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15 East Fifth Street, Tulsa, OK 74103 • 918-947-7000 • ONEGas.com
Annual Report 2019
DELIVERING NATURAL GASFOR A BETTER TOMORROW O NE 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:
Kansas Gas Service
the largest in Kansas
Oklahoma Natural Gas
the largest in Oklahoma
Texas Gas Service
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.
We primarily serve residential, commercial and transportation
customers in all three states.
ONEGas.com
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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 21, 2020 – 9 a.m. CDT
Auditors
PricewaterhouseCoopers LLP
Two Warren Place
6120 South Yale Avenue, Suite 1850
Tulsa, OK 74136
Corporate Headquarters
First Place Tower
15 East Fifth Street
Tulsa, OK 74103
Credit Ratings
Moody’s: A2 (Stable)
Standard & Poor’s: A (Stable)
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.
Non-GAAP Reconciliation
2019
2018
2017
Years Ended December 31,
Total revenues
Cost of natural gas
Net margin
(Millions of dollars)
$ 1,652.7
$ 1,633.7
$ 1,539.6
687.9
714.6
614.5
$ 964.8
$ 919.1
$ 925.1
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 stake-
holders.
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.
Delivering Natural Gas
For a Better Tomorrow
To Our Fellow Shareholders:
At ONE Gas, our mission is to deliver natural gas
for a better tomorrow. As one of the largest publicly
traded natural gas distribution companies, our focused
business strategy offers a clear mission, vision, strategy
and values-driven culture that enables us to deliver a
safe, reliable and affordable energy choice to 2.2 million
customers each day.
2019 Performance at a Glance
We had the sixth consecutive year of successfully
executing on our business strategy while delivering value
for shareholders. In 2019, diluted earnings per share
increased approximately 9% to $3.51. We increased
our dividends by 8% over dividends paid in 2018. Total
shareholder return was up 20% in 2019, up 156% since
our spinoff as a new company in 2014, and for two
years in a row, the average customer’s bill has remained
relatively flat.
We measure the value we create with the same five key
themes each year: safety, a high-performing workforce,
leveraging technology, growth and regulatory strategy.
Safety is our number one core value and at the
foundation of everything we do. This commitment has
resulted in the lowest number of safety incidents in our
company’s history in 2019, as measured through national
metrics reported by the American Gas Association.
During the year, we improved our personal safety metrics
of Total Recordable Incident Rate (TRIR) by 17%, our
Days Away, Restricted or Transferred (DART) by 42%
and held our Preventable Vehicle Incident Rate (PVIR)
steady at an all-time company low. We also added a new
public safety metric in 2019 with the goal of reducing
response time to emergency calls. We remain committed
to refining our processes and procedures to produce zero
harm to our employees, customers and the public.
Advancing a safe, ethical, inclusive and diverse culture
for our 3,600 employees creates a high-performing
workforce and an environment where top talent wants
to work. It also creates engaged employees who care
as much about one another as they do the customers
we serve. In 2019, we again had record-breaking
participation in our employee engagement survey, with
more than 90% of employees providing feedback. The
scores were again among the highest in our company’s
history and for our industry.
By leveraging technology, we focused on reducing
risk and expenses while making it easier to do business
with us. We were able to optimize how we manage
service orders and thereby reduced our response times
and lowered costs. We leveraged data-driven systems to
evaluate priority and distance resulting in more work
orders completed and fewer miles driven.
2019 HIGHLIGHTS
Earnings Per Share
$3.51
compared with
$3.25 in 2018
Net Income Increased to
$187 million $465 million
compared with
$172 million in 2018
in capital investments
70% for system integrity
and reliability
Enhancements for customers include improvements
to our interactive voice response (IVR) system, which
resulted in a 10% lower call volume to our customer
service representatives in 2019. In addition to more
self-service options, we also have more than one-third of
our customers signed up for electronic statements. This
reduces our cost and our impact on the environment.
We continue to manage our capital plan by paying
attention to the condition of our system, construction
resources, credit metrics and customer bill impacts. In
2019, we invested $465 million of capital, of which
70% was for system reliability improvements and
infrastructure replacement.
With these investments, we replaced 430 miles of
distribution mains, service lines and transmission lines
that included 197 miles of vintage pipelines. We also
completed our five-year accelerated cast iron replacement
program ahead of schedule, a huge milestone for our
company. We will now turn our attention to the other
vintage pipe materials remaining in our system. With
the remaining vintage materials left to replace, we
have a 20-plus-year runway to deploy our capital. Our
ongoing investment also results in new customer
growth. In 2019, we added 15,000 net new customers
compared to 2018.
Our success as a company is also based on maintaining
collaborative relationships with our regulators. Our
regulatory strategy ensures we provide the most cost-
effective, safe and reliable service as our customer base
grows. We ended the year with an average rate base of
$3.62 billion, with 42% of that in Oklahoma, 29% in
Kansas and 29% in Texas.
With the arrival of a new decade, we look ahead to our
opportunities to implement solutions that continue our
focus on safety, reliability and reducing emissions. The
solutions for achieving zero emissions while providing
reliable service and keeping energy affordable continues
to evolve. We have great conviction that natural gas
and natural gas distribution assets will continue to be
a significant part of the solution to achieve emissions
reductions. We invite you to learn more about our
environmental, social and governance (ESG) strategy in
our ONE Gas Corporate Responsibility Report at
www.onegas.com/sustainability.
Our story is a simple one. The strategy is effective, and
we remain committed to it. We can proudly reflect on all
that we’ve accomplished from when we first spun off in
2014. Our exceptional employees have and will continue
to make it possible to execute our business strategy. We
thank them for living out our core values and for serving
our customers and our communities every day.
As we transition into 2020, the world is facing
circumstances that have rarely presented themselves in
history. The 2020 COVID-19 pandemic has demanded
leadership that demonstrates compassion, trust, stability
and hope for the future. Be assured as a stakeholder
in ONE Gas, our focused strategy and values have
guided and will continue to guide our response to
these unique challenges as the COVID-19 pandemic
continues to evolve. The safety of our employees and our
customers remains our top priority. We will continue
to take proactive precautionary measures to protect our
employees, serve our customers and operate our business
at the highest level.
Thank you for your confidence and trust in ONE Gas.
John W. Gibson
Pierce H. Norton II
Chairman
ONE Gas, Inc.
President and CEO
ONE Gas, Inc.
2019 HIGHLIGHTS
15,000 $2.5 million 430 miles
net new customers
in ONE Gas Foundation grants
and community giving
of distribution mains, service
lines and transmission lines
replaced.
FINANCIAL OVERVIEW
We reported 2019 net income of $187 million,
or $3.51 per diluted share, compared with $172
million, or $3.25 per diluted share, in 2018; and
2019 capital expenditures and asset removal costs
of $465 million, compared with $447 million in
2018. Our 2019 net margin increased by $45.7
million compared with last year, which primarily is
reflected by new rates in our service territories along
with an increase in our average residential customer
count in Oklahoma and Texas.
In 2020, our diluted earnings per share performance
is expected to be within a range of $3.44 to $3.68
per share. Our 2020 capital expenditures and asset
removal costs are expected to be approximately
$475 million.
On Jan. 21, 2020, the ONE Gas Board of Directors
increased the quarterly dividend by 4 cents per
share to 54 cents per share, effective for first-quarter
2020, resulting in an annualized dividend of $2.16
per share.
Our average annual dividend growth rate is expected
to increase 6% to 8% between 2019 and 2024 with
a targeted dividend payout ratio of 55% to 65% of
net income, all subject to board approval.
HIGHLIGHTS
2019
2018
2017
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
$1,652,730
$1,633,731
$1,539,633
$186,749
$172,234
$162,995
$3.53
$3.51
$2.00
$3.27
$3.25
$1.84
$3.10
$3.08
$1.68
$964,756
$919,095
$925,132
396.4
10,490
9,828
2,194
3,600
392.5
10,521
9,959
2,179
3,500
343.7
8,184
9,938
2,166
3,500
Market Value Per Share: Year-end Closing Price
$93.57
$79.60
$73.26
Average Shares of Common Stock, Outstanding (thousands):
Basic
Diluted
*See discussion of non-GAAP financial measure inside back cover.
52,895
53,240
52,693
53,029
52,527
52,979
BOARD OF DIRECTORS
Michael G. Hutchinson
Retired Partner
Deloitte & Touche
Eduardo A. Rodriguez
President
Strategic Communication
Consulting Group
Robert B. Evans
Retired President and Chief
Executive Officer
Duke Energy Americas
Tracy E. Hart
President and Chief Executive
Officer
Tarlton Corporation
John W. Gibson
Chairman
ONE Gas, Inc.
Pierce H. Norton II
President and Chief Executive
Officer
ONE Gas, Inc.
Pattye L. Moore
Retired Board Chair and Interim
Chief Executive Officer
Red Robin Gourmet Burgers
Douglas H. Yaeger
Retired Chairman, President
and Chief Executive Officer
The Laclede Group, Inc.
(Spire, Inc.)
EXECUTIVE TEAM
As of April 1, 2020
Pierce H. Norton II, 60
President and
Chief Executive Officer
Caron A. Lawhorn, 59
Senior Vice President
Chief Financial Officer
and Treasurer
Joseph L. McCormick, 60
Senior Vice President
General Counsel and
Assistant Secretary
Curtis L. Dinan, 52
Senior Vice President
Commercial
Robert S. McAnnally, 56
Senior Vice President
Operations
Mark. A. Bender, 55
Senior Vice President
Administration Chief
Information Officer
Julie A. White, 49
Vice President Communications,
Public Affairs and Inclusion &
Diversity
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, 2019.
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
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
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
u
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
d
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
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.
ff
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, 2019, was $4.5 billion.
n
On February 7, 2020, we had 52,774,254 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 21, 2020, are
incorporated by reference in Part III.
ONE Gas, Inc.
2019 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
22
22
22
23
24
25
25
43
45
84
84
84
84
85
85
86
86
87
90
91
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
ACA
AFUDC
Annual Report
ASC
ASU
ATSR
Bcf
CERCLA
CFTC
Clean Air Act
Clean Water Act
CNG
Code
COG
COGR
COSA
DOT
Dth
ECP
EDIT
EPA
EPS
ESPP
Exchange Act
FASB
FERC
GAAP
GPAC
GRIP
GSRS
Heating Degree Day or HDD
HCA(s)
IRS
KCC
KDHE
kWh
LDC
LIBOR
MAOP(s)
MGP
MMcf
Moody’s
Net margin
NOL
NPRM
Accounting Authority Order
Accumulated deferred income tax
Annual Cost Adjustment
Allowance for funds used during construction
Annual Report on Form 10-K for the year ended December 31, 2019
Accounting Standards Codification
Accounting Standards Update
Ad-Valorem Tax Surcharge Rider
Billion cubic feet
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 gas
Cost of gas rider
Cost-of-Service Adjustment
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
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)
U.S. Internal Revenue Service
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
3
NYMEX
NYSE
OCC
ONE Gas
ONE Gas Credit Agreement
ONEOK
OSHA
PBRC
PGA
PHMSA
Pipeline Safety Improvement Act
Pipeline Safety, Regulatory Certainty and
Job Creation Act
ROE
RRC
S&P
SEC
Securities Act
Senior Notes
TAC
WNA
XBRL
New York Mercantile Exchange
New York Stock Exchange
Oklahoma Corporation Commission
ONE Gas, Inc.
ONE Gas’ $700 million amended and restated revolving credit agreement, which
expires on October 4, 2024
ONEOK, Inc. and its subsidiaries
Occupational Safety and Health Administration
Performance-Based Rate Change
Purchased Gas Adjustment
United States Department of Transportation Pipeline and Hazardous Materials
Safety Administration
Pipeline Safety Improvement Act of 2002, as amended
Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended
Return on equity calculated consistent with utility ratemaking principles in each
jurisdiction in which we operate
Railroad Commission of Texas
Standard and Poor’s Rating Services
Securities and Exchange Commission
Securities Act of 1933, as amended
ONE Gas’ registered notes consisting of $300 million of 3.61 percent senior notes
due 2024, $600 million of 4.658 percent notes due 2044, and $400 million of
4.50 percent senior notes due 2048
Temperature Adjustment Clause
Weather normalization adjustments
eXtensible Business Reporting Language
The statements in this Annual Report that are not historical information, including statements concerning plans and objectives
of management for future operations, economic performance or related assumptions, are forward-looking statements.
Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,”
“believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and
other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on
reasonable assumptions, we can give no assurance that such expectations and assumptions will be achieved. Important factors
that could cause actual results to differ materially from those in the forward-looking statements are described under Part I,
Item 1A, Risk Factors, and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of
Operation, 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.
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:
•
•
•
p
y
y,
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.
g
g p
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.
g
y
g
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 rate base growth.
• Maintaining a Conservative Financial Profile - As we increase rate base through system investments, we are focused
g
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.
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 Texas and all
appellate matters are subject to regulatory oversight by the RRC. These regulatory authorities have the responsibility of
ensuring that the utilities in their jurisdictions provide safe and reliable service at a reasonable cost, while providing utility
companies the opportunity to earn a fair and reasonable return on their investments.
Generally, our rates and charges are established in rate case proceedings. Regulatory authorities may also approve mechanisms
that allow for adjustments for specific costs or investments made between rate cases. Due to the nature of the regulatory
process, there is an inherent lag between the time that we make investments or incur additional costs and the setting of new
rates and/or charges to recover those investments or costs. Additionally, we are not allowed recovery of certain costs we incur. uu
5
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 is required to make filings pursuant to the PBRC mechanism for the 12 months ending December 31 for
each of the years 2016 through 2019. 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 ending December 31, 2020. Other regulatory mechanisms in Oklahoma
include the following:
• Rate Design for Residential Customers - Oklahoma Natural Gas has an authorized rate structure providing customers
with two rate choices. Rate Choice “A” is designed for customers whose annual normalized usage is less than 50 Dth.
These customers pay a fixed monthly service charge and a per Dth delivery fee. Although a portion of the delivery
charges for customers in Rate Choice “A” is dependent on usage, these customers use relatively small quantities of
natural gas and therefore the delivery charge that is dependent on usage is not significant. Rate Choice “B” is
designed for customers whose annual normalized usage is 50 Dth or greater. These customers pay a fixed monthly
service charge with no delivery fee. At December 31, 2019, 71 percent of Oklahoma Natural Gas’ residential
customers were on Rate Choice “B.”
• Rate Design for Commercial and Industrial Customers - Oklahoma Natural Gas is authorized to provide two different
rate choices for its Small Commercial and Industrial, or SCI, customers. Rate Choice “A” is designed for SCI
customers whose annual normalized usage is less than 40 Dth. These customers pay both a fixed monthly service
charge and a delivery fee. Rate Choice “B” is designed for SCI customers whose annual normalized usage is 40 Dth
or greater but less than 150 Dth. These customers pay a fixed monthly service charge with no delivery fee. All of
Oklahoma Natural Gas’ Large Commercial and Industrial, or LCI, customers, whose annual volume is 150 Dth or
greater, but less than 5,000 Dth, pay a fixed monthly service charge. At December 31, 2019, 80 percent of Oklahoma
Natural Gas’ commercial and industrial customers were on either SCI Rate Choice “B” or LCI.
PGA Clause - Oklahoma Natural Gas’ commodity, transportation, storage and gas purchase operations and
maintenance costs are passed through to its sales customers, without profit, via the PGA. Costs associated with
natural gas that is lost, used or unaccounted for in operations and the fuel-related portion of bad debts are also
recovered through the PGA.
•
• TAC - The TAC is a weather normalization mechanism 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 volumes not used when actual HDDs are less than the normal
HDDs. Normalized HDDs established through our most recent rate proceeding are based on 10-year weighted
average HDDs as of December 31, 2014, as calculated using 11 weather stations across Oklahoma and weighted on
average customer count for Oklahoma. The TAC is in effect from November through April.
• Energy Efficiency Programs - Oklahoma Natural Gas has energy efficiency programs, available to all sales customers.
The costs associated with these programs and an incentive to offer these programs are recovered through a monthly
surcharge on customer bills. Oklahoma Natural Gas collects approximately $15.4 million each year from customers to
fund the programs, which provide rebates for energy-efficient natural gas appliances.
• CNG Rebate Program - The CNG rebate program is designed to promote and support the CNG market in the state of
Oklahoma by offering rebates to Oklahoma residents and companies who purchase dedicated and bi-fueled natural gas
vehicles or install residential CNG fueling stations. The rebates are funded by a $0.25 per gasoline gallon equivalent
surcharge that Oklahoma Natural Gas is authorized to collect on fuel purchased from publicly accessible CNG
dispensers owned by Oklahoma Natural Gas. Collections from the surcharge to fund the program were not material in
2019.
• EDIT - Changes in ADIT resulting from changes in enacted tax rates are credited or billed to customers annually in the
PBRC filing. Beginning in February 2019, customers receive an annual bill credit reflecting the prior year’s
amortization. The amortization is based upon an amortization period in compliance with the tax normalization rules
for the portions of EDIT stipulated by the Code and ten years for all other components of EDIT.
For the year ended December 31, 2019, approximately 86 percent of kl h
customers was recovered from fixed charges.
fi d h
d f
f Oklahoma Natural Gas’ net margin from its sales
f
l
i
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6
Kansas - Kansas Gas Service files periodic rate cases with the KCC as needed to increase base rates to reflect Kansas Gas
Service’s revenue requirement as authorized by the KCC. Other regulatory mechanisms in Kansas include the following:
• GSRS - This surcharge 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. Safety-related investments also include expenditures for 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 the
surcharge.
• COGR and ACA - These mechanisms allow Kansas Gas Service to recover the actual cost of the natural gas it sells to
its customers. The COGR includes a monthly estimate of the cost Kansas Gas Service incurs in transporting, storing
and purchasing natural gas supply for its sales customers, the ACA and other charges and credits. The ACA is an
annual component of the COGR that compares the cost of gas recovered through the COGR for the preceding year
with the actual natural gas supply costs and the fuel-related portion of bad debts for the same period. Any over- or
under-recovery is reflected in the subsequent year’s COGR.
• WNA Clause - The WNA is 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. For April 2019 and forward, normal HDDs are based on a 30-year rolling
average for years 1988-2017 published by the National Oceanic and Atmospheric Administration, as calculated using
three weather stations across Kansas and weighted on HDDs by weather station and customers for Kansas. For 2017
to March 2019, normal HDDs were based on a 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 for Kansas. Beginning in June 2019, small transportation customers, whose
annual usage is less than 800 Mcf, are included in the accrual for the WNA calculation that will become effective in
June 2020. Annually, the amount of the adjustment is determined and is then applied to customers’ bills over the
subsequent 12-month period.
• ATSR - This rider requires Kansas Gas Service to recover the difference each year between the property tax costs
included in its base rates and its actual property tax costs incurred without having to file a rate case. The amount of
the adjustment is determined annually and recovered over the subsequent 12 months as a change in the delivery charge
component of customers’ bills.
Pension and Other Postemployment Benefits Trackers - These trackers require Kansas Gas Service to track and defer
for recovery in its next rate case the difference between the pension and other postemployment benefit costs included
in base rates and actual expense as determined in accordance with GAAP.
•
• MGP Remediation Expense Tracker - This tracker allows Kansas Gas Service to record and defer for recovery
expenses incurred after January 1, 2017, related to MGP site remediation. Kansas Gas Service is allowed to seek
recovery of its costs within a general rate case application. In February 2019, the KCC approved amortization of MGP
costs over 15 years.
• EDIT - EDIT is amortized and included in base rates. The amortization is based upon an amortization period in
compliance with the tax normalization rules for the portions of EDIT stipulated by the Code and five years for all
other components of EDIT.
For the year ended December 31, 2019, approximately 55 percent of Kansas Gas Service’s net margin from its sales customers
was recovered from fixed charges.
Texas - Texas Gas Service has grouped its customers into six service areas. These service areas are further divided into the
incorporated cities and the unincorporated areas, referred to as the environs. The incorporated cities in the service areas havea
original jurisdiction, with the RRC having appellate authority, and the RRC has original jurisdiction for the environs. Periodic
rate cases are filed with the cities or the RRC, as needed, to increase rates to reflect the respective service area’s authorized
revenue requirement. Other regulatory mechanisms and constructs in Texas include the following:
• GRIP Statute - For the incorporated cities in three of the service areas and for the environs in all six service areas,
comprising 81 percent of Texas Gas Service’s customers, Texas Gas Service makes an annual filing under the GRIP
statute, which allows it to recover taxes and depreciation and to earn a return on the annual net increase in investment
for the service area. After five annual GRIP filings, Texas Gas Service is required to file a full rate case. A full rate
case may be filed at shorter intervals if desired by either Texas Gas Service or the regulator.
7
• COSA Filings - In three of the service areas, comprising 19 percent of its customers, Texas Gas Service makes an
annual COSA filing for the incorporated cities. COSA tariffs permit Texas Gas Service to recover return, taxes and
depreciation on the annual increases in net investment, as well as annual increases or decreases in certain expenses and
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.
• WNA Clause - Texas Gas Service employs WNA clauses in all six service areas. The WNA clause is 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
service areas and are generally based on a 10-year average of HDDs in each service area. The WNA clause is in effect
from September through May.
• COG Clause - In all service areas, Texas Gas Service recovers 100 percent of its natural gas costs, including
transportation and storage costs, interest on natural gas in storage and the natural gas cost component of bad debts,
subject to a limitation of 5 percent on lost-and-unaccounted-for natural gas. Annually, natural gas costs recovered
through the COG are compared with actual natural gas supply costs. Any over- or under-recovery is refunded or
recovered, as applicable, in the subsequent year.
Pension and Other Postemployment Benefits Trackers - Texas Gas Service is authorized by statute to defer pension
and other postemployment benefit costs that exceed the amount recovered in base rates and to seek recovery of the
deferred costs in a future rate case.
Pipeline-Integrity Testing Riders - Texas Gas Service recovers 100 percent of its non-labor related pipeline-integrity
testing expenses via riders.
Safety-Related Plant Replacements - Texas Gas Service is authorized by RRC rule to defer interest cost, taxes and
depreciation expense on safety-related plant replacements from the time the replacements are in service until the plant
is reflected in base rates, and to seek recovery of those accrued amounts in a future rate proceeding.
•
•
•
• Energy Conservation Programs - Texas Gas Service has energy conservation programs in the incorporated cities of our
Central Texas and Rio Grande Valley service areas, comprising 46 percent of total customers. Texas Gas Service
collects approximately $3.5 million per year from customers to fund the programs, which provide energy audits,
weatherization and appliance rebates to promote energy conservation.
• EDIT - Three service areas in Texas have authorized EDIT to be credited to customers annually. The credit reflects an
annual amortization of the EDIT balance. The amortization is based upon an amortization period in compliance with
the tax normalization rules for the portions of EDIT stipulated by the Code and ten years for all other components of
EDIT. The timing of the return of EDIT to customers in our remaining three service areas in Texas will be determined
as we work with our regulators.
For the year ended December 31, 2019, approximately 72 percent of Texas Gas Service’s net margin from its sales customers
was recovered from fixed charges.
MARKET CONDITIONS AND SEASONALITY
Supplypp y - We purchased 174 Bcf and 180 Bcf of natural gas supply in 2019 and 2018, 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
mitigate the impact on our supply from physical interruption, financial difficulties of a single supplier, natural disasters and
other unforeseen force majeure events, as well as to ensure these resources are reliable and flexible to meet the variations of
customer demands.
We do not anticipate problems with securing natural gas supply to satisfy customer demand; however, if supply shortages were
to occur, we have curtailment 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.
8
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, 2019, 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 f
supply needs for our sales customers is expected to be supplied from storage.
b
i
of our winter natural gas
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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 -d See discussion below under Seasonality, Competition and CNG for factors affecting demand for our services.
Seasonalityy - 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 TAC and WNA mechanisms. See discussion above under
Regulatory Overview.
- We encounter competition based on customers’ preference for natural gas, compared with other energy
p
Competition
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.
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, 2019.
(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, 2019.
(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.
10.22¢
3.24¢
3.2x
12.73¢
3.23¢
3.9x
11.84¢
3.93¢
3.0x
9
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, 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, 2019, we supply
150 fueling stations, 33 of which we operate in conjunction with our own fleets. Of the 117 remaining stations, 67 are retail
and 50 are private stations. We transported 2.8 million Dth to CNG stations in 2019, which represents a decrease of 2 percent
compared with 2018.
ENVIRONMENTAL AND SAFETY MATTERS
See Note 16 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 3,600 people at February 1, 2020, 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, 2020:
The United Steelworkers
International Brotherhood of Electrical Workers
Union
Approximate
Employees
400
300
Contract Expires
May 31, 2022
June 30, 2021
10
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*
59
2014 to present
Business Experience in Past Five Years
President, Chief Executive Officer and Director
58
2019 to present
Senior Vice President and Chief Financial Officer
2014 to 2019
Senior Vice President, Commercial
Joseph L. McCormick
60
2014 to present
Senior Vice President, General Counsel and Assistant
Secretary
Curtis L. Dinan
52
2019 to present
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
56
2015 to present
Senior Vice President, Operations
Mark A. Bender
2014 to 2015
Senior Vice President, Marketing and Customer Service,
Alabama Gas Corporation, a subsidiary of The Laclede
Group, Inc. (now Spire Inc.)
55
2015 to present
Senior Vice President, Administration and Chief Information
Officer
2014 to 2015
Vice President and Chief Information Officer
Jeffrey J. Husen
48
2018 to present Vice President, Chief Accounting Officer and Controller
* As of January 1, 2020
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
g
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 Corporate Responsibility
Report are also available on our website.
g
(
)
)
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 are 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 have tried to discuss key
factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any
time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors
should carefully consider the following discussion of risks and the other information included or incorporated by reference in
11
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
Regulatory actions could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover
our operating costs.
In addition to regulation by other governmental authorities, we are subject to regulation by the OCC, KCC, RRC and various
municipalities in Texas. These authorities set the rates that we charge our customers for our services. Our ability to obtain
timely future rate increases depends on regulatory discretion. As such, there can be no assurance that we will be able to obtain
rate increases or that our authorized rates of return will continue at the current levels. We monitor and compare the rates of
return we achieve with our allowed rates of return and initiate general and specific rate proceedings as needed. If a regulatory
agency were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return by
significantly lowering our allowed return or adversely altering our cost allocation, rate design or other tariff provisions,
modifying or eliminating cost trackers, prohibiting recovery of regulatory assets or disallowing portions of our expenses, then
our earnings could be 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 interveners. 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 recoveryrr
of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets
at that time, which would also adversely affect our results of operations and cash flows. Regulatory authorities also review
whether our natural gas costs are prudent and can adjust the amount of our natural gas costs that we pass through to our
customers. If any of our natural gas costs were disallowed, our results of operations and cash flows would also be 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
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 charger
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.
12
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.
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.
Unfavorable economic and market conditions could adversely affect our earnings.
Weakening economic activity in our markets could result in a loss of existing customers, fewer new customers, especially in
newly constructed homes and other buildings, or a decline in energy consumption, any of which could adversely affect our
revenues or restrict our future growth. It may become more difficult for customers to pay their natural gas bills, leading to slow
collections and higher-than-normal levels of accounts receivable, which in turn could increase our financing requirements and
bad debt expense. 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. 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. 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 has put downward pressure on the
wholesale cost of natural gas; however, other factors could put upward pressure on natural gas prices, including 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. Additionally, the CFTC under the 2010 Dodd-Frank Wall Street Reform and
Consumer Protection Act has regulatory authority of the over-the-counter derivatives markets. Regulations affecting
derivatives could increase the price of our natural gas supply. Also, the threat of terrorist activities or heightened international
tensions could lead to increased economic instability and volatility in the price of natural gas.
Natural gas costs are passed through to our customers based on the actual cost of the natural gas we purchase. However, 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. Costs are recovered through our collection on customer bills following consumption
by our customers. The delay in recovery of our natural gas costs could adversely affect our financial condition and cash flows.
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.
13
Our risk-management policies and procedures may not be effective, and employees may violate our risk-management
policies.
We have implemented a set of policies and procedures that involve both our senior management and the Audit Committee of
our Board of Directors to assist us in managing risks associated with our business. These risk-management policies and
procedures are intended to align strategies, processes, people, information technology and business knowledge so that risk is
managed throughout the organization. However, as conditions change and become more complex, current risk measures may
fail to assess adequately the relevant risk due to changes in the market and the presence of risks previously unknown to us.
Additionally, if employees fail to adhere to our policies and procedures or if our policies and procedures are not effective,
potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended.
Ineffective risk-management policies and procedures or violation of risk-management policies and procedures could have an
adverse effect on our earnings, financial condition and cash flows.
Our business is subject to competition that could adversely affect our results of operations.
The natural gas distribution business is competitive, and we face competition from other companies that supply energy,
including electric companies, private generation, solar, propane dealers, renewable energy providers and coal companies in
relation to sources of energy for electric power plants, as well as nuclear energy. Significant competitive factors include
efficiency, quality and reliability of the services we provide and price.
The most significant product competition occurs between natural gas and electricity in the residential and small commercial
markets. Natural gas competes with electricity for water and space heating, cooking, clothes drying and other general energy
needs. Increases in the price of natural gas or decreases in the price of other energy sources could 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.
The availability of adequate natural gas pipeline transportation and storage capacity and natural gas supply may decrease
and impair our ability to meet customers’ natural gas requirements and reduce our earnings.
In order to meet customers’ natural gas demands, we 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 and our financial condition, cash flow and results of operations may be
impacted adversely. A significant disruption to or reduction in natural gas supply, pipeline capacity or storage capacity due to
events including, but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas
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wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions, could reduce our normal supply of
natural gas and thereby reduce our earnings.
A downgrade in our credit ratings could adversely affect our cost of and ability to access capital.
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. 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.
We are subject to new and existing laws and regulations that may require significant expenditures or result in significant
increases in operating costs or significant fines or penalties for noncompliance.
Our business and operations are subject to regulation by a number of federal agencies, including FERC, DOT, OSHA, EPA,
CFTC and various regulatory agencies in Oklahoma, Kansas and Texas, and we are subject to numerous federal and state laws
and regulations. Future changes to laws, regulations and policies may impair our ability to compete for business or to recover
costs and may increase the cost of our operations. Furthermore, because the language in some laws and regulations is not
prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of
regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures
affecting our operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under
the Natural Gas Act of 1938, as amended, to impose penalties for current violations of up to $1 million per day for each
violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent
noncompliance could also increase. 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, credit rating or 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.
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
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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 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.
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 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 hurricanes, thunderstorms, tornados and snow or ice storms.
To the extent the frequency of extreme weather events increases, our cost of providing service could increase. We may not be
able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks. To the extent
financial markets view climate change and emissions of greenhouse gases as a financial risk, this could adversely affect our
ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business
could be affected by the potential for lawsuits related to or against greenhouse gas emitters based on the claimed connection
between greenhouse gas emissions and climate change, which could adversely impact our business, results of operations and
cash flows.
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Demand for natural gas is highly weather sensitive and seasonal, and weather conditions may cause our earnings to vary
from year to year.
Our earnings can vary from year to year, depending in part on weather conditions, which directly influence the volume of
natural gas delivered to customers. Natural gas sales to residential and commercial customers are seasonal, as a substantial
portion of their natural gas requirements are for heating during the winter months. Warmer-than-normal weather can reduce
our utility margins as customer consumption declines. We have implemented weather normalization mechanisms for our sales
to customers in Oklahoma, Kansas and Texas, which are designed to reduce our earnings sensitivity to weather. Weather
normalization 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.
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
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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.
We may pursue acquisitions, divestitures and other strategic opportunities, the success of which 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 affected materially and adversely if we are unable to
successfully integrate businesses that we acquire.
An impairment of goodwill and long-lived assets could reduce our earnings.
At December 31, 2019, 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 will be dependent on the
ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding
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commitments if they experience shortages of capital and liquidity. Disruptions and volatility in the global credit markets could
cause the interest rate we pay on our ONE Gas Credit Agreement, which is based on LIBOR, to increase. This could result in
higher interest rates on future financings and could impact the liquidity of the lenders under our ONE Gas Credit Agreement,
potentially impairing their ability to meet their funding commitments to us. Disruptions in the capital and credit markets as a
result of uncertainty, changing or increased regulation or failures of significant financial institutions could adversely affect our
access to capital needed for our business. The inability to access adequate capital or an increase in the cost of capital may
require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate our
dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our
ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and
increase our costs of borrowing.
Changes in federal and state fiscal, tax and monetary policy could significantly increase our costs or decrease our cash
flows.
Changes in federal and state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary
pressures on the costs of goods, services and labor 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
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 billings and customer growth. Changes in tax rates, including the effects of
the Tax Cuts and Jobs Act of 2017, could adversely affect our cash flows and may increase the cash we pay for income taxes in
the future. Any of these events may cause us to increase debt, conserve cash, adversely affect our ability to make capital
expenditures to grow the business or other discretionary uses of cash and could adversely affect our cash flows.
Federal, state and local jurisdictions may challenge our tax return positions.
The preparation of our federal and state tax return filings 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.
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, 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 its potential revision, repeal and/or
replacement 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 only 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.
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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 larger
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part to the Patient Protection and Affordable Care Act of 2010, and its potential revision, repeal and/or replacement. 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 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, which may adversely affect our cash flows and earnings.
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 tornados, hurricanes, earthquakes, floods or other similar events beyond our control. 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. 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 certainrr
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
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.rr
The occurrence of any of the foregoing could have a material adverse effect on our financial condition, results of operations
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.
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
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affected adversely. Our financial results could also be affected adversely 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 information technology, 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 businesses. Physical damage due
to a cyber security incident or acts of cyber terrorism could impact services and could lead to material liabilities. As potential
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 reputation. 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 protect us from unauthorized access 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, and our business, financial
condition, results of operations and cash flows could be affected adversely.
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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, 2020, approximately 700 of our estimated 3,600 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 nn
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.
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
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of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain
areas, combined with the 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.
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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.
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 and our ONE Gas Credit Agreement restrict our ability to create or
permit certain liens, to consolidate or merge or to convey, transfer or lease substantially all of our properties and assets.
The ONE Gas Credit Agreement includes a requirement that our debt to total capital ratio may not exceed 70 percent as of the
end of any calendar quarter. Events beyond our control could impair our ability to satisfy this requirement. As long as our
indebtedness remains outstanding, these restrictive covenants could impair our ability to expand or pursue our growth strategy.
In addition, the breach of any covenants or any payment obligations in any of these debt agreements will result in an event of
default under the applicable debt instrument. If there were an event of default under one of our debt agreements, the holders of
the defaulted debt may have the ability to cause all amounts outstanding with respect to that debt to be due and payable, subject
to applicable grace periods. This could trigger cross-defaults under our other debt agreements, including our Senior Notes.
Forced repayment of some or all of our indebtedness would reduce our available cash and have an adverse impact on our
financial condition, results of operations and cash flows.
Some of our debt, including borrowings under our ONE Gas Credit Agreement and our commercial paper program, is
based on variable rates of interest, which could result in higher interest expenses in the event of an increase in interest
rates.
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 and commercial paper program are based on variable rates of
interest. If these rates rise, the interest rate on this debt will also increase. Therefore, an increase in these rates will increase
our interest payment obligations and have a negative effect on our cash flows and financial position.
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 an adverse effect on our
financial condition, results of operations and cash flows.
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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
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.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
PROPERTIES
The following table sets forth the approximate miles of distribution mains and transmission pipeline as of December 31, 2019:
Properties (miles)
Distribution
Transmission
Total properties
OK
KS
TX
Total
18,900
700
19,600
11,500
1,500
13,000
10,400
300
10,700
40,800
2,500
43,300
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 16 of the Notes to Consolidated Financial Statements in this Annual Report for information regarding legal
proceedings.
22
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
23
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
PART II
MARKET HOLDERS AND DIVIDENDS
Our common stock is listed on the NYSE under the trading symbol “OGS.”
At February 7, 2020, there were 11,175 registered shareholders of the company’s common stock.
In January 2020, we declared a dividend of $0.54 per share ($2.16 per share on an annualized basis) for shareholders of record
as of February 21, 2020, payable on March 6, 2020.
Performance Graph
The following performance graph compares the performance of our common stock with the S&P MidCap 400 Index, the Dow
Jones Industrial Average and a ONE Gas peer group during the period beginning December 31, 2014 and ending on December
31, 2019. This graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period
and a reinvestment of dividends paid on such investments throughout the period.
Value of $100 Investment Assuming Reinvestment of Dividends at December 31, 2014, Through
December 31, 2019, among ONE Gas, Inc., the S&P MidCap 400 Utilities Index, the S&P MidCap
400 Index, the Dow Jones Industrial Average and the ONE Gas peer group
$275
$250
$225
$200
$175
$150
$125
$100
ONE Gas, Inc.
S&P MidCap 400 Index
ONE Gas Peer Group*
S&P MidCap 400 Utilities Index
Dow Jones Industrial Average
Cumulative Total Return
As of Each Year Ending
ONE Gas, Inc.
S&P MidCap 400 Utilities Index
S&P MidCap 400 Index
Dow Jones Industrial Average
ONE Gas Peer Group*
December 31,
2015
2016
2017
2018
2019
$
$
$
$
$
125.08 $
163.19 $
191.41 $
213.23 $
256.47
94.06 $
119.79 $
133.07 $
142.13 $
162.50
97.82 $
118.11 $
137.30 $
122.08 $
154.07
100.21 $
116.74 $
149.56 $
144.35 $
180.94
104.01 $
127.17 $
146.21 $
150.05 $
176.16
* The ONE Gas peer group used in this graph is the same peer group that will be used in determining our level of performance under our 2019 performance
units at the end of the three-year performance period and is comprised of the following companies: Alliant Energy Corporation.; Atmos Energy Corporation.;
Avista Corporation.; CenterPoint Energy Inc.; Chesapeake Utilities Corporation.; CMS Energy Corporation.; New Jersey Resources Corporation; NiSource
Inc.; Northwest Natural Gas Company; NorthWestern Corporation.; South Jersey Industries Inc.; Southwest Gas Corporation.; and Spire Inc.
24
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for each of the periods indicated:
2019
Years Ended December 31,
2017
(Millions of dollars except per share data)
2016
2018
2015
Consolidated Statements of Income data:
Total revenues (a)
Cost of natural gas
Net margin (b)
Operating income (a)
Net income
Basic earnings per share
Diluted earnings per share
Dividends declared per common share
$ 1,652.7
687.9
$
964.8
$
295.3
$
186.7
$
3.53
$
3.51
$
2.00
$
$ 1,633.7
714.6
$
919.1
$
288.4
$
172.2
$
3.27
$
3.25
$
1.84
$
$ 1,539.6
614.5
$
925.1
$
316.7
$
163.0
$
3.10
$
3.08
$
1.68
$
$ 1,427.2
541.8
$
885.4
$
288.9
$
140.1
$
2.67
$
2.65
$
1.40
$
$ 1,547.7
706.0
$
841.7
$
265.2
$
119.0
$
2.26
$
2.24
$
1.20
$
(a) Reflects the impact of the adoption of new accounting standards in fiscal year 2018 related to revenue recognition and the presentation of
net periodic benefit costs. See Note 1 of the Notes to Consolidated Financial Statements in this Annual Report for additional information
regarding our adoption of these standards.
(b) Net margin is considered a non-GAAP financial measure consisting of total revenues less the cost of natural gas. See additional
discussion under Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report.
Consolidated Balance Sheets data:
Total assets
Long-term debt, including current maturities
2019
2018
December 31,
2017
(Millions of dollars)
2016
2015
$ 5,708.3
$ 1,286.1
$ 5,468.6
$ 1,285.5
$ 5,206.9
$ 1,193.3
$ 4,942.8
$ 1,192.5
$ 4,634.8
$ 1,191.7
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 our revenue requirements needed to achieve our authorized rates of return. We earn revenues
from the delivery of natural gas, but do not earn a profit on the natural gas that we deliver, as those costs are passed through to
our customers at cost. The primary components of our revenue requirements are the amount of capital invested in our business,
which is also known as rate base, our allowed rate of return on our capital investments and our recoverable operating expenses,
including depreciation, 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 2019 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 weather normalization 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) regulatory outcomes, which
determine the returns we are authorized to earn and the rates we are allowed to charge for our service; (2) the consumption of
natural gas, which impacts the amount of our net margin derived from the variable component of our rates; (3) our operating
performance, which impacts our operating expenses; and (4) the perceived value of natural gas relative to other energy sources,
particularly electricity, which influences our customers’ choice of natural gas to provide a portion of their energy needs.
25
We are subject to regulatory requirements for pipeline integrity and environmental compliance. These requirements impact our
operating expenses and the level of capital expenditures required for compliance. Historically, our regulators have allowed
recovery of these expenditures. However, because integrity and environmental regulation is changing constantly, our capital
and operating expenditures to comply will change as well. Although we believe our regulators will continue to allow recovery
of such expenditures in the future, we will continue to make these expenditures with no assurance about if, or over what period,
we will be permitted to recover them.
RECENT DEVELOPMENTS
Dividend - In January 2020, we declared a dividend of $0.54 per share ($2.16 per share on an annualized basis) for
shareholders of record as of February 21, 2020, payable on March 6, 2020.
REGULATORY ACTIVITIES
Oklahoma - 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 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 to be
issued in 2020.
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 an amortization period 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.rr
In March 2017, Oklahoma Natural Gas filed its first annual PBRC following the general rate case that was approved in January
2016. This filing was based on a calendar test year of 2016. The PBRC filing demonstrated that Oklahoma Natural Gas was
earning within the 100 basis point dead-band of 9.0 to 10.0 percent. Therefore, Oklahoma Natural Gas did not seek a
modification to base rates. The filing also requested a utility incentive adjustment of approximately $1.9 million and an energyr
efficiency program true-up adjustment of $2.3 million. A joint stipulation and settlement agreement was approved by the OCC
in August 2017.
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 - 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 we have started the transition process with an intent
to acquire the assets in the fourth quarter of 2020.
In August 2018, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.4 million
related to its GSRS. In November 2018, the KCC approved the increase effective December 2018.
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 weather normalization
adjustment rider to small transportation customers and the implementation of a cybersecurity tracker.
ff
26
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.
In August 2017, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.9 million
related to its GSRS. In November 2017, the KCC approved the increase effective December 2017.
In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs
incurred at, and nearby, the 12 former MGP sites which we own or retain responsibility for certain environmental conditions.
In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement
agreement with the KCC. The agreement allows Kansas Gas Service to defer and seek recovery of costs that are necessary for
investigation and remediation at the 12 former MGP sites incurred after January 1, 2017, up to a cap of $15.0 million, net of
any related insurance recoveries. Costs approved 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. At the time future investigation and
remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas Service will be
required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC issued an order
approving the settlement agreement in November 2017. A regulatory asset of approximately $5.9 million was recorded for
estimated costs that have been accrued at January 1, 2017. See discussion below in Environmental, Safety and Regulatory
Matters and in Note 16 of the Notes to Consolidated Financial Statements for additional information concerning the 12 former
MGP sites.
Texas - West Texas Service Area - 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.
In March 2017, Texas Gas Service made GRIP filings for all customers in the West Texas service area. The RRC and the cities
approved an increase of $4.3 million, and new rates became effective in July 2017.
Central Texas Service Area - 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 requested to consolidate the two service areas into one. If approved, new
rates are expected to become effective in the third quarter of 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.
In March 2017, Texas Gas Service made GRIP filings for all customers in the Central Texas service area. The cities and the
RRC approved an increase of $4.9 million, and new rates became effective in June 2017.
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 $1.9 million, $1.6 million and $5.0 million in 2019, 2018 and
2017, respectively.
27
In 2018, Texas Gas Service requested a total of $11.1 million of decreases to rates for customers in its service areas due to thet
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. Three service areas in Texas have authorized EDIT to be credited to customers annually. The timing of the returnrr
of EDIT to customers in our remaining three service areas 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 included the amortization of the regulatory liability as a
credit in income tax expense. During the year ended December 31, 2019, we credited income tax expense $12.8 million for the
amortization of the regulatory liability associated with EDIT that was returned to customers. See “Liquidity and Capital
Resources - Tax Reform” and Note 14 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 writeoff of
regulatory assets and stranded costs may be required. There were no writeoffs of regulatory assets resulting from the failure to
meet the criteria for capitalization during 2019, 2018 and 2017.
FINANCIAL RESULTS AND OPERATING INFORMATION
Selected Financial Results - Net income was $186.7 million, or $3.51 per diluted share, $172.2 million, or $3.25 per diluted
share, and $163.0 million, or $3.08 per diluted share, for the years ended December 31, 2019, 2018 and 2017, 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 (a)
Depreciation and amortization
Operating income (a)
Net income
Capital expenditures and asset removal costs
Years Ended December 31,
2018
2017
2019
Variances
2019 vs. 2018
Increase (Decrease)
Variances
2018 vs. 2017
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
$
$
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
$
$
$
$
1,409.1
100.9
29.6
1,539.6
614.5
925.1
456.5
151.9
316.7
163.0
408.8
$
$
$
$
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 % $
83.3
8.8
2.0
94.1
100.1
(6.0)
14.1
8.2
(28.3)
9.2
38.6
6 %
9 %
7 %
6 %
16 %
(1)%
3 %
5 %
(9)%
6 %
9 %
(a) Reflects the impact of the adoption of a new accounting standard in fiscal year 2018 related to the presentation of net periodic benefit
costs. See Note 1 of the Notes to Consolidated Financial Statements in this Annual Report for additional information regarding our adoption
of this standard.
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,
28
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.
The following table sets forth reconciliation of net margin to the most directly comparable GAAP measure for the periods
indicated:
Years Ended December 31,
2019 vs. 2018
Variances
Variances
2018 vs. 2017
Non-GAAP Reconciliation
2019
2018
2017
Increase (Decrease)
Increase (Decrease)
Total revenues
Cost of natural gas
Net margin
(Millions of dollars, except percentages)
$ 1,652.7
$ 1,633.7
$ 1,539.6
$
19.0
1 % $
94.1
687.9
714.6
614.5
(26.7)
(4)%
100.1
$
964.8
$
919.1
$
925.1
$
45.7
5 % $
(6.0)
6 %
16 %
(1)%
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,
2018
2017
2019
Variances
2019 vs. 2018
Increase (Decrease)
Variances
2018 vs. 2017
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
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
$
$
663.8
124.2
6.6
794.6
100.9
29.6
925.1
$
$
36.9
4.4
1.1
42.4
4.4
(1.1)
45.7
6 % $
3 %
17 %
5 %
4 %
(3)%
5 % $
(19.7)
2.9
—
(16.8)
8.8
2.0
(6.0)
(3)%
2 %
— %
(2)%
9 %
7 %
(1)%
Our net margin on natural gas sales is comprised of two components, fixed and variable margin. Fixed margin reflects the
portion of our net margin attributable to the monthly fixed customer charge component of our rates, which does not fluctuate
based on customer usage in each period. Variable margin reflects the portion of our net margin that fluctuates with the volumes
delivered and billed 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,
2018
2017
2019
Variances
2019 vs. 2018
Increase (Decrease)
Variances
2018 vs. 2017
Increase (Decrease)
(Millions of dollars, except percentages)
$
$
590.2
230.0
820.2
$
$
553.9
223.9
777.8
$
$
567.1
227.5
794.6
$
$
36.3
6.1
42.4
7% $
3%
5% $
(13.2)
(3.6)
(16.8)
(2)%
(2)%
(2)%
29
2019 vs. 2018 - Net margin increased $45.7 million due primarily to the following:
•
•
•
•
•
an increase of $36.2 million from new rates;
an increase of $6.5 million in residential sales due primarily to net customer growth in Oklahoma and Texas;
an increase of $1.9 million due to higher transport volumes in Kansas; and
an increase of $1.2 million due to higher sales volumes, net of weather normalization, in Texas; offset by,
a decrease of $0.9 million due to the impact of the retroactive 2017 CNG federal excise tax credit enacted in February
2018.
Operating costs increased $18.5 million due primarily to the following:
•
•
•
•
•
•
an increase of $10.1 million in employee-related costs, which includes costs for our nonqualified employee benefit
plans that are offset by earnings on the investments for these plans as discussed in “Other Factors Affecting Net
Income”;
an increase of $2.6 million in outside service costs;
an increase of $1.8 million in materials for pipeline repair and maintenance activities;
an increase of $1.5 million in bad debt expense;
an increase of $1.3 million in fleet costs; and
an increase of $1.1 million in legal-related costs.
Depreciation and amortization expense increased $20.3 million due primarily to an increase in depreciation from our capital
expenditures being placed in service, higher depreciation rates in Kansas and an increase in amortization of the ad-valorem
surcharge rider in Kansas.
g
Other Factors Affecting Net Income - Other factors that affect net income include other expenses, interest expense, and income
tax expense as follows:
•
•
•
a decrease of $8.4 million in other expense, net, due primarily to earnings on investments associated with nonqualified
employee benefit plans, which offset the increase in costs for the plans included in operating costs;
an increase of $11.4 million in interest expense resulting primarily from the refinancing of our $300 million senior
notes, with a 2.07 percent interest rate, with $400 million senior notes, with a 4.50 percent interest rate due November
2048; and
a decrease of $10.7 million in income tax expense due primarily to $12.8 million amortization of EDIT, which is offset
by a decrease in revenues.
p
p
Capital Expenditures and Asset Removal Costs
extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements,
automated meter reading, government-mandated pipeline relocations, fleet, facilities, information technology 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.
- Our capital expenditures program includes expenditures for pipeline integrity,
Capital expenditures and asset removal costs increased $17.7 million for 2019, compared with 2018, due primarily to increased
system integrity activities and extending service to new areas. Our capital expenditures and asset removal costs are expected to
be approximately $475.0 million for 2020.
30
Selected Operating Information - The following tables set forth certain selected operating information for the periods
indicated:
(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
(in thousands)
2018
2017
Increase (Decrease)
Average Number of Customers
OK
KS
TX
Total
OK
KS
TX
Total
OK
KS
TX
Total
Years Ended
December 31,
Variances
2018 vs. 2017
Residential
798
583
Commercial and industrial
Other
Transportation
Total customers
74
—
5
50
—
6
624
35
3
1
2,005
159
3
12
793
582
73
—
5
50
—
6
618
35
3
1
1,993
158
3
12
877
639
663
2,179
871
638
657
2,166
5
1
—
—
6
1
—
—
—
1
6
—
—
—
6
12
1
—
—
13
The following table reflects the total volumes delivered, excluding the effects of weather normalization 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,
2018
2017
2019
128,723
40,690
2,688
172,101
224,304
396,405
128,393
40,743
2,505
171,641
220,884
392,525
99,940
32,242
1,933
134,115
209,551
343,666
Total volumes delivered increased for 2019, compared with 2018, due primarily to colder weather in the first quarter 2019. The
impact of weather on residential and commercial net margin is mitigated by weather normalization mechanisms in all
jurisdictions.
The following table sets forth the HDD’s by state for the periods indicated:
HDDs
Oklahoma
Kansas
Texas
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
31
3,771
5,012
1,738
3,263
4,914
1,782
(1)%
(1)%
4 %
114%
104%
102%
116%
102%
98%
Years Ended
December 31,
2018
2017
Actual
Normal
Actual
Normal
2018 vs.
2017
Actual
Variance
2018
2017
Actual as a percent of
Normal
3,771
5,012
1,738
3,263
4,914
1,782
2,849
4,088
1,247
3,264
4,889
1,785
32%
23%
39%
116%
102%
98%
87%
84%
70%
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 2016-2019, 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 2018, compared with 2017, 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, 2018.
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 16 of the Notes to
Consolidated Financial Statements in this Annual Report for information with respect to legal proceedings.
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 each jurisdiction that reduce the
lag in earning a return on our capital expenditures by allowing for increases in 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 a strong credit rating, which we believe will provide us access to diverse sources of capital at favorable rates for
certain investments and expenses.
32
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, 2019, our total debt-to-
capital ratio was 46 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 the event LIBOR is not available, and such circumstances
are unlikely to be temporary, our lenders 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.
aa
At December 31, 2019, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement,
with $698.8 million of credit available under the ONE Gas Credit Agreement.
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, 2019, we had $516.5 million of commercial paper outstanding. The ONE Gas Credit Agreement is
available to repay the commercial paper notes, if necessary.
Long-Term Debt - In November 2018, we issued $400 million of 4.50 percent senior notes due 2048. The proceeds from the
issuance were used to retire the $300 million 2.07 percent senior notes due 2019, to reduce the amount of 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, 2019, our long-term debt-to-capital ratio was 38 percent.
33
Credit Ratings - Our credit ratings as of December 31, 2019, were:
Rating Agency
Moody’s
S&P
Rating
A2
A
Outlook
Stable
Stable
Our commercial paper is rated Prime-1 by Moody’s and A-1 by S&P. We intend to maintain strong credit metrics while we
pursue a balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be
competitive with our peer group.
Tax Reform - The reduction in the federal corporate income tax rate associated with the Tax Cuts and Jobs Act of 2017
resulted in less revenues collected from customers related to the recovery of tax expense included in our rates. Although cash
collected from this revenue is ultimately used to remit our income tax expense payments, we will lose a portion of the timing
benefit when we collect and remit tax payments, thereby reducing cash that may have been retained for several years. Under
the new tax law, natural gas utilities are not eligible to take bonus depreciation, but they are also not subject to the new
limitations on the deduction of interest expense. The loss of bonus depreciation will result in earlier cash tax payments, as
compared to the previous tax law, once accumulated NOLs are utilized. Additionally, the lowering of the federal corporate
income tax rate effectively resulted in an over-collection of tax expenses, as customers’ rates include tax expenses based on thet
statutory federal corporate income tax rate.
We have addressed the regulatory liability for EDIT in Oklahoma and Kansas. Three service areas in Texas have authorized
EDIT to be credited to customers annually. The timing of the return of EDIT in our remaining three service areas in Texas will
be determined as we work with our regulators. Cash flows in 2019 were reduced by approximately $12.8 million for EDIT
returned to customers.
Pension and Other Postemployment Benefit Plans - During 2019, we contributed $29.2 million to our defined benefit
pension plan and $6.2 million to our other postemployment benefit plans. During 2018, we contributed $42.4 million to our
defined benefit pension plan and $7.7 million to our other postemployment benefit plans. Information about our pension and
other postemployment benefits plans, including anticipated contributions, is included under Note 13 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.
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
2019
2018
2017
2019 vs. 2018
2018 vs. 2017
(Millions of dollars)
$
$
310.4
(422.9)
109.1
(3.4)
21.3
17.9
$
$
467.7
(394.5)
(66.3)
6.9
14.4
21.3
$
$
253.8
(355.8)
101.7
(0.3)
14.7
14.4
$
$
(157.3) $
(28.4)
175.4
(10.3)
6.9
(3.4) $
213.9
(38.7)
(168.0)
7.2
(0.3)
6.9
34
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, 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.
2019 vs. 2018 - Cash flows from operating activities were lower in 2019 compared with 2018, due primarily to working capital
changes resulting from the timing of customer collections, payments for natural gas purchases, and gas cost recoveries from our
purchased gas cost mechanisms, which vary from period to period and vary with changes in commodity prices. Additionally,
operating cash flows in 2019 were reduced due to changes in rates and credits provided to customers as a result of the Tax Cuts
and Jobs Act of 2017 as discussed in Regulatory Activities.
Investing Cash Flows - 2019 vs. 2018 - Cash used in investing activities increased for 2019, compared to 2018, due primarily
to capital expenditures for increased system integrity activities and extending service to new areas.
Financing Cash Flows - 2019 vs. 2018 - Cash provided by financing activities for 2019 increased, compared with 2018, due
primarily to net borrowings on our commercial paper.
2018 vs. 2017 - Cash flows in 2018, compared with 2017, 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, 2018.
ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS
Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or
regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to,
d
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 2019, 2018 or 2017.
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 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. During the first quarter 2019, we completed a
project to remove the source of contamination and associated contaminated materials at the twelfth site where no active soil
remediation had previously occurred. We are also finalizing a study of the feasibility of various options to address the
remainder of the site.
With regard to one of our former MGP sites in Kansas, periodic monitoring and a 2016 interim site investigation indicated
elevated levels of contaminants generally associated with MGP sites. In 2016, we estimated the potential costs associated with
additional investigation and remediation to be in the range of $4.0 million to $7.0 million. In the second quarter of 2018, we
35
revised our estimate of the potential costs associated with additional investigation and remediation to be in the range of $5.6
million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in
the ultimate remediation approach that will be utilized. Accordingly, we recorded in the second quarter of 2018 an adjustment
to the reserve of $1.6 million bringing the total to $5.6 million for this site, which also increased our regulatory asset pursuant
to our AAO in Kansas. In 2019, the KDHE approved the remediation plan that is the basis of our estimated cost range.
In Kansas, 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. At the time future
investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas
Service will be required to file an application with the KCC for approval to increase the $15.0 million cap.
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 2019, 2018 or 2017. A number of environmental issues may exist with
respect to 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.
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 include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM
comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process,
PHMSA is being 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 has 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
36
pipelines. The GPAC met in June 2019 on gas gathering pipelines. In addition to reviewing public and committee comments,
PHMSA announced they will split this NPRM into three separate final rulemakings:
•
•
•
the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs
Creation Act and will be 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 rulemakings referenced above, which addresses 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 potential capital and operating expenditures associated with compliance with the first final rulemaking are
under review but are not expected to be material.
PHMSA has indicated it now expects the second pending rulemaking to be issued as a final rule during 2020. The potential
capital and operating expenditures associated with compliance with these pending rulemakings are currently being evaluated
and could be significant depending on the final regulations.
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 - The 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.
37
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; and (4) reducing the loss of methane from our facilities.
We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on
maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the
release of natural gas during pipeline and facility maintenance and operations. 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 in 2018 and between six and seven
percent in 2017. We anticipate reporting in 2020 our calendar year 2019 performance relative to our commitment.
Additional information about our environmental matters is included in the section entitled Environmental Matters in Note 16 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 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 2019,
2018 or 2017.
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.
38
For further discussion of regulatory assets and liabilities, see Note 10 of the Notes to Consolidated Financial Statements in thist
Annual Report.
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 2019 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, 2019, no event has occurred indicating that our fair value is less than the carrying value of our
f
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.
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.
Pension and Other Postemployment Benefits - We have defined benefit retirement 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.
During 2019, we contributed approximately $29.2 million to our defined benefit pension plan and $6.2 million to our other
postemployment benefit plans. In 2020, our required contributions are expected to be $1.1 million and $4.0 million,
respectively, to our defined benefit pension plans and other postemployment benefit plans. In 2019, we purchased group
annuity contracts 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 pension plans, prior to regulatory deferrals, of $23.8 million in 2019, and estimate
that in 2020, we will record expenses of approximately $28.3 million. Net periodic benefits costs for our postemployment benefit ff
plans were not material in 2019, and we estimate that in 2020, we will record credits of approximately $6.2 million prior to
regulatory deferrals.
39
The following table sets forth the significant assumptions used to determine our estimated 2020 net periodic benefit cost related
to our defined pension and other postemployment benefit plans and sensitivity to changes with respect to these assumptions:
Discount rate for pension
Discount rate for other postemployment benefits
Expected long-term return on plan assets (c)
Rate Used
Cost
Sensitivity (a)
Obligation
Sensitivity (b)
3.50% $
3.40% $
7.20%/7.65% $
(Millions of dollars)
3.3
$
(0.2) $
$
2.6
33.7
5.9
—
(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 7.20 percent and 7.65 percent, respectively.
Assumed health care cost-trend rates have a significant effect on the amounts reported for our other postemployment benefit
plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
Effect on total of service and interest cost
Effect on other postemployment benefit obligation
One Percentage
Point Increase
One Percentage
Point Decrease
(Millions of dollars)
$
$
0.1
2.3
$
$
(0.1)
(2.4)
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 revenuenn
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.
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 weather normalization mechanism in Kansas, where the KCC
determines how we reflect variations in weather in our rates billed to customers.
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. As a result, we estimated unbilled revenues at the end of each accounting period consistent with
past practice. The accrued unbilled natural gas sales revenue at December 31, 2019 and 2018 was $109.7 million and $127.6
million, respectively, and is included in accounts receivable on our Consolidated Balance Sheets. See Note 2 of the Notes to
Consolidated Financial Statements in this Annual Report for additional information regarding our revenues.
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 2016, we recorded a reserve of $4.0 million for potential costs associated with
further investigation and remediation at one of the former MGP sites in Kansas. In 2017, we recorded a regulatory asset of
approximately $5.9 million for estimated costs incurred at, and nearby, our 12 former MGP sites in Kansas that was accrued at
January 1, 2017. In the second quarter of 2018, we revised our estimate of the potential costs associated with additional
40
investigation and remediation of this Kansas site to be in the range of $5.6 million to $7.0 million. Accordingly, we recorded ind
the second quarter of 2018 an adjustment to the reserve of $1.6 million bringing the total to $5.6 million for this site. 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.
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 2019, 2018 or 2017. Actual results may differ from our estimates resulting in an impact,
positive or negative, on earnings.
See Note 16 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.
CONTRACTUAL OBLIGATIONS
The following table sets forth our contractual obligations at December 31, 2019:
Contractual Obligations
(Millions of dollars)
2020
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
Employee benefit plans
Operating leases
Total
516.5
56.9
187.9
116.7
5.1
7.6
890.7
$
$
— $
—
56.9
163.4
0.1
4.0
7.2
231.6
$
— $
—
56.9
124.0
0.1
4.0
6.9
191.9
$
— $
—
56.9
92.0
0.1
4.0
5.8
158.8
$
300.0
—
46.9
46.8
0.1
4.0
3.1
400.9
Thereafter
$ 1,001.3
—
1,011.5
42.2
0.1
—
8.5
$ 2,063.6
Total
$ 1,301.3
516.5
1,286.0
656.3
117.2
21.1
39.1
$ 3,937.5
,
g
Long-term debt, commercial paper borrowings and interest payments on debt - Long-term debt includes our three debt
p y
issuances at their due dates. Interest payments on debt are calculated by multiplying our long-term debt by the respective
coupon rates.
p p
g
p
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.
g
g
p
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,
2019. 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.
p y
Employee benefit plans - Employee benefit plans include our anticipated contributions to maintain the minimum required
funding level for our pension and other postemployment benefit plans. See Note 13 of the Notes to Consolidated Financial
Statements in this Annual Report for discussion of employee benefit plans.
p
p
g
Operating leases - Our operating leases consist primarily of office facilities and information technology leases. See Note 5 o
the Notes to Consolidated Financial Statements in this Annual Report for discussion of leases.
f
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
41
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
to be materially different from any future results, performance or achievements expressed or implied by forward-looking
statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions
and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual
results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
our ability to recover operating costs, 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;
changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;
the economic climate and, particularly, its effect on the natural gas requirements of our residential and
commercial customers;
competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power,
geothermal energy and biofuels;
conservation and energy storage efforts of our customers;
variations in weather, including seasonal effects on demand, the occurrence of storms and disasters, and climate
change;
indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to
borrow additional funds and/or place us at competitive disadvantage compared with competitors;
our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including
decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of
existing supply and transportation and storage arrangements that are not replaced with contracts with similar terms and
pricing;
the mechanical integrity of facilities operated;
operational hazards and unforeseen operational interruptions;
adverse labor relations;
the effectiveness of our strategies to reduce earnings lag, margin protection strategies and risk mitigation strategies,
which may be affected by risks beyond our control such as commodity price volatility and counterparty
creditworthiness;
our ability to generate sufficient cash flows to meet all our liquidity needs;
changes in the financial markets during the periods covered by the forward-looking statements, particularly those
affecting the availability of capital and our ability to refinance existing debt and fund investments and acquisitions;
actions of rating agencies, including the ratings of debt, general corporate ratings and changes in the rating agencies’
ratings criteria;
changes in inflation and interest rates;
our ability to recover the costs of natural gas purchased for our customers;
impact of potential impairment charges;
volatility and changes in markets for natural gas;
possible loss of LDC franchises or other adverse effects caused by the actions of municipalities;
payment and performance by counterparties and customers as contracted and when due;
changes in existing or the addition of new environmental, safety, tax and other laws to which we and our subsidiaries
are subject;
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;
42
•
•
•
•
•
•
•
•
•
•
•
•
cyber attacks 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;
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 and the ONE Gas Credit Agreement, 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;
unexpected increases in the costs of providing health care benefits, along with pension and postretirement 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;
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; and
the costs associated with increased regulation and enhanced disclosure and corporate governance requirements
pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those
expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future
results. These and other risks are described in greater detail in 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.
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. We maintain a
provision for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of
43
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.
44
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, 2019 and 2018, 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, 2019, 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, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
k
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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 2019 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, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
k
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.
aa
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 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.
a
45
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 10 to the consolidated financial statements, total regulatory assets and total regulatory liabilities are
approximately $438 million and $549 million, respectively, as of December 31, 2019. 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 new, or changes in existing, rate regulation is a critical audit matter are there was significant judgment by management when
assessing the impact of new regulation, or changes to existing regulation, on regulatory assets and liabilities, which in turn led to
significant auditor judgment and subjectivity in performing procedures and evaluating audit evidence related to the impacts of
new, or changes in existing, rate regulation on 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 thet
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 20, 2020
We have served as the Company’s auditor since 2013.
46
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47
Years Ended December 31,
2018
(Thousands of dollars, except per share amounts)
2017
2019
$
1,652,730
$
1,633,731
$
1,539,633
687,974
714,636
614,501
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
$
$
$
$
399,290
151,889
57,225
608,404
316,728
(14,525)
(46,065)
256,138
(93,143)
162,995
3.10
3.08
52,527
52,979
1.68
$
$
$
$
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.
48
Years Ended December 31,
2018
2017
2019
(Thousands of dollars)
$
172,234
$
186,749
162,995
(1,435)
(1,435)
185,314
$
1,407
1,407
173,641
$
(778)
(778)
162,217
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
$479, $(848), and $486, respectively
Total other comprehensive income (loss), net of tax
Comprehensive income
See accompanying Notes to Consolidated Financial Statements.
$
$
49
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,
2019
2018
(Thousands of dollars)
$
$
6,433,119
1,867,893
4,565,226
6,073,143
1,789,431
4,283,712
17,853
260,012
55,732
104,259
47,440
20,906
506,202
21,323
295,421
44,333
107,295
54,420
20,495
543,287
391,036
157,953
87,883
636,872
5,708,300
$
437,479
157,953
46,211
641,643
5,468,642
$
50
ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
(Continued)
Equity and Liabilities
Equity and long-term debt
Common stock, $0.01 par value:
December 31, December 31,
2019
2018
(Thousands of dollars)
authorized 250,000,000 shares; issued and outstanding 52,771,749 shares at
December 31, 2019; issued 52,598,005 shares and outstanding 52,564,902 shares at
December 31, 2018
Paid-in capital
Retained earnings
Accumulated other comprehensive loss
$
$
528
1,733,092
402,509
(6,739)
526
1,727,492
320,869
(4,086)
(2,145)
2,042,656
1,285,483
3,328,139
299,500
174,510
47,640
48,394
61,183
67,664
698,891
652,426
520,866
178,720
89,600
1,441,612
—
2,129,390
1,286,064
3,415,454
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
$
5,708,300
$
5,468,642
Treasury stock, at cost: 33,103 shares at December 31, 2018
Total equity
Long-term debt, excluding current maturities, and net of issuance costs of $10,936 and $11,457,
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.
51
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52
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
186,749
$
172,234
$
162,995
2019
Years Ended December 31,
2018
(Thousands of dollars)
2017
180,395
13,307
9,314
8,994
26,415
(11,399)
3,036
(47,784)
(59,293)
316
(3,196)
28,203
(35,401)
10,689
310,345
(417,322)
(7,009)
1,399
—
(422,932)
217,000
—
—
—
5,116
160,086
53,242
8,195
8,506
(5,159)
(4,661)
22,859
(52,855)
36,885
6,316
372
109,437
(50,100)
2,337
467,694
(394,450)
—
—
—
(394,450)
(57,715)
—
395,648
(4,324)
4,803
—
(300,000)
(105,424)
(7,575)
109,117
(3,470)
21,323
17,853
61,160
30,152
$
$
$
$
$
$
(96,594)
(8,152)
(66,334)
6,910
14,413
21,323
49,371
800
$
$
$
151,889
92,393
8,876
7,323
(15,147)
(5,588)
(4,722)
(52,376)
1,945
(1,247)
(398)
29,250
(118,095)
(3,298)
253,800
(356,361)
—
—
618
(355,743)
212,215
(17,512)
—
—
4,457
—
(87,951)
(9,516)
101,693
(250)
14,663
14,413
44,436
(1,389)
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
Employee benefit obligation
Other assets and liabilities
Cash provided by operating activities
Investing activities
Capital expenditures
Other investing expenditures
Other investing receipts
Other
Cash used in investing activities
Financing activities
Borrowings (repayment) on notes payable, net
Repurchase of common stock
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
q
p
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.
53
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
January 1, 2017
Cumulative effect of accounting change
Net income
Other comprehensive loss
Repurchase of common stock
Common stock issued and other
Common stock dividends - $1.68 per share
December 31, 2017
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
See accompanying Notes to Consolidated Financial Statements.
Common
Stock Issued
(Shares)
Common
Paid-in
Capital
Stock
(Thousands of dollars)
52,598,005 $
—
—
—
—
—
—
52,598,005
—
—
—
—
52,598,005
—
—
—
173,744
—
52,771,749 $
526 $
—
—
—
—
—
—
526
—
—
—
—
526
—
—
—
2
—
528 $
1,749,574
—
—
—
—
(12,949)
926
1,737,551
—
—
(10,951)
892
1,727,492
—
—
—
4,697
903
1,733,092
54
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
(Continued)
January 1, 2017
Cumulative effect of accounting change
Net income
Other comprehensive loss
Repurchase of common stock
Common stock issued and other
Common stock dividends - $1.68 per share
December 31, 2017
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
See accompanying Notes to Consolidated Financial Statements.
Retained
Earnings
Accumulated
Other
Treasury
Comprehensive
Loss
Stock
(Thousands of dollars)
Total Equity
$
$
161,021 $
10,982
162,995
—
—
—
(88,877)
246,121
172,234
—
—
(97,486)
320,869
186,749
—
1,218
—
(106,327)
402,509 $
(18,126) $
—
—
—
(17,512)
17,142
—
(18,496)
—
—
16,351
—
(2,145)
—
—
—
2,145
—
— $
(4,715) $ 1,888,280
10,982
162,995
—
—
(778)
—
—
—
(5,493)
—
1,407
—
—
(4,086)
—
(1,435)
(1,218)
—
—
(778)
(17,512)
4,193
(87,951)
1,960,209
172,234
1,407
5,400
(96,594)
2,042,656
186,749
(1,435)
—
6,844
(105,424)
(6,739) $ 2,129,390
55
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 the 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.
ff
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.
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.
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 10 for additional discussion of purchased gas cost
recoveries.
Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for natural gas sold or
services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our customers. Those customers
who do not meet minimum standards 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, 2019 and 2018, our allowance for doubtful accounts was $6.6 million and $4.7 million, respectively.
Inventories - Natural gas in storage is maintained on the basis of weighted-average cost. Natural gas inventories that are
injected into storage are recorded in inventory based on actual purchase costs, including storage and transportation costs.
Natural gas inventories that are withdrawn from storage are accounted for in our purchased-gas cost adjustment mechanisms at
the weighted-average inventory cost.
Materials and supplies inventories are stated at the lower of weighted-average cost or net realizable value.
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.
56
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 9 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
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:
y
or
• 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 9 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.
57
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.
See Note 11 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 thana
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 2018 and 2017 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, 2019, 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 asset impairments in 2019, 2018 or 2017.
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 10 for additional information regarding our regulatory assets and liabilities disclosures.
Pension and Other Postemployment Employee Benefits - We have defined benefit retirement plans covering eligible
employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible
employees who retire with at least five years of service. To calculate the costs and liabilities related to our plans, we utilize an
outside actuarial consultant, which uses statistical and other factors to anticipate future events. These factors include
assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and mortality
and employment periods. We use tables issued by the Society of Actuaries to estimate mortality rates. In determining the
58
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.
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, 2019 and 2018.
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, 2019 and 2018.
t
Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date.
See Note 14 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 a
give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon
the discontinued use of the natural gas distribution system. We recognize the fair value of a liability for an asset retirement
obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate
reasonably the fair value of the asset retirement obligations for portions of our assets because the settlement dates are
indeterminable given our expected continued use of the assets with proper maintenance. We expect our natural gas distribution
systems will continue in operation as long as natural gas supply and demand for natural gas distribution service exists. Based
on 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 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 have made an
estimate of 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. We record the estimated asset removal obligation in noncurrent liabilities in other deferred credits on our
Consolidated Balance Sheets. To the extent this estimated liability is adjusted, such amounts will be reclassified between
accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on earnings.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and
environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred
and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution.
59
Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion
of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets
when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or
negative, on earnings.
See Note 16 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 relocations, not
geographic location or regulatory jurisdiction.
In 2019, 2018 and 2017, we had no single external customer from which we received 10 percent or more of our gross revenues.
k
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.
Recently Issued Accounting Standards Update - 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 intraperiod allocation and calculating income taxes in interim periods. The ASU 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, and early adoption is permitted. We are currently assessing the timing and impacts of adopting this standard.
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 the company would capitalize those same costs under the internal-use software guidance for an arrangement that is a
software license. This standard is effective for interim and annual periods in fiscal years beginning after December 15, 2019,
and early adoption is permitted. We will adopt this new guidance in the first quarter of 2020 using the prospective transition
approach and do not expect our adoption will result in a material impact 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 March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation
of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic
service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the
service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and
(3) reporting the other components of net periodic benefit costs separately from the service cost component and outside a
subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization for GAAP, when
60
applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate
regulated entities. We adopted this guidance in the first quarter of 2018. The presentation changes required for net periodic
benefit costs did not impact previously reported net income; however, the reclassification of the other components of benefits
costs resulted in an increase in operating income and an increase in other expenses of $17.3 million for the year ended
December 31, 2017. We elected the practical expedient to use the retroactive presentation of the amounts disclosed for the
various components of net benefit cost in our Employee Benefit Plans footnote as the basis for the retrospective application. In
addition, we updated our information systems for the capitalization of service costs to property, plant and equipment and non-
service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply
retroactive reclassification.
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. It is effective for fiscal years beginning after December 15, 2019, including interim periods withint
those fiscal years, and early adoption is permitted for fiscal years beginning after December 15, 2018. We will adopt this new
guidance in the first quarter of 2020 using the modified retrospective method. Our adoption is not expected to result in a
cumulative adjustment to our opening retained earnings or 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 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 5 for additional information regarding our leases.
In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and
converges the revenue recognition principles under GAAP and International Financial Reporting Standards. We adopted this
new guidance 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. Our adoption did not result in a cumulative adjustment to our opening retained
earnings. Our adoption resulted in a reclassification of certain revenues associated with certain regulatory mechanisms that do
not meet the requirements under ASC 606 as revenue from contracts with customers, but will continue to be reflected as other
revenues in determining total revenues. The reclassified revenues relate primarily to the weather normalization mechanism in
Kansas, where the KCC determines how we reflect variations in weather in our rates billed to customers. See Note 2 for
additional information regarding our revenues.
61
2.
REVENUE
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 represent revenue from contracts with customers through implied contracts established by
our tariff rates approved by the regulatory authorities. For natural gas sales, the customer receives the benefits of our
performance when the commodity is received and simultaneously consumed by the customer. The performance obligation is
satisfied over time as the customer consumes the natural gas.
Our transportation revenues represent revenue from contracts with customers through implied contracts established by our tariff
rates approved by the regulatory authorities and tariff-based negotiated contracts. The customer receives the benefits of our
performance when the commodity is delivered to the customer and the performance obligation is satisfied over time as the
customer receives the natural gas.
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. 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, 2019 and 2018 were $109.7 million and $127.6 million,
respectively, and are 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 related primarily reflect our weather normalization mechanism in
Kansas. This mechanism adjusts our revenues earned for the variance between actual and normal HDDs. This mechanism can
have either positive (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.
The following table sets forth our revenues disaggregated by source for the periods indicated:
Year Ended December 31,
2019
2018
(Thousands of dollars)
1,512,886
114,014
20,579
$
1,647,479
(4,699)
9,950
5,251
1,495,250
109,658
21,710
1,626,618
(2,806)
9,919
7,113
1,652,730
$
1,633,731
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
$
$
62
3.
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.
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, 2019, our total debt-to-
capital ratio was 46 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 the event LIBOR is not available, and such circumstances
are unlikely to be temporary, our lenders 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, 2019 we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement,
with $698.8 million of remaining credit available under the ONE Gas Credit Agreement.
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, 2019, we had $516.5 million of commercial paper outstanding. The ONE Gas Credit Agreement is
available to repay the commercial paper notes, if necessary.
4.
LONG-TERM DEBT
In November 2018, ONE Gas issued $400 million of 4.50 percent senior notes due 2048. The proceeds from the issuance were
used to retire the $300 million of 2.07 percent senior notes due 2019, 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, $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.
63
5.
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.
t
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.
We have operating leases for office facilities, gas storage facilities, information technology equipment and right-of-way
contracts. Our leases have remaining lease terms of 1 year to 14 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 $34.2 million as of December 31, 2019, 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 $8.5 million, $8.2 million, and $8.7 million in 2019, 2018 and 2017, respectively.
In January 2020, we entered into a lease extension resulting in an increase in our right-of-use asset and operating lease liability
of $7.2 million and $7.5 million, respectively.
Other information related to operating leases
Weighted-average remaining lease term
Weighted-average discount rate
Supplemental cash flows information
Lease payments
Right-of-use assets obtained in exchange for lease obligations
December 31,
2019
(Millions of dollars)
7 years
3.62%
$
$
(8.4)
9.5
64
Future minimum lease payments under non-cancellable operating leases
December 31,
2019
(Millions of dollars)
2020
2021
2022
2023
2024
Thereafter
Total future minimum lease payments
Imputed interest
Total operating lease liability
Consolidated balance sheets as of December 31, 2019
Current operating lease liability
Long-term operating lease liability
Total operating lease liability
The following table sets forth the required disclosures for the period prior to adoption of ASC 842:
Future minimum lease payments under non-cancellable operating leases
2019
2020
2021
2022
2023
Thereafter
Total future minimum lease payments
6.
EQUITY
$
$
$
$
$
$
$
7.6
7.2
6.9
5.8
3.1
8.5
39.1
(4.6)
34.5
6.5
28.0
34.5
December 31,
2018
(Millions of dollars)
6.3
5.1
4.5
4.3
4.2
3.8
28.2
Preferred Stock - At December 31, 2019, 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.
k
Common Stock - At December 31, 2019, we had approximately 197.2 million shares of authorized common stock available for
issuance.
k
Treasury Shares - We are 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 may be made in the
open market or in private transactions at times, and in amounts that we deem appropriate. There is no guarantee as to the exact
number of shares that we purchase, and we can terminate or limit the program at any time.
Dividends Declared - In 2019 and 2018, we declared and paid dividends of $2.00 per share ($0.50 per share quarterly) and
$1.84 per share ($0.46 per share quarterly), respectively. In January 2020, we declared a dividend of $0.54 per share ($2.16 per
share on an annualized basis) for shareholders of record on February 21, 2020, payable March 6, 2020.
65
7.
ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the balance in accumulated other comprehensive loss for the periods indicated:
January 1, 2018
Pension and other postemployment benefit plans obligations
Other comprehensive income before reclassification, net of tax of $(577)
Amounts reclassified from accumulated other comprehensive loss, net of tax of $(271)
Other comprehensive income
December 31, 2018
Pension and other postemployment benefit plans obligations
Other comprehensive loss 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
Accumulated Other
Comprehensive Loss
(Thousands of dollars)
$
(5,493)
596
811
1,407
(4,086)
(2,074)
639
(1,435)
(1,218)
(6,739)
$
(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
2019
2018
2017
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)
$
$
35,283
(673)
34,610
(33,758)
852
(213)
639
$
$
43,800
(4,567)
39,233
(38,151)
1,082
(271)
811
$
$
42,591
(4,597)
37,994
(37,157)
837 Income before income taxes
(322) Income tax expense
515 Net income
(a) These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note 13 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 10 for additional information regarding our regulatory assets and liabilities.
8.
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, 2019
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
$
$
186,749
52,895
$
3.53
—
186,749
345
53,240
$
3.51
66
Year Ended December 31, 2018
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
Basic EPS Calculation
Net income available for common stock
Diluted EPS Calculation
Effect of dilutive securities
Net income available for common stock and common stock equivalents
Basic EPS Calculation
Net income available for common stock
Diluted EPS Calculation
Effect of dilutive securities
Net income available for common stock and common stock equivalents
$
$
$
$
172,234
52,693
$
3.27
—
172,234
336
53,029
$
3.25
Year Ended December 31, 2017
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
162,995
52,527
$
3.10
—
162,995
452
52,979
$
3.08
9.
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS
Derivative Instruments - At December 31, 2019, we held purchased natural gas call options for the heating season ending
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. At December 31, 2018, we held purchased natural gas call options for the heating season ended March 2019,
with total notional amounts of 14.3 Bcf, for which we paid premiums of $4.1 million, and which had a fair value of $2.1
million. The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in
current regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment
mechanisms. Additionally, changes in fair value associated with these contracts are deferred as part of our unrecovered
purchased-gas costs in our 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
bank and money market accounts and are classified as Level 1. Our other current and noncurrent assets include $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 $1.3 billion at both
December 31, 2019 and 2018. The estimated fair value of our long-term debt, including current maturities, was $1.5
billion and $1.4 billion at December 31, 2019 and 2018, respectively. The estimated fair value of our long-term debt at
December 31, 2019 and December 31, 2018, was determined using quoted market prices, and is considered Level 2.
67
10.
REGULATORY ASSETS AND LIABILITIES
The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:
December 31, 2019
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
Federal income tax rate changes
Over-recovered purchased-gas costs
Weather normalization
Total regulatory liabilities
Net regulatory assets and liabilities
Remaining
Recovery Period
1 year
See Note 13
8 years
15 years
1 year
1 to 19 years
(a)
1 year
1 year
Current
Noncurrent
(Thousands of dollars)
— $
$
$ 17,172
21,213
812
98
2,921
5,224
47,440
(10,297)
(27,623)
(7,281)
(45,201)
373,266
5,677
9,709
—
2,384
391,036
(503,518)
—
—
(503,518)
Total
17,172
394,479
6,489
9,807
2,921
7,608
438,476
(513,815)
(27,623)
(7,281)
(548,719)
$
2,239
$ (112,482) $ (110,243)
(a) Recovery period varies by jurisdiction. See discussion below for additional information regarding our regulatory liabilities related to
federal income tax rate changes.
December 31, 2018
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
Federal income tax rate changes
Over-recovered purchased-gas costs
Weather normalization
Total regulatory liabilities
Net regulatory assets and liabilities
Remaining
Recovery Period
1 year
See Note 13
9 years
15 years
1 year
1 to 20 years
(a)
1 year
1 year
Current
Noncurrent
(Thousands of dollars)
— $
$
Total
$ 25,083
23,384
812
—
1,070
4,071
54,420
(30,934)
(13,668)
(3,792)
(48,394)
6,026
$
$
421,726
6,487
7,724
—
1,542
437,479
(520,866)
—
—
(520,866)
25,083
445,110
7,299
7,724
1,070
5,613
491,899
(551,800)
(13,668)
(3,792)
(569,260)
(83,387) $ (77,361)
(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. yy
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 areaa
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.
68
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.
Recovery through rates resulted in amortization of regulatory assets of approximately $2.5 million, $1.7 million and $1.0 million
for the years ended December 31, 2019, 2018 and 2017, respectively.
Federal income tax rate changes represent 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.
In 2018, we accrued a separate current regulatory liability associated with the change in the federal corporate income tax rates
collected in our rates resulting in a reduction to our revenues of $36.6 million for the year ended December 31, 2018. In
January 2019, the OCC issued an order that resulted in the establishment of a $15.8 million liability, including interest, at
December 31, 2018, for the estimated impact on customer rates of earnings, including amounts attributable to tax savings,
above the 9.5 percent approved ROE in the 2018 review period, to be returned to customers within the 2019 PBRC filing. A
settlement was reached and the OCC approved a joint stipulation in August 2019. This stipulation included a PBRC credit of
$15.6 million to be credited over a 12-month period to Oklahoma customers beginning in the third quarter 2019. In a separate
order issued in February 2019, the KCC required Kansas Gas Service to refund the regulatory liability for the portion of its
revenue representing the difference between the 21 percent and 35 percent federal corporate income tax rate for the period
between January 1, 2018, and through the date on which the KCC issued a final order in Kansas Gas Service’s June 2018 rate
case. In 2019 and 2018, we accrued a $2.4 million and $14.2 million, respectively, reduction to revenues for the periods until
new rates were implemented in Kansas. The total refund of $16.6 million was issued through a bill credit to Kansas customers
in the second quarter 2019. In 2018, Texas Gas Service issued 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 in its service
areas.
As a result of the enactment of the Tax Cuts and Jobs Act of 2017, we remeasured our ADIT. As a regulated entity, the change
in ADIT was recorded as a noncurrent regulatory liability and is subject to refund to our customers. The Tax Cuts and Jobs Act
of 2017 retains the tax normalization provisions of the Code that stipulate how these excess deferred income taxes for certain
accelerated tax depreciation benefits are to be refunded to customers. Our customers began receiving refunds as determined by
our regulators in 2019. In January 2019, the OCC issued an order in response to Oklahoma Natural Gas’ March 2018 PBRC
filing requiring Oklahoma Natural Gas to credit customers for the reduction in ADIT based upon an amortization period in
compliance with the tax normalization rules for the portions of EDIT stipulated by the Code and ten years for all other
components of EDIT. In February 2019, the KCC issued an order adjusting Kansas Gas Service’s base rates, which included an
amortization credit associated with the refund of ADIT based on an amortization period in compliance with the tax
normalization rules for the portion of EDIT stipulated by the Code and five years for all other components of EDIT. As a result
of the orders in Oklahoma and Kansas, the estimated EDIT is being returned to customers beginning in 2019. Three 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 three service areas in Texas will be determined as we work with our regulators. In 2019, we credited income tax
expense $12.8 million for the amortization of the regulatory liability associated with EDIT that was returned to customers.
See Note 14 for additional information regarding our regulatory liabilities for federal corporate income tax rate changes.
69
11.
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
2018
(Thousands of dollars)
5,117,496
549,788
612,984
152,851
6,433,119
(1,867,893)
4,565,226
4,861,340
517,697
567,580
126,526
6,073,143
(1,789,431)
4,283,712
$
We compute depreciation expense by applying composite, straight-line rates of approximately 2.0 percent to 3.0 percent that
were approved by various regulatory authorities.
We recorded capitalized interest of $4.6 million, $3.4 million and $3.0 million for the years ended December 31, 2019, 2018
and 2017, respectively. We incurred liabilities for construction work in process that had not been paid at December 31, 2019,
2018 and 2017 of $20.9 million, $15.6 million and $21.7 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.
12.
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, 2019, 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, 2019, we had approximately 1.8 million shares available for issuance under the ECP, which
reflect shares issued and estimated shares expected to be issued upon vesting of outstanding awards granted under the plan, less
forfeitures. The plan allows for the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code
section 409A requirements.
Compensation expense for our share-based payment plans was $6.8 million, net of tax benefits of $2.2 million, for 2019, $6.1
million, net of tax benefits of $2.1 million, for 2018, and $4.9 million, net of tax benefits of $3.0 million, for 2017.
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
70
awards will only be adjusted for forfeitures. A forfeiture rate of 3 percent per year based on historical forfeitures under our uu
share-based payment plans is used.
Restricted Stock Unit Award Activity
As of December 31, 2019, there was $3.0 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 1.8 years. The following
tables set forth activity and various statistics for restricted stock unit awards outstanding under the respective plans for the
period indicated:
Number of
Units
Weighted-
Average Price
Nonvested at December 31, 2018
Granted
Vested
Forfeited
Nonvested at December 31, 2019
$
109,506
35,753
$
(39,418) $
(1,443) $
$
104,398
Weighted-average grant date fair value (per share)
Fair value of shares granted (thousands of dollars)
2019
2018
2017
$
$
83.94
3,001
$
$
68.17
2,583
$
$
63.45
83.94
58.60
69.87
72.21
63.97
2,420
The fair value of restricted stock vested was $3.3 million and $4.7 million in 2019 and 2018, respectively.
Performance Stock Unit Award Activity
As of December 31, 2019, there was $6.4 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 1.8 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 2019, 2018 and 2017 grants at the grant date:
Nonvested at December 31, 2018
Granted
Vested
Forfeited
Nonvested at December 31, 2019
Volatility (a)
Dividend yield
Risk-free interest rate (b)
Number of
Units
Weighted-
Average Price
$
219,331
$
71,237
(70,548) $
(1,844) $
$
218,176
69.21
89.86
64.06
73.57
77.58
2019
18.70%
2.38%
2.50%
2018
18.80%
2.70%
2.38%
2017
20.70%
2.63%
1.48%
(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)
2019
2018
2017
$
$
89.86
6,401
$
$
74.04
5,882
$
$
68.94
5,110
The fair value of performance stock vested was $12.7 million and $13.7 million in 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
71
exercise date. Approximately 44 percent, 45 percent and 43 percent of employees participated in the plan in 2019, 2018 and
2017, respectively, and purchased 71,613 shares at $71.42 in 2019, 76,231 shares at $63.01 in 2018, and 78,472 shares at
$56.80 in 2017.
Compensation expense, before taxes, was $1.5 million, $1.0 million and $1.2 million in 2019, 2018 and 2017, respectively.
13.
EMPLOYEE BENEFIT PLANS
Retirement and Other Postemployment Benefit Plans
Retirement 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.
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,
2019
2018
3.50%
3.40%
3.10% - 4.00%
4.40%
4.40%
3.20% - 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,
2018
3.80%
3.70%
7.25%
2019
4.40%
4.40%
7.20%
2017
4.30%
4.20%
7.75%
Expected long-term return on plan assets - other postemployment plans
Compensation increase rate
7.35%
3.20% - 4.00%
7.60%
3.25% - 3.35%
7.60%
3.25% - 3.40%
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 would be reflected in earnings.
72
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.
Since adoption of ASU 2017-07 on January 1, 2018, we continue to capitalize all eligible service cost and non-service cost
components under the accounting requirements of ASC Topic 980 (Regulated Operations) for rate-regulated entities. Our
consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset. We have recognized a
regulatory asset of $4.7 million and $1.5 million as of December 31, 2019 and December 31, 2018, respectively. See Note 10
for additional information.
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
Benefit obligation, beginning of period
Service cost
Interest cost
Plan participants’ contributions
Actuarial loss (gain)
Benefits paid
Settlements
Benefit obligation, end of period
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
Balance at December 31
Current liabilities
Noncurrent liabilities
Balance at December 31
Pension Benefits
Other Postemployment Benefits
December 31,
December 31,
2019
2018
2019
2018
(Thousands of dollars)
$
950,510
$
993,891
$
220,144
$
255,040
12,030
40,670
—
98,231
(50,915)
(49,158)
1,001,368
814,112
162,785
29,199
—
(50,915)
(47,207)
907,974
12,919
36,801
—
(42,540)
(50,561)
—
950,510
884,804
(62,752)
42,386
—
(50,561)
235
814,112
1,734
9,318
3,697
13,945
(18,348)
—
230,490
176,859
38,772
6,202
3,697
(18,348)
—
207,182
$
$
$
(93,394) $
(136,398) $
(23,308) $
(1,045) $
(962) $
— $
(92,349)
(135,436)
(23,308)
(93,394) $
(136,398) $
(23,308) $
2,354
9,117
3,563
(31,607)
(18,323)
—
220,144
190,226
(6,325)
7,718
3,563
(18,323)
—
176,859
(43,285)
—
(43,285)
(43,285)
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 $937.8 million and $890.4 million at December
31, 2019 and 2018, respectively.
In 2020, our required contributions are expected to be $1.1 million and $4.0 million, respectively, to our defined benefit
pension plans and other postemployment benefit plans. There are no plan assets expected to be withdrawn and returned to us in
2020.
73
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,
2019
2018
2017
(Thousands of dollars)
$
$
12,030
$
12,919
$
40,670
(61,939)
33,039
36,801
(60,579)
39,913
23,800
$
29,054
$
12,176
40,453
(58,496)
36,107
30,240
(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 15 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,
2019
2018
2017
(Thousands of dollars)
$
$
1,734
$
2,354
$
9,318
(12,586)
(673)
2,244
9,117
(14,284)
(4,567)
3,887
37
$
(3,493) $
2,509
9,890
(12,590)
(4,597)
6,484
1,696
(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 15 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,
2019
2018
2017
$
$
(Thousands of dollars)
(2,766) $
1,173
$
852
479
1,082
(848)
(1,435) $
1,407
$
(2,101)
837
486
(778)
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.
74
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,
2019
2018
(Thousands of dollars)
(381,633) $
(381,633)
373,025
(8,608)
1,869
(6,739) $
Other Postemployment Benefits
December 31,
2019
2018
(Thousands of dollars)
202
$
(19,660)
(19,458) $
19,458
— $
(419,238)
(419,238)
412,545
(6,693)
2,607
(4,086)
875
(34,144)
(33,269)
33,269
—
$
$
$
$
$
The following table sets forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets
expected to be recognized as components of net periodic benefit expense in the next fiscal year:
Amounts to be recognized in 2020
(Thousands of dollars)
Prior service cost
Actuarial net loss
$
$
— $
42,319
$
(117)
173
Pension Benefits
Other Postemployment
Benefits
Health Care Cost Trend Rates - The following table sets forth the assumed health care cost-trend rates for the periods
indicated:
Health care cost-trend rate assumed for next year
Rate to which the cost-trend rate is assumed to decline
(the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
2019
6.50%
5.00%
2025
2018
7.00%
5.00%
2024
75
Assumed health care cost-trend rates have a significant effect on the amounts reported for our other postemployment benefit
plans. A one percentage point change in assumed health care cost-trend rates would have the following effects:
Effect on total of service and interest cost
Effect on other postemployment benefit obligation
One Percentage
One Percentage
Point Increase
Point Decrease
(Millions of dollars)
$
$
0.1
2.3
$
$
(0.1)
(2.4)
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.
76
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, 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 is primarily money market funds.
(d) - This category represents alternative investments such as hedge funds and other financial instruments.
Pension Benefits
December 31, 2018
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
$
282,668 $
35,870 $
— $
—
—
2,419
—
—
69,475
240,900
71,991
—
1,139
—
—
—
30,445
79,205
318,538
69,475
240,900
74,410
30,445
80,344
$
285,087 $
419,375 $
109,650 $
814,112
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category represents alternative investments such as hedge funds and other financial instruments.
77
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 is primarily money market funds.
(d) - This category includes equity securities and bonds held in a captive insurance product.
Other Postemployment Benefits
December 31, 2018
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
$
$
58,087 $
2,382 $
— $
—
—
1,249
—
74
25,857
300
88,910
—
—
—
—
60,469
74
25,857
1,549
88,910
59,336 $
117,523 $
— $
176,859
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category includes equity securities and bonds held in a captive insurance product.
The following table sets forth the reconciliation of Level 3 fair value measurements of our pension plans for the periods
indicated:
January 1, 2018
Net realized and unrealized gains (losses)
Purchases
Settlements
December 31, 2018
Net realized and unrealized gains (losses)
Purchases
Sales and settlements
December 31, 2019
Pension Benefits
Insurance
Contracts
Other
Investments
Total
(Thousands of dollars)
35,158
$
78,707
$
113,865
(611)
—
(4,100)
496
—
—
(115)
—
(4,100)
30,445
$
79,205
$
109,650
(860)
—
(3,597)
2,588
—
—
1,728
—
(3,597)
25,988
$
81,793
$
107,781
$
$
$
78
Pension and Other Postemployment Benefit Payments - Benefit payments for our defined benefit pension and other
postemployment benefit plans for the period ended December 31, 2019 were $50.9 million and $18.3 million, respectively.
The following table sets forth the pension benefits and other postemployment benefits payments expected to be paid in
2020-2029:
Benefits to be paid in:
(Thousands of dollars)
Pension
Benefits
Other Postemployment
Benefits
2020
2021
2022
2023
2024
2025 through 2029
$
$
$
$
$
$
49,631
50,378
51,547
52,628
53,562
280,547
$
$
$
$
$
$
16,464
16,308
16,269
16,090
15,757
73,787
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31,
2019, 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 $12.8 million, $12.1 million and $11.7 million in 2019, 2018 and 2017, 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 $8.5 million, $7.4 million and
$8.1 million in 2019, 2018 and 2017, respectively.
14.
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
2019
Years Ended December 31,
2018
(Thousands of dollars)
2017
$
$
24,537
5,008
29,545
8,375
4,932
13,307
42,852
$
$
— $
289
289
42,413
10,829
53,242
53,531
$
—
750
750
83,138
9,255
92,393
93,143
79
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,
2018
(Thousands of dollars)
$
225,765
$
2019
229,601
21%
21%
48,215
9,758
—
(12,828)
(2,116)
(177)
42,852
$
47,411
8,783
74
—
(2,770)
33
53,531
$
2017
256,138
35%
89,648
6,503
2,162
—
(5,162)
(8)
93,143
As a result of the enactment of the Tax Cuts and Jobs Act of 2017, we remeasured our ADIT. As a regulated entity, the change
in ADIT was recorded as a regulatory liability and is subject to refund to our customers. The effect on the net deferred income
tax liability for the enacted decrease in the federal income tax rate was $518.7 million, of which $520.9 million was recorded as
a reduction to the deferred income tax liabilities and deferred as a regulatory liability for ratemaking purposes, offset by $2.2
million recorded as an increase in deferred income tax expense in 2017 attributable to the remeasured deferred income taxes
associated with certain expenses not recovered in our rates. These adjustments had no impact on our 2018 or 2017 cash flows.
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,
2018
2019
(Thousands of dollars)
$
$
32,036
124,680
752
8,599
2,772
168,839
742,860
3,556
96,456
8,599
851,471
682,632
$
$
48,243
129,201
2,778
—
34
180,256
717,903
8,981
105,798
—
832,682
652,426
As of December 31, 2019, we have no federal income tax NOL carryforwards and state income tax NOL carryforwards of
$13.6 million, which will expire at various dates from 2025 through 2027. We believe that it is more likely than not that the tax
benefits of the NOL carryforwards will be utilized prior to their expirations; therefore, no valuation allowance is necessary.
We have completed or made a reasonable estimate for the measurement and accounting of the effects of the Tax Cuts and Jobs
Act of 2017, which were reflected in our consolidated financial statements for the year 2018. While we still expect additional
guidance from the U.S. Department of the Treasury and the IRS, we have finalized our calculations using available guidance.
Any additional guidance issued or future actions of our regulators could potentially affect the accounting effects arising from
the implementation of the Tax Cuts and Jobs Act of 2017.
We have filed our consolidated federal and state income tax returns for years 2016, 2017 and 2018. We are no longer subject to
income tax examination for years prior to 2016.
80
15.
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
Other, net
Total other expense, net
16.
COMMITMENTS AND CONTINGENCIES
Years Ended December 31,
2019
2018
2017
(Thousands of dollars)
$
$
(5,895) $
(8,824) $
(17,252)
2,919
(2,535)
2,727
(2,976) $
(11,359) $
(14,525)
Commitments - See Note 5 of the Notes to Consolidated Financial Statements in this Annual Report for discussion of
operating leases.
Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or
d
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
aa
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 2019, 2018 or 2017.
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 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. During the first quarter of 2019, we completed
a project to remove the source of contamination and associated contaminated materials at the twelfth site where no active soil
remediation had previously occurred. We are also finalizing a study of the feasibility of various options to address the
remainder of the site.
With regard to one of our former MGP sites in Kansas, periodic monitoring and a 2016 interim site investigation indicated
elevated levels of contaminants generally associated with MGP sites. In 2016, we estimated the potential costs associated with
additional investigation and remediation to be in the range of $4.0 million to $7.0 million. In the second quarter of 2018, we
revised our estimate of the potential costs associated with additional investigation and remediation to be in the range of $5.6
million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in
the ultimate remediation approach that will be utilized. Accordingly, we recorded in the second quarter of 2018 an adjustment
to the reserve of $1.6 million bringing the total to $5.6 million for this site, which also increased our regulatory asset pursuant
to our AAO in Kansas. In 2019, the KDHE approved the remediation plan that is the basis of our estimated cost range.
81
In Kansas, 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. At the time future
investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas
Service will be required to file an application with the KCC for approval to increase the $15.0 million cap.
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 2019, 2018 or 2017. A number of environmental issues may exist with
respect to 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.
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 include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM
comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process,
PHMSA is being 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 has 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 will split this NPRM into three separate final rulemakings:
•
the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs
Creation Act and will be called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of
Assessment Requirements, and Other Related Amendments;
82
•
•
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 rulemakings referenced above, which addresses 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 potential capital and operating expenditures associated with compliance with the first final rulemaking are
under review but are not expected to be material.
PHMSA has indicated it now expects the second pending rulemaking to be issued as a final rule during 2020. The potential
capital and operating expenditures associated with compliance with these pending rulemakings are currently being evaluated
and could be significant depending on the final regulations.
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.
17.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Year Ended December 31, 2019
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Revenues
Operating income
Net income
Earnings per share
Basic
Diluted
Year Ended December 31, 2018
Revenues
Operating income (a)
Net income
Earnings per share
Basic
Diluted
$
$
$
$
$
$
$
$
$
$
661,000
127,619
93,660
1.77
1.76
First
Quarter
638,464
130,290
90,835
1.73
1.72
$
$
$
$
$
$
$
$
$
$
(Thousands of dollars)
290,560
46,891
24,470
0.46
0.46
$
$
$
$
$
248,563
38,777
17,457
0.33
0.33
$
$
$
$
$
452,607
81,971
51,162
0.97
0.96
Second
Quarter
Third
Quarter
Fourth
Quarter
(Thousands of dollars)
292,521
41,043
20,419
0.39
0.39
$
$
$
$
$
$
238,280
$
36,241
16,276 $
464,466
80,855
44,704
0.31
0.31
$
$
0.85
0.84
(a) Reflects the impact of the adoption of a new accounting standard in fiscal year 2018 related to the presentation of net periodic benefit
costs. See Note 1 for additional information regarding our adoption of this standard.
83
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, 2019.
The effectiveness of our internal control over financial reporting as of December 31, 2019, 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
There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2019, 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 2020 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 2020 definitive Proxy Statement and is
incorporated herein by this reference.
84
Code of Ethics
Information concerning the code of ethics, or code of business conduct, is set forth in our 2020 definitive Proxy Statement and
is incorporated herein by this reference.
Nominating Procedures
Information concerning the nominating procedures is set forth in our 2020 definitive Proxy Statement and is incorporated
herein by this reference.
The Audit Committee
Information concerning the Audit Committee is set forth in our 2020 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 2020 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 2020 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 2020 definitive Proxy Statement and is
incorporated herein by this reference.
The Executive Committee
Information concerning the Executive Committee is set forth in our 2020 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 2020 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 2020 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 2020 definitive Proxy Statement and is
incorporated herein by this reference.
85
Equity Compensation Plan Information
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2019:
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)
—
—
2,921,919
238,309
3,160,228
Plan Category
Equity compensation plans approved
by security holders (1)
Equity compensation plans not
approved by security holders (2)
Total
(1) Includes restricted stock incentive units and performance-unit awards granted under our ECP and our Deferred Compensation Plan for Non-employee
Directors. For a brief description of the material features of this plan, see Note 12 of the Notes to Consolidated Financial Statements in this Annual Report.
(2) Includes shares granted under our ESPP and Employee Stock Award Program. For a brief description of the material features of these plans, see Note 12 of
the Notes to Consolidated Financial Statements in this Annual Report. Column (c) includes 236,497 and 1,812 shares available for future issuance under our
ESPP and Employee Stock Award Program, respectively.
(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 for these plans to calculate the weighted-average exercise price in the table is $93.57, which
represents the year-end closing price of our common stock on the NYSE.
ff
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 2020 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 2020 definitive Proxy Statement and is
incorporated herein by this reference.
86
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV.
( )
(1) Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Page No.
g
45-46
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017
48
Consolidated Statements of Comprehensive Income for the years ended December 31, 2019,
2018 and 2017
49
Consolidated Balance Sheets as of December 31, 2019 and 2018
50-51
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017 53
Consolidated Statements of Equity for the years ended December 31, 2019, 2018 and 2017
54-55
Notes to Consolidated Financial Statements
56-83
( )
(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
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 July 23, 2018 (incorporated by reference to Exhibit
3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on July 27, 2018 (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)).
Second Supplemental Indenture, dated of 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)).
Description of the Registrant’s securities registered pursuant to Section 12 of the Securities Act of 1934.
87
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. Annual Officer Incentive Plan (incorporated by reference to Appendix A to ONE Gas, Inc.’s
Definitive Proxy Statement on Schedule 14A filed on April 5, 2017 (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 10.12 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)).
10.16
ONE Gas, Inc. Amended and Restated Employee Stock Purchase Plan.
10.17
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)).
10.18
Not used.
88
10.19
Form of Commercial Paper Dealer Agreement (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s
Current Report on Form 8-K filed on September 10, 2014 (File No. 1-36108)).
10.20
Form of 2020 Performance Unit Award Agreement.
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
Form of 2020 Restricted Unit Award Agreement.
Form of 2016 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.24 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 18, 2016 (File No. 1-36108)).
Form of 2016 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.25 to ONE Gas,
Inc.’s Annual Report on Form 10-K filed on February 18, 2016 (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. 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).
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).
10.31
ONE Gas, Inc. Amended and Restated Annual Officer Incentive Plan, effective January 1, 2020.
21.1
23.1
31.1
31.2
32.1
32.2
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)).
89
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, 2019, 2018 and 2017; (iii) Consolidated
Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017; (iv) Consolidated Balance
Sheets as of December 31, 2019 and 2018; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2019,
2018 and 2017; (vi) Consolidated Statements of Equity for the years ended December 31, 2019, 2018 and 2017; 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.
90
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 20, 2020
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 20th day of February 2020.
/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
91
O NE 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:
Kansas Gas Service
the largest in Kansas
Oklahoma Natural Gas
the largest in Oklahoma
Texas Gas Service
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.
We primarily serve residential, commercial and transportation
customers in all three states.
ONEGas.com
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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 21, 2020 – 9 a.m. CDT
Auditors
PricewaterhouseCoopers LLP
Two Warren Place
6120 South Yale Avenue, Suite 1850
Tulsa, OK 74136
Corporate Headquarters
First Place Tower
15 East Fifth Street
Tulsa, OK 74103
Credit Ratings
Moody’s: A2 (Stable)
Standard & Poor’s: A (Stable)
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.
Non-GAAP Reconciliation
2019
Total revenues
Cost of natural gas
Net margin
Years Ended December 31,
2018
(Millions of dollars)
$ 1,633.7
714.6
$ 919.1
$ 1,539.6
614.5
$ 925.1
2017
$ 1,652.7
687.9
$ 964.8
MIX
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responsible sources
FSC® C103375
15 East Fifth Street, Tulsa, OK 74103 • 918-947-7000 • ONEGas.com
Annual Report 2019
DELIVERING NATURAL GASFOR A BETTER TOMORROW