
May 20, 2020, in Oklahoma, through May 31, 2020, in Kansas, and through December 31, 2020, in some areas of Texas. As of
December 31, 2020, we have temporarily suspended disconnects for safety reasons in all of our jurisdictions due to the level of
COVID-19 infection. Since the onset of the pandemic in the first quarter of 2020, we have experienced impacts on our results
of operations including, but not limited to: lower late payment, reconnect and collection fees and incremental expenses for bad
debts related to the suspensions of disconnects for nonpayment; incremental expenses for PPE, cleaning supplies, outside
services and other expenses; and lower expenses for travel and employee training that have been impacted by the pandemic. We
have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes
certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions
associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be
determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any
amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At
December 31, 2020, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our
business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable. Going
forward, we expect continuing impacts on our revenues and expenses during the course of the pandemic. We also could
experience a possible reduction in revenues from commercial and transportation customers temporarily or permanently
impacted by the pandemic.
41
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 or the discovery of presently unknown
environmental conditions 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 and results of operations. Our expenditures for environmental
investigation, and remediation 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 2020, 2019, or 2018.
We own or retain legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. These sites
contain contaminants generally associated with MGP sites and are subject to control or remediation under various
environmental laws and regulations. A consent agreement with the KDHE governs all environmental investigation and
remediation work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation
activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of
contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. Regulatory
closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result
in additional costs.
We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and
remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net
of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-
year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a
determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of
any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to
increase the $15.0 million cap. At December 31, 2020 and 2019, we have deferred $18.8 million and $9.8 million, respectively,
for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon
as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2021.
We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor
groundwater at eight of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a
source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had
previously occurred. A remediation plan was submitted to the KDHE concerning this site in 2020 and the KDHE has provided
comments that we are addressing. We are also working on a remediation plan that will be submitted to the KDHE in 2021 for
an additional site.
As a result of our work to investigate and remediate the environmental impacts of our MGP sites in 2020, we estimated the
potential costs associated with additional investigation and remediation to be in the range of $9.1 million to $23.3 million. A
single reliable estimate of the remediation costs for these sites was not feasible due to the amount of uncertainty in the ultimate
remediation approach that will be utilized. Accordingly, in 2020, we recorded an adjustment to our reserve of $9.1 million,
which also increased our regulatory asset pursuant to our AAO in Kansas, as we believe recovery of these costs is probable
through our existing AAO or future regulatory filings. At December 31, 2020 and 2019, the reserve for remediation of our
MGP sites was $14.5 million and $5.8 million, respectively.
We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of
the Texas Commission on Environmental Quality, we began investigating the level and extent of contamination associated with
the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants
generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations.
Until the investigation is complete, we are unable to determine what, if any, active remediation will be required. A reliable
estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to the levels and extent of
contamination.
42
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 2020, 2019 or 2018.
We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding
the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such
laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation
and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase
in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and
those costs may adversely affect our financial condition, results of operations and cash flows. We do not expect expenditures
for these matters to have a material adverse effect on our financial condition, results of operations or cash flows.
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations
require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline
segments that pass through densely populated areas or near specifically designated HCAs. 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
HCAs;
a verification of records for pipelines in class 3 and 4 locations and HCAs to confirm MAOPs; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in HCAs.
In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to
revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals
included changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment
period ended July 7, 2016, and comments were reviewed by PHMSA. As part of the comment review process, PHMSA was
advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily
mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews
PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality
of each proposal. The GPAC met six times since January 2017 to review public comments and make recommendations to
PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering pipelines. The GPAC
met in June 2019 on gas gathering pipelines. In addition to reviewing public and committee comments, PHMSA announced
they would split this NPRM into three separate final rulemakings:
•
•
•
the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation
Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment
Requirements, and Other Related Amendments;
the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management
Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all
remaining elements of the NPRM (except for gas gathering pipelines); and
the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.
A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations
filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas
transmission and gathering pipelines.
On October 1, 2019, PHMSA published the first of the three final rules referenced above, which addressed the 2011
congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to
collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline,
and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP
within 15 years. The first final rule became effective July 1, 2020. The estimated capital and operating expenditures associated
with compliance with the first final rule were not material.
PHMSA has not yet issued the second final rule. The potential capital and operating expenditures associated with compliance
with this rule are currently being evaluated and could be significant depending on the final regulations. We do not expect to be
impacted by the third final rule, as we do not own gas gathering pipelines.
43
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.
International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to regulate greenhouse gas
emissions. We monitor relevant legislation and regulatory initiatives 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 for natural gas distribution that assesses any costs, fees or
expenses on any of these emissions.
CERCLA - 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 U.S. Department of Homeland Security’s Transportation Security Administration issued updated
pipeline security guidelines in March 2018. 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 integrity of our pipelines; (3) following
developing technologies for emission control; (4) promoting end-use conservation through programs that incentivize the use of
high-efficiency equipment; and (5) reducing the loss of methane from our facilities. In addition, RNG and hydrogen
technologies offer potential opportunities to secure new natural gas supply sources that could be transported on our pipeline
system and reduce greenhouse gas emissions.
We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on
maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the
release of natural gas during pipeline and facility maintenance and operations. Additionally, in March 2016, we were one of 40
founding partners to launch the EPA’s Natural Gas STAR Methane Challenge Program, whereby oil and natural gas companies
agree to promote and track commitments to reduce methane emissions beyond what is federally required. Our Methane
Challenge Program commitment to annually replace or rehabilitate at least two percent of our combined inventory of cast iron
and noncathodically-protected steel pipe aligns with our planned system integrity expenditures for infrastructure replacements.
We exceeded our goal by achieving an overall replacement rate greater than two percent annually in 2016, 2017, 2018, and
2019 and anticipate reporting on our 2020 progress in 2021.
In September 2020, we announced membership in Our Nation’s Energy Future (ONE Future), a group of natural gas companies
working together to voluntarily reduce methane emissions across the natural gas value chain to one percent or less by 2025. In
its most recent report, ONE Future reported that its members registered a 2019 methane intensity of 0.334%.
Additional information about our environmental matters is included in the section entitled Environmental Matters in Note 17 of
the Notes to Consolidated Financial Statements in this Annual Report. We cannot assure that existing environmental statutes
and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional
regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on
our business, financial condition and results of operations. Our expenditures for environmental investigation, and remediation
44
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 2020, 2019, or 2018.
Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional
information regarding our regulatory initiatives in “Regulatory Activities” in Management’s Discussion and Analysis of
Financial Condition and Results of Operations.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of new accounting standards is included in Note 1 of the Notes to Consolidated Financial
Statements in this Annual Report.
ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The preparation of our consolidated 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 consolidated financial
statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting
period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates. See
our Risk Factors and/or Forward-Looking Statements for factors which could impact our estimates.
The following summary sets forth what we consider to be our most critical estimates and accounting policies. Our critical
accounting policies are defined as those estimates and policies most important to the portrayal of our financial condition and
results of operations and that require management’s most difficult, subjective or complex judgment, particularly because of the
need to make estimates concerning the impact of inherently uncertain matters.
Regulation - Our operations are subject to regulation with respect to rates, service, maintenance of accounting records and
various other matters by the respective regulatory authorities in the states in which we operate. We account for the financial
effects of the ratemaking and accounting practices and policies of the various regulatory commissions in our consolidated
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
returned 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 11 of the Notes to Consolidated Financial Statements in this
Annual Report.
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. 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. The accrued unbilled natural gas sales revenue at December 31, 2020 and 2019 was $144.9 million and $109.7 million,
respectively, and is included in accounts receivable on our Consolidated Balance Sheets.
We adopted ASC 606 which clarifies the revenue recognition principles under GAAP for our interim and annual reports
beginning in the first quarter 2018, using the modified retrospective method. We evaluated all of our sources of revenue to
determine the potential effect of the new standard on our financial position, results of operations, cash flows and the related
accounting policies and business processes. Upon adoption, there was no cumulative adjustment to our opening retained
earnings. The only impact of adopting ASC 606 is that we reclassified certain revenues that do not meet the requirements under
ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total
revenue. The items we reclassified relate primarily to the WNA mechanism in Kansas, where the KCC determines how we
reflect variations in weather in our rates billed to customers.
45
We have determined the majority of our natural gas sales and transportation tariffs to be implied contracts with customers,
which are settled over time, where our performance obligation is settled with our customer when natural gas is delivered and
simultaneously consumed by the customer. In addition, we used the invoice method practical expedient, where we recognized
revenue for volumes delivered for which we have a right to invoice. For our other utility revenue, which are primarily one-time
service fees that meet the requirements under ASC 606, the performance obligation is satisfied at a point in time when services
are rendered to the customer. See Note 3 of the Notes to Consolidated Financial Statements in this Annual Report for additional
information regarding our revenues.
Pension and Other Postemployment Benefits - We have defined benefit pension plans covering eligible retirees and full-time
employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible
retirees and employees who retire with at least five years of service.
To calculate the expense and liabilities related to our plans, we utilize an outside actuarial consultant, which uses statistical and
other factors to anticipate future events. These factors include assumptions about the discount rate, expected return on plan
assets, rate of future compensation increases, age and mortality and employment periods. We use tables issued by the Society of
Actuaries to estimate mortality rates. In determining the projected benefit costs, assumptions can change from period to period
and may result in material changes in the costs and liabilities we recognize.
We did not make any material contributions to our defined benefit pension plan or other postemployment plans in 2020. In
2021, our contributions are expected to be $1.1 million to our defined benefit pension plans, and no contributions are expected
to be made to our other postemployment benefit plans. In 2020, we paid $12.5 million of lump-sum settlements to certain
terminated-vested participants in our defined benefit pension plan. In 2019, we purchased a group annuity contract and
transferred approximately $49.2 million of liabilities related to certain participants in our defined benefit pension plan to a third-
party insurance company.
We recorded net periodic benefit costs for our defined benefit pension plans, prior to regulatory deferrals, of $28.2 million in
2020, and estimate that in 2021, we will record expenses of approximately $26.4 million. Net periodic benefits costs for our
postemployment benefit plans, prior to regulatory deferrals, were a credit of $6.2 million in 2020, and estimate that in 2021, we
will record credits of approximately $8.9 million, prior to regulatory deferrals.
The following table sets forth the significant assumptions used to determine our estimated 2021 net periodic benefit cost related
to our defined benefit pension and other postemployment benefit plans and sensitivity to changes with respect to these
assumptions:
Discount rate for pension
Discount rate for other postemployment benefits
Expected long-term return on plan assets (c)
Rate Used
Cost
Sensitivity (a)
Obligation
Sensitivity (b)
2.80% $
2.70% $
7.15%/7.50% $
(Millions of dollars)
3.6
$
(0.2) $
$
2.8
37.1
6.5
—
(a) Approximate impact a quarter percentage point decrease in the assumed rate would have on net periodic pension costs.
(b) Approximate impact a quarter percentage point decrease in the assumed rate would have on defined benefit pension obligation.
(c) Expected long-term return on plan assets for pension and other postemployment benefits are 7.15 percent and 7.50 percent, respectively.
Impairment of Goodwill - We assess our goodwill for impairment at least annually as of July 1, unless events of change in
circumstances indicate an impairment may have occurred before that time. Goodwill impairment reviews are performed at a
reporting unit level, which for ONE Gas equates to our single business segment. Our goodwill impairment analysis, performed
in 2020 and 2018, utilized a qualitative assessment and did not result in any impairment indicators, nor did our analysis reflect
our reporting unit at risk. Additionally, we performed a quantitative analysis in 2019 which did not result in any impairment
indicators. Subsequent to July 1, 2020, no event has occurred indicating that our fair value is less than the 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 the carrying amount of our net assets. If further testing is necessary or a quantitative test is elected to
refresh our recurring qualitative assessment, we perform an impairment test for goodwill. Our impairment test 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
measured by the amount of our carrying value that exceeds our fair value, not to exceed the carrying amount of our goodwill.
46
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 market 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 Consolidated Financial Statements in this Annual Report for further discussion of goodwill.
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. In 2020, we submitted a remediation plan to the KDHE for one of our sites and the KDHE has
provided comments that we are addressing. We are also working on a remediation plan that will be submitted to the KDHE in
2021 for an additional site. As a result of our work to investigate and remediate the environmental impacts of our MGP sites in
2020, we estimated the potential costs associated with additional investigation and remediation to be in the range of $9.1
million to $23.3 million. A single reliable estimate of the remediation costs for these sites was not feasible due to the amount of
uncertainty in the ultimate remediation approach that will be utilized. Accordingly, in 2020, we recorded an adjustment to our
reserve of $9.1 million, which also increased our regulatory asset pursuant to our AAO in Kansas, as we believe recovery of
these costs is probable through our existing AAO or future regulatory filings. At December 31, 2020 and 2019, the reserve for
remediation of our MGP sites was $14.5 million and $5.8 million, respectively.
We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and
remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net
of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-
year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a
determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of
any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to
increase the $15.0 million cap. At December 31, 2020 and 2019, we have deferred $18.8 million and $9.8 million, respectively,
for accrued investigation and remediation costs pursuant to our AAO.
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 2020, 2019 or 2018. Environmental issues may exist with respect to these MGP sites that
are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial
actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the
extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition,
results of operations or cash flows.
See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.
47
CONTRACTUAL OBLIGATIONS
The following table sets forth our contractual obligations at December 31, 2020:
Contractual Obligations
(Millions of dollars)
2021
2022
2023
2024
Long-term debt, including current maturities
$
— $
Commercial paper
Interest payments on long-term debt
Firm transportation and storage capacity contracts
Natural gas purchase commitments
Operating leases
Total
418.2
62.9
175.6
141.3
7.9
805.9
$
$
— $
—
62.9
135.0
—
7.4
205.3
$
— $
—
62.9
98.9
—
6.2
168.0
$
300.0
—
52.9
49.5
—
4.7
407.1
$
$
2025
Thereafter
— $ 1,301.3
—
—
946.0
52.0
35.5
36.8
—
—
11.0
4.1
$ 2,293.8
92.9
Total
$ 1,601.3
418.2
1,239.6
531.3
141.3
41.3
$ 3,973.0
Long-term debt, commercial paper borrowings and interest payments on debt - Long-term debt includes our four debt issuances
at their due dates. Interest payments on debt are calculated by multiplying our long-term debt by the respective coupon rates.
On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility to enhance our liquidity position as part of the
financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of the 2021
winter weather event and the repayment of indebtedness.
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 as of December 31,
2020. 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.
Due to the historic winter weather event in February 2021, we experienced unforeseeable and unprecedented market pricing for
gas costs in our Kansas, Oklahoma, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month
of February of approximately $2.2 billion. These purchases are generally payable at the end of March 2021.
Operating leases - Our operating leases consist primarily of office facilities and IT leases. See Note 6 of the Notes to
Consolidated Financial Statements in this Annual Report for discussion of leases.
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,” “likely,” 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
48
to be materially different from any future results, performance or achievements expressed or implied by forward-looking
statements. Those factors may affect our operations, costs, liquidity, 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:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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•
our ability to recover costs (including operating costs and increased commodity costs related to the recent winter
weather storm), income taxes and amounts equivalent to the cost of property, plant and equipment, regulatory assets
and our allowed rate of return in our regulated rates;
our ability to manage our operations and maintenance costs;
the concentration of our operations in Kansas, Oklahoma, and Texas;
changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;
regulations in local jurisdictions in which we operate authorizing utilities to record in a regulatory asset account or
comparable account the expenses associated with the recent winter weather event, including but not limited to gas
costs, other costs related to the procurement and transportation of gas supply and the associated financing costs;
the economic climate and, particularly, its effect on the natural gas requirements of our residential and
commercial customers;
the length and severity of a pandemic or other health crisis, such as the outbreak of COVID-19, including the impact to
our operations, customers, contractors, vendors and employees, and the measures that international, federal, state and
local governments, agencies, law enforcement and/or health authorities implement to address it, which may (as with
COVID-19) precipitate or exacerbate one or more of the above-mentioned and/or other risks, and significantly disrupt
or prevent us from operating our business in the ordinary course for an extended period;
competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power,
geothermal energy and biofuels;
conservation and energy efficiency efforts of our customers;
adverse weather conditions and variations in weather, including seasonal effects on demand and/or supply, the
occurrence of storms, including the most recent unprecedented winter weather storm in the territories in which we
operate and the related effects on supply, demand, and costs and disasters, and climate change;
indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to
borrow additional funds and/or place us at competitive disadvantage compared with competitors;
our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including
decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of
existing supply and transportation and storage arrangements that are not replaced with contracts with similar terms and
pricing;
our ability to complete necessary or desirable expansion or infrastructure development projects, which may delay or
prevent us from serving our customers or expanding our business;
operation and mechanical hazards or interruptions;
adverse labor relations;
the effectiveness of our strategies to reduce earnings lag, margin protection strategies and risk mitigation strategies,
which may be affected by risks beyond our control such as commodity price volatility, counterparty performance or
creditworthiness and interest rate risk;
the capital-intensive nature of our business, and the availability of and access to, in general, funds to meet our debt
obligations prior to or when they become due and to fund our operations and capital expenditures, either through (i)
cash on hand, (ii) operating cash flow, or (iii) access to the capital markets and other sources of liquidity;
our ability to raise capital to reduce the draw under the ONE Gas 2021 Term Loan Facility and/or repay a portion of
the proceeds under the ONE Gas 2021 Term Loan Facility to reduce the costs of indebtedness;
in light of ONE Gas recently entering into the ONE Gas 2021 Term Loan Facility, our ability to borrow additional
funds, if needed, including raising the funds on commercially reasonable terms, or on terms acceptable to us, or at all;
limitations on our operating flexibility, earnings and cash flows due to restrictions in our financing arrangements;
cross-default provisions in our borrowing arrangements, which may lead to our inability to satisfy all of our
outstanding obligations in the event of a default on our part;
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 to
execute our business strategy;
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 recover the costs of natural gas purchased for our customers, including related to the recent winter
weather storms and any financings required to support our purchase of natural gas supply;
49
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
impact of potential impairment charges;
volatility and changes in markets for natural gas and our ability to secure additional and sufficient liquidity on
reasonable commercial terms to cover costs associated with such volatility;
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, including our counterparties
maintaining ordinary course terms of supply and payments;
changes in existing or the addition of new environmental, safety, tax and other laws to which we and our subsidiaries
are subject, including those that may require significant expenditures, significant increases in operating costs or, in the
case of noncompliance, substantial fines or penalties;
the effectiveness of our risk-management policies and procedures, and employees violating our risk-management
policies;
the uncertainty of estimates, including accruals and costs of environmental remediation;
advances in technology, including technologies that increase efficiency or that improve electricity’s competitive
position relative to natural gas;
population growth rates and changes in the demographic patterns of the markets we serve, and conditions in these
areas’ housing markets;
acts of nature and the potential effects of threatened or actual terrorism and war;
cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the
COVID-19 pandemic, or breaches of technology systems that could disrupt our operations or result in the loss or
exposure of confidential or sensitive customer, employee or Company information; further, increased remote working
arrangements as a result of the pandemic have required enhancements and modifications to our IT infrastructure (e.g.
Internet, Virtual Private Network, remote collaboration systems, etc.), and any failures of the technologies, including
third-party service providers, that facilitate working remotely could limit our ability to conduct ordinary operations or
expose us to increased risk or effect of an attack;
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 and the
requirements of our regulators as a result of the Tax Cuts and Jobs Act of 2017;
changes in accounting standards;
changes in corporate governance standards;
discovery of material weaknesses in our internal controls;
our ability to comply with all covenants in our indentures, the ONE Gas Credit Agreement, the ONE Gas 364-day
Credit Agreement and the ONE Gas 2021 Term Loan Facility, a violation of which, if not cured in a timely manner,
could trigger a default of our obligations;
our ability to attract and retain talented employees, management and directors, and shortage of skilled-labor;
unexpected increases in the costs of providing health care benefits, along with pension and postemployment health
care benefits, as well as declines in the discount rates on, declines in the market value of the debt and equity securities
of, and increases in funding requirements for, our defined benefit plans; and
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.
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 Part 1, Item 1A, Risk Factors, in this Annual Report. All forward-looking
statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than
as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a
result of new information, subsequent events or change in circumstances, expectations or otherwise.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our exposure to market risk discussed below includes forward-looking statements. Our views on market risk are not
necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may
occur since actual gains and losses will differ from those estimated based on actual fluctuations in commodity prices or interest
rates and the timing of transactions.
50
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 may use derivative instruments to economically hedge the cost of anticipated natural gas purchases
during the winter heating months to reduce the impact on our customers of upward market price volatility of natural gas.
Additionally, we inject natural gas into storage during the summer months and withdraw the natural gas during the winter
heating season. Gains or losses associated with these derivative instruments and storage activities are included in, and
recoverable through our purchased-gas cost adjustment mechanisms, which are subject to review by regulatory authorities.
Interest-Rate Risk
We are exposed to interest-rate risk primarily associated with commercial paper borrowings and 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 and allowed by tariff. With approximately
2.2 million customers across three states, we are not exposed materially to a concentration of credit risk. As ordered by our
regulators, customer disconnects for nonpayment were suspended from mid-March through May 20, 2020, in Oklahoma,
through May 31, 2020, in Kansas, and through December 31, 2020, in some areas of Texas. As of December 31, 2020, we have
temporarily suspended disconnects for safety reasons in all of our jurisdictions due to the level of COVID-19 infection. Since
the onset of the pandemic in the first quarter of 2020, we have experienced impacts on our results of operations including, but
not limited to: lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the
suspensions of disconnects for nonpayment; incremental expenses for PPE, cleaning supplies, outside services and other
expenses; and lower expenses for travel and employee training that have been impacted by the pandemic. We have received
accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain
incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions
associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be
determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any
amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At
December 31, 2020, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our
business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable. 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. We are able to recover the fuel-related portion of bad
debts through our purchased-gas cost adjustment mechanisms.
51
ITEM 8.
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of ONE Gas, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of ONE Gas, Inc. and its subsidiaries (the “Company”) as of
December 31, 2020 and 2019, and the related consolidated statements of income, comprehensive income, equity and cash flows
for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the
“consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of
December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2020 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, 2020, based on criteria established in Internal Control - Integrated Framework (2013)
issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated 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 the Company’s consolidated financial statements and on the Company's internal control over financial
reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight
Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material
respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement
of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. 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.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (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
52
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.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial
statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or
disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate
opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of New, or Changes in Existing, Rate Regulation
As described in Notes 1 and 11 to the consolidated financial statements, total regulatory assets and total regulatory liabilities are
approximately $424 million and $563 million, respectively, as of December 31, 2020. The Company is subject to rate
regulation and accounting requirements of regulatory authorities in the states in which it operates, and it follows the accounting
and reporting guidance for regulated operations. As disclosed by management, regulatory assets are recorded for costs that have
been deferred for which future recovery through customer rates is considered probable and regulatory liabilities are recorded
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 accounting principles generally accepted in the United States
of America for non-regulated entities are capitalized or deferred on the balance sheet because it is probable they can be
recovered through rates. The amounts to be recovered or recognized are based upon historical experience and management’s
understanding of regulations and may be affected by decisions of the regulatory authorities or the issuance of new regulations.
The principal considerations for our determination that performing procedures relating to the Company’s accounting for the
effects of rate regulation is a critical audit matter are the significant judgment by management when assessing the impact of
regulation on accounting for new and existing regulatory assets and liabilities, which in turn led to significant auditor judgment
and subjectivity in performing procedures and evaluating audit evidence related to the accounting for the impact of regulatory
proceedings on new and existing regulatory assets and liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall
opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the
assessment of new rate regulation or changes to existing regulation, including controls over management’s process for
evaluating and recording (i) deferred costs, including the amounts to be deferred and the future recovery, resulting in regulatory
assets or (ii) a reduction to revenues for amounts that will be credited to customers resulting in regulatory liabilities. These
procedures also included, among others, (i) obtaining and evaluating regulatory rate orders, including correspondence between
the Company and regulators, (ii) assessing the reasonableness of management’s judgments regarding new or updated regulatory
guidance and proceedings and the related accounting implications, and (iii) testing regulatory assets and liabilities based on
provisions and formulas outlined in regulatory orders and other correspondence.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 26, 2021
We have served as the Company’s auditor since 2013.
53
Years Ended December 31,
2019
(Thousands of dollars, except per share amounts)
2018
2020
$
1,530,268
$
1,652,730
$
1,633,731
537,445
687,974
714,636
431,115
194,881
63,311
689,307
303,516
(3,020)
(62,505)
237,991
(41,579)
196,412
3.70
3.68
53,133
53,370
2.16
$
$
$
$
429,126
180,395
59,977
669,498
295,258
(2,976)
(62,681)
229,601
(42,852)
186,749
3.53
3.51
52,895
53,240
2.00
$
$
$
$
411,702
160,086
58,878
630,666
288,429
(11,359)
(51,305)
225,765
(53,531)
172,234
3.27
3.25
52,693
53,029
1.84
$
$
$
$
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF INCOME
Total revenues
Cost of natural gas
Operating expenses
Operations and maintenance
Depreciation and amortization
General taxes
Total operating expenses
Operating income
Other expense, net
Interest expense, net
Income before income taxes
Income taxes
Net income
Earnings per share
Basic
Diluted
Average shares (thousands)
Basic
Diluted
Dividends declared per share of stock
See accompanying Notes to Consolidated Financial Statements.
54
Years Ended December 31,
2019
2018
2020
(Thousands of dollars)
$
186,749
$
196,412
172,234
(1,038)
(1,038)
195,374
$
(1,435)
(1,435)
185,314
$
1,407
1,407
173,641
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plans liability, net of tax of
$289, $479, and $(848), respectively
Total other comprehensive income (loss), net of tax
Comprehensive income
See accompanying Notes to Consolidated Financial Statements.
$
$
55
ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
Assets
Property, plant and equipment
Property, plant and equipment
Accumulated depreciation and amortization
Net property, plant and equipment
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Natural gas in storage
Regulatory assets
Other current assets
Total current assets
Goodwill and other assets
Regulatory assets
Goodwill
Other assets
Total goodwill and other assets
Total assets
See accompanying Notes to Consolidated Financial Statements.
December 31, December 31,
2020
2019
(Thousands of dollars)
$
$
6,838,603
1,971,546
4,867,057
6,433,119
1,867,893
4,565,226
7,993
292,985
52,766
93,946
56,773
35,406
539,869
17,853
250,012
55,732
104,259
47,440
30,906
506,202
366,956
157,953
96,877
621,786
6,028,712
$
391,036
157,953
87,883
636,872
5,708,300
$
56
ONE Gas, Inc.
CONSOLIDATED 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 53,166,733 shares at
December 31, 2020; issued and outstanding 52,771,749 shares at December 31, 2019
Paid-in capital
Retained earnings
Accumulated other comprehensive loss
Total equity
Long-term debt, excluding current maturities, and net of issuance costs of $13,159 and $10,936,
respectively
Total equity and long-term debt
Current liabilities
Notes payable
Accounts payable
Accrued taxes other than income
Regulatory liabilities
Customer deposits
Other current liabilities
Total current liabilities
Deferred credits and other liabilities
Deferred income taxes
Regulatory liabilities
Employee benefit obligations
Other deferred credits
Total deferred credits and other liabilities
Commitments and contingencies
Total liabilities and equity
See accompanying Notes to Consolidated Financial Statements.
December 31, December 31,
2020
2019
(Thousands of dollars)
$
$
532
1,756,921
483,635
(7,777)
2,233,311
528
1,733,092
402,509
(6,739)
2,129,390
1,582,428
3,815,739
1,286,064
3,415,454
418,225
152,313
63,800
15,761
68,028
78,952
797,079
656,806
547,563
97,637
113,888
1,415,894
516,500
120,490
47,956
45,201
57,987
84,603
872,737
682,632
503,518
115,657
118,302
1,420,109
$
6,028,712
$
5,708,300
57
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58
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
Deferred income taxes
Share-based compensation expense
Provision for doubtful accounts
Changes in assets and liabilities:
Accounts receivable
Materials and supplies
Natural gas in storage
Asset removal costs
Accounts payable
Accrued taxes other than income
Customer deposits
Regulatory assets and liabilities - current
Regulatory assets and liabilities - non-current
Employee benefit obligation
Other assets and liabilities - current
Other assets and liabilities - non-current
Cash provided by operating activities
Investing activities
Capital expenditures
Other investing expenditures
Other investing receipts
Cash used in investing activities
Financing activities
Borrowings (repayment) on notes payable, net
Issuance of debt, net of discounts
Long-term debt financing costs
Issuance of common stock
Repayment of long-term debt
Dividends paid
Tax withholdings related to net share settlements of stock compensation
Cash provided by (used in) financing activities
Change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized
Cash paid (received) for income taxes, net
See accompanying Notes to Consolidated Financial Statements.
2020
Years Ended December 31,
2019
(Thousands of dollars)
2018
$
196,412
$
186,749
$
172,234
194,881
18,485
9,803
15,450
(58,423)
2,966
10,313
(40,833)
28,376
15,844
10,041
(38,773)
23,648
(3,109)
(12,877)
(7,704)
364,500
(471,345)
(2,804)
3,777
(470,372)
(98,275)
298,428
(2,885)
19,383
—
180,395
13,307
9,314
8,994
30,415
(11,399)
3,036
(47,784)
(59,293)
316
(3,196)
3,787
24,416
(35,401)
7,173
(484)
310,345
(417,322)
(7,009)
1,399
(422,932)
217,000
—
—
5,116
—
(114,372)
(105,424)
(6,267)
96,012
(9,860)
17,853
7,993
60,126
30,361
$
$
$
(7,575)
109,117
(3,470)
21,323
17,853
61,160
30,152
$
$
$
$
$
$
160,086
53,242
8,195
8,506
841
(4,661)
22,859
(52,855)
36,885
6,316
372
72,716
36,721
(50,100)
(1,885)
(1,778)
467,694
(394,450)
—
—
(394,450)
(57,715)
395,648
(4,324)
4,803
(300,000)
(96,594)
(8,152)
(66,334)
6,910
14,413
21,323
49,371
800
59
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
January 1, 2018
Net income
Other comprehensive income
Common stock issued and other
Common stock dividends - $1.84 per share
December 31, 2018
Net income
Other comprehensive loss
Reclassification of stranded tax effects
Common stock issued and other
Common stock dividends - $2.00 per share
December 31, 2019
Net income
Other comprehensive loss
Common stock issued and other
Common stock dividends - $2.16 per share
December 31, 2020
See accompanying Notes to Consolidated Financial Statements.
Common
Stock Issued
(Shares)
Paid-in
Common
Capital
Stock
(Thousands of dollars)
52,598,005 $
—
—
—
—
52,598,005
—
—
—
173,744
—
52,771,749
—
—
394,984
—
53,166,733 $
526 $
—
—
—
—
526
—
—
—
2
—
528
—
—
4
—
532 $
1,737,551
—
—
(10,951)
892
1,727,492
—
—
—
4,697
903
1,733,092
—
—
22,915
914
1,756,921
60
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
(Continued)
January 1, 2018
Net income
Other comprehensive income
Common stock issued and other
Common stock dividends - $1.84 per share
December 31, 2018
Net income
Other comprehensive loss
Reclassification of stranded tax effects
Common stock issued and other
Common stock dividends - $2.00 per share
December 31, 2019
Net income
Other comprehensive loss
Common stock issued and other
Common stock dividends - $2.16 per share
December 31, 2020
See accompanying Notes to Consolidated Financial Statements.
Retained
Earnings
Accumulated
Other
Comprehensive
Treasury
Loss
Stock
(Thousands of dollars)
Total Equity
$
$
246,121 $
172,234
—
—
(97,486)
320,869
186,749
—
1,218
—
(106,327)
402,509
196,412
—
—
(115,286)
483,635 $
(18,496) $
—
—
16,351
—
(2,145)
—
—
—
2,145
—
—
—
—
—
—
— $
(5,493) $ 1,960,209
172,234
—
1,407
—
—
(4,086)
—
(1,435)
(1,218)
—
—
(6,739)
—
(1,038)
—
—
1,407
5,400
(96,594)
2,042,656
186,749
(1,435)
—
6,844
(105,424)
2,129,390
196,412
(1,038)
22,919
(114,372)
(7,777) $ 2,233,311
61
ONE Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations - We provide natural gas distribution services to our approximately 2.2 million
customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and
Texas Gas Service, respectively. We primarily serve residential, commercial and transportation customers in all three states.
We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under
the trading symbol “OGS.”
Basis of Presentation - The consolidated financial statements include the accounts of our natural gas distribution business as
set forth in “Organization and Nature of Operations” above. All significant balances and transactions between our subsidiaries
have been eliminated.
Use of Estimates - The preparation of our consolidated financial statements and related disclosures in accordance with GAAP
requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that
affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the
consolidated 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 income 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.
Revenues - We recognize revenue from contracts with customers to depict the transfers of goods and services to customers at
an amount that we expect to be entitled to receive in exchange for these goods and services. Our sources of revenue are
disaggregated by natural gas sales, transportation revenues, and miscellaneous revenues, which are primarily one-time service
fees, that meet the requirements of ASC 606. Certain revenues that do not meet the requirements of ASC 606 are classified as
other revenues in our Notes to Consolidated Financial Statements in this Annual Report.
Our natural gas sales to customers and transportation revenues represent revenues from contracts with customers through
implied contracts established by our tariffs approved by the regulatory authorities. Our customers receive the benefits of our
performance when the commodity is delivered to the customer. The performance obligation is satisfied over time as the
customer receives the natural gas.
For 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. 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. We use the invoice method practical expedient, where we
recognize revenue for volumes delivered for which we have a right to invoice. Our estimate of 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 accrued unbilled natural gas sales revenue at December 31, 2020 and 2019 was $144.9 million and $109.7 million,
respectively, and is included in accounts receivable on our consolidated balance sheets.
Our miscellaneous revenues from contracts with customers represent implied contracts established by our tariff rates approved
by the regulatory authorities and include miscellaneous utility services with the performance obligation satisfied at a point in
time when services are rendered to the customer.
Total other revenues consist of revenues associated with regulatory mechanisms that do not meet the requirements of ASC 606
as revenue from contracts with customers, but authorize us to accrue revenues earned based on tariffs approved by the
regulatory authorities. Other revenues - natural gas sales primarily relate to the WNA mechanism in Kansas. This mechanism
adjusts our revenues earned for the variance between actual and normal HDDs. This mechanism can have either positive
62
(warmer than normal) or negative (colder than normal) effects on revenues.
We collect and remit other taxes on behalf of governmental authorities, and we record these amounts in accrued taxes other than
income in our consolidated balance sheets. See Note 3 for additional discussion of revenues.
Cost of Natural Gas - Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase
costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating
costs or depreciation and amortization. In addition, our cost of natural gas regulatory mechanisms provide a method of
recovering natural gas costs on an ongoing basis without a profit. See Note 11 for additional discussion of purchased gas cost
recoveries.
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.
Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for natural gas sold or
services rendered, net of an allowance for doubtful accounts. We assess the creditworthiness of our customers. Those
customers who do not meet minimum standards may be required to provide security, including deposits and other forms of
collateral, when appropriate and allowed by our tariffs. With approximately 2.2 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. We are able to recover natural gas costs related to doubtful accounts through purchased-gas cost adjustment
mechanisms. At December 31, 2020 and 2019, our allowance for doubtful accounts was $16.6 million and $6.6 million,
respectively.
Inventories - Natural gas in storage is accounted for 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 are stated at the lower of weighted-average cost or net realizable value.
Leases - We determine if an arrangement is a lease at inception if the contract conveys the right to control the use and obtain
substantially all the economic benefits from the use of an identified asset for a period of time in exchange for consideration.
We identify a lease as a finance lease if the agreement includes any of the following criteria: transfer of ownership by the end of
the lease term; an option to purchase the underlying asset that the lessee is reasonably certain to exercise; a lease term that
represents 75 percent or more of the remaining economic life of the underlying asset; a present value of lease payments and any
residual value guaranteed by the lessee that equals or exceeds 90 percent of the fair value of the underlying asset; or an
underlying asset that is so specialized in nature that there is no expected alternative use to the lessor at the end of the lease term.
A lease that does not meet any of these criteria is considered an operating lease.
Lease right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our
obligation to make lease payments arising from the lease. Right-of-use assets and liabilities are recognized at the
commencement date of a lease based on the present value of lease payments over the lease term. Our lease terms may include
options to extend or terminate the lease. We include these extension or termination options in the determination of the lease
term when it is reasonably certain that we will exercise that option. We have lease agreements with lease and non-lease
components, which are accounted for separately. Additionally, for certain office equipment leases, we apply a portfolio
approach to effectively account for the operating lease right-of-use assets and liabilities. We do not recognize leases having a
term of less than one year in our consolidated balance sheets.
For purposes of determining the present value of the lease payments, we use a lease’s implicit interest rate when readily
determinable. As most of our leases do not provide an implicit interest rate, we use an incremental borrowing rate based on
available information at the commencement of the lease. Lease cost for operating leases is recognized on a straight-line basis
over the lease term. See Note 6 for additional information regarding our leases.
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.
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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. We have not elected to designate any of our derivative instruments as hedges.
The table below summarizes the various ways in which we account for our derivative instruments and the impact on our
consolidated 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
See Note 10 for additional information regarding our hedging activities using derivatives.
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 consolidated 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 10 for additional information regarding our
fair value measurements.
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
regulatory proceedings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are
approved by our regulators and become 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 Consolidated 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.
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See Note 12 for additional information regarding our property, plant and equipment.
Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually as of July 1,
unless events or a change in circumstances indicate an impairment may have occurred before that time. 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 the
carrying amount of our net assets. If further testing is necessary or a quantitative test is elected to refresh our recurring
qualitative assessment, we perform a quantitative impairment test for goodwill.
Our impairment test 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 measured by the amount of our carrying value that exceeds our fair value, not to exceed the
carrying amount of our goodwill.
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 market transactions. The forecasted cash flows are based on average forecasted cash flows over a
period of years.
We performed a quantitative analysis in 2019, which did not result in any impairment indicators, nor did our analysis reflect our
reporting unit at risk. Our goodwill impairment analysis performed in 2020 and 2018 utilized a qualitative assessment and did
not result in any impairment indicators, nor did our analysis reflect our reporting unit at risk. Subsequent to July 1, 2020, no
event has occurred indicating that it is more likely than not that our fair value is less than the carrying value of our net assets.
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 material asset impairments in 2020, 2019 or 2018.
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 customers. 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 our 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 11 for additional information regarding our regulatory assets and liabilities disclosures.
Pension and Other Postemployment Employee Benefits - We have defined benefit pension plans covering eligible
employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible
employees who retire with at least five years of service. To calculate the costs and liabilities related to our plans, we utilize an
outside actuarial consultant, which uses statistical and other factors to anticipate future events. These factors include
assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and mortality
and employment periods. We use tables issued by the Society of Actuaries to estimate mortality rates. 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.
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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 income 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 income tax assets is recognized when it is more likely than not that some or all of the benefit
from the deferred income 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 income tax liabilities, as well as the current and forecasted business economics of our
industry. We had no valuation allowance at December 31, 2020 and 2019.
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, 2020 and 2019.
Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date.
See Note 15 for additional information regarding income taxes.
Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-
lived assets that result from the acquisition, construction, development and/or normal use of the asset. Certain long-lived assets
that comprise our natural gas distribution systems, primarily our pipeline assets, are subject to agreements or regulations that
give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon
the discontinued use of the natural gas distribution system. We recognize the fair value of a liability for an asset retirement
obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate
reasonably the fair value of the asset retirement obligations for portions of our assets because the settlement dates are
indeterminable given our expected continued use of the assets with proper maintenance. We expect our natural gas distribution
systems will continue in operation for the foreseeable future. Based on our proximity to significant natural gas reserves and
infrastructure and the widespread use of natural gas for heating and cooking activities by residential and commercial customers
in our service areas, we expect 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. The
amounts collected for non-legal asset removal costs that are in excess of costs incurred, if any, 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. These
costs are addressed prospectively in depreciation rates, rather than as a regulatory liability, in each general rate order.
For financial reporting purposes, if the removal costs collected have exceeded our removal cost incurred, we estimate our
regulatory liability using current rates since the last general rate order in each of our jurisdictions. 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. To the
extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization
and other deferred credits and therefore will not have an impact on earnings.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and
environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred
and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution.
Accruals for the estimated cost of 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.
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See Note 17 for additional information regarding contingencies.
Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate
forfeiture rates based on historical forfeitures under our share-based payment plans.
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 primarily to
residential, commercial 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. 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, operating efficiency, growth opportunities and government-requested
pipeline relocations, not geographic location or regulatory jurisdiction.
In 2020, 2019 and 2018, we had no single external customer from which we received 10 percent or more of our gross revenues.
Treasury Stock - We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are
recorded as reductions in equity in our consolidated balance sheets. We record the reissuance of treasury stock at our weighted
average cost of treasury shares recorded in equity in our consolidated balance sheets.
Reclassifications - Certain reclassifications have been made in the prior-year financial statements to conform to the current-
year presentation. For the year ended December 31, 2019, an accrued amount totaling $10 million that was previously presented
within “accounts receivable, net” on our balance sheets was reclassified to “other current assets.” Additionally, we have
updated our 2019 and 2018 Statements of Cash Flows to disaggregate regulatory assets and liabilities and other assets and
liabilities into current and non-current components that are presented on our balance sheet to conform to our current year
presentation.
Recently Issued Accounting Standards Update - In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform
(Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting,” which provides relief from the
accounting analysis and impacts that may otherwise be required for modifications to agreements (e.g., loans, debt securities,
derivatives, borrowings) necessitated by reference rate reform. It also provides optional expedients to enable companies to
continue to apply hedge accounting to certain hedging relationships impacted by reference rate reform. In the first quarter 2020,
we adopted this new guidance effective for contracts modified between March 12, 2020 and December 31, 2022. Our revolving
lines of credit under the ONE Gas Credit Agreement and the ONE Gas 364-day Credit Agreement utilize LIBOR as the
reference rate. If modified, we may elect the optional practical expedients to account for the modifications prospectively. Our
adoption did not result in a material impact to our consolidated financial statements.
In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income
Taxes,” which removes certain exceptions for recognizing deferred taxes for investments, performing intra-period allocation
and calculating income taxes in interim periods. ASU 2019-12 also adds guidance to reduce complexity in certain areas,
including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. This standard is
effective for interim and annual periods in fiscal years beginning after December 15, 2020. We adopted this new guidance in
the first quarter of 2021 and our adoption did not result in a material impact to our financial position or results of operations or
to our consolidated financial statements.
In August 2018, the FASB issued ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40):
Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a
consensus of the FASB Emerging Issues Task Force).” Under this guidance, a company should defer implementation costs that
it incurs if a company would capitalize those same costs under the internal-use software guidance for an arrangement that is a
software license. The deferred implementation costs should be amortized over the term of the hosting arrangement, including
any probable renewals. We are party to hosting arrangements identified as service contracts for various information systems
used in our operations. We adopted this new guidance using the prospective transition approach for implementation costs
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incurred in hosting arrangement service contracts beginning January 1, 2020. In certain jurisdictions, we have orders from our
regulators allowing us to amortize deferred implementation costs for hosting arrangements entered into after January 1, 2020,
over the life approved by our regulators for our internal-use software systems rather than the term of the hosting arrangement.
The difference in amortization calculated between the term of the hosting arrangement and internal-use software life approved
by our regulators is deferred as a regulatory asset and amortized over the remaining internal-use software life that exceeds the
term of the hosting arrangement. Our adoption did not result in a material impact to our consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-14, an amendment to ASC 715, “Compensation - Retirement Benefits.” This
guidance eliminates requirements for certain disclosures such as the amount and timing of plan assets expected to be returned to
the employer and the amount of future annual benefits covered by insurance contracts. The standard is effective for periods
ending after December 15, 2020, and we adopted this guidance in the first quarter 2020. The guidance added new disclosure
requirements for sponsors of the defined benefit plans to provide information relating to the weighted-average interest crediting
rate for cash balance plans and other plans with promised interest crediting rates and an explanation for significant gains or
losses related to changes in the benefit obligations for the period. We have reflected these changes as presented in Note 14 to
our consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework - Changes
to the Disclosure Requirements for Fair Value Measurement”, which removes, modifies and adds to certain disclosure
requirements of fair value measurements. The guidance was effective for the Company beginning January 1, 2020, and we
adopted this guidance in the first quarter 2020. Disclosure requirements removed include the amount of and reasons for
transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the
valuation processes for Level 3 fair value measurements. Modifications include considerations around the requirement to
disclose the timing of liquidation of an investee’s assets and the date when restrictions from redemption might lapse. The
additions include the requirement to disclose changes in unrealized gains and losses for the period in other comprehensive
income for recurring Level 3 fair value measurements held and the range and weighted average of significant unobservable
inputs used to develop Level 3 fair value measurements. The guidance did not have a material impact on the Company’s fair
value disclosure, and we have reflected these changes as presented in Note 14 to our consolidated financial statements.
In February 2018, the FASB issued ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220):
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” which allows a reclassification from
accumulated other comprehensive income (loss) to retained earnings for stranded tax effects resulting from the Tax Cuts and
Jobs Act of 2017. We adopted this new guidance in the first quarter 2019 and our adoption did not result in a material impact to
our consolidated financial statements. This change is reflected in our consolidated statements of equity.
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on
Financial Instruments,” which introduces new guidance to the accounting for credit losses on instruments within its scope,
including trade receivables. We adopted this new guidance in the first quarter 2020 using the modified retrospective method.
Our financial assets within scope of this guidance primarily include our trade receivables from customers. Our policy for
measuring our allowance for doubtful accounts is disclosed in the aforementioned policy for accounts receivable. We did not
create any new accounting policies, nor did we modify any of our existing policies, as a result of adopting this guidance. Our
adoption did not result in a cumulative adjustment to our opening retained earnings or have a material impact to our
consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” as amended, (“Topic 842”) which prescribes
recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing
arrangements. We adopted this new guidance effective January 1, 2019, and applied the modified retrospective approach to all
existing leases. Upon adoption, we recognized lease liabilities of approximately $32 million, with corresponding right-of-use
assets of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.
Our adoption did not result in a material impact to our results of operations or cash flows. We utilized the practical expedients
that allow us to: (1) not reassess expired or existing contracts to determine whether they are subject to lease accounting
guidance, (2) not reconsider lease classification at transition, and (3) not evaluate previously capitalized initial direct costs
under the revised requirements. We also utilized the practical expedients that allowed us to: (1) not evaluate under Topic 842
existing or expired land easements that were not previously accounted for as leases under the current lease guidance in ASC
Topic 840 (“Topic 840”) and (2) use an additional transition method in which an entity initially applies the new leases standard
at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of
adoption. We adopted an accounting policy that exempts leases with terms of less than one year from the recognition
requirements of Topic 842, and we disclose such leases in our interim and annual disclosures upon adoption. Our adoption did
not result in a cumulative adjustment to our opening retained earnings or a material impact to our consolidated financial
statements. See Note 6 for additional information regarding our leases.
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2.
SUBSEQUENT EVENTS
A historic winter weather event in February 2021 impacted supply, market pricing and demand for natural gas in a number of
states, including our service territories of Kansas, Oklahoma, and Texas. During this time, the governors of Kansas, Oklahoma,
and Texas, each declared a state of emergency, and certain regulatory agencies issued emergency orders that impacted the
utility and natural gas industries, including statewide utilities curtailment programs and orders requiring jurisdictional natural
gas and electric utilities to do all things possible and necessary to ensure that natural gas and electricity utility services continue
to be provided to their customers. Due to the historic nature of this winter weather event, we experienced unforeseeable and
unprecedented market pricing for gas costs in our Kansas, Oklahoma, and Texas jurisdictions, which resulted in aggregated
natural gas purchases for the month of February of approximately $2.2 billion. These purchases are generally payable at the end
of March 2021.
On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility to enhance our liquidity position as part of the
financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of the 2021
winter weather event and the repayment of indebtedness. See Note 5 for additional discussion of the ONE Gas 2021 Term Loan
Facility.
Our purchased gas costs are recoverable through our tariffs in each state where we operate. Due to the higher level of gas
purchase costs during the 2021 winter event, we are working with regulators to extend the recovery periods of such costs in
order to lessen the immediate customer impact. In that regard, the Kansas Corporation Commission and the Railroad
Commission of Texas each authorized certain utilities, including local natural gas distribution companies, to record a regulatory
asset to account for the extraordinary costs associated with this winter weather event, including but not limited to gas purchase
costs and other costs related to the procurement and transportation of gas supply. We have filed a motion with the Oklahoma
Corporation Commission to seek comparable authority in Oklahoma to record a regulatory asset to account for the
extraordinary costs, including carrying costs, associated with this winter weather event. An administrative law judge has
recommended approval of our motion by the Oklahoma Corporation Commission. The recommendation from the
administrative law judge will next be considered by the Oklahoma Corporation Commission.
3.
REVENUE
The following table sets forth our revenues disaggregated by source for the periods indicated:
Natural gas sales to customers
Transportation revenues
Miscellaneous revenues
Total revenues from contracts with customers
Other revenues - natural gas sales related
Other revenues
Total other revenues
Total revenues
$
$
2020
1,381,141
113,855
15,505
1,510,501
8,299
11,468
19,767
Year Ended December 31,
2019
(Thousands of dollars)
1,512,886
$
114,014
20,579
$
1,647,479
(4,699)
9,950
5,251
2018
1,495,250
109,658
21,710
1,626,618
(2,806)
9,919
7,113
1,530,268
$
1,652,730
$
1,633,731
4.
CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE
In October 2019, we exercised a one-year extension of the ONE Gas Credit Agreement and amended the agreement to provide
that we may extend the maturity date by one year, subject to the lenders’ consent, two additional times. The ONE Gas Credit
Agreement remains a $700 million revolving unsecured credit facility and includes a $20 million letter of credit subfacility and
a $60 million swingline subfacility. We are able to request an increase in commitments of up to an additional $500 million
upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments
from existing lenders. The ONE Gas Credit Agreement expires in October 2024, and is available to provide liquidity for
working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate
purposes.
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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. The ONE Gas
Credit Agreement also 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, 2020, our total debt-to-
capital ratio was 47 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement.
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.
In April 2020, we entered into the ONE Gas 364-day Credit Agreement. The ONE Gas 364-day Credit Agreement is a
$250 million revolving unsecured credit facility containing various customary conditions to borrowing and affirmative,
negative and financial ratio maintenance covenants, all of which are substantially the same as those of the ONE Gas
Credit Agreement. The ONE Gas 364-day Credit Agreement also contains provisions for an applicable margin rate and a
quarterly 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 115 basis points, and the quarterly facility fee is 10 basis points.
Both the ONE Gas Credit Agreement and the ONE Gas 364-day Credit Agreement utilize LIBOR as the reference rate for
determining interest to accrue on borrowings under the respective agreements. In the event LIBOR is not available, and such
circumstances are unlikely to be temporary, our lenders for each respective agreement may establish an alternative interest rate
for the impacted loans by replacing LIBOR with one or more secured overnight financing-based rates or another alternate
benchmark rate.
At December 31, 2020, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement
or the ONE Gas 364-day Credit Agreement, with $948.8 million of combined remaining credit available to repay our
commercial paper borrowings.
We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of
$700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary, but may not exceed
270 days from the date of issue. The commercial paper notes are sold generally at par less a discount representing an interest
factor. At December 31, 2020, we had $418.2 million of commercial paper outstanding. The weighted-average interest rate on
our commercial paper was 0.18 percent and 1.83 percent at December 31, 2020 and 2019, respectively.
5.
LONG-TERM DEBT
Senior Notes - In April 2020, ONE Gas issued $300 million of 2.00 percent senior notes due 2030. The proceeds from the
issuance were used to reduce the amount of outstanding commercial paper and for general corporate purposes.
Our long-term debt includes $300 million of 3.61 percent senior notes due in 2024, $300 million of 2.00 percent senior notes
due 2030, $600 million of 4.658 percent senior notes due 2044, and $400 million of 4.50 percent senior notes due 2048. 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.
Depending on the series, we may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date,
starting three months or six months 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.
ONE Gas 2021 Term Loan Facility - On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility to enhance
our liquidity position as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our
obligations as a result of the 2021 winter weather event and the repayment of indebtedness.
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The ONE Gas 2021 Term Loan Facility provides for a $2.5 billion unsecured term loan facility. Proceeds of the loans under the
ONE Gas 2021 Term Loan Facility will be available for natural gas purchases as a result of the 2021 winter weather event and
the repayment of indebtedness. The ONE Gas 2021 Term Loan Facility matures two years after the loans are funded under the
ONE Gas 2021 Term Loan Facility. The loans under the ONE Gas 2021 Term Loan Facility will bear interest at a “Eurodollar
Rate” or a “Base Rate” as specified in the ONE Gas 2021 Term Loan Facility, plus a margin specified in the ONE Gas 2021
Term Loan Facility which adjusts based on our debt ratings and the outstanding amount of loans remaining under the ONE Gas
2021 Term Loan Facility. Outstanding loans or commitments under the ONE Gas 2021 Term Loan Facility are required to be
prepaid or reduced, as applicable, with the net cash proceeds received by us or any of our subsidiaries from certain debt and
equity issuances.
The ONE Gas 2021 Term Loan Facility contains customary conditions to borrowing, and customary affirmative and negative
covenants, including a financial ratio maintenance covenant requiring us to maintain a total debt-to-capital ratio of no more than
72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent at the end of any calendar quarter
thereafter. The ONE Gas 2021 Term Loan Facility also contains various customary events of default, the occurrence of which
could result in a termination of the lenders’ commitments and the acceleration of all of our obligations thereunder.
6.
LEASES
We have operating leases for office facilities, gas storage facilities, IT equipment and right-of-way contracts. Our leases have
remaining lease terms of one year to nine years, some of which include options to extend the leases for up to 10 years, and some
of which include options to terminate the leases within specified time frames. We have not entered into any finance leases.
Our right-of-use asset is $37.2 million and $34.2 million as of December 31, 2020 and 2019, respectively, and is reported
within other assets in our Consolidated Balance Sheets. Operating lease liabilities are reported within our other current
liabilities and other liabilities in our consolidated balance sheets. Total operating lease cost including immaterial amounts
attributable to short-term operating leases was $8.4 million, $8.5 million, and $8.2 million in 2020, 2019 and 2018,
respectively.
In 2020, we reassessed certain operating leases for office facilities and IT which were extended or modified, resulting in an
increase in our right-of-use asset and operating lease liability of $9.8 million and $10.2 million, respectively.
Other information related to operating leases
Weighted-average remaining lease term
Weighted-average discount rate
Supplemental cash flows information
Years Ended
December 31,
2019
2020
(Millions of dollars)
7 years
7 years
2.81% 3.62%
Lease payments
$
Right-of-use assets obtained in exchange for lease obligations $
(8.0) $
9.8 $
(8.4)
9.5
71
Future minimum lease payments under non-cancellable operating leases
2021
2022
2023
2024
2025
Thereafter
Total future minimum lease payments
Imputed interest
Total operating lease liability
Consolidated balance sheets as of December 31, 2020
Current operating lease liability
Long-term operating lease liability
Total operating lease liability
December 31,
2020
(Millions of dollars)
7.9
$
7.4
6.2
4.7
4.1
11.0
41.3
(3.5)
37.8
$
$
$
$
7.0
30.8
37.8
7.
EQUITY
Preferred Stock - At December 31, 2020, we had 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, 2020, we had approximately 196.8 million shares of authorized common stock available for
issuance.
Treasury Shares - In 2019, we were authorized to purchase treasury shares to be used to offset shares issued under our equity
compensation plan and the ESPP. Our Board of Directors established an annual limit of $20 million of treasury stock
purchases, exclusive of funds received through the dividend reinvestment and the ESPP. Stock purchases could have been
made in the open market or in private transactions at times, and in amounts that we deemed appropriate. There was no
guarantee as to the exact number of shares that we would have purchased, and we terminated the program in 2019.
At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity
distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to
$250 million (including any shares of common stock that may be sold pursuant to the master forward sale confirmation entered
into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock
are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us
and the sales agent. We are under no obligation to offer and sell common stock under the program. At December 31, 2020, we
had issued and sold 179,514 shares of our common stock for $13.6 million, generating proceeds, net of issuance costs, of
$13.5 million, and had $236.4 million of equity available for issuance under the program.
Dividends Declared - In 2020 and 2019, we declared and paid dividends of $2.16 per share ($0.54 per share quarterly) and
$2.00 per share ($0.50 per share quarterly), respectively. In January 2021, we declared a dividend of $0.58 per share ($2.32 per
share on an annualized basis) for shareholders of record on February 19, 2021, payable March 5, 2021.
72
8.
ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the balance in accumulated other comprehensive loss for the periods indicated:
January 1, 2019
Pension and other postemployment benefit plans obligations
Other comprehensive income before reclassification, net of tax of $692
Amounts reclassified from accumulated other comprehensive loss, net of tax of $(213)
Other comprehensive loss
Reclassification of stranded tax effects (a)
December 31, 2019
Pension and other postemployment benefit plans obligations
Other comprehensive loss before reclassification, net of tax of $587
Amounts reclassified from accumulated other comprehensive loss, net of tax of $(298)
Other comprehensive loss
December 31, 2020
Accumulated Other
Comprehensive Loss
(Thousands of dollars)
$
$
(4,086)
(2,074)
639
(1,435)
(1,218)
(6,739)
(1,932)
894
(1,038)
(7,777)
(a) Reflects the impact of the adoption of ASU 2018-02 in fiscal year 2019 related to stranded tax effects in accumulated other comprehensive
loss as a result of the Tax Cuts and Jobs Act of 2017. See Note 1 for additional information regarding our adoption of this standard.
The following table sets forth the effect of reclassifications from accumulated other comprehensive loss on our Consolidated
Statements of Income for the periods indicated:
Details about Accumulated Other Comprehensive
Years Ended December 31,
Consolidated Statements of
Loss Components
2020
2019
2018
Income
Affected Line Item in the
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss
Amortization of unrecognized prior service cost
Regulatory adjustments (b)
Total reclassifications for the period
(Thousands of dollars)
$
$
42,492
(117)
42,375
(41,183)
1,192
(298)
894
$
$
35,283
(673)
34,610
(33,758)
852
(213)
639
$
$
43,800
(4,567)
39,233
(38,151)
1,082 Income before income taxes
(271) Income tax expense
811 Net income
(a) These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note 14 for
additional information regarding our net periodic benefit cost.
(b) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred
as part of our regulatory assets. See Note 11 for additional information regarding our regulatory assets and liabilities.
9.
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, 2020
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
$
$
196,412
53,133
$
3.70
—
196,412
237
53,370
$
3.68
73
Basic EPS Calculation
Net income available for common stock
Diluted EPS Calculation
Effect of dilutive securities
Net income available for common stock and common stock equivalents
Basic EPS Calculation
Net income available for common stock
Diluted EPS Calculation
Effect of dilutive securities
Net income available for common stock and common stock equivalents
$
$
$
$
Year Ended December 31, 2019
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
186,749
52,895
$
3.53
—
186,749
345
53,240
$
3.51
Year Ended December 31, 2018
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
172,234
52,693
$
3.27
—
172,234
336
53,029
$
3.25
10.
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS
Derivative Instruments - At December 31, 2020, we held purchased natural gas call options for the heating season ending
March 2021, with total notional amounts of 14.7 Bcf, for which we paid premiums of $6.7 million, and which had a fair value
of $0.8 million. At December 31, 2019, we held purchased natural gas call options for the heating season ended March 2020,
with total notional amounts of 14.3 Bcf, for which we paid premiums of $4.4 million, and which had a fair value of
$0.3 million. The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs
in current regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment
mechanisms. Additionally, changes in fair value associated with these contracts are deferred as part of our unrecovered
purchased-gas costs in our consolidated 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 cash
and money market accounts, which we consider to be Level 1. At December 31, 2020, other current and noncurrent assets
included $1.6 million of corporate bonds and $3.2 million of United States treasury notes, for which the fair value approximates
our cost, and are classified as Level 2 and Level 1, respectively. At December 31, 2019, other current and noncurrent assets
included $2.6 million of corporate bonds and $3.0 million of United States treasury notes, for which the fair value approximates
our cost, and are classified as Level 2 and Level 1, respectively.
Short-term notes payable and commercial paper are due upon demand and, therefore, the carrying amounts approximate fair
value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $1.6 billion
and $1.3 billion at December 31, 2020 and 2019, respectively. The estimated fair value of our long-term debt, including current
maturities, was $2.0 billion and $1.5 billion at December 31, 2020 and 2019, respectively. The estimated fair value of our long-
term debt at December 31, 2020 and December 31, 2019, was determined using quoted market prices, and is considered Level
2.
74
11.
REGULATORY ASSETS AND LIABILITIES
The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
Under-recovered purchased-gas costs
Pension and other postemployment benefit costs
Reacquired debt costs
MGP remediation costs
Ad-valorem tax
WNA
Customer credit deferrals
Other
Total regulatory assets, net of amortization
Income tax rate changes (a)
Over-recovered purchased-gas costs
Total regulatory liabilities
Net regulatory assets and liabilities
Remaining
Recovery Period
December 31, 2020
Current
Noncurrent
(Thousands of dollars)
Total
1 year
See Note 14
7 years
15 years
1 year
1 year
1 year
1 to 18 years
(a)
1 year
$ 16,502
16,541
812
98
5,558
4,806
10,267
2,189
56,773
—
(15,761)
(15,761)
$
— $
341,266
4,866
18,711
—
—
—
2,113
366,956
(547,563)
—
(547,563)
16,502
357,807
5,678
18,809
5,558
4,806
10,267
4,302
423,729
(547,563)
(15,761)
(563,324)
$ 41,012
$ (180,607) $ (139,595)
(a) Includes the reclassification of $81.5 million of deferred taxes related to the elimination of state income tax for utilities in Kansas.
Recovery period varies by jurisdiction. See discussion below for additional information regarding our regulatory liabilities related to federal
income tax rate changes.
Remaining
Recovery Period
December 31, 2019
Current
Noncurrent
(Thousands of dollars)
Total
Under-recovered purchased-gas costs
Pension and other postemployment benefit costs
Reacquired debt costs
MGP remediation costs
Ad-valorem tax
Other
Total regulatory assets, net of amortization
Income tax rate changes (a)
Over-recovered purchased-gas costs
WNA
Total regulatory liabilities
Net regulatory assets and liabilities
1 year
See Note 14
8 years
15 years
1 year
1 to 19 years
(a)
1 year
1 year
$ 17,172
21,213
812
98
2,921
5,224
47,440
(10,297)
(27,623)
(7,281)
(45,201)
2,239
$
$
— $
17,172
394,479
6,489
9,807
2,921
7,608
438,476
(513,815)
(27,623)
(7,281)
(548,719)
$ (112,482) $ (110,243)
373,266
5,677
9,709
—
2,384
391,036
(503,518)
—
—
(503,518)
(a) Recovery period varies by jurisdiction. See discussion below for additional information regarding our regulatory liabilities related to
federal income tax rate changes.
Regulatory assets in our consolidated balance sheets, as authorized by various regulatory authorities, are probable of recovery.
Base rates and certain riders are designed to provide a recovery of costs 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 are
subject to review by the respective regulatory authorities during future regulatory proceedings. We are not aware of any
evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to
recover such costs, consistent with our historical recoveries.
Purchased-gas costs represent the natural gas costs that have been over- or under-recovered from customers through the
purchased-gas cost adjustment mechanisms, and includes natural gas utilized in our operations and premiums paid and any cash
settlements received from our purchased natural gas call options.
We amortize reacquired debt costs in accordance with the accounting guidelines prescribed by the OCC and KCC.
75
Weather normalization represents revenue over- or under-recovered through the WNA 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.
The current portion of the regulatory liability for income tax rate changes represents the effect of the Tax Cuts and Jobs Act of
2017. In each state, we received accounting orders requiring us to establish a regulatory liability for the difference in taxes
included in our rates that have been calculated based on a 35 percent federal corporate income tax rate and the new 21 percent
federal corporate income tax rate effective in January 2018 and to refund the reduction in ADIT due to the remeasurement
resulting from the change in the exacted tax rate.
The customer credit deferrals and the noncurrent regulatory liability for income tax rate changes represents deferral of the
effects of enacted federal and state income tax rate changes on our ADIT and the effects of these changes on our rates.
The noncurrent regulatory liability for income tax changes reflects EDIT associated with the remeasurement of our ADIT as a
result of a bill amending the Kansas state income tax code exempting public utilities regulated by the KCC from paying Kansas
state income taxes beginning January 1, 2021, that was signed into law in May 2020 and the Tax Cuts and Jobs Act of 2017.
Our customers began receiving credit for this liability as determined by our regulators in 2019. Our customers receive credit
annually based upon amortization periods in compliance with the tax normalization rules for the portions of EDIT stipulated by
the Code and varying periods of five to ten years for all other components of EDIT. See Note 15 for additional information
regarding our regulatory liabilities for income tax rate changes.
See Note 17 for additional information regarding our regulatory assets for MGP remediation costs.
We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes
certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions
associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be
determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any
amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At
December 31, 2020, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our
business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.
Recovery through rates resulted in amortization of regulatory assets of approximately $3.2 million, $2.5 million and
$1.7 million for the years ended December 31, 2020, 2019 and 2018, respectively. For the years ended December 31, 2020 and
2019, income tax expense reflects credits of $17.4 million and $12.8 million, respectively, for the amortization of the regulatory
liability associated with EDIT that was returned to customers.
12.
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
$
$
$
2019
2020
(Thousands of dollars)
5,517,488
586,360
657,037
77,718
6,838,603
(1,971,546)
4,867,057
5,117,496
549,788
612,984
152,851
6,433,119
(1,867,893)
4,565,226
$
We compute depreciation expense by applying composite, straight-line rates of approximately 2.5 percent to 3.5 percent that
were approved by various regulatory authorities.
76
We recorded capitalized interest of $4.2 million, $4.6 million and $3.4 million for the years ended December 31, 2020, 2019
and 2018, respectively. We incurred liabilities for construction work in process that had not been paid at December 31, 2020,
2019 and 2018 of $24.3 million, $20.9 million and $15.6 million, respectively. Such amounts are not included in capital
expenditures or in the change of working capital items on our Consolidated Statements of Cash Flows.
13.
SHARE-BASED PAYMENTS
The ECP 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. At December 31, 2020, we have
4.3 million shares of common stock reserved for issuance under the ECP. In May 2018, shareholders approved making an
additional 1.8 million shares available under the ECP, less the number of shares remaining available for future grants on the
effective date. At December 31, 2020, we had approximately 1.9 million shares available for issuance under the ECP, which
reflect shares issued and estimated shares expected to be issued upon vesting of outstanding awards granted under the plan, less
forfeitures. The plan allows for the deferral of awards granted in stock or cash, in accordance with the Code section 409A
requirements.
Compensation expense for our share-based payment plans was $7.0 million, net of tax benefits of $2.3 million, for 2020,
$6.8 million, net of tax benefits of $2.2 million, for 2019, and $6.1 million, net of tax benefits of $2.1 million, for 2018.
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. Restricted stock unit awards granted
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 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. 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
expense for these awards being recognized on a straight-line basis over the requisite service period, provided that the requisite
service period is fulfilled, regardless of when, if ever, the market condition is satisfied. The performance stock unit awards
granted accrue dividend equivalents in the form of additional performance stock units prior to vesting. The fair value of these
performance stock units was estimated on the grant date based on a Monte Carlo model. The compensation expense on these
awards will only be adjusted for forfeitures. A forfeiture rate of 3 percent per year based on historical forfeitures under our
share-based payment plans is used.
Restricted Stock Unit Award Activity
As of December 31, 2020, there was $3.1 million of total unrecognized compensation expense related to the nonvested
restricted 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 for restricted stock unit awards outstanding under the respective plans for the
period indicated:
Nonvested at December 31, 2019
Granted
Vested
Forfeited
Nonvested at December 31, 2020
77
Number of
Units
Weighted-
Average Grant
Date Fair Value
72.21
104,398
$
96.21
$
31,233
64.32
(34,066) $
78.89
(1,765) $
82.29
$
99,800
Weighted-average grant date fair value (per share)
Fair value of shares granted (thousands of dollars)
2020
2019
2018
$
$
96.21
3,005
$
$
83.94
3,001
$
$
68.17
2,583
The fair value of restricted stock vested was $3.3 million, $3.3 million, and $4.7 million in 2020, 2019, and 2018, respectively.
Performance Stock Unit Award Activity
As of December 31, 2020, there was $6.7 million of total unrecognized compensation expense 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 in the
valuations of the 2020, 2019 and 2018 grants at the grant date:
Nonvested at December 31, 2019
Granted
Vested
Forfeited
Nonvested at December 31, 2020
Volatility (a)
Dividend yield
Risk-free interest rate (b)
Number of
Units
Weighted-
Average Grant
Date Fair Value
77.58
$
218,176
102.77
$
63,268
68.94
(69,107) $
84.10
(3,817) $
87.97
$
208,520
2020
16.40%
2.25%
1.40%
2019
18.70%
2.38%
2.50%
2018
18.80%
2.70%
2.38%
(a) - Volatility based on historical volatility over three years using daily stock price observations of our peer utilities.
(b) - Using 3-year treasury.
Weighted-average grant date fair value (per share)
Fair value of shares granted (thousands of dollars)
2020
2019
2018
$
$
102.77
6,502
$
$
89.86
6,401
$
$
74.04
5,882
The fair value of performance stock vested was $10.2 million, $12.7 million, and $13.7 million in 2020, 2019, and 2018,
respectively.
Employee Stock Purchase Plan
We have reserved a total of 700 thousand shares of common stock for issuance under our 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 50 percent, 44 percent and 45 percent of employees participated in the plan in 2020, 2019 and
2018, respectively, and purchased 92,507 shares at $64.77 in 2020, 71,613 shares at $71.42 in 2019, and 76,231 shares at
$63.01 in 2018.
Compensation expense, before taxes, was $1.1 million, $1.5 million and $1.0 million in 2020, 2019 and 2018, respectively.
14.
EMPLOYEE BENEFIT PLANS
Defined Benefit Pension and Other Postemployment Benefit Plans
Defined Benefit Pension Plans - We have a defined benefit pension plan and a supplemental executive retirement plan, both of
which are closed to new participants. Certain employees of the Texas Gas Service division are entitled to benefits under a
frozen cash-balance pension plan. 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.
78
Other Postemployment Benefit Plans - We sponsor health and welfare plans that provide postemployment medical and life
insurance benefits to certain employees who retire with at least five years of service. The postemployment medical plan is
contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other
cost-sharing features such as deductibles and coinsurance.
Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit
obligations for pension and postemployment benefits for the periods indicated:
Discount rate - pension plans
Discount rate - other postemployment plans
Compensation increase rate
December 31,
2020
2019
2.80%
2.70%
3.10% - 3.90%
3.50%
3.40%
3.10% - 4.00%
The following table sets forth the weighted-average assumptions used by us to determine the periodic benefit costs for the
periods indicated:
Discount rate - pension plans
Discount rate - other postemployment plans
Expected long-term return on plan assets - pension plans
Years Ended December 31,
2019
4.40%
4.40%
7.20%
2020
3.50%
3.40%
7.20%
2018
3.80%
3.70%
7.25%
Expected long-term return on plan assets - other postemployment plans
Compensation increase rate
7.65%
3.10% - 4.00%
7.35%
3.20% - 4.00%
7.60%
3.25% - 3.35%
We determine our discount rates annually. We estimate our discount rate based upon a comparison of the expected cash flows
associated with our future payments under our defined benefit pension and other postemployment obligations to a hypothetical
bond portfolio created using high-quality bonds that closely match expected cash flows. Bond portfolios are developed by
selecting a bond for each of the next 60 years based on the maturity dates of the bonds. Bonds selected to be included in the
portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue
size, yield outliers and other filtering criteria to remove unsuitable bonds.
We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and
economic growth models. We update our assumed mortality rates to incorporate new tables issued by the Society of Actuaries
as needed.
Regulatory Treatment - The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and
other postemployment benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service,
respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for
defined benefit pension and other postemployment costs. Differences, if any, between the net periodic benefit cost, net of
deferrals, and the amount recovered through rates are reflected in earnings.
We historically have recovered defined benefit pension and other postemployment benefit costs through rates. We believe it is
probable that regulators will continue to include the net periodic pension and other postemployment benefit costs in our cost of
service.
We capitalize all eligible service cost and non-service cost components pursuant to the accounting requirements of ASC Topic
980 (Regulated Operations) for rate-regulated entities, as these costs are authorized by our regulators to be included in
capitalized costs. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset. We
have recognized a regulatory asset of $6.0 million and $4.7 million as of December 31, 2020 and December 31, 2019,
respectively. See Note 11 for additional information.
79
Obligations and Funded Status - The following table sets forth our defined benefit pension and other postemployment benefit
plans, benefit obligations and fair value of plan assets for the periods indicated:
Changes in Benefit Obligation
(Thousands of dollars)
Benefit obligation, beginning of period
$
1,001,368
$
950,510
$
230,490
$
220,144
Pension Benefits
Other Postemployment Benefits
December 31,
December 31,
2020
2019
2020
2019
Service cost
Interest cost
Plan participants’ contributions
Actuarial loss (gain)
Benefits paid
Settlements
12,869
34,179
—
91,566
(62,341)
—
12,030
40,670
—
98,231
(50,915)
(49,158)
Benefit obligation, end of period
1,077,641
1,001,368
1,692
7,557
3,500
14,013
(17,722)
—
239,530
207,182
35,837
2,098
3,500
1,734
9,318
3,697
13,945
(18,348)
—
230,490
176,859
38,772
6,202
3,697
(17,722)
(18,348)
—
230,895
—
207,182
(23,308)
—
(23,308)
(23,308)
907,974
140,939
1,011
—
(62,341)
—
987,583
814,112
162,785
29,199
—
(50,915)
(47,207)
907,974
$
$
$
(90,058) $
(93,394) $
(8,635) $
(1,056) $
(1,045) $
— $
(89,002)
(92,349)
(8,635)
(90,058) $
(93,394) $
(8,635) $
Change in Plan Assets
Fair value of plan assets, beginning of period
Actual return (loss) on plan assets
Employer contributions
Plan participants’ contributions
Benefits paid
Settlements
Fair value of assets, end of period
Benefit Obligation, net at December 31
Current liabilities
Noncurrent liabilities
Benefit Obligation, net at December 31
Benefits paid reflects $12.5 million of lump sum payments to certain terminated-vested participants. During 2019, we
purchased a group annuity contract for $47.2 million, and transferred to a third-party insurance company liabilities of
$49.2 million related to certain participants in our defined benefit pension plan.
The accumulated benefit obligation for our defined benefit pension plans was $1.0 billion and $937.8 million at December 31,
2020 and 2019, respectively. At December 31, 2020 and 2019, the accumulated benefit obligations of each of our plans
exceeded the fair value of the related plan’s assets.
The pension benefit obligations experienced an actuarial loss of $91.6 million and $98.2 million in 2020 and 2019, respectively,
primarily due to the impact of decreases in the discount rates used to calculate the benefit obligations.
In 2021, our contributions are expected to be $1.1 million to our defined benefit pension plans, and no contributions are
expected to be made to our other postemployment benefit plans.
80
Components of Net Periodic Benefit Cost - The following tables set forth the components of net periodic benefit cost, prior to
regulatory deferrals, for our defined benefit pension and other postemployment benefit plans for the period indicated:
Components of net periodic benefit cost
Service cost
Interest cost (a)
Expected return on assets (a)
Amortization of net loss (a)
Net periodic benefit cost
Pension Benefits
Year Ended December 31,
2020
2019
2018
(Thousands of dollars)
$
$
12,869
$
12,030
$
34,179
(61,119)
42,319
40,670
(61,939)
33,039
28,248
$
23,800
$
12,919
36,801
(60,579)
39,913
29,054
(a) These amounts, net of any amounts capitalized as a regulatory asset since adoption of ASU 2017-07 on January 1, 2018, have been
recognized as other income (expense), net in the Consolidated Statements of Income. See Note 16 for additional detail of our other income
(expense), net.
Components of net periodic benefit cost
Service cost
Interest cost (a)
Expected return on assets (a)
Amortization of unrecognized prior service cost (a)
Amortization of net loss (a)
Net periodic benefit cost (credit)
Other Postemployment Benefits
Year Ended December 31,
2020
2019
2018
(Thousands of dollars)
$
$
1,692
$
1,734
$
7,557
(15,469)
(117)
173
9,318
(12,586)
(673)
2,244
(6,164) $
37
$
2,354
9,117
(14,284)
(4,567)
3,887
(3,493)
(a) These amounts, net of any amounts capitalized as a regulatory asset since adoption of ASU 2017-07 on January 1, 2018, have been
recognized as other income (expense), net in the Consolidated Statements of Income. See Note 16 for additional detail of our other income
(expense), net.
Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income
(loss), net of regulatory deferrals, related to our defined benefit pension benefits for the period indicated:
Net gain (loss) arising during the period
Amortization of loss
Deferred income taxes
Total recognized in other comprehensive income (loss)
Pension Benefits
Year Ended December 31,
2020
2019
2018
$
$
(Thousands of dollars)
(2,519) $
(2,766) $
1,192
289
852
479
(1,038) $
(1,435) $
1,173
1,082
(848)
1,407
Due to our regulatory deferrals, there were no amounts recognized in other comprehensive income (loss) related to our other
postemployment benefits for the periods presented.
81
The tables below set forth the amounts in accumulated other comprehensive loss that had not yet been recognized as
components of net periodic benefit expense for the periods indicated:
Accumulated loss
Accumulated other comprehensive loss
before regulatory assets
Regulatory asset for regulated entities
Accumulated other comprehensive loss
after regulatory assets
Deferred income taxes
Accumulated other comprehensive loss,
net of tax
Prior service credit
Accumulated loss
Accumulated other comprehensive loss
before regulatory assets
Regulatory asset for regulated entities
Accumulated other comprehensive loss
after regulatory assets
Pension Benefits
December 31,
2020
2019
(Thousands of dollars)
(351,059) $
(351,059)
341,125
(9,934)
2,157
(7,777) $
Other Postemployment Benefits
December 31,
2020
2019
(Thousands of dollars)
85
$
(13,134)
(13,049) $
13,049
— $
(381,633)
(381,633)
373,025
(8,608)
1,869
(6,739)
202
(19,660)
(19,458)
19,458
—
$
$
$
$
$
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
2020
6.25%
4.50%
2026
2019
6.50%
5.00%
2025
82
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 funded status of the defined benefit pension plan increases. 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:
Investment-grade bonds
U.S. large-cap equities
Alternative investments
Developed foreign large-cap equities
Mid-cap equities
Emerging markets equities
Small-cap equities
Total
40.0 %
18.0 %
14.0 %
10.0 %
7.0 %
6.0 %
5.0 %
100 %
As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above.
All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of
indexing purposes, are prohibited from owning our stock.
The current target allocation for the assets of our other postemployment benefits plan is 30 percent fixed income securities and
70 percent equity securities.
The following tables set forth our pension benefits and other postemployment benefits plan assets by fair value category as of
the measurement date:
Pension Benefits
December 31, 2020
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
$
392,639 $
35,454 $
— $
—
—
1,589
—
—
78,080
343,118
23,311
—
1,155
—
—
—
24,603
87,634
428,093
78,080
343,118
24,900
24,603
88,789
$
394,228 $
481,118 $
112,237 $
987,583
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category primarily represents money market funds.
(d) - This category represents alternative investments such as hedge funds and other financial instruments.
83
Pension Benefits
December 31, 2019
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
$
323,737 $
27,267 $
— $
—
—
1,687
—
—
54,726
304,457
87,422
—
897
—
—
—
25,988
81,793
351,004
54,726
304,457
89,109
25,988
82,690
$
325,424 $
474,769 $
107,781 $
907,974
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category primarily represents money market funds.
(d) - This category represents alternative investments such as hedge funds and other financial instruments.
Other Postemployment Benefits
December 31, 2020
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 (d)
Total assets
$
$
73,578 $
—
—
52
—
— $
—
39,115
8,071
110,079
— $
—
—
—
—
73,630 $
157,265 $
— $
73,578
—
39,115
8,123
110,079
230,895
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category primarily represents money market funds.
(d) - This category includes equity securities and bonds held in a captive insurance product.
84
Other Postemployment Benefits
December 31, 2019
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 (d)
Total assets
$
$
61,688 $
—
—
18,350
—
— $
—
26,852
682
99,610
— $
—
—
—
—
61,688
—
26,852
19,032
99,610
80,038 $
127,144 $
— $
207,182
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category primarily represents money market funds.
(d) - This category includes equity securities and bonds held in a captive insurance product.
Insurance contracts and group annuity contracts include investments in the Immediate Participation Guarantee Fund (“IPG
Fund”) with John Hancock and are valued at fair value. John Hancock invests the IPG Fund in its general fund portfolio. The
contract value of the IPG Fund at the end of the year, which approximates fair value, is estimated. The difference between this
estimated balance and the actual balance, as subsequently determined by John Hancock, is charged or credited to the net assets
of the plans.
Certain investments that are categorized as money market funds in Level 2 and “Other investments” in Level 3 represent
alternative investments such as hedge funds and other financial instruments measured using the net asset value per share (or its
equivalent) practical expedient.
The following tables set forth additional information regarding commitments and redemption limitations of these other
investments at the periods indicated:
Grosvenor Registered Multi Limited Partnership
K2 Institutional Investors II Limited Partnership
Grosvenor Registered Multi Limited Partnership
K2 Institutional Investors II Limited Partnership
December 31, 2020
Unfunded
Commitments
Redemption
Frequency
Fair Value
(in thousands)
42,632 $
45,002 $
— quarterly
— quarterly
December 31, 2019
Unfunded
Commitments
Redemption
Frequency
Fair Value
(in thousands)
40,577 $
41,215 $
— quarterly
— quarterly
$
$
$
$
Redemption
Notice Period
(in days)
65
91
Redemption
Notice Period
(in days)
65
91
85
The following table sets forth the reconciliation of Level 3 fair value measurements of our pension plans for the periods
indicated:
January 1, 2019
Unrealized gains
Unrealized (losses)
Settlements
December 31, 2019
Unrealized gains
Purchases
Settlements
December 31, 2020
Pension Benefits
Insurance
Contracts
Other
Investments
Total
(Thousands of dollars)
30,445
$
79,205
$
109,650
—
(860)
(3,597)
2,588
—
—
2,588
(860)
(3,597)
25,988
$
81,793
$
107,781
1,764
—
(3,149)
4,849
992
—
6,613
992
(3,149)
24,603
$
87,634
$
112,237
$
$
$
Pension and Other Postemployment Benefit Payments - Benefit payments for our defined benefit pension and other
postemployment benefit plans for the period ended December 31, 2020 were $62.3 million and $17.7 million, respectively. The
following table sets forth the pension benefits and other postemployment benefits payments expected to be paid in 2021-2030:
Benefits to be paid in:
(Thousands of dollars)
Pension
Benefits
Other Postemployment
Benefits
2021
2022
2023
2024
2025
2026 through 2030
$
$
$
$
$
$
51,127
51,945
52,810
53,633
54,498
279,689
$
$
$
$
$
$
16,032
15,987
15,853
15,487
15,262
70,385
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31,
2020, 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 eligible compensation, subject to certain limits.
Our contributions made to the plan were $13.8 million, $12.8 million and $12.1 million in 2020, 2019 and 2018, respectively.
Profit-Sharing Plan - We have a profit-sharing plan for all employees who do not participate in our defined benefit pension
plan. We plan to make a contribution to the profit-sharing plan each quarter equal to 1 percent of each participant’s eligible
compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year.
Employee contributions are not allowed under the plan. Our contributions made to the plan were $9.4 million, $8.5 million and
$7.4 million in 2020, 2019 and 2018, respectively.
86
15.
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
2020
Years Ended December 31,
2019
(Thousands of dollars)
2018
$
$
20,129
2,965
23,094
10,757
7,728
18,485
41,579
$
$
24,537
5,008
29,545
8,375
4,932
13,307
42,852
$
$
—
289
289
42,413
10,829
53,242
53,531
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
EDIT not recovered in rates
Amortization of EDIT regulatory liability
Tax benefit of employee share-based compensation
Other, net
Total provision for income taxes
$
$
Years Ended December 31,
2019
(Thousands of dollars)
$
229,601
$
2018
225,765
2020
237,991
21 %
21 %
21 %
49,978
10,693
—
(17,031)
(1,489)
(572)
41,579
48,215
9,758
—
(12,828)
(2,116)
(177)
42,852
$
$
47,411
8,783
74
—
(2,770)
33
53,531
As of December 31, 2020, we have no uncertain tax positions. Changes in tax laws or tax rates are recognized in the financial
reporting period that includes the enactment date. As a regulated entity, the change in ADIT resulting from a change in tax laws
or tax rates is recorded as a regulatory liability and is subject to refund to our customers.
In May 2020, a bill amending the Kansas state income tax code was signed into law that exempts public utilities regulated by
the KCC from paying Kansas state income taxes beginning January 1, 2021. As a result of the enactment of this legislation, we
remeasured our ADIT. As a regulated entity, the reduction in ADIT of $81.5 million was recorded as an EDIT regulatory
liability and will be refunded to our customers. This adjustment had no material impact on our income tax expense and no
impact on our cash flows for the year ended December 31, 2020. The bill stipulates that, if requested by the utility, this EDIT
will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next
general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates to
reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the
reduction, effective January 1, 2021.
87
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
Regulatory adjustments for enacted tax rate changes
Net operating loss
Lease obligation basis
Other
Total deferred tax assets
Deferred tax liabilities
Excess of tax over book depreciation
Purchased-gas cost adjustment
Other regulatory assets and liabilities, net
Right-of-use asset basis
Total deferred tax liabilities
Net deferred tax liabilities
December 31,
2019
2020
(Thousands of dollars)
$
$
28,127
121,738
—
9,319
4,790
163,974
717,492
5,240
88,260
9,788
820,780
656,806
$
$
32,036
124,680
752
8,599
2,772
168,839
742,860
3,556
96,456
8,599
851,471
682,632
As of December 31, 2020, we have no federal or state income tax NOL carryforwards.
We have filed our consolidated federal and state income tax returns for years 2017, 2018 and 2019. We are no longer subject to
income tax examination for years prior to 2017.
16.
OTHER INCOME AND OTHER EXPENSE
The following table sets forth the components of other income and other expense for the periods indicated:
Net periodic benefit cost other than service cost
Earnings (losses) on investments associated with nonqualified employee benefit
plans
Other, net
Total other expense, net
Years Ended December 31,
2020
2019
2018
(Thousands of dollars)
(5,071) $
(5,895) $
(8,824)
4,616
(2,565)
5,268
(2,349)
(1,343)
(1,192)
(3,020) $
(2,976) $
(11,359)
$
$
88
17.
COMMITMENTS AND CONTINGENCIES
Commitments - See Note 6 of the Notes to Consolidated Financial Statements in this Annual Report for discussion of
operating leases.
COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have
implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and
communities. As ordered by our regulators, customer disconnects for nonpayment were suspended from mid-March through
May 20, 2020, in Oklahoma, through May 31, 2020, in Kansas, and through December 31, 2020, in some areas of Texas. As of
December 31, 2020, we have temporarily suspended disconnects for safety reasons in all of our jurisdictions due to the level of
COVID-19 infection. Since the onset of the pandemic in the first quarter of 2020, we have experienced impacts on our results
of operations including, but not limited to: lower late payment, reconnect and collection fees and incremental expenses for bad
debts related to the suspensions of disconnects for nonpayment; incremental expenses for PPE, cleaning supplies, outside
services and other expenses; and lower expenses for travel and employee training that have been impacted by the pandemic. We
have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes
certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions
associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be
determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any
amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At
December 31, 2020, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our
business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable. Going
forward, we expect continuing impacts on our revenues and expenses during the course of the pandemic. We also could
experience a possible reduction in revenues from commercial and transportation customers temporarily or permanently
impacted by the pandemic.
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 or the discovery of presently unknown
environmental conditions 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 and results of operations. Our expenditures for environmental
investigation, and remediation 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 2020, 2019 or 2018.
We own or retain legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. These sites
contain contaminants generally associated with MGP sites and are subject to control or remediation under various
environmental laws and regulations. A consent agreement with the KDHE governs all environmental investigation and
remediation work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation
activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of
contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. Regulatory
closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result
in additional costs.
We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and
remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net
of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-
year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a
determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of
any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to
increase the $15.0 million cap. At December 31, 2020 and 2019, we have deferred $18.8 million and $9.8 million, respectively,
for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon
as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2021.
89
We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor
groundwater at eight of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a
source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had
previously occurred. A remediation plan was submitted to the KDHE concerning this site in 2020 and the KDHE has provided
comments that we are addressing. We are also working on a remediation plan that will be submitted to the KDHE in 2021 for
an additional site.
As a result of our work to investigate and remediate the environmental impacts of our MGP sites in 2020, we estimated the
potential costs associated with additional investigation and remediation to be in the range of $9.1 million to $23.3 million. A
single reliable estimate of the remediation costs for these sites was not feasible due to the amount of uncertainty in the ultimate
remediation approach that will be utilized. Accordingly, in 2020, we recorded an adjustment to our reserve of $9.1 million,
which also increased our regulatory asset pursuant to our AAO in Kansas, as we believe recovery of these costs is probable
through our existing AAO or future regulatory filings. At December 31, 2020 and 2019, the reserve for remediation of our
MGP sites was $14.5 million and $5.8 million, respectively.
We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request
of the Texas Commission on Environmental Quality, we began investigating the level and extent of contamination associated
with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains
contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws
and regulations. Until the investigation is complete, we are unable to determine what, if any, active remediation will be
required. A reliable estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to
the levels and extent of contamination.
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 2020, 2019 or 2018.
We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding
the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such
laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation
and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase
in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and
those costs may adversely affect our financial condition, results of operations and cash flows. We do not expect expenditures
for these matters to have a material adverse effect on our financial condition, results of operations or cash flows.
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations
require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline
segments that pass through densely populated areas or near specifically designated HCAs. 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
HCAs;
a verification of records for pipelines in class 3 and 4 locations and HCAs to confirm MAOPs; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in HCAs.
In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to
revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals
included changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment
period ended July 7, 2016, and comments were reviewed by PHMSA. As part of the comment review process, PHMSA was
advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily
mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews
PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality
of each proposal. The GPAC met six times since January 2017 to review public comments and make recommendations to
PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering pipelines. The GPAC
met in June 2019 on gas gathering pipelines. In addition to reviewing public and committee comments, PHMSA announced
they would split this NPRM into three separate final rulemakings:
90
•
•
•
the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation
Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment
Requirements, and Other Related Amendments;
the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management
Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all
remaining elements of the NPRM (except for gas gathering pipelines); and
the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.
A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations
filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas
transmission and gathering pipelines.
On October 1, 2019, PHMSA published the first of the three final rules referenced above, which addressed the 2011
congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to
collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline,
and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP
within 15 years. The first final rule became effective July 1, 2020. The estimated capital and operating expenditures associated
with compliance with the first final rulemaking were not material.
PHMSA has not yet issued the second final rule. The potential capital and operating expenditures associated with compliance
with this rule are currently being evaluated and could be significant depending on the final regulation. We do not expect to be
impacted by the third final rule, as we do not own gas gathering pipelines.
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.
91
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, 2020.
The effectiveness of our internal control over financial reporting as of December 31, 2020, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included
herein (Item 8).
Changes in Internal Control Over Financial Reporting
In response to the COVID-19 pandemic, we have required employees, some of whom are involved in the operation of our
internal controls over financial reporting, to work remotely. Despite working remotely, there have been no changes in our
internal control over financial reporting during the quarter ended December 31, 2020, 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 2021 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 2021 definitive Proxy Statement and is
incorporated herein by this reference.
92
Code of Ethics
Information concerning the code of ethics, or code of business conduct, is set forth in our 2021 definitive Proxy Statement and
is incorporated herein by this reference.
Nominating Procedures
Information concerning the nominating procedures is set forth in our 2021 definitive Proxy Statement and is incorporated
herein by this reference.
The Audit Committee
Information concerning the Audit Committee is set forth in our 2021 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 2021 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 2021 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 2021 definitive Proxy Statement and is
incorporated herein by this reference.
The Executive Committee
Information concerning the Executive Committee is set forth in our 2021 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 2021 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 2021 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 2021 definitive Proxy Statement and is
incorporated herein by this reference.
93
Equity Compensation Plan Information
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2020:
Number of Securities Issued
Upon Exercise of Outstanding
Options, Warrants and Rights
(a)
Weighted-Average Exercise
Price of Outstanding Options,
Warrants and Rights
(b)
Number of Securities
Remaining Available For
Future Issuance Under Equity
Compensation Plans
(Excluding Securities in
Column (a))
(c)
— $
— $
— $
— (3)
—
—
2,942,946
1,812
2,944,758
Plan Category
Equity compensation plans approved
by security holders (1)
Equity compensation plans not
approved by security holders (2)
Total
(1) Includes shares granted under our ESPP and restricted stock incentive units and performance-unit awards granted under our ECP and our Deferred
Compensation Plan for Non-employee Directors. For a brief description of the material features of this plan, see Note 13 of the Notes to Consolidated
Financial Statements in this Annual Report. Column (c) includes 143,990 and 2,798,956 shares available for future issuance under our ESPP and our ECP and
Deferred Compensation Plan for Non-employee Directors, respectively.
(2) Includes the Employee Stock Award Program. No shares under the Employee Stock Award Program have been issued since May 2017, and the Company
does not intend to issue any further shares thereunder.
(3) Compensation deferred into our common stock under our ECP and Deferred Compensation Plan for Non-employee Directors is distributed to participants
at fair market value on the date of distribution. The price used to calculate the weighted-average exercise price in the table is $76.77, 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 2021 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 2021 definitive Proxy Statement and is
incorporated herein by this reference.
94
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV.
(1) Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Page No.
52-53
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018
54
Consolidated Statements of Comprehensive Income for the years ended December 31, 2020,
2019 and 2018
55
Consolidated Balance Sheets as of December 31, 2020 and 2019
56-57
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018 59
Consolidated Statements of Equity for the years ended December 31, 2020, 2019 and 2018
60-61
Notes to Consolidated Financial Statements
62-91
(2) Consolidated Financial Statements Schedules
All schedules have been omitted because of the absence of conditions under which they are required.
(3) Exhibits
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
Amended and Restated Certificate of Incorporation of ONE Gas, Inc., dated May 24, 2018 (incorporated by
reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on May 30, 2018 (File No.
1-36108)).
Amended and Restated By-Laws of ONE Gas, Inc. dated April 27, 2020 (incorporated by reference to
Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on April 27, 2020 (File No. 1-36108)).
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, with respect to the 2.070% Senior Notes due 2019, the 3.610% Senior Notes due
2024 and the 4.685% Senior Notes due 2044-(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)).
Supplemental Indenture No. 2, dated November 5, 2018, among ONE Gas, Inc. and U.S. Bank National
Bank Association, as trustee, with respect to the 4.50% Notes due 2048 (incorporated by reference to Exhibit
4.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 6, 2018 (File No. 1-36108)).
Supplemental Indenture No. 3, dated May 4, 2020, among ONE Gas, Inc. and U.S. Bank National Bank
Association, as trustee, with respect to the 2.00% Notes due 2030 (incorporated by reference to Exhibit 4.2 to
ONE Gas, Inc.’s Current Report on Form 8-K filed on May 4, 2020 (File No. 1-36108)).
Description of the Registrant’s securities registered pursuant to Section 12 of the Securities Act of 1934.
95
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
10.14
10.15
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. 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. 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, as amended and restated effective December 1,
2017 (incorporated by reference to Exhibit 10.8 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on
February 22, 2018 (File No. 1-36108)).
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, as amended and restated effective December 1, 2017
(incorporated by reference to Exhibit 10.11 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on
February 22, 2018 (File No. 1-36108)).
Form of 2019 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.12 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 20, 2019 (File No. 1-36108)).
Form of 2019 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.13 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 20, 2019 (File No. 1-36108)).
Form of 2018 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.14 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 22, 2018 (File No. 1-36108)).
Form of 2018 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.15 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 22, 2018 (File No. 1-36108)).
Extension Agreement dated as of October 5, 2018, among ONE Gas, Inc., Bank of America, N.A., as
administrative agent, swing line lender, a letter of credit issuer and a lender, and the other lenders and letter
of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONE Gas Inc’s Current Report
on Form 8-K filed on October 5, 2018 (File No. 1-36108)).
ONE Gas, Inc. Amended and Restated Employee Stock Purchase Plan (incorporated by reference to Exhibit
10.16 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 20, 2020 (File No. 1-36108)).
ONE Gas, Inc. Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to
Exhibit 10.19 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 23, 2017 (File No.
1-36108)).
Credit Agreement, dated as of April 7, 2020, among ONE Gas, Inc., Bank of America, N.A., as
administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to ONE
Gas, Inc.’s Current Report on Form 8-K filed on April 7, 2020 (File No. 1-36108)).
96
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
Form of Commercial Paper Dealer Agreement (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s
Current Report on Form 8-K filed on September 10, 2014 (File No. 1-36108)).
Form of 2020 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.20 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 20, 2020 (File No. 1-36108)).
Form of 2020 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.21 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 20, 2020 (File No. 1-36108)).
Equity Distribution Agreement, dated as of February 26, 2020, among ONE Gas, Inc. and Morgan Stanley &
Co. LLC, BofA Securities, Inc., and Mizuho Securities USA LLC, acting as managers; Morgan Stanley &
Co. LLC, Bank of America, N.A. and Mizuho Securities Americas LLC, acting as forward purchasers; and
Morgan Stanley & Co. LLC, BofA Securities, Inc. and Mizuho Securities USA LLC, acting as forward
sellers (incorporated by reference to Exhibit 1.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on
February 26, 2020 (File No. 1-36108)).
Form of Master Forward Sale Confirmation (incorporated by reference to Exhibit 1.2 to ONE Gas, Inc.’s
Current Report on Form 8-K filed on February 26, 2020 (File No. 1-36108)).
Form of 2017 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 23, 2017 (File No. 1-36108)).
Form of 2017 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 23, 2017 (File No. 1-36108)).
Amended and Restated Credit Agreement, dated as of October 5, 2017, 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 10.1 to ONE Gas, Inc.’s
Current Report on Form 8-K filed on October 6, 2017 (File No. 1-36108)).
ONE Gas, Inc. Nonqualified Deferred Compensation Plan, as amended and restated effective January 1,
2018 (incorporated by reference to Exhibit 10.28 to ONE Gas, Inc.’s Annual Report on Form 10-K filed
February 22, 2018 (File No. 1-36108)).
First Amendment and Extension Agreement, dated as of October 4, 2019, among ONE Gas, Inc., Bank of
America, N.A., as administrative agent, swing line lender, a letter of credit issuer and a lender, and the other
lenders and letter of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONE Gas,
Inc.’s Current Report on Form 8-K filed on October 4, 2019 (File No. 1-36108)).
ONE Gas, Inc. Amended and Restated Equity Compensation Plan (2018) (incorporated by reference to
Appendix A to ONE Gas, Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 4, 2018 (File
No. 1-36108)).
ONE Gas, Inc. Amended and Restated Annual Officer Incentive Plan, effective January 1, 2020
(incorporated by reference to Exhibit 10.31 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on
February 20, 2020 (File No. 1-36108)).
Form of 2021 Restricted Unit Award Agreement.
Form of 2021 Performance Unit Award Agreement.
Form of 2020 Restricted Unit Award Agreement dated July 2020
ONE Gas Inc. Annual Officer Incentive Plan, effective January 1, 2019 (incorporated by reference to Exhibit
10.30 to ONE Gas, Inc.’s Annual Report on Form 10-K filed February 20, 2019 (File No. 1-36108)).
97
10.32
21.1
23.1
31.1
31.2
32.1
32.2
Credit Agreement, dated as of February 22, 2021, among ONE Gas, Inc., the lenders from time to time party
thereto and Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to
ONE Gas Inc.’s Current Report on Form 8-K filed on February 22, 2021 (File No. 1-36108)).
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 Caron A. Lawhorn 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 Caron A. Lawhorn 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)).
101.INS
XBRL Instance Document - the instance document does not appear in the Interactive Data File because its
XBRL tags are embedded within the Inline XBRL 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.
104
Cover Page Interactive Data File (embedded within the Inline XBRL document and contained in Exhibit
101).
Attached as Exhibit 101 to this Annual Report are the following XBRL-related documents: (i) Document and Entity
Information; (ii) Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018; (iii) Consolidated
Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018; (iv) Consolidated Balance
Sheets as of December 31, 2020 and 2019; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2020,
2019 and 2018; (vi) Consolidated Statements of Equity for the years ended December 31, 2020, 2019 and 2018; and (vii) Notes
to Consolidated Financial Statements.
We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report.
ITEM 16.
FORM 10-K SUMMARY
None.
98
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.
Signatures
Date: February 26, 2021
ONE Gas, Inc.
Registrant
By:
/s/ Caron A. Lawhorn
Caron A. Lawhorn
Senior Vice President and
Chief Financial Officer
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 26th day of February 2021.
/s/ John W. Gibson
John W. Gibson
Chairman of the Board
/s/ Caron A. Lawhorn
Caron A. Lawhorn
Senior Vice President and
Chief Financial Officer
/s/ Robert B. Evans
Robert B. Evans
Director
/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/ Jeffrey J. Husen
Jeffrey J. Husen
Vice President, Chief Accounting Officer
and Controller
(Principal Accounting Officer)
/s/ Tracy E. Hart
Tracy E. Hart
Director
/s/ Pattye L. Moore
Pattye L. Moore
Director
/s/ Douglas H. Yaeger
Douglas H. Yaeger
Director
99
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
EQ Shareowner Services
P.O. Box 64874
St. Paul, MN 55164-0856
P: 855-217-6403
P: (Outside U.S.) 651-450-4064
TDD number: 651-450-4144
www.shareowneronline.com
DIRECT STOCK PURCHASE &
DIVIDEND REINVESTMENT PLAN
ONE Gas’ Direct Stock Purchase and Dividend
Reinvestment Plan provides new investors
and current shareholders a convenient way to
purchase ONE Gas common stock without paying
processing fees or service charges and to reinvest
cash dividends.
For more information or to enroll in a plan, call EQ
at 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 27, 2021 – 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: A3 (Negative)
Standard & Poor’s: BBB+ (Negative)
ONE Gas Investor Relations
P.O. Box 21049
Tulsa, OK 74121
P: 855-496-0200
E: IR@onegas.com
Non-GAAP Information
ONE Gas has disclosed in this annual report net margin, which
is a non-GAAP financial measure.
Net margin is defined as total revenues less cost of natural
gas. Cost of natural gas includes commodity purchases, fuel,
storage, transportation and other gas purchase costs recovered
through our cost of natural gas regulatory mechanisms, as
required by our regulators, and does not include an allocation
of general operating costs or depreciation and amortization. In
addition, our cost of natural gas regulatory mechanisms provide
a method of recovering natural gas costs on an ongoing basis
without a profit. Therefore, although our revenues will fluctuate
with the cost of natural gas that we pass through to our
customers, net margin is not affected by fluctuations in the cost
of natural gas. We believe that net margin provides investors
a more relevant and useful measure to analyze our financial
performance as a 100-percent regulated natural gas utility than
total revenues because the change in the cost of natural gas
from period to period does not impact our operating income.
Net margin should not be considered in isolation or as a
substitute for total revenue or any other measure of financial
performance presented in accordance with GAAP. Additionally,
our calculation may not be comparable with similarly titled
measures of other companies.
15 East Fifth Street, Tulsa, OK 74103 • 918-947-7000 • ONEGas.com