Integrated
Reliability.
ONEOK 2019 ANNUAL REPORT
ONEOK, Inc. (pronounced ONE-OAK) (NYSE: OKE) is a leading midstream service provider and owner of one of the nation's premier natural gas liquids (NGL) systems,
connecting NGL supply in the Rocky Mountain, Permian and Mid-Continent regions with key market centers and an extensive network of natural gas gathering,
processing, storage and transportation assets.
ONEOK is a FORTUNE 500 company and is included in the S&P 500. For the latest news about ONEOK, find us on LinkedIn, Facebook, Twitter and Instagram.
Financial Performance
$1.30
$1.39
$1.00
$1.84
$1.91
$1.99
$1.85
$1.58
$2.45
$2.58
2015
2016
2017
2018
2019
OPERATING INCOME
(billions of dollars)
2015
2016
2017
2018
2019
ADJUSTED EBITDA
(billions of dollars)
$2.46
$2.72
$2.43
$3.245
$3.53
2015
2016
2017
2018
2019
DIVIDEND
GROWTH
TOTAL SHAREHOLDER RETURN*
5-YEAR
-32%
3-YEAR
-13%
1-YEAR
102%
ONEOK
ONEOK Peer Group
74%
S&P 500 Index
54%
ONEOK
53%
48%
9%
31%
ONEOK Peer Group
S&P 500 Index
ONEOK
ONEOK Peer Group
S&P 500 Index
As of Dec. 31, 2019
*Total return represents share-price appreciation and the reinvestment of dividends.
Setting a New Standard
for Midstream
2019 was an outstanding year of project execution and record-setting safety performance for ONEOK. These results set the stage for strong growth at
attractive returns. Our extensive asset position and exceptional financial strength allow us to perform well even in challenging times.
In 2018 and 2019, we turned our attention to construction of several significant capital-growth projects. Building an organic growth program of this
scale, while maintaining safe and reliable operations of our existing assets, is challenging. It requires focus, dedication and collaboration with all
stakeholders, including landowners, public officials, contractors and many others.
Thankfully, but not surprisingly, our employees rose to the challenge, completing these projects safely, on time and on budget. These critical projects
are expected to significantly increase capacity and demonstrate our ability to grow alongside our customers.
For example, Williston Basin producers continue to see improvements through enhanced completion techniques, yielding increased natural gas liquids
(NGL) and natural gas volumes delivered to our system.
To meet our Williston customers’ needs for additional capacity, ONEOK built the Elk Creek NGL pipeline and two natural gas processing plants –
Demicks Lake I and Demicks Lake II. We are also expanding the Bear Creek facility and the Elk Creek Pipeline. This new infrastructure will bring much
needed support to our customers as they strive to significantly reduce the amount of natural gas flared in the region.
In addition to completing several growth projects in 2019, we also:
• Achieved outstanding environment, safety and health (ESH) performance, resulting in the company's lowest incident rates for employee injuries
and preventable vehicle accidents in the past 10 years and agency reportable environmental events over the past six years.
• Increased volumes of NGL raw feed throughput and natural gas processed across our system each by 7% compared with 2018.
• Increased net income and adjusted earnings before interest, taxes, depreciation and amortization (adjusted EBITDA) by 11% and 5%,
respectively, compared with 2018.
• Announced expansions of our Bear Creek natural gas processing plant and Mid-Continent NGL fractionation facility and infrastructure; an
additional 40,000 bpd expansion of our West Texas LPG pipeline; and an extension of our Bakken NGL Pipeline.
• Increased dividends paid to $3.53 per share, a 9% increase compared with 2018.
• Achieved dividend coverage of 1.38 times.
• Ended the year with a strong balance sheet and investment-grade credit ratings.
Elk Creek Pipeline Construction in Colorado
Mont Belvieu Fractionation Facility Construction in Texas
1
LETTER TO OUR INVESTORS Demicks Lake I Natural Gas Processing Plant Construction in North Dakota
Our focus in 2020 remains on operating our network of assets in the manner for which ONEOK has a strong reputation – safely, reliably and in an
environmentally sustainable way. The anticipated completion of additional growth projects, many in the first quarter 2020, will result in a decrease in
capital spending as our strong balance sheet gets even stronger.
We expect earnings from our completed projects to drive net income and adjusted EBITDA growth of approximately 16% and 25%, respectively, in
2020 and provide support for continued growth through:
• Increased natural gas on our system as a result of new supply and reduced flaring in the Williston Basin.
• Increased NGLs from our Rocky Mountain region and Permian Basin operations to the Gulf Coast market center.
• Completion of the Arbuckle II Pipeline, MB-4 fractionator and an 80,000 bpd expansion of the West Texas LPG pipeline.
We continue to focus on our environmental, social and governance (ESG) practices, and our efforts have been rewarded. In 2019, we were the only
U.S. midstream company added to the Dow Jones Sustainability North America Index. In total, we now are listed in 30 ESG-related indexes.
We invite you to read our most recent Corporate Sustainability Report for more on these efforts.
Of course, our achievements over the past year are attributable to the nearly 3,000 employees across our operations. We thank them for their
continued dedication to our company and to the communities where we operate and where they live and work.
In 2019, some of our operating areas experienced record-breaking floods. ONEOK and our employees responded with more than $1 million for
flood relief efforts, as well as countless hours volunteered by employees. We are proud that they continue to exhibit our core values every day, and
especially during the times of greatest need.
Thank you to our board of directors for its support as our company evolves to meet the needs of our stakeholders. Our focus in 2020 remains on
maintaining our financial strength and safely and successfully completing our capital-growth projects, which are expected to create exceptional value
for our stakeholders and investors by building on our strong asset position.
And finally, thank you to our investors for your continued trust and investment in ONEOK. You are a part of our reliability story as you continue to invest
in ONEOK’s future.
John W. Gibson
Chairman
March 11, 2020
2
Terry K. Spencer
President and Chief Executive Officer
Our Assets
M O N T A N A
A
B
C
N O R T H
D A K O T A
M I N N E S O T A
WILLISTON BASIN
W I S C O N S I N
POWDER
RIVER BASIN
W Y O M I N G
D
S O U T H D A K O T A
DENVER-
JULESBURG
BASIN
C O L O R A D O
I O W A
N E B R A S K A
K A N S A S
E
F
O K L A H O M A
I N D I A N A
I L L I N O I S
M I S S O U R I
K E N T U C K Y
T E N N E S S E E
LEGEND
Natural Gas
Gathering Pipelines
Natural Gas
Processing Plants
NGL Pipelines
NGL Fractionators
NGL Storage
Partial Interest
Natural Gas Pipelines
Natural Gas Storage
Growth Projects
Basins
N E W M E X I C O
K
STACK &
SCOOP PLAYS
J
G
I
PERMIAN BASIN
T E X A S
H
L
A R K A N S A S
L O U I S I A N A
GROWTH PROJECTS
A
B
C
D
E
F
*Suspended or scope reduced on March 11, 2020.
G
H
I
J
K
L
3
Bakken NGL Pipeline Extension (IN PROGRESS)Demicks Lake Plants I, II (COMPLETED) and III* (IN PROGRESS)Bear Creek Plant Expansion (IN PROGRESS)Elk Creek Pipeline (COMPLETED) and Expansion* (IN PROGRESS)Mid-Continent Fractionation Facility Expansions (IN PROGRESS)Canadian Valley Plant Expansion (COMPLETED)ONEOK Gas Transportation Expansions (COMPLETED)Sterling III Pipeline Expansion (COMPLETED)Arbuckle II Pipeline (COMPLETED) and Expansion (IN PROGRESS)West Texas LPG Pipeline Expansions I (COMPLETED), II, III and IV* (IN PROGRESS)Roadrunner and ONEOK WesTex Expansions (COMPLETED)MB-4 and MB-5 Fractionators and Storage (IN PROGRESS) Growth Projects Timeline
2018
West Texas LPG Pipeline Expansion I
Sterling III Pipeline Expansion
Canadian Valley Plant Expansion
and Infrastructure
ONEOK Gas Transportation
Westbound Expansion
2019
ONEOK Gas Transportation
Eastbound Expansion
ONEOK WesTex Transmission Expansion
Roadrunner Gas Transmission
Bidirectional Expansion
Demicks Lake I Plant and Infrastructure
Elk Creek Pipeline and Infrastructure
MIDSTREAM INDUSTRY
Natural Gas Pipeline
Natural Gas Gathering
Residue Gas
Raw Feed NGLs
WELLHEAD
NATURAL GAS
PROCESSING PLANT
NGL Gathering Pipeline
4
2020
2021
Demicks Lake II Plant and Infrastructure
MB-5 Fractionator and Infrastructure
Arbuckle II Pipeline and Infrastructure
MB-4 Fractionator and Infrastructure
Arbuckle II Pipeline Extension
and Infrastructure
Arbuckle II Pipeline Expansion
West Texas LPG Pipeline Expansion II
and Arbuckle II Connection
West Texas LPG Pipeline Expansions III and IV*
Bakken NGL Pipeline Extension
Mid-Continent Fractionation Facility Expansions
Completed Project
Expected Completion
Bear Creek Plant Expansion and Infrastructure
Elk Creek Pipeline Expansion*
*Suspended or scope reduced on March 11, 2020.
Demicks Lake III Plant and Infrastructure*
Natural Gas Pipeline
Local Distribution Companies
Electric Generation
Large Industrials
Liquefied Natural Gas Exports
NATURAL GAS STORAGE &
END-USE MARKETS
NGL FRACTIONATOR
NGL STORAGE & MARKET CENTER
NGL Distribution Pipeline
Ethane
Propane
Isobutane
Normal Butane
Natural Gasoline
5
Petrochemical
Refining
Heating
Exports
Operational Highlights
As a midstream service provider, our producers
Consumers also rely on the products that move
environment; to how we adapt to meet changing
rely on our nondiscretionary services to
through our assets to fuel their businesses and
regulations; to how we retain our talented
transport, process, fractionate and store
daily activities.
workforce – reliability is a necessary part of
NGLs and natural gas. In short, our network
everything we do.
of assets is a critical link between the wellhead
That’s why reliability is so important to us. From
and the marketplace.
how we design our pipeline system with safety
It is built into every step of our operations to
in mind; to how we plan our asset maintenance
facilitate uninterrupted service for customers and
and integrity programs; to how we care for the
consumers when and where they need us most.
Bushton Fractionation Facility in Kansas
6
Arbuckle II Pipeline Construction in Texas
Mont Belvieu Fractionation Facility Construction in Texas
Doubling the Backbone
of Our NGL Business
In 2019, demand for NGL services continued to
increase in some of the most productive shale
plays in the country – the Williston Basin in North
Dakota, the Powder River Basin in Wyoming, the
Denver-Julesburg Basin in Colorado, the STACK
and SCOOP areas in the Mid-Continent and the
Permian Basin in West Texas.
ONEOK is uniquely positioned in the heart
of these basins and has made significant
investments in organic capital-growth projects
to provide additional takeaway capacity to meet
producer needs in the short- and long-term.
The Elk Creek Pipeline, completed in late 2019,
provides key NGL raw feed takeaway from the
Williston and Powder River basins to the Conway,
Kansas, market center.
The Arbuckle II Pipeline, which was completed
in the first quarter 2020, moves supply growth
from the basins we serve to the Mont Belvieu,
Texas, market center. Through low cost, high
return expansions, the pipeline is expandable
up to 1 million bpd of capacity with additional
pump stations.
In the Permian Basin, we continue to execute
on our long-term contracting strategy. We have
announced three expansions to our West Texas
LPG pipeline system, totaling an estimated
160,000 bpd of additional capacity, since
ONEOK’s acquisition of it in 2014.
Upon completion, all of our announced NGL
pipeline growth projects are expected to more
than double systemwide NGL gathering capacity
compared with 2018.
We also announced expansions at our
Mid-Continent NGL fractionation facilities
totaling an estimated 65,000 bpd.
In addition to our long-haul pipeline projects, we
also are in the midst of adding two 125,000 bpd
fractionators at our Mont Belvieu facilities: the
MB-4 fractionator, which is nearing full completion,
and our MB-5 fractionator, which is scheduled to
be completed in the first quarter 2021.
Once these projects are completed by the end of
the first quarter 2021, ONEOK expects to operate
more than 1.1 million bpd of total fractionation
capacity at the Conway and Mont Belvieu NGL
market centers. This represents more than a
35% increase in fractionation capacity compared
with 2018.
895
1,010
1,079
836
1,175-1,315
NGL RAW FEED
THROUGHPUT
in thousand barrels per day (MBbl/d)
2016
2017
2018
2019
2020 (Guidance)
7
Expanding Our Reliable
Natural Gas Services
Providing reliable natural gas services in many
plants in the region: the 200 MMcf/d Demicks
By the first quarter 2021, we expect to operate
of the same basins where we gather NGLs
Lake I and the 200 MMcf/d Demicks Lake II.
nearly 2.7 Bcf/d of natural gas processing
continues to be a key part of ONEOK’s strategy.
capacity systemwide.
Gathering, processing and transporting natural
And we announced a 200 MMcf/d expansion
gas is essential to the many customers we serve
of our Bear Creek facility to add much needed
ONEOK also completed approximately 1.5 Bcf/d
as their production continues to grow.
processing capacity in a geographically isolated
of natural gas transportation infrastructure
In 2019, ONEOK added more than 640 new well
area of the basin.
expansions across our system in late 2018
and early 2019. These projects, located in
connections from which we gather natural gas.
Once completed, these facilities are expected to
the Permian Basin and Mid-Continent region,
Approximately 525 of total wells connected
bring our total natural gas processing capacity
are backed by multiple firm transportation
in 2019 were in the Rocky Mountain region,
to approximately 1.7 billion cubic feet per day
commitments and provide much needed residue
where ONEOK has more than 3 million acres
(Bcf/d) in the Williston Basin by the end of the
takeaway for customers.
dedicated to our system in the Williston Basin
first quarter 2021.
and approximately 130,000 acres dedicated in
These expansions on existing infrastructure in
the Powder River Basin.
In the Mid-Continent, which includes the
our natural gas and NGL businesses are central
STACK and SCOOP areas in Oklahoma, ONEOK
to our long-term growth strategy.
To meet the growing demand for natural gas
connected approximately 120 new wells in 2019
processing capacity to extract NGLs, we
and operates approximately 1.0 Bcf/d of natural
completed construction in 2019 and early 2020
gas processing capacity.
on our eighth and ninth natural gas processing
Canadian Valley Natural Gas Processing Plant in Oklahoma
8
1,552
1,808
1,933
1,409
2,010-2,270
Rock Creek Compressor Station
in Oklahoma
NATURAL GAS
PROCESSED
in million cubic feet per day (MMcf/d)
2016
2017
2018
2019
2020 (Guidance)
Bear Creek Natural Gas Processing Plant in North Dakota
9
Employee Volunteering for United Way
Environmental Surveys in North Dakota
Standard of Sustainability
Critical to our reliability efforts, environmental,
social and governance (ESG) is multifaceted
and helps reduce risks to allow for consistent
operations while pursuing new opportunities –
all to meet the needs of our stakeholders.
ONEOK has a dedicated Sustainability team that
furthers sustainable business practices and
awareness, and identifies industry opportunities
and challenges. An internal ESG Council, composed
of leaders from all areas of the company, identifies
and recommends opportunities for improving our
sustainability performance and reporting.
Additional information about our companywide efforts
is available online at ONEOK.com/Sustainability.
RECOGNITIONS
In 2019, we are proud to have earned the following
ESG-related recognitions:
• Added to the Dow Jones Sustainability
North America Index.
• Inclusion in the FTSE4Good and MSCI USA
ESG-related indexes.
• First in industry in Just Capital’s JUST ETF.
• Platinum Verification in Sustainable Tulsa’s
Scorecard program.
• M.e.t. Green Business of the Year.
• GPA Midstream Energy Conservation Award.
• Oklahoma Veteran Employee Champion.
• Scored 95/100 on Human Rights Campaign
Foundation’s Corporate Equality Index.
• Henry Bellmon Sustainability Award.
10
ONEOK Financial Highlights
Years ended Dec. 31
2019
2018
2017
Consolidated financial information (millions of dollars)
Operating income
Net income1
Net income attributable to ONEOK, Inc.1
Total assets
Common stock data
Shares outstanding at Dec. 31
Data per common share
Diluted earnings per share from net income
available to common shareholders1
Dividends paid per share
Market price range
High
Low
Year-end
$
$
$
$
$
$
$
$
$
1,914.4
1,278.6
1,278.6
21,812.1
413,239,050
3.07
3.53
76.50
54.28
75.67
$
$
$
$
$
$
$
$
$
1,835.5
1,155.0
1,151.7
18,231.7
411,532,606
2.78
3.245
71.40
50.79
53.95
$
$
$
$
$
$
$
$
$
1,391.8
593.5
387.8
16,845.9
388,703,543
1.29
2.72
58.83
47.41
53.45
1 Financial results for 2017 include one-time noncash charges of $141.3 million, or 47 cents per diluted share, related to the enactment of the Tax Cuts and
Jobs Act, noncash impairment charges of $20.2 million, or 4 cents per diluted share, and $50 million, or 10 cents per diluted share, in one-time and ONEOK
and ONEOK Partners merger transaction-related costs.
RECONCILIATION OF ONEOK'S NET INCOME TO ADJUSTED EBITDA
AND DISTRIBUTABLE CASH FLOW — UNAUDITED (MILLIONS OF DOLLARS)
2019
2018
$
1,278.6
$
1,155.0
$
Net income
Interest expense, net of capitalized interest
Depreciation and amortization
Income tax expense
Impairment charges
Noncash compensation expense
Equity AFUDC and other noncash items2
Adjusted EBITDA3
Interest expense, net of capitalized interest
Maintenance capital
Equity in net earnings from investments, excluding noncash
impairment charges
Distributions received from unconsolidated affiliates
Other
Distributable cash flow3
Dividends paid to preferred shareholders
Distributions paid to public limited partners
Distributable cash flow to shareholders
Dividends paid
Distributable cash flow in excess of dividends paid
Dividends paid per share
Dividend coverage ratio3
$
$
$
$
$
491.8
476.5
372.4
–
26.7
(65.8)
2,580.2
(491.8)
(195.6)
(154.5)
257.6
20.2
2,016.1
(1.1)
–
2,015.0
(1,456.5)
558.5
3.530
1.38
$
$
$
$
$
469.6
428.6
362.9
–
38.0
(6.6)
2,447.5
(469.6)
(188.4)
(158.4)
197.3
(6.0)
1,822.4
(1.1)
–
1,821.3
(1,334.0)
487.3
3.245
1.37
$
$
$
$
$
2017
593.5
485.7
406.3
447.3
20.2
13.4
20.5
1,986.9
(485.7)
(147.2)
(159.3)
196.1
(6.1)
1,384.7
(0.6)
(271.0)
1,113.1
(828.1)
285.0
2.720
1.34
2 2017 includes our contribution to the ONEOK Foundation of 20,000 shares of Series E Preferred Stock, with an aggregate value of $20.0 million.
3 2017 includes transaction-related pretax cash costs of $30 million, or 0.04 times dividend coverage, associated with the ONEOK and ONEOK Partners
merger transaction.
11
NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) FINANCIAL MEASURES
ONEOK has disclosed in this annual report adjusted EBITDA, distributable cash flow and dividend coverage ratio, which are non-GAAP financial metrics, used to measure the company's financial performance and are defined as follows:
• Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, noncash compensation expense, allowance for equity funds used
during construction (equity AFUDC), and other noncash items.
• Distributable cash flow is defined as adjusted EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, excluding noncash impairment
charges, adjusted for cash distributions received from unconsolidated affiliates and certain other items.
• Dividend coverage ratio is defined as ONEOK's distributable cash flow to ONEOK shareholders divided by the dividends paid for the period.
These non-GAAP financial measures described above are useful to investors because they, and similar measures, are used by many companies in the industry as a measure of financial performance and are commonly employed by financial
analysts and others to evaluate ONEOK's financial performance and to compare ONEOK's financial performance with the performance of other companies within ONEOK's industry. Adjusted EBITDA, distributable cash flow and dividend
coverage ratio should not be considered in isolation or as a substitute for net income or any other measure of financial performance presented in accordance with GAAP.
These non-GAAP financial measures exclude some, but not all, items that affect net income. Additionally, these calculations may not be comparable with similarly titled measures of other companies. Reconciliations of net income to
adjusted EBITDA, distributable cash flow and dividend coverage ratio are included in the tables.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this annual report are forward-looking statements as defined under federal securities laws. The forward-looking statements relate to our anticipated financial
performance (including projected operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s plans and objectives for our future capital-growth projects and
other future operations (including plans to construct additional natural gas and NGL pipelines and processing and fractionation facilities and related cost estimates), 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 federal securities legislation and other applicable laws. 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,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “plan,” “outlook,” “potential,” “project,” “scheduled,”
“should,” “will,” ‘would” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements. 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:
•
the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to drill and obtain necessary permits; regulatory compliance; reserve
performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling or extended periods of ethane rejection;
•
• competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as
ethanol and biodiesel;
• demand for our services and products in the proximity of our facilities;
•
future demand for and prices of natural gas, NGLs and crude oil;
the ability to market pipeline capacity on favorable terms, including the effects of:
–
– competitive conditions in the overall energy market;
– availability of supplies of United States natural gas and crude oil; and
– availability of additional storage capacity;
•
the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;
• acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’, customers’ or shippers’ facilities;
•
• economic climate and growth in the geographic areas in which we do business;
•
•
• our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing,
the timing and extent of changes in energy commodity prices;
the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions throughout the world;
storage, fractionation and transportation facilities without labor or contractor problems;
the profitability of assets or businesses acquired or constructed by us;
the risk of a slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
the uncertainty of estimates, including accruals and costs of environmental remediation;
•
•
•
•
• changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns about climate change;
•
•
•
• our ability to control construction costs and completion schedules of our pipelines and other projects;
•
the impact of uncontracted capacity in our assets being greater or less than expected;
the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized
rates of recovery of natural gas and natural gas transportation costs;
the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
the results of administrative proceedings and litigation, regulatory actions, executive orders, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the
National Transportation Safety Board, the PHMSA, the EPA and the CFTC;
•
•
• difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;
•
•
• risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in
the capital-intensive nature of our businesses;
the mechanical integrity of facilities operated;
•
•
connection with any such acquisitions and dispositions;
the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and
postretirement expense and funding resulting from changes in equity and bond market returns;
• our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages
compared with our competitors that have less debt or have other adverse consequences;
the impact and outcome of pending and future litigation;
• actions by rating agencies concerning our credit;
• our ability to access capital at competitive rates or on terms acceptable to us;
•
• performance of contractual obligations by our customers, service providers, contractors and shippers;
• our ability to control operating costs and make cost-saving changes;
•
•
•
the impact of recently issued and future accounting updates and other changes in accounting policies;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
the risk inherent in the use of information systems in our respective businesses and those of our counterparties and service providers, implementation of new software and hardware, and the impact on the timeliness of
information for financial reporting;
the impact of potential impairment charges; and
the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.
•
•
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 affect adversely our future results.
These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in this annual report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at
www.oneok.com. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such
statement is made, and 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.
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 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma
(State or other jurisdiction of
incorporation or organization)
100 West Fifth Street, Tulsa, OK
(Address of principal executive offices)
73-1520922
(I.R.S. Employer Identification No.)
74103
(Zip Code)
Registrant’s telephone number, including area code (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common stock, par value of $0.01
Trading Symbol(s)
OKE
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been
subject to such filing requirements for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to
Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit such files). Yes
No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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
Non-accelerated filer
Accelerated filer
Emerging growth company
Smaller reporting company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
No
.
Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on June 28, 2019, was $28.1
billion.
On February 18, 2020, the Company had 413,319,000 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 20, 2020, are incorporated by reference in Part III.
ONEOK, Inc.
2019 ANNUAL REPORT
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
Part I.
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Part II.
Item 5.
Item 6.
Item 7.
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
Page No.
5
19
30
30
31
31
31
33
33
50
54
112
112
112
112
113
113
114
114
115
122
123
As used in this Annual Report, references to “we,” “our,” or “us” refer to ONEOK, 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:
$1.5 Billion Term Loan Agreement
The senior unsecured delayed-draw three-year $1.5 billion term loan agreement
$2.5 Billion Credit Agreement
AFUDC
Annual Report
ASU
Bbl
BBtu/d
Bcf
Bcf/d
Btu
CFTC
Clean Air Act
Clean Water Act
DJ
DOT
EBITDA
EPA
Exchange Act
FERC
Foundation
GAAP
GHG
Intermediate Partnership
KCC
LIBOR
MBbl/d
MDth/d
Merger Transaction
MMBbl
MMBbl/d
MMBtu
MMcf/d
Moody’s
Natural Gas Act
Natural Gas Policy Act
NGL(s)
NGL products
Northern Border Pipeline
NYMEX
NYSE
OCC
ONEOK
ONEOK Partners
ONEOK Partners Term Loan Agreement
dated November 19, 2018
ONEOK’s $2.5 billion revolving credit agreement, as amended
Allowance for funds used during construction
Annual Report on Form 10-K for the year ended December 31, 2019
Accounting Standards Update
Barrels, 1 barrel is equivalent to 42 United States gallons
Billion British thermal units per day
Billion cubic feet
Billion cubic feet per day
British thermal unit
U.S. Commodity Futures Trading Commission
Federal Clean Air Act, as amended
Federal Water Pollution Control Act Amendments of 1972, as amended
Denver-Julesburg
United States Department of Transportation
Earnings before interest expense, income taxes, depreciation and amortization
United States Environmental Protection Agency
Securities Exchange Act of 1934, as amended
Federal Energy Regulatory Commission
ONEOK Foundation, Inc.
Accounting principles generally accepted in the United States of America
Greenhouse gas
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary
of ONEOK Partners, L.P.
Kansas Corporation Commission
London Interbank Offered Rate
Thousand barrels per day
Thousand dekatherms per day
The transaction, effective June 30, 2017, in which ONEOK acquired all of
ONEOK Partners’ outstanding common units not already directly or indirectly
owned by ONEOK
Million barrels
Million barrels per day
Million British thermal units
Million cubic feet per day
Moody’s Investors Service, Inc.
Natural Gas Act of 1938, as amended
Natural Gas Policy Act of 1978, as amended
Natural gas liquid(s)
Marketable natural gas liquid purity products, such as ethane, ethane/propane
mix, propane, iso-butane, normal butane and natural gasoline
Northern Border Pipeline Company, a 50% owned joint venture
New York Mercantile Exchange
New York Stock Exchange
Oklahoma Corporation Commission
ONEOK, Inc.
ONEOK Partners, L.P.
The senior unsecured three-year $1.0 billion term loan agreement dated
January 8, 2016, as amended
3
OPIS
Overland Pass Pipeline
PHMSA
POP
Quarterly Report(s)
Roadrunner
RRC
S&P
SCOOP
SEC
Securities Act
Series E Preferred Stock
STACK
Tax Cuts and Jobs Act
Topic 606
West Texas LPG
WTI
WTLPG
XBRL
Oil Price Information Service
Overland Pass Pipeline Company, LLC, a 50% owned joint venture
United States Department of Transportation Pipeline and Hazardous Materials
Safety Administration
Percent of Proceeds
Quarterly Report(s) on Form 10-Q
Roadrunner Gas Transmission, LLC, a 50% owned joint venture
Railroad Commission of Texas
S&P Global Ratings
South Central Oklahoma Oil Province, an area in the Anadarko Basin in
Oklahoma
Securities and Exchange Commission
Securities Act of 1933, as amended
Series E Non-Voting, Perpetual Preferred Stock, par value $0.01 per share
Sooner Trend Anadarko Canadian Kingfisher, an area in the Anadarko Basin in
Oklahoma
H.R. 1, the tax reform bill, signed into law on December 22, 2017
Accounting Standards Update 2014-09, “Revenue from Contracts with
Customers”
West Texas LPG pipeline and Mesquite pipeline
West Texas Intermediate
West Texas LPG Pipeline Limited Partnership
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,” “believe,” “continue,” “could,” “estimate,” “expect,”
“forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,”
“should,” “will,” “would” 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 or 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 Operations and “Forward-Looking Statements,” in this Annual Report.
4
ITEM 1.
BUSINESS
GENERAL
PART I
We are incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading
symbol “OKE.” We are a leading midstream service provider and own one of the nation’s premier NGL systems, connecting
NGL supply in the Rocky Mountain, Permian and Mid-Continent regions with key market centers and an extensive network of
natural gas gathering, processing, storage and transportation assets. We apply our core capabilities of gathering, processing,
fractionating, transporting, storing and marketing natural gas and NGLs through vertical integration across the midstream value
chain to provide our customers with premium services while generating consistent and sustainable earnings growth.
Midstream Value Chain
Legend
Natural Gas Gathering & Processing
Natural Gas Liquids
Natural Gas Pipelines
Raw natural gas is typically gathered at the
wellhead, compressed and transported through
pipelines to our processing facilities. Most raw
natural gas produced at the wellhead contains a
mixture of NGL components, such as ethane,
propane, iso-butane, normal butane and natural
gasoline, which remain in a mixed
unfractionated form.
Gathered wellhead natural gas is directed to our
processing plants to remove NGLs, resulting in
residue natural gas (primarily methane).
NGLs extracted at processing plants, both third-
party and our own, are then gathered by our
NGL gathering pipelines.
Gathered NGLs are directed to our downstream
fractionators in the Mid-Continent region and
Mont Belvieu, Texas, to be separated into purity
products.
Purity products are stored or distributed to our
customers, such as petrochemical companies,
propane distributors, heating fuel users, ethanol
producers, refineries and exporters.
We are connected to supply in natural gas and
NGL producing basins and have significant
basin diversification, including the Williston,
Permian, Powder River and DJ Basins and the
STACK and SCOOP areas. In our Natural Gas
Gathering and Processing segment, we have
more than 3 million dedicated acres in the
Williston Basin and approximately 300,000
dedicated acres in the STACK and SCOOP
areas. In our Natural Gas Liquids segment, we
are the largest NGL takeaway provider in the
Williston Basin; Oklahoma, including the
STACK and SCOOP areas; Kansas; and the
Texas Panhandle. We also have a significant
presence in the Permian Basin.
Once processed, residue natural gas is
recompressed and delivered to intrastate and
interstate natural gas pipelines.
Residue natural gas is transported to storage
facilities and end-users, such as large industrial
customers, natural gas and electric utilities
serving commercial and residential consumers,
and international markets through liquefied
natural gas exports.
5
EXECUTIVE SUMMARY
Business Update and Market Conditions - We operate primarily fee-based businesses in each of our three reportable
segments, and our consolidated earnings were approximately 90% fee-based in 2019. Volumes increased across our system in
our Natural Gas Gathering and Processing and Natural Gas Liquids segments in 2019, compared with 2018, as a result of our
completed capital-growth projects, continued drilling and producer improvements in production due to enhanced completion
techniques, offset partially by natural production declines. Since the beginning of 2018, we have completed several capital-
growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas and NGL
infrastructure, and expect capital expenditures to decrease in 2020 and 2021, compared with 2019. Our NGL projects in the
Gulf Coast allow flexibility to add NGL fractionators, NGL storage and, potentially, new export facilities in the future. We
expect these projects to meet the needs of producers, natural gas processors and the petrochemical industry that require
additional midstream infrastructure to accommodate increasing supply and demand.
We experienced fluctuating NGL location price differentials due to increased supply, increased demand in the Mid-Continent
region, infrastructure constraints and slower demand growth in the Gulf Coast due primarily to delays in the startup of
petrochemical facilities and constrained NGL export facilities. The Conway-to-Mont Belvieu OPIS price differential for ethane
in ethane/propane mix averaged $0.07 per gallon in 2019, compared with $0.15 per gallon in 2018, which resulted in lower
earnings from our optimization and marketing activities in our Natural Gas Liquids segment. We expect narrower NGL
location price differentials in 2020.
Rocky Mountain Region - We expect to benefit from increased production in this region, which includes the Williston,
Powder River and DJ Basins. In our Natural Gas Gathering and Processing segment, gathered and processed volumes
increased in 2019, compared with 2018, due primarily to our capital-growth projects, new well connections and increased
producer productivity. Our Demicks Lake I natural gas processing plant was placed in service in October 2019, and we expect
it to reach its 200 MMcf/d capacity in the first quarter 2020 due to natural gas flaring by producers on our more than 3 million
dedicated acres in the Williston Basin. In addition, we completed construction of our Demicks Lake II natural gas processing
plant in January 2020. With continued volume growth expected, we are in the process of expanding our Bear Creek plant by
200 MMcf/d, which is expected to be completed in first quarter 2021, and recently announced plans to construct our Demicks
Lake III natural gas processing plant, with capacity of 200 MMcf/d and expected completion in the third quarter 2021. Upon
completion of these projects, our total processing capacity will be approximately 1.9 Bcf/d in the Williston Basin and is
expected to help producers meet North Dakota’s natural gas capture targets and add incremental NGLs to our NGL gathering
system.
In our Natural Gas Liquids segment, we announced the completion of our Elk Creek pipeline in December 2019. We are the
largest NGL takeaway provider and expect our NGL pipelines to transport more than 240 MBbl/d of NGLs out of this region
by the end of the first quarter 2020 due to a combination of growth in volumes from our new and existing processing plants,
third-party processing plants and volumes previously transported by rail. In addition, we recently announced an expansion of
our Elk Creek pipeline to 400 MBbl/d by adding additional pump stations. The project is expected to be fully completed in the
third quarter 2021, with a portion of this incremental capacity available as early as first quarter 2021. In April 2019, we
announced a project to extend our Bakken NGL pipeline into an area of the Williston Basin with limited access to NGL
pipeline takeaway capacity. This project will provide connectivity for third-party processing plants to key NGL market centers
as well as provide additional volumes to our Elk Creek pipeline. To accommodate expected volumes, we are also expanding
our Mid-Continent NGL fractionation facilities by 65 MBbl/d and constructing an extension of our Arbuckle II pipeline farther
north.
Mid-Continent Region - In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the STACK and
SCOOP areas where volumes continued to increase in 2019, compared with 2018. We expect continued demand for our
services from producers that need takeaway capacity for natural gas and NGLs out of this region. In our Natural Gas Gathering
and Processing segment, natural gas gathered and processed volumes increased in this region in 2019, compared with 2018, due
primarily to new well connections. We expect volumes in this region to decline modestly in 2020, compared with 2019.
Our Natural Gas Pipelines segment transports natural gas from more than 35 natural gas processing plants in Oklahoma. We
completed pipeline expansions to provide increased westbound transportation services from the STACK area to multiple
interstate pipeline delivery points in western Oklahoma and a 150 MMcf/d eastbound expansion from the STACK and SCOOP
areas to an eastern Oklahoma interstate pipeline delivery point.
Permian Basin - We expect our Natural Gas Liquids and Natural Gas Pipelines business segments to continue to benefit from
increased production in the Permian Basin from the highly productive Delaware and Midland Basins. In our Natural Gas
Liquids segment, we are well-positioned in the Permian Basin through our West Texas LPG pipeline system. Due to our
6
expansion of the system in the third quarter 2018 and new plant connections, volumes increased in 2019, compared with 2018.
We expect volumes to continue to increase on our West Texas LPG pipeline system as our previously announced second and
third expansions are completed, which will increase the mainline capacity out of the Permian Basin by 80 MBbl/d in the first
quarter 2020 and 40 MBbl/d in the first quarter 2021, respectively, as well as connect our West Texas LPG pipeline with our
Arbuckle II pipeline in north Texas. In addition, we recently announced the fourth expansion of our West Texas LPG pipeline
system by 100 MBbl/d, which is expected to be completed in the second quarter 2021. These projects are expected to position
our West Texas LPG pipeline system for significant NGL volume growth and are backed by long-term acreage and/or plant
dedications.
In our Natural Gas Pipelines segment, our Roadrunner joint venture and our WesTex pipeline are well-positioned to serve
growth in the Permian Basin. The Roadrunner pipeline connects with our existing natural gas pipeline and storage
infrastructure in Texas and, together with our completed WesTex intrastate natural gas pipeline expansion project, creates future
opportunities for us to deliver natural gas to Mexico and transport natural gas to other markets in the region.
Gulf Coast - Demand for NGLs is expected to increase at the Mont Belvieu, Texas, NGL market center as new world-scale
ethylene production projects, petrochemical plant expansions and NGL export facilities continue to be completed. We are
constructing our Arbuckle II pipeline to support expected supply growth and transport NGLs to the Gulf Coast market center
and have announced an expansion of our Arbuckle II pipeline to a total capacity of 500 MBbl/d. NGL supply growth and other
new NGL pipelines recently completed or being constructed, including our Elk Creek and West Texas LPG pipeline projects,
are increasing NGL deliveries to Mont Belvieu, Texas. While we have significant NGL fractionation and storage assets in this
area, additional capacity is needed to accommodate expected volume growth. To respond to this need, we are constructing two
additional 125 MBbl/d fractionators with related infrastructure in Mont Belvieu, Texas, MB-4 and MB-5, which are both fully
contracted. In December 2019, we completed construction of 75 MBbl/d of the MB-4 capacity, with the remaining 50 MBbl/d
to be completed in the first quarter 2020, and MB-5 is expected to be completed in the first quarter 2021. Following the
completion of MB-4 and MB-5, we expect our NGL fractionation capacity to be approximately 600 MBbl/d in the Gulf Coast
and more than 1 MMBbl/d across our entire system. Our MB-5 project also includes system expansions that provide
infrastructure capacity to support additional assets as we continue to evaluate opportunities for fractionation, storage and,
potentially, export facilities to meet the supply and demand for NGLs.
See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual
Report for more information on our growth projects, results of operations, liquidity and capital resources.
BUSINESS STRATEGY
Our primary business strategy is to maintain prudent financial strength and flexibility while growing our fee-based earnings and
dividends per share with a focus on safe, reliable, environmentally responsible, legally compliant and sustainable operations for
our customers, employees, contractors and the public through the following:
• Operate in a safe, reliable, environmentally responsible and sustainable manner - environmental, safety and health
continues to be a primary focus for us, and our emphasis on personal and process safety has produced improvements
in the key indicators we track. We also continue to look for ways to reduce our environmental impact by conserving
resources and utilizing more efficient technologies. In 2019, we were added to the Dow Jones Sustainability North
America Index, which recognizes companies for industry-leading environmental, social and governance performance;
Pursue organic investments in our existing operating regions to support earnings growth - we expect our investment in
capital projects to create stable earnings growth that positions us to grow our dividend. In 2019, we paid dividends of
$3.53 per share, an increase of 9% compared with the prior year. Our dividend increase and expected future dividend
growth is due primarily to earnings growth from capital projects;
•
• Manage our balance sheet and maintain investment-grade credit ratings - we seek to maintain investment-grade credit
ratings, fund capital-growth projects and begin to pay down debt. We expect to benefit from increasing cash flows
from operations in 2020, which we expect to reduce leverage and fund capital-growth projects. At December 31,
2019, we had no borrowings outstanding under our $2.5 Billion Credit Agreement, $220 million of commercial paper
outstanding and $21 million of cash and cash equivalents; and
• Attract, select, develop, motivate, challenge and retain a diverse group of employees to support strategy execution -
we continue to execute on our recruiting strategy that targets professional and field personnel in our operating areas.
We also continue to focus on employee development efforts with our current employees and monitor our benefits and
compensation package to remain competitive.
7
NARRATIVE DESCRIPTION OF BUSINESS
We report operations in the following business segments:
• Natural Gas Gathering and Processing;
• Natural Gas Liquids; and
• Natural Gas Pipelines.
Natural Gas Gathering and Processing
Overview - Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota,
Montana, Wyoming, Kansas and Oklahoma.
Rocky Mountain region - The Williston Basin is located in portions of North Dakota and Montana and includes the oil-
producing, NGL-rich Bakken Shale and Three Forks formations, and is an active drilling region. Our completed capital-growth
projects in the Williston Basin have increased our gathering and processing capacity and allow us to capture increased natural
gas production from new wells and previously flared natural gas production.
The Powder River Basin is primarily located in Wyoming, which includes the NGL-rich Niobrara Shale and Frontier, Turner
and Sussex formations where we provide gathering and processing services to customers in the eastern portion of Wyoming.
Mid-Continent region - The Mid-Continent region is an active drilling region and includes the oil-producing, NGL-rich STACK
and SCOOP areas and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian
Lime formations of Oklahoma and Kansas, and the Hugoton and Central Kansas Uplift Basins of Kansas.
Property - Our Natural Gas Gathering and Processing segment owns the following assets:
•
•
•
18,900 miles of natural gas gathering pipelines;
ten natural gas processing plants with 1.0 Bcf/d of processing capacity in the Mid-Continent region, and 12 natural gas
processing plants with 1.5 Bcf/d of processing capacity in the Rocky Mountain region; and
14 MBbl/d of NGL fractionation capacity at various natural gas processing plants.
8
In addition, we have access to up to 200 MMcf/d of processing capacity in the Mid-Continent region through a long-term
processing services agreement with an unaffiliated third party.
We are in the process of expanding our Bear Creek plant by 200 MMcf/d and recently announced plans to construct our
Demicks Lake III natural gas processing plant, with capacity of 200 MMcf/d, in the core of the Williston Basin. The additional
capacity from these projects is excluded from the assets listed above.
See “Recent Developments” in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of
Operations, in this Annual Report for more information on our growth projects.
Sources of Earnings - Earnings for this segment are derived primarily from the following types of service contracts:
•
•
•
POP with fee contracts with no producer take-in-kind rights - We purchase raw natural gas and charge contractual fees
for providing midstream services, which include gathering, treating, compressing and processing the producer’s
natural gas. After performing these services, we sell the commodities and remit a portion of the commodity sales
proceeds to the producer less our contractual fees. This type of contract represented 63% and 60% of supply volumes
in this segment for 2019 and 2018, respectively.
POP with fee contracts with producer take-in-kind rights - We purchase a portion of the raw natural gas stream, charge
fees for providing the midstream services listed above, return primarily the residue natural gas to the producer, sell the
remaining commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees.
This type of contract represented 33% and 36% of supply volumes in this segment for 2019 and 2018, respectively.
Fee-only - Under this type of contract, we charge a fee for the midstream services we provide, based on volumes
gathered, processed, treated and/or compressed. Our fee-only contracts represented 4% of supply volumes in this
segment in 2019 and 2018.
For commodity sales, we contract to deliver residue natural gas, condensate and/or unfractionated NGLs to downstream
customers at a specified delivery point. Our sales of NGLs are primarily to our affiliate in the Natural Gas Liquids segment.
Utilization - The utilization rates for our natural gas processing plants were 84% and 83% for 2019 and 2018, respectively. We
calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service.
Unconsolidated Affiliates - Our Natural Gas Gathering and Processing segment includes the following unconsolidated
affiliates:
•
•
•
•
49% ownership interest in Bighorn Gas Gathering, which gathers dry natural gas produced in the Powder River Basin;
42.6% ownership interest in Fort Union Gas Gathering, which gathers dry natural gas produced in the Powder River
Basin and delivers it to the interstate pipeline system;
35% ownership interest in Lost Creek Gathering Company, which gathers natural gas produced from conventional dry
natural gas wells in the Wind River Basin of central Wyoming and delivers it to the interstate pipeline system; and
10.2% ownership interest in Venice Energy Services Co., a natural gas processing facility near Venice, Louisiana.
See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our
unconsolidated affiliates.
Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the
transportation or sale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas
Act. Although the FERC has made no specific declaration as to the jurisdictional status of our natural gas processing
operations or facilities, our natural gas processing plants are primarily involved in extracting NGLs and, therefore, are exempt
from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC.
We believe our natural gas gathering facilities and operations meet the criteria used by the FERC for nonjurisdictional natural
gas gathering facility status. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically
distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. We transport residue
natural gas from certain of our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the
Natural Gas Policy Act. Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, to varying
degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is
filed against the gatherer with the appropriate state regulatory agency.
See further discussion in the “Regulatory, Environmental and Safety Matters” section.
9
Natural Gas Liquids
Overview - Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs
and store NGL products, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes
the Williston, Powder River and DJ Basins. We provide midstream services to producers of NGLs and deliver those products
to the two primary market centers: one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont
Belvieu, Texas. We own or have an ownership interest in FERC-regulated NGL gathering and distribution pipelines in
Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities
in Missouri, Nebraska, Iowa and Illinois. The majority of the pipeline-connected natural gas processing plants in the Williston
Basin, Oklahoma, Kansas and the Texas Panhandle are connected to our NGL gathering systems. We own and operate truck-
and rail-loading and -unloading facilities connected to our NGL fractionation and pipeline assets. We also own FERC-
regulated NGL distribution pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent
assets with Midwest markets, including Chicago, Illinois. A portion of our ONEOK North System transports refined petroleum
products, including unleaded gasoline and diesel, from Kansas to Iowa.
Property - Our Natural Gas Liquids segment owns the following assets:
•
•
•
•
•
•
•
8,380 miles of gathering pipelines with peak capacity of 1,820 MBbl/d, including 5,550 miles of FERC-regulated
pipelines with peak capacity of 920 MBbl/d;
4,490 miles of distribution pipelines with peak capacity of 1,400 MBbl/d, including 4,460 miles of FERC-regulated
pipelines with peak capacity of 1,360 MBbl/d;
eight NGL fractionators with combined operating capacity of 870 MBbl/d (includes interests in our proportional share
of operating capacity), including 520 MBbl/d in the Mid-Continent region and 350 MBbl/d in the Gulf Coast region;
one isomerization unit with operating capacity of 10 MBbl/d;
one ethane/propane splitter with operating capacity of 40 MBbl/d;
six NGL storage facilities with operating storage capacity of 20 MMBbl; and
eight NGL product terminals.
10
In addition, we lease 10 MMBbl of annual pipeline capacity near our ONEOK North System and have access to 5 MMBbl of
combined NGL storage capacity at facilities in Kansas and Texas and 60 MBbl/d of NGL fractionation capacity in the Gulf
Coast through service agreements.
Our uncompleted growth projects are excluded from the assets listed above and include:
•
•
•
•
gathering pipelines, including expansions, with combined operating capacity of 880 MBbl/d;
the MB-5 fractionator in the Gulf Coast with operating capacity of 125 MBbl/d;
remaining fractionation capacity on the MB-4 fractionator in the Gulf Coast of 50 MBbl/d; and
additional fractionation capacity in the Mid-Continent of 65 MBbl/d.
See “Recent Developments” in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of
Operations, in this Annual Report for more information on our growth projects.
Sources of Earnings - Earnings for our Natural Gas Liquids segment are derived primarily from commodity sales and fee-based
services. We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing
segment. Our business activities are categorized as follows:
• Exchange services - We utilize our assets to gather, transport, treat and fractionate unfractionated NGLs, thereby
converting them into marketable NGL products delivered to a market center or customer-designated location. Many
of these exchange volumes are under contracts with minimum volume commitments that provide a minimum level of
revenues regardless of volumetric throughput. Our exchange services activities are primarily fee-based and include
some rate-regulated tariffs; however, we also capture certain product price differentials through the fractionation
process.
• Transportation and storage services - We transport NGL products and refined petroleum products, primarily under
FERC-regulated tariffs. Tariffs specify the maximum rates we may charge our customers and the general terms and
conditions for transportation service on our pipelines. Our storage activities consist primarily of fee-based NGL
storage services at our Mid-Continent and Gulf Coast storage facilities.
• Optimization and marketing - We utilize our assets, contract portfolio and market knowledge to capture location,
product and seasonal price differentials through the purchase and sale of NGLs and NGL products. We primarily
transport NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials
between the two market centers. Our marketing activities also include utilizing our NGL storage facilities to capture
seasonal price differentials. A growing portion of our marketing activities serves truck and rail markets. Our
isomerization activities capture the price differential when normal butane is converted into the more valuable iso-
butane at our isomerization unit in Conway, Kansas.
In many of our exchange services contracts, we purchase the unfractionated NGLs at the tailgate of the processing plant and
deduct contractual fees related to the transportation and fractionation services we must perform before we can sell them as NGL
products. To the extent we hold unfractionated NGLs in inventory, the related contractual fees will not be recognized until the
unfractionated inventory is fractionated and sold.
Utilization - The utilization rates for our various assets, including leased assets, have been impacted by ethane rejection. The
utilization rates for 2019 and 2018, respectively, were as follows:
•
•
•
our NGL gathering pipelines were 78% in both years;
our NGL distribution pipelines were 63% and 59%; and
our NGL fractionators were 84% and 85%.
We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service. Our
fractionation utilization rate reflects approximate proportional capacity associated with our ownership interests.
Unconsolidated Affiliates - Our Natural Gas Liquids segment includes the following unconsolidated affiliates:
•
•
•
50% ownership interest in Overland Pass Pipeline Company, which operates an interstate NGL pipeline system
extending 760 miles, originating in Wyoming and Colorado and terminating in Kansas;
50% ownership interest in Chisholm Pipeline Company, which operates an interstate NGL pipeline system extending
185 miles from origin points in Oklahoma and terminating in Kansas; and
50% ownership interest in Heartland Pipeline Company, which operates a terminal and pipeline system that transports
refined petroleum products in Kansas, Nebraska and Iowa.
11
See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of
unconsolidated affiliates.
Government Regulation - The operations and revenues of our NGL pipelines are regulated by various state and federal
government agencies. Our interstate NGL pipelines are regulated by the FERC, which has authority over the terms and
conditions of service; rates, including depreciation and amortization policies; and initiation of service. In Oklahoma, Kansas
and Texas, certain aspects of our intrastate NGL pipelines that provide common carrier service are subject to the jurisdiction of
the OCC, KCC and RRC, respectively.
See further discussion in the “Regulatory, Environmental and Safety Matters” section.
Natural Gas Pipelines
Overview - Our Natural Gas Pipelines segment provides transportation and storage services to end users through its wholly
owned assets and its 50% ownership interests in Northern Border Pipeline and Roadrunner.
Interstate Pipelines - Our interstate pipelines are regulated by the FERC and are located in North Dakota, Minnesota,
Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies
include:
• Midwestern Gas Transmission, which is a bidirectional system that interconnects with Tennessee Gas Transmission
Company’s pipeline near Portland, Tennessee, and with several interstate pipelines that have access to both the Utica
Shale and the Marcellus Shale at the Chicago Hub near Joliet, Illinois;
• Viking Gas Transmission, which is a bidirectional system that interconnects with a TransCanada Corporation pipeline
at the United States border near Emerson, Canada, and ANR Pipeline Company near Marshfield, Wisconsin;
• Guardian Pipeline, which interconnects with several pipelines at the Chicago Hub near Joliet, Illinois, and with local
natural gas distribution companies in Wisconsin; and
• OkTex Pipeline, which has interconnections with several pipelines in Oklahoma, Texas and New Mexico.
Intrastate Pipelines - Our intrastate natural gas pipeline assets in Oklahoma transport natural gas through the state and have
access to the major natural gas production areas in the Mid-Continent region, which include the STACK and SCOOP areas and
the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations. In
Texas, our intrastate natural gas pipelines are connected to the major natural gas producing formations in the Texas Panhandle,
including the Granite Wash formation and Delaware and Midland Basins in the Permian Basin. These pipelines are capable of
transporting natural gas throughout the western portion of Texas, including the Waha area where other pipelines may be
accessed for transportation to western markets, exports to Mexico, the Houston Ship Channel market to the east and the Mid-
Continent market to the north. Our intrastate natural gas pipeline assets also have access to the Hugoton and Central Kansas
Uplift Basins in Kansas.
12
Property - Our Natural Gas Pipelines segment owns the following assets:
•
•
•
1,500 miles of FERC-regulated interstate natural gas pipelines with 3.5 Bcf/d of peak transportation capacity;
5,100 miles of state-regulated intrastate transmission pipelines with peak transportation capacity of 4.3 Bcf/d; and
six underground natural gas storage facilities with 52.2 Bcf of total active working natural gas storage capacity.
Our storage includes two underground natural gas storage facilities in Oklahoma, two underground natural gas storage facilities
in Kansas and two underground natural gas storage facilities in Texas.
Sources of Earnings - Earnings in this segment are derived primarily from transportation and storage services.
Our transportation earnings are primarily fee-based from the following types of services:
•
•
Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates
the customer to pay regardless of usage. Under this type of contract, the customer pays a monthly fixed fee and
incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or
store. Under the firm service contract, the customer generally is guaranteed access to the capacity they reserve.
Interruptible service - Under interruptible service transportation agreements, the customer may utilize available
capacity after firm service requests are satisfied. The customer is not guaranteed use of our pipelines unless excess
capacity is available.
Our regulated natural gas transportation services contracts are based upon rates stated in the respective tariffs, which have
generally been established through shipper specific negotiation, discounts and negotiated settlements. The rates are filed with
FERC or the appropriate state jurisdictional agencies. In addition, customers typically are assessed fees, such as a commodity
charge, and we may retain a percentage or specified volume of natural gas in-kind based on the natural gas volumes
transported.
Our storage earnings are primarily fee-based from the following types of services:
•
•
Firm service - Customers reserve a specific quantity of storage capacity, including injection and withdrawal rights, and
generally pay fixed fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage
contracts typically have terms longer than one year.
Park-and-loan service - An interruptible storage service offered to customers providing the ability to park (inject) or
loan (withdraw) natural gas into or out of our storage, typically for monthly or seasonal terms. Customers reserve the
13
right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity
is available.
Utilization - Our natural gas pipelines were 98% and 96% subscribed in 2019 and 2018, respectively, and our natural gas
storage facilities were 64% subscribed in both 2019 and 2018.
Unconsolidated Affiliates - Our Natural Gas Pipelines segment includes the following unconsolidated affiliates:
•
•
50% ownership interest in Northern Border Pipeline, which owns a FERC-regulated interstate pipeline that transports
natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, and the Williston Basin in North
Dakota to a terminus near North Hayden, Indiana.
50% ownership interest in Roadrunner, a bidirectional pipeline, which has the capacity to transport 570 MMcf/d of
natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas, and has capacity to
transport approximately 1.0 Bcf/d of natural gas from the Delaware Basin to the Waha area. We are the operator of
Roadrunner.
See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of
unconsolidated affiliates.
Government Regulation - Interstate - Our interstate natural gas pipelines are regulated under the Natural Gas Act, which gives
the FERC jurisdiction to regulate virtually all aspects of this business, such as transportation of natural gas, rates and charges
for services, construction of new facilities, depreciation and amortization policies, acquisition and disposition of facilities, and
the initiation and discontinuation of services.
Intrastate - Our intrastate natural gas pipelines in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC,
respectively, and by the FERC under the Natural Gas Policy Act for certain services where we deliver natural gas into FERC
regulated natural gas pipelines. While we have flexibility in establishing natural gas transportation rates with customers, there
is a maximum rate that we can charge our customers in Oklahoma and Kansas and for the services regulated by the FERC. In
Texas and Kansas, natural gas storage may be regulated by the state and by the FERC for certain types of services. In
Oklahoma, natural gas storage operations are not subject to rate regulation by the state, and we have market-based rate
authority from the FERC for certain types of services.
See further discussion in the “Regulatory, Environmental and Safety Matters” section.
Market Conditions and Seasonality
We operate primarily fee-based businesses in each of our three reportable segments, and our consolidated earnings were
approximately 90% fee-based in 2019. While our Natural Gas Gathering and Processing and Natural Gas Liquids segments
generate primarily fee-based earnings, those segments’ results of operations are exposed to volumetric risk. We are exposed to
volumetric risk from declining well productivity, reduced drilling activity, severe weather disruptions, operational outages and
ethane rejection.
Supply and Demand - Supply for each of our segments depends on crude oil and natural gas drilling and production activities,
which are driven by the strength of the economy; the decline rate of existing production; producer access to capital; producer
firm commitments to transportation pipelines; natural gas, crude oil and NGL prices; or the demand for each of these products
from end users.
Demand for gathering and processing services is dependent on natural gas production by producers in the regions in which we
operate. State requirements in North Dakota for producers to reduce natural gas flaring have increased the need for our
services to capture, gather and process natural gas. Demand for NGLs and the ability of natural gas processors to successfully
and economically sustain their operations affect the volume of unfractionated NGLs produced by natural gas processing plants,
thereby affecting the demand for NGL gathering, transportation and fractionation services. Natural gas and NGL products are
affected by economic conditions and the demand associated with the various industries that utilize the commodities, such as
butanes and natural gasoline used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents
for crude oil. Ethane, propane, normal butane and natural gasoline are also used by the petrochemical industry to produce
chemical products, such as plastic, rubber and synthetic fibers. Propane is also used to heat homes and businesses. Demand for
NGLs is expected to increase at the Mont Belvieu, Texas, NGL market center as new world-scale ethylene production projects,
petrochemical plant expansions and NGL export facilities continue to be completed.
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Commodity Prices - Our earnings are primarily fee-based in all three of our segments, with limited commodity price risk. In
our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of
the commodity sales proceeds associated with our POP with fee contracts. In our Natural Gas Liquids segment, we are exposed
to commodity price risk associated with changes in the price of NGLs; the location differential between the Mid-Continent,
Chicago, Illinois, and Gulf Coast regions; and the relative price differential between natural gas, NGLs and individual NGL
products, which affect our NGL purchases and sales, our exchange services, transportation and storage services, and
optimization and marketing financial results. NGL storage revenue may be affected by price volatility and forward pricing of
NGL physical contracts versus the price of NGLs on the spot market. In our Natural Gas Pipelines segment, we are exposed to
commodity price risk associated with (i) changes in the price of natural gas, which impact our fuel costs and retained fuel in-
kind received for our services; and (ii) the differential between forward pricing of natural gas physical contracts and the price of
natural gas on the spot market, which affects our natural gas storage revenue.
See additional discussion regarding our commodity price risk and related hedging activities under “Commodity Price Risk” in
Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report.
Seasonality - Cold temperatures usually increase demand for natural gas and certain NGL products, such as propane, the main
heating fuels for homes and businesses. Warm temperatures usually increase demand for natural gas used in gas-fired electric
generation for residential and commercial cooling, as well as agriculture-related equipment like irrigation pumps and crop
dryers. Demand for butanes and natural gasoline, which are primarily used by the refining industry as blending stocks for
motor fuel, denaturant for ethanol and diluents for crude oil, are also subject to some variability during seasonal periods when
certain government restrictions on motor fuel blending products change. During periods of peak demand for a certain
commodity, prices for that product typically increase.
Extreme weather conditions, seasonal temperature changes and the impact of temperature and humidity on the mechanical
abilities of the processing equipment impact the volumes of natural gas gathered and processed and NGL volumes gathered,
transported and fractionated. Power interruptions and inaccessible well sites as a result of severe storms or freeze-offs, a
phenomenon where water produced from natural gas freezes at the wellhead or within the gathering system, may cause a
temporary interruption in the flow of natural gas and NGLs.
In our Natural Gas Pipelines segment, natural gas storage is necessary to balance the relatively steady natural gas supply with
the seasonal demand of residential, commercial and electric-generation users.
Competition - We compete for natural gas and NGL supply with other midstream companies and major integrated oil
companies and independent exploration and production companies that have gathering and processing assets, fractionators,
intrastate and interstate pipelines and storage facilities. The factors that typically affect our ability to compete for natural gas
and NGL supply are:
•
•
•
•
•
•
•
•
•
•
quality of services provided;
producer drilling activity;
proceeds remitted and/or fees charged under our contracts;
proximity of our assets to natural gas and NGL supply areas and markets;
location of our assets relative to those of our competitors;
efficiency and reliability of our operations;
receipt and delivery capabilities for natural gas and NGLs that exist in each pipeline system, plant, fractionator and
storage location;
the petrochemical industry’s level of capacity utilization and feedstock requirements;
current and forward natural gas and NGL prices; and
cost of and access to capital.
We have responded by making capital investments to access and connect new supplies with end-user demand; increasing
gathering, processing, fractionation and pipeline capacity; increasing storage, withdrawal and injection capabilities; and
reducing operating costs so that we compete effectively. Our competitors also continue to invest in midstream infrastructure to
address the growing natural gas and NGL supply and market demand. Our and our competitors’ infrastructure projects may
affect commodity prices and compete with and could displace supply volumes from the Mid-Continent and Rocky Mountain
regions and the Permian Basin where our assets are located. We believe our assets are located strategically, connecting diverse
supply areas to market centers.
Customers - Our Natural Gas Gathering and Processing and Natural Gas Liquids segments derive services revenue from major
and independent crude oil and natural gas producers. Our Natural Gas Liquids segment’s customers also include NGL and
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natural gas gathering and processing companies. Our downstream commodity sales customers are primarily utilities, large
industrial companies, natural gasoline distributors, propane distributors, municipalities and petrochemical, refining and
marketing companies. Our Natural Gas Pipeline segment’s assets primarily serve local natural gas distribution companies,
electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies. Our
utility customers generally require our services regardless of commodity prices. See discussion regarding our customer credit
risk under “Counterparty Credit Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this
Annual Report.
Other
Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own a 17-story office building
(ONEOK Plaza) with 517,000 square feet of net rentable space and a parking garage in downtown Tulsa, Oklahoma, where our
headquarters are located. ONEOK Leasing Company, L.L.C. leases excess office space to others and operates our headquarters
office building. ONEOK Parking Company, L.L.C. owns and operates a parking garage adjacent to our headquarters.
REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS
Environmental Matters - We are subject to a variety of historical preservation and environmental laws and/or regulations that
affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air
emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands and
waterways preservation, cultural resources protection, hazardous materials transportation, and pipeline and facility
construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances,
registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may
expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. For
example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own,
operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response,
investigation and cleanup costs, which could affect adversely our results of operations and cash flows. In addition, emissions
controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could
require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations
will not be revised or that new regulations will not be adopted or become applicable to us.
Some scientists have determined that GHG emissions endanger public health and the environment because emissions of such
gases may contribute to warming of the earth’s atmosphere and other climatic changes. GHG emissions originate primarily
from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. International, federal, regional and/or
state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at
issues associated with climate change. Various federal and state legislative proposals have been introduced to regulate the
emission of GHGs, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon
dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally
binding reductions in emissions of GHGs.
Our environmental actions focus on minimizing the impact of our operations on the environment. These actions include:
(i) developing and maintaining an accurate GHG emissions inventory according to current rules issued by the EPA;
(ii) improving the efficiency of our various pipelines, natural gas processing facilities and NGL fractionation facilities;
(iii) following developing technologies for emissions control and the capture of carbon dioxide to keep it from reaching the
atmosphere; and (iv) utilizing practices to reduce the loss of methane from our facilities. In addition, many of our compressor
station facilities are designed and operated with electric-driven compression units, which reduce the potential emission from
these facilities, including GHG emissions.
We participate in the EPA’s Natural Gas STAR Program to reduce voluntarily methane emissions. We continue to focus on
maintaining low methane gas release rates through expanded implementation of best practices to limit the release of natural gas
during pipeline and facility maintenance and operations.
We believe it is likely that future governmental legislation and/or regulation may require us either to limit GHG emissions from
our operations, to purchase allowances for such emissions or to be subject to a carbon emissions tax. However, we cannot
predict precisely what form these future regulations will take, the stringency of the regulations, when they will become
effective or the impact on our results of operations. In addition to activities on the federal level, state and regional initiatives
could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations
could be more stringent than any federal legislation that may be adopted.
16
For additional information regarding the potential impact of laws and regulations on our operations see Item 1A “Risk Factors.”
Pipeline Safety - We are subject to PHMSA safety regulations, including pipeline asset integrity-management regulations. The
Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity
assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence
areas. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) increased
maximum penalties for violating federal pipeline safety regulations, directs the DOT and Secretary of Transportation to conduct
further review or studies on issues that may or may not be material to us and may result in the imposition of more stringent
regulations.
In 2015, PHMSA issued notices of proposed rule-making for hazardous liquid pipeline safety regulations, natural gas
transmission and gathering lines and underground natural gas storage facilities, known as “the Mega Rule.” Due to the large
number of rules being considered, PHMSA partitioned the new rulemaking into three sections. To date, the first section of
rules was finalized and published in 2019 in the federal register. These final rules mostly address congressional mandates due
to former pipeline safety reauthorizations. Coupled together, these new rules provide increased requirements for operating and
maintenance, integrity management, public awareness and civil/criminal penalties. The potential capital and operating
expenditures related to the new regulations are not fully known, but we do not anticipate a material impact to our planned
capital or operations and maintenance costs resulting from compliance with the new or pending regulations. In 2019,
legislation was introduced to reauthorize PHMSA through 2024. If passed, requirements for operations and maintenance,
integrity management, public awareness, civil and criminal penalties could be increased. The potential capital and operating
expenditures related to the proposed regulations are unknown, but we do not anticipate a material impact to our planned capital
or operations and maintenance costs resulting from compliance with the current or pending regulations.
Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations 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. 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 control or limit GHG
emissions, including initiatives directed at issues associated with climate change. We monitor all relevant legislation and
regulatory initiatives to assess the potential impact on our operations and otherwise take efforts to limit GHG emissions from
our facilities, including methane. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual GHG emissions
reporting from affected facilities and the carbon dioxide emission equivalents for the natural gas delivered by us and the
emission equivalents for all NGLs produced by us as if all of these products were combusted, even if they are used otherwise.
Our 2018 total emissions reported pursuant to EPA requirements were approximately 60 million metric tons of carbon dioxide
equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines
and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers and produced as
if all such fuel and NGL products were combusted. 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 GHG emissions, including carbon dioxide and
methane. Likewise, the EPA may institute additional regulatory rule-making associated with GHG emissions from the oil and
natural gas industry. At this time, no rule or legislation has been enacted that assesses any material costs, fees or expenses on
any of these emissions.
We monitor proposed and final rule-makings. At this time, we do not anticipate a material impact to our planned capital,
operations and maintenance costs resulting from compliance with the current or pending regulations and EPA actions.
However, the EPA may issue additional regulations, responses, amendments and/or policy guidance, which could alter our
present expectations. Generally, EPA rule-makings require expenditures for updated emissions controls, monitoring and
record-keeping requirements at affected facilities.
Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released the Chemical
Facility Anti-Terrorism Standards in 2007, and the new final rule associated with these regulations was issued in December
2014. We provided information regarding our chemicals via Top-Screens submitted to Homeland Security, and our facilities
subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to
low risk. To date, one of our facilities has been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to
17
complete Site Security Plans, including possible physical security enhancements. We do not expect the cost of the Site Security
Plans to have a material impact on our results of operations, financial position or cash flows.
Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration and the
DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the
Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the
determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline
requirements, and there have been no material changes required to date.
EMPLOYEES
At January 31, 2020, we employed 2,882 people.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
All executive officers are elected annually by our Board of Directors. Our executive officers listed below include the officers
who have been designated by our Board of Directors as our Section 16 executive officers.
Name and Position
John W. Gibson
Chairman of the Board
Terry K. Spencer
Age
Business Experience in Past Five Years
67
2011 to present
Chairman of the Board, ONEOK
2007 to 2017
Chairman of the Board, ONEOK Partners
60
2014 to present
President and Chief Executive Officer, ONEOK
President and Chief Executive Officer
2014 to 2017
President and Chief Executive Officer, ONEOK Partners
Robert F. Martinovich
Executive Vice President and Chief
Administrative Officer
Walter S. Hulse III
Chief Financial Officer, Treasurer and Executive
Vice President, Strategic Planning and Corporate
Affairs
2014 to present
Member of the Board of Directors, ONEOK
2014 to 2017
Member of the Board of Directors, ONEOK Partners
62
2015 to present
Executive Vice President and Chief Administrative Officer, ONEOK
2015 to 2017
Executive Vice President and Chief Administrative Officer, ONEOK Partners
2014 to 2015
Executive Vice President, Commercial, ONEOK and ONEOK Partners
56
2019 to present
Chief Financial Officer, Treasurer and Executive Vice President, Strategic Planning and
Corporate Affairs, ONEOK
2017 to 2019
Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs,
ONEOK
2015 to 2017
Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK and ONEOK
Partners
2012 to 2015
Managing Member, Spinnaker Strategic Advisory Services, LLC
Kevin L. Burdick
55
2017 to present
Executive Vice President and Chief Operating Officer, ONEOK
Executive Vice President and Chief Operating
Officer
2017
Executive Vice President and Chief Commercial Officer, ONEOK and ONEOK Partners
Charles M. Kelley
61
2018 to present
Senior Vice President, Natural Gas, ONEOK
Senior Vice President, Natural Gas
2017 to 2018
Senior Vice President, Natural Gas Gathering & Processing, ONEOK
2016 to 2017
Senior Vice President, Natural Gas Gathering and Processing, ONEOK Partners
2013 to 2016
Vice President, Natural Gas Gathering and Processing, ONEOK Partners
2015 to 2017
Senior Vice President, Corporate Planning and Development, ONEOK and ONEOK Partners
2014 to 2015
Vice President, Corporate Development, ONEOK and ONEOK Partners
Sheridan C. Swords
50
2017 to present
Senior Vice President, Natural Gas Liquids, ONEOK
Senior Vice President, Natural Gas Liquids
2013 to 2017
Senior Vice President, Natural Gas Liquids, ONEOK Partners
Stephen B. Allen
46
2017 to present
Senior Vice President, General Counsel and Assistant Secretary, ONEOK
Senior Vice President, General Counsel
and Assistant Secretary
2008 to 2017
Vice President and Associate General Counsel, ONEOK and ONEOK Partners
Mary M. Spears
40
2019 to present
Vice President and Chief Accounting Officer, ONEOK
Vice President and Chief Accounting Officer
2015 to 2019
Director, SEC Reporting, ONEOK
2015 to 2017
Director, SEC Reporting, ONEOK Partners
2009 to 2015
Director, Natural Gas Liquids Accounting, ONEOK Partners
No family relationships exist between any of the executive officers, nor is there any arrangement or understanding between any
executive officer and any other person pursuant to which the officer was selected.
INFORMATION AVAILABLE ON OUR WEBSITE
We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, 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
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as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our
Code of Business Conduct and Ethics, Corporate Governance Guidelines, Director Independence Guidelines, Corporate
Sustainability Report, Bylaws and the written charter of our Audit Committee also are available on our website, and we will
provide copies of these documents upon request.
In addition to our filings with the SEC and materials posted on our website, we also use social media platforms as additional
channels of distribution to reach public investors. Information contained on our website, posted on our social media accounts,
and any corresponding applications, 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 identify 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 consider carefully the following discussion of risks and the other information included or incorporated by reference in
this Annual Report, including “Forward-Looking Statements,” which are included in Part II, Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations.
If the level of drilling in the regions in which we operate declines substantially near our assets, our volumes and
revenues could decline.
Our gathering and transportation pipeline systems are dependent upon production from natural gas and crude oil wells, which
naturally declines over time. As a result, our cash flows associated with these wells will also decline over time. In order to
maintain or increase throughput levels on our gathering and transportation pipeline systems and the asset utilization rates at our
processing and fractionation facilities, we must continually obtain new supplies. Our ability to maintain or expand our
businesses depends largely on the level of drilling and production by third parties in the regions in which we operate. Our
natural gas and NGL supply volumes may be impacted if producers curtail or redirect drilling and production activities.
Drilling and production are impacted by factors beyond our control, including:
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demand and prices for natural gas, NGLs and crude oil;
producers’ access to capital;
producers’ finding and development costs of reserves;
producers’ ability to obtain necessary permits, drilling rights and surface access in a timely manner and on reasonable
terms;
natural gas field characteristics and production performance; and
capacity constraints on natural gas, crude oil and NGL infrastructure from the producing areas and our facilities.
Commodity prices have experienced significant volatility. Drilling and production activity levels may vary across our
geographic areas; however, a prolonged period of low commodity prices may reduce drilling and production activities across
all areas. If we are not able to obtain new supplies to replace the natural decline in volumes from existing wells or because
of competition, throughput on our gathering and transportation pipeline systems and the utilization rates of our processing
and fractionation facilities would decline, which could affect adversely our business, results of operations, financial position
and cash flows, and our ability to pay cash dividends.
Continued development of supply sources outside of our operating regions could impact demand for our services.
Natural gas production areas outside of our operating regions may compete with natural gas originating in production areas
connected to our systems. For example, increased production in the Marcellus Shale may cause natural gas and NGLs in
supply areas connected to our systems to be diverted to markets other than our traditional market areas and may affect capacity
utilization adversely on our pipeline systems and our ability to renew or replace existing contracts. In our Natural Gas
Gathering and Processing segment, the development of reserves could move drilling rigs from our current service areas to other
areas, which may reduce demand for our services. In our Natural Gas Pipelines segment, the displacement of natural gas
originating in supply areas connected to our pipeline systems by supply sources that are closer to the end-use markets could
reduce demand for our services. Either of these possibilities could result in lower revenues, which could affect adversely our
business, results of operations, financial position and cash flows.
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Our operations are subject to operational hazards and unforeseen interruptions, which could affect adversely our
business and for which we may not be adequately insured.
Our operations are subject to all of the risks and hazards typically associated with the operation of natural gas and NGL
gathering, transportation and distribution pipelines, storage facilities and processing and fractionation facilities, which include,
but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes and the performance of
facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include
adverse weather conditions, accidents, explosions, fires, the collision of equipment with our pipeline facilities (for example,
this may occur if a third party were to perform excavation or construction work near our facilities) and catastrophic events such
as tornados, hurricanes, earthquakes, floods, and other similar events beyond our control. Also, the United States government
warned that energy assets, specifically the nation’s pipeline infrastructure, may be targets of terrorist attacks. An act of
terrorism could target our facilities, those of our suppliers or customers or those of other pipelines. A casualty occurrence may
result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred and interruptions to the
operations of our pipeline or other facilities caused by such an event could reduce our revenues and increase expenses, thereby
impairing our ability to meet our obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses
incurred or revenues lost, and we are not fully insured against all risks inherent to our business.
As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in
some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently,
we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable
terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could affect adversely our
business, results of operations, financial position and cash flows. Further, the proceeds of any such insurance may not be paid
in a timely manner and may be insufficient if such an event were to occur.
Our operating results may be affected adversely by unfavorable economic and market conditions.
An adverse change in economic conditions worldwide or in the economic regions in which we operate could negatively affect
the crude oil and natural gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced
demand and increased price competition for our services and products. Our operating results in one or more geographic
regions may also be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices
may have an impact on many of our suppliers and customers, which, in turn, could have a negative impact on their ability to
meet their obligations to us. Periods of severe volatility in equity and credit markets may disrupt our access to such markets,
make it difficult to obtain financing necessary to expand facilities or acquire assets, increase financing costs and result in the
imposition of restrictive financial covenants. If adverse global or regional economic and market conditions remain uncertain or
persist, spread or deteriorate further, we may experience material impacts on our business, results of operations, financial
position, cash flows and liquidity.
Increased regulation of exploration and production activities, including hydraulic fracturing, well setbacks and disposal
of waste water, could result in reductions or delays in drilling and completing new crude oil and natural gas wells.
The crude oil and natural gas industry is relying increasingly on supplies from nonconventional sources, such as shale and tight
sands. Natural gas extracted from these sources frequently requires hydraulic fracturing, which involves the pressurized
injection of water, sand and chemicals into a geologic formation to stimulate crude oil and natural gas production. Legislation
or regulations placing restrictions on exploration and production activities, including hydraulic fracturing and disposal of waste
water, could result in operational delays, increase operating costs and additional regulatory burdens on exploration and
production operators. Any of these factors could reduce their production of unprocessed natural gas and, in turn, affect
adversely our revenues and results of operations by decreasing the volumes of natural gas and NGLs gathered, treated,
processed, fractionated and transported on our or our joint ventures’ assets.
In the competition for supply, we may have significant levels of excess capacity on our natural gas and NGL pipelines,
processing, fractionation and storage assets.
Our natural gas and NGL pipelines, processing, fractionation and storage assets compete with other pipelines, processing,
fractionation and storage assets for natural gas and NGL supply delivered to the markets we serve. As a result of competition,
we may have significant levels of uncontracted or discounted capacity on our assets, which could affect adversely our business,
results of operations, financial position and cash flows.
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Growing our business by constructing new pipelines and facilities or making modifications to our existing facilities
subjects us to construction risk and supply risks, should adequate natural gas or NGL supply be unavailable upon
completion of the facilities.
To expand our business, we regularly construct new and modify or expand existing pipelines and gathering, processing, storage
and fractionation facilities. The construction and modification of these facilities may involve the following risks:
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projects may require significant capital expenditures, which may exceed our estimates, and involve numerous
regulatory, environmental, political, legal and weather-related uncertainties;
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projects may increase demand for labor, materials and rights of way, which may, in turn, affect our costs and schedule;
• we may be unable to obtain new rights of way to connect new natural gas or NGL supplies to our existing gathering or
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transportation pipelines;
if we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost;
our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we
build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material
increases in revenues until after completion of the project;
• we may construct facilities to capture anticipated future growth in production in a region in which anticipated
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production growth does not materialize;
opposition from environmental groups, landowners, tribal groups, local groups and other advocates could result in
organized protests, attempts to block or sabotage our construction activities or operations, intervention in regulatory or
administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the
construction or operation of our assets; and
• we may be required to rely on third parties downstream of our facilities to have available capacity for our delivered
natural gas or NGLs, which may not yet be operational.
As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve our expected investment return,
which could affect adversely our business, results of operations, financial position and cash flows.
Estimates of hydrocarbon reserves may be inaccurate which could result in lower than anticipated volumes.
We may not be able to accurately estimate hydrocarbon reserves and production volumes expected to be delivered to us for a
variety of reasons, including the unavailability of sufficiently detailed information and unanticipated changes in producers’
expected drilling schedules. Accordingly, we may not have accurate estimates of total reserves serviced by our assets, the
anticipated life of such reserves or the expected volumes to be produced from those reserves. In such event, if we are unable to
secure additional sources, then the volumes that we gather or process in the future could be less than anticipated. A decline in
such volumes could affect adversely our business, results of operations, financial position and cash flows.
The volatility of natural gas, crude oil and NGL prices could affect adversely our earnings and cash flows.
A significant portion of our revenues are derived from the sale of commodities that are received in conjunction with natural gas
gathering and processing services, the transportation and storage of natural gas, and from the purchase and sale of NGLs and
NGL products. Commodity prices have been volatile and are likely to continue to be so in the future. The prices we receive
for our commodities are subject to wide fluctuations in response to a variety of factors beyond our control, including, but not
limited to, the following:
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overall domestic and global economic conditions;
relatively minor changes in the supply of, and demand for, domestic and foreign energy;
the availability and cost of third-party transportation, natural gas processing and fractionation capacity;
the level of consumer product demand and storage inventory levels;
ethane rejection;
geopolitical conditions impacting supply and demand for natural gas, NGLs and crude oil;
domestic and foreign governmental regulations and taxes;
the price and availability of alternative fuels;
speculation in the commodity futures markets;
the effects of imports and exports on the price of natural gas, crude oil, NGL and liquefied natural gas;
the effect of worldwide energy-conservation measures;
the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials; and
technology and improved efficiency impacting supply and demand for natural gas, NGLs and crude oil.
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These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of
commodities and the impact commodity price fluctuations have on our customers and their need for our services, which could
affect adversely our business, results of operations, financial position and cash flows. As commodity prices decline, we could
be paid less for our commodities, thereby reducing our cash flows. In addition, crude oil, natural gas and NGL production
could also decline due to lower prices.
We do not hedge fully against commodity price risk or interest rate risk, including commodity price changes, seasonal
price differentials, product price differentials or location price differentials. This could result in decreased revenues,
increased costs and lower margins, affecting adversely our results of operations.
Certain of our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs and crude oil
prices. Market risk refers to the risk of loss of future cash flows and earnings arising from adverse changes in commodity
prices. Our primary commodity price exposures arise from:
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the value of the commodities sold under POP with fee contracts of which we retain a portion of the sales proceeds;
the price differentials between the individual NGL products with respect to our NGL transportation and fractionation
agreements;
the location price differentials in the price of natural gas and NGLs;
the seasonal price differentials in natural gas and NGLs related to our storage operations;
the price risk related to electric costs to operate our facilities, primarily in Texas; and
the fuel costs and the value of the retained fuel in-kind in our natural gas pipelines and storage operations.
To manage the risk from market price fluctuations in natural gas, NGLs and crude oil prices, we may use derivative instruments
such as swaps, futures, forwards and options. However, we do not hedge fully against commodity price changes, and we
therefore retain some exposure to market risk. Further, hedging instruments that are used to reduce our exposure to interest-rate
fluctuations could expose us to risk of financial loss where we may contract for fixed-rate swap instruments to hedge variable-
rate instruments and the fixed rate exceeds the variable rate. Finally, hedging arrangements for forecasted sales and purchases
are used to reduce our exposure to commodity price fluctuations and may limit the benefit we would otherwise receive if
market prices for natural gas, crude oil and NGLs differ from the stated price in the hedge instrument for these commodities.
A breach of information security, including a cybersecurity attack, or failure of one or more key information technology
or operational systems, or those of third parties, may affect adversely our operations, financial results or reputation.
Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. The
various uses of these information technology systems, networks and services include, but are not limited to:
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controlling our plants and pipelines with industrial control systems including Supervisory Control and Data
Acquisition (SCADA);
collecting and storing customer, employee, investor and other stakeholder information and data;
processing transactions;
summarizing and reporting results of operations;
hosting, processing and sharing confidential and proprietary research, business plans and financial information;
complying with regulatory, legal, financial or tax requirements;
providing data security; and
other processes necessary to manage our business.
If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to
repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to
perform critical functions, which could affect adversely our business and results of operations. Our financial results could also
be affected adversely if an individual causes our operational systems to fail, either as a result of inadvertent error or by
deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may
further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in
losses that are difficult to detect.
Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our
businesses. We use software to help manage and operate our businesses, and this may subject us to increased risks. In recent
years, there has been a rise in the number and sophistication of cyberattacks on companies’ network and information systems
by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase.
A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, physical
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damages, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. If any such failure,
interruption or similar event results in the improper disclosure of information maintained in our information systems and
networks or those of our vendors, including personnel, customer and vendor information, we could also be subject to liability
under relevant contractual obligations and laws and regulations protecting personal data and privacy. Efforts by us and our
vendors to develop, implement and maintain security measures may not be successful in preventing these events from
occurring, and any network and information systems-related events could require us to expend significant resources to remedy
such event. Cybersecurity, physical security and the continued development and enhancement of our controls, processes and
practices designed to protect our enterprise, information systems and data from attack, damage or unauthorized access and to
identify and appropriately report cyberattacks, remain a priority for us. Although we believe that we have robust information
security procedures and other safeguards in place, as cyberthreats continue to evolve, we may be required to expend additional
resources to continue to enhance our information security measures and/or to investigate and remediate information security
vulnerabilities.
Cyberattacks against us or others in our industry could result in additional regulations. Current efforts by the federal
government, such as the Improving Critical Infrastructure Cybersecurity executive order, and any potential future regulations
could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the
potential impact to our business or the energy industry resulting from additional regulations.
Our operations are subject to federal and state laws and regulations relating to the protection of the environment, which
may expose us to significant costs and liabilities.
The risk of incurring substantial environmental costs and liabilities is inherent in our business. Our operations are subject to
extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the
protection of, the environment. Examples of these laws include:
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the Clean Air Act and analogous state laws that impose obligations related to air emissions;
the Clean Water Act and analogous state laws that regulate discharge of wastewater from our facilities to state and
federal waters;
the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and analogous state
laws that regulate the cleanup of hazardous substances that may have been released at properties currently or
previously owned or operated by us or locations to which we have sent waste for disposal; and
the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the
handling and discharge of solid and hazardous waste from our facilities.
Various federal and state governmental authorities, including the EPA, have the power to enforce compliance with these laws
and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties,
including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the
CERCLA, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.
There is an inherent risk of incurring environmental costs and liabilities in our business due to our handling of the products we
gather, transport, process and store, air emissions related to our operations, past industry operations and waste disposal
practices, some of which may be material. Private parties, including the owners of properties through which our pipeline
systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance
with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we
operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that
contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies
could increase significantly our compliance costs and the cost of any remediation that may become necessary, some of which
may be material. Additional information is included under Item 1, Business, under “Regulatory, Environmental and Safety
Matters” and in Note N of the Notes to Consolidated Financial Statements in this Annual Report.
Our insurance may not cover all environmental risks and has limits on coverage in the event an environmental claim is made
against us. Our business may be affected adversely by increased costs due to stricter pollution-control requirements or
liabilities resulting from noncompliance with required operating or other regulatory permits. New or revised environmental
regulations might also affect adversely our products and activities, and federal and state agencies could impose additional
safety requirements, all of which could affect adversely our profitability.
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We may face significant costs to comply with the regulation of GHG emissions.
GHG emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions.
International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG
emissions, including initiatives directed at issues associated with climate change. Various federal and state legislative proposals
have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane, and the United States
Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been
international efforts seeking legally binding reductions in emissions of GHGs.
We believe it is likely that future governmental legislation and/or regulation on the federal, state and regional levels, may
require us either to limit GHG emissions associated with our operations, pay additional taxes or to purchase allowances for
such emissions. These legislative and/or regulatory initiatives could make some of our activities uneconomic to maintain or
operate. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with
GHG regulatory requirements. Our future results of operations, financial position or cash flows could be affected adversely if
such costs are not recovered or otherwise passed on to our customers. However, we cannot predict precisely what form these
future regulations will take, the stringency of the regulations or when they may become effective.
We may be subject to physical and financial risks associated with climate change and changes in investor sentiment
towards climate change may affect the demand for our securities.
The threat of global climate change may create physical and financial risks to our business. 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. Increased energy use due to weather changes may
require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to
weather changes may affect our financial condition, through decreased revenues. 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. 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, this could increase our cost of providing service. We may not be able to pass on the
higher costs to our customers or recover all costs related to mitigating these physical risks.
Due to climate change concerns, some investors may choose to either not invest, or reduce their investment, in companies that
explore for, produce, process, transport or sell products derived from hydrocarbons. If this investor sentiment increases, we
may see reduced demand for our securities, which could impact our liquidity or the value of our securities. In addition, to the
extent financial markets view climate change and emissions of GHGs as a financial risk, this could affect negatively our ability
to access capital markets or cause us to receive less favorable terms and conditions in future financings.
Changes in regulatory policies, public sentiment or technology due to the threat of climate change that result in a reduction in
the demand for hydrocarbon products, restrictions on their use, or increased use of renewable energy could reduce future
demand for hydrocarbons and reduce volumes available to us for gathering, processing, fractionation, transportation, storage
and marketing. Finally, increasing attention to climate change and the impacts of GHG emissions has resulted in an increased
likelihood of governmental investigations, regulation and private litigation, which could increase our costs or otherwise affect
adversely our business.
Our business is subject to regulatory oversight and potential penalties.
The energy industry historically has been subject to heavy state and federal regulation that extends to many aspects of our
businesses and operations, including:
regulatory approval and review of certain of our rates, operating terms and conditions of service;
the types of services we may offer our counterparties;
construction of new facilities;
the integrity, safety and security of facilities and operations;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
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relationships with affiliate companies involved in all aspects of the natural gas and energy businesses.
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Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these
areas may impair our ability to compete for business or to recover costs and may increase the cost and burden of our operations.
We cannot guarantee that state or federal regulators will not challenge our safety practices or will authorize any projects or
acquisitions that we may propose in the future. Moreover, there can be no guarantee that, if granted, any such authorizations
will be made in a timely manner or will be free from potentially burdensome conditions.
Under the Natural Gas Act, which is applicable to our interstate natural gas pipelines, and the Interstate Commerce Act, which
is applicable to our NGL pipelines, our interstate transportation rates are regulated by the FERC and many changes to our
pipeline tariffs must be approved in a regulatory proceeding. Additionally, either shippers, the FERC and/or state regulatory
agencies may investigate our tariff rates which could result in, among other things, being ordered to reduce rates or make
refunds to shippers.
Failure to comply with all applicable state or federal statutes, rules and regulations and orders could bring substantial penalties
and fines.
Our regulated pipeline companies have recorded certain assets that may not be recoverable from our customers.
Accounting policies for FERC-regulated companies permit certain assets that result from the regulated rate-making process to
be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as
regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If we
determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs.
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 midstream energy business has, at times, caused us to conduct certain
operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs. This shortage
of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain
areas, combined with the challenges of attracting new, qualified workers to the midstream energy industry. This shortage of
skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could affect
adversely our labor productivity and costs and our ability to expand operations in the event there is an increase in the demand
for our services and products, which could affect adversely our business, results of operations, financial position and cash
flows.
Measurement adjustments on our pipeline system may be impacted materially by changes in estimation, type of
commodity and other factors.
Natural gas and NGL measurement adjustments occur as part of the normal operating conditions associated with our assets.
The quantification and resolution of measurement adjustments are complicated by several factors including: (i) the significant
quantities (i.e., thousands) of measurement equipment that we use across our natural gas and NGL systems, primarily around
our gathering and processing assets; (ii) varying qualities of natural gas in the streams gathered and processed through our
systems and the mixed nature of NGLs gathered and fractionated; and (iii) variances in measurement that are inherent in
metering technologies. Each of these factors may contribute to measurement adjustments that may occur on our systems,
which could affect adversely our business, results of operations, financial position and cash flows.
Many of our assets have been in service for several decades.
Many of our pipeline and storage assets are designed as long-lived assets. Over time the age of these assets could result in
increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and
liabilities. Any significant increase in these expenditures, costs or liabilities could affect adversely our business, results of
operations, financial position and cash flows, as well as our ability to pay cash dividends.
We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint-
venture participants agree.
We participate in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint
ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter
documents contain certain features designed to provide each participant with the opportunity to participate in the management
of the joint venture and to protect its investment, as well as any other assets that may be substantially dependent on or
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otherwise affected by the activities of that joint venture. These participation and protective features customarily include a
corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a
greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant
activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or
otherwise raising capital, transactions with affiliates of a joint-venture participant, litigation and transactions not in the ordinary
course of business, among others. Thus, without the concurrence of joint-venture participants with enough voting interests, we
may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the
best interest of us or the particular joint venture.
Moreover, subject to contractual restrictions, any joint-venture owner generally may sell, transfer or otherwise modify its
ownership interest in a joint venture, whether in a transaction involving third parties or the other joint-venture owners. Any
such transaction could result in us being required to partner with different or additional parties who may have business interests
different from ours.
We do not operate all of our joint-venture assets nor do we employ directly all of the persons responsible for providing
administrative, operating and management services. This reliance on others to operate joint-venture assets and to
provide other services could affect adversely our business and results of operations.
We rely on others to provide administrative, operating and management services for certain of our joint-venture assets. We
have a limited ability to control the operations and the associated costs of such operations. The success of these operations
depends on a number of factors that are outside our control, including the competence and financial resources of the operator or
an outsourced service provider. We may have to contract elsewhere for outsourced services, which may cost more than we are
currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in
a timely manner, which may impact our ability to perform under our contracts and affect adversely our business and results of
operations.
We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and
equipment, which could disrupt our operations.
We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the
risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and
related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these
rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could
affect adversely our business, results of operations, financial position and cash flows.
Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per-share basis.
Any acquisition involves potential risks that may include, among other things:
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inaccurate assumptions about volumes, revenues and costs, including potential synergies;
an inability to integrate successfully the businesses we acquire;
decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to
finance the acquisition;
a significant increase in our interest expense and/or financial leverage if we incur additional debt to finance the
acquisition;
the assumption of unknown liabilities for which we are not indemnified, our indemnity is inadequate or our insurance
policies may exclude from coverage;
an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets;
limitations on rights to indemnity from the seller;
inaccurate assumptions about the overall costs of equity or debt;
the diversion of management’s and employees’ attention from other business concerns;
unforeseen difficulties operating in new product areas or new geographic areas;
increased regulatory burdens;
customer or key employee losses at an acquired business; and
increased regulatory requirements.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors
will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in
determining the application of our resources to future acquisitions.
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If we fail to maintain an effective system of internal controls, we may not be able to report accurately our financial
results or prevent fraud. As a result, current and potential holders of our equity and debt securities could lose
confidence in our financial reporting.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a
public company. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able
to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to
comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal
controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or
cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in
our reported financial information, which would likely have a negative effect on the trading price of our equity, our access to
capital markets and the cost of capital.
Our employees or directors may engage in misconduct or other improper activities, including noncompliance with
regulatory standards and requirements.
As with all companies, we are exposed to the risk of employee fraud or other misconduct. Our Board of Directors has adopted
a code of business conduct and ethics that applies to our directors, officers (including our principal executive and financial
officers, principal accounting officer, controllers and other persons performing similar functions) and all other employees. We
require all directors, officers and employees to adhere to our code of business conduct and ethics in addressing the legal and
ethical issues encountered in conducting their work for our company. Our code of business conduct and ethics requires, among
other things, that our directors, officers and employees avoid conflicts of interest, comply with all applicable laws and other
legal requirements, conduct business in an honest and ethical manner and otherwise act with integrity and in our company’s
best interest. All directors, officers and employees are required to report any conduct that they believe to be an actual or
apparent violation of our code of business conduct and ethics. However, it is not always possible to identify and deter
misconduct, and the precautions we take to detect and prevent this activity may not be effective in controlling unknown or
unmanaged risks or losses or in protecting us from governmental investigations or other actions or lawsuits stemming from a
failure to comply with such laws or regulations. If any such actions are instituted against us, and we are not successful in
defending ourselves or asserting our rights, those actions could affect adversely our reputation, business, results of operations,
financial position and cash flows.
An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce
our earnings.
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, including intangible assets with finite
useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may
not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair
value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than
temporary. For example, if a low commodity price environment persisted for a prolonged period, it could result in lower
volumes delivered to our systems and impairments of our assets or equity-method investments. If we determine that an
impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on
equity and balance sheet leverage as measured by consolidated debt to total capitalization.
Any reduction in our credit ratings could affect adversely our business, results of operations, financial position and cash
flows.
Our long-term debt and our commercial paper program have been assigned an investment-grade credit rating of “Baa3” and
Prime-3, respectively, by Moody’s and “BBB” and A-2, respectively, by S&P. We cannot provide assurance that any of our
current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a
rating agency. If Moody’s or S&P were to downgrade our long-term debt or our commercial paper rating, particularly below
investment grade, our borrowing costs would increase, which would affect adversely our financial results, and our potential
pool of investors and funding sources could decrease. Ratings from credit agencies are not recommendations to buy, sell or
hold our securities. Each rating should be evaluated independently of any other rating.
27
Holders of our common stock may not receive dividends in the amount identified in guidance, or any dividends at all.
We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual
amount of cash we pay in the form of dividends may fluctuate from quarter to quarter and will depend on various factors, some
of which are beyond our control, including our working capital needs, our ability to borrow, the restrictions contained in our
indentures and credit facility, our debt service requirements and the cost of acquisitions, if any. A failure either to pay
dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage and a
decrease in the value of our stock price.
Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates.
Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates, as
discussed in Note M of the Notes to Consolidated Financial Statements in this Annual Report. The amount of cash that our
unconsolidated affiliates can distribute principally depends upon the amount of cash flows these affiliates generate from their
respective operations, which may fluctuate from quarter to quarter. We do not have any direct control over the cash distribution
policies of our unconsolidated affiliates. This lack of control may contribute to us not having sufficient available cash each
quarter to continue paying dividends at the current levels.
Additionally, the amount of cash that we have available for cash dividends depends primarily upon our cash flows, including
working capital borrowings, and is not solely a function of profitability, which will be affected by noncash items such as
depreciation, amortization and provisions for asset impairments. As a result, we may be able to pay cash dividends during
periods when we record losses and may not be able to pay cash dividends during periods when we record net income.
We are exposed to the credit risk of our customers or counterparties, and our credit-risk management may not be
adequate to protect against such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties. Our
customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market
conditions, commodity prices or financial difficulties that could impact their creditworthiness or ability to pay us for our
services. We assess the creditworthiness of our customers and counterparties and obtain collateral or contractual terms as we
deem appropriate. We cannot, however, predict to what extent our business may be impacted by deteriorating market or
financial conditions, including possible declines in our customers’ and counterparties’ creditworthiness. Our customers and
counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent our customers and
counterparties are in financial distress or commence bankruptcy proceedings, contracts with them may be subject to
renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If our risk-management policies
and procedures fail to assess adequately the creditworthiness of existing or future customers and counterparties, any material
nonpayment or nonperformance by our customers and counterparties due to inability or unwillingness to perform or adhere to
contractual arrangements could affect adversely our business, results of operations, financial position, cash flows and ability to
pay cash dividends to our shareholders.
Our primary market areas are located in the Mid-Continent, Rocky Mountain, Permian Basin and Gulf Coast regions of the
U.S. Our counterparties are primarily major integrated and independent exploration and production, pipeline, marketing and
petrochemical companies. Therefore our counterparties may be similarly affected by changes in economic, regulatory or other
factors that may affect our overall credit risk.
Changes in interest rates could affect adversely our business.
We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our short-term
borrowings. Our results of operations, cash flows and financial position could be affected adversely by significant fluctuations
in interest rates from current levels.
In July 2017, the head of the United Kingdom Financial Conduct Authority announced the desire to phase out the use of
LIBOR by the end of 2021. In addition, the U.S. Federal Reserve, in conjunction with the Alternative Reference Rates
Committee, a steering committee composed of large US financial institutions, is considering replacing U.S. dollar LIBOR with
the Secured Overnight Financing Rate (SOFR), a new index supported by short-term Treasury repurchase agreements.
Although there have been some issuances utilizing SOFR, it is unknown whether this alternative reference rate will attain
market acceptance as a replacement for LIBOR.
28
Our $2.5 Billion Credit Agreement and our $1.5 Billion Term Loan Agreement include provisions that grant the agreement’s
administrative agents with broad discretion to establish a replacement rate for LIBOR, if necessary.
Our indebtedness and guarantee obligations could impair our financial condition and our ability to fulfill our
obligations.
As of December 31, 2019, we had total indebtedness of $12.8 billion. Our indebtedness and guarantee obligations could have
significant consequences. For example, they could:
• make it more difficult for us to satisfy our obligations with respect to senior notes and other indebtedness due to the
increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or the
senior notes;
impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or
general business purposes;
diminish our ability to withstand a downturn in our business or the economy;
require us to dedicate a substantial portion of our cash flows from operations to debt-service payments, reducing the
availability of cash for working capital, capital expenditures, acquisitions, dividends or general corporate purposes;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
place us at a competitive disadvantage compared with our competitors that have proportionately less debt and fewer
guarantee obligations.
•
•
•
•
•
We are not prohibited under the indentures governing the senior notes from incurring additional indebtedness, but our debt
agreements do subject us to certain operational limitations summarized in the next paragraph. If we incur significant additional
indebtedness, it could worsen the negative consequences mentioned above and could affect adversely our ability to repay our
other indebtedness.
Our $2.5 Billion Credit Agreement and $1.5 Billion Term Loan Agreement contain provisions that restrict our ability to finance
future operations or capital needs or to expand or pursue our business activities. For example, certain of these agreements
contain provisions that, among other things, limit our ability to make loans or investments, make material changes to the nature
of our business, merge, consolidate or engage in asset sales, grant liens or make negative pledges. Certain agreements also
require us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur, as described in
the “Liquidity and Capital Resources” section of Part II, Item 7, Management’s Discussion and Analysis of Financial Condition
and Results of Operations, in this Annual Report. These restrictions could result in higher costs of borrowing and impair our
ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive
covenants.
If we are unable to meet our debt-service obligations or comply with financial covenants, we could be forced to restructure or
refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on
satisfactory terms, or at all.
The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be
effectively subordinated to any future secured indebtedness as well as to any existing and future indebtedness of our
subsidiaries that do not guarantee the senior notes.
Although many of our operating subsidiaries have guaranteed our debt securities, the guarantees are subject to release under
certain circumstances, and we may have subsidiaries that are not guarantors. In that case, the debt securities effectively would
be subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not
guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of
a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any
distribution is made to us or the holders of the debt securities.
An event of default may require us to offer to repurchase certain of our and ONEOK Partners’ senior notes or may
impair our ability to access capital.
The indentures governing certain of our and ONEOK Partners’ senior notes include an event of default upon the acceleration of
other indebtedness of $15 million or more for certain of our senior notes or $100 million or more for certain of our and
ONEOK Partners’ senior notes. Such events of default would entitle the trustee or the holders of 25% in aggregate principal
amount of our and ONEOK Partners’ outstanding senior notes to declare those senior notes immediately due and payable in
full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to
29
borrow money under our credit facility or seek alternative financing sources to finance the repurchases and repayment. We
could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for
acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.
A court may use fraudulent conveyance considerations to avoid or subordinate the cross guarantees of our and ONEOK
Partners’ indebtedness.
ONEOK, ONEOK Partners and the Intermediate Partnership have cross guarantees in place for our and ONEOK Partners’
indebtedness. A court may use fraudulent conveyance laws to subordinate or avoid the cross guarantees of certain of our and
ONEOK Partners’ indebtedness. It is also possible that under certain circumstances, a court could avoid or subordinate the
guarantor’s guarantee of our and ONEOK Partners’ indebtedness in favor of the guarantor’s other debts or liabilities to the
extent that the court determined either of the following were true at the time the guarantor issued the guarantee:
•
•
the guarantor incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or
the guarantor contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of
others; or
the guarantor did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the
time it issued the guarantee, the guarantor:
– was insolvent or rendered insolvent by reason of the issuance of the guarantee;
– was engaged or about to engage in a business or transaction for which its remaining assets constituted
unreasonably small capital; or
intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.
–
The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction.
Generally, however, an entity would be considered insolvent for purposes of the foregoing if:
•
•
•
the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair
valuation;
the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability
on its existing debts, including contingent liabilities, as they become absolute and mature; or
it could not pay its debts as they become due.
Among other things, a legal challenge of the cross guarantees of our and ONEOK Partners’ indebtedness on fraudulent
conveyance grounds may focus on the benefits, if any, realized by the guarantor as a result of our and ONEOK Partners’
issuance of such debt. To the extent the guarantor’s guarantee of our and ONEOK Partners’ indebtedness is avoided as a result
of fraudulent conveyance or held unenforceable for any other reason, the holders of such debt would cease to have any claim in
respect of the guarantee.
The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is
subject to changes in pension fund values and changing demographics and may increase.
We have a defined benefit pension plan for certain employees and former employees hired before January 1, 2005, and
postretirement welfare plans that provide postretirement medical and life insurance benefits to certain employees hired prior to
2017 who retire with at least five years of full-time service. The cost of providing these benefits to eligible current and former
employees is subject to changes in the market value of our pension and postretirement benefit plan assets, changing
demographics, including longer life expectancy of plan participants and their beneficiaries and changes in health care costs.
For further discussion of our defined benefit pension plan and postretirement welfare plans, see Note K of the Notes to
Consolidated Financial Statements in this Annual Report.
Any sustained declines in equity markets and reductions in bond yields may affect adversely the value of our pension and
postretirement benefit plan assets. In these circumstances, additional cash contributions to our pension plans may be required,
which could affect adversely our business, financial condition and liquidity.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
PROPERTIES
A description of our properties is included in Item 1, Business.
30
ITEM 3.
LEGAL PROCEEDINGS
Information about our legal proceedings is included in Note N of the Notes to Consolidated Financial Statements in this Annual
Report.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the NYSE under the trading symbol “OKE.” The corporate name ONEOK is used in newspaper
stock listings.
At February 18, 2020, there were 14,001 holders of record of our 413,319,000 outstanding shares of common stock.
For information regarding our Employee Stock Award Program and other equity compensation plans see Note J of the Notes to
Consolidated Financial Statements and “Equity Compensation Plan Information” included in Part III, Item 12, Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, in this Annual Report.
31
PERFORMANCE GRAPH
The following performance graph compares the performance of our common stock with the S&P 500 Index, the Alerian
Midstream Energy Select Index and a ONEOK Peer Group during the period beginning on December 31, 2014, and ending on
December 31, 2019.
The 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 Distributions/Dividends,
at December 31, 2014, and at the End of Every Year Through December 31, 2019.
2015
2016
Cumulative Total Return
Years Ended December 31,
2017
2018
2019
ONEOK, Inc.
S&P 500 Index
ONEOK Peer Group (a)
Alerian Midstream Energy Select Index (b)
$
$
$
$
52.64
101.37
55.66
62.86
$
$
$
$
131.26
113.49
78.90
90.08
$
$
$
$
128.53
138.26
73.65
90.52
$
$
$
$
136.60
132.19
63.01
74.34
$
$
$
$
201.86
173.80
68.41
90.52
(a) - The ONEOK Peer Group is composed of the following companies: DCP Midstream, LP; Enable Midstream Partners, LP; Energy
Transfer LP.; EnLink Midstream, LLC; Enterprise Products Partners L.P.; Kinder Morgan, Inc.; Magellan Midstream Partners, L.P.; MPLX
LP; NuStar Energy L.P.; Plains All American Pipeline, L.P.; Targa Resources Corp.; and The Williams Companies, Inc.
(b) - The Alerian Midstream Energy Select Index measures the composite performance of approximately 35 North American energy
infrastructure companies who are engaged in midstream activities involving energy commodities.
32
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for the periods indicated:
Revenues
Net income
Total assets
Long-term debt, including current maturities
Earnings per share - total
Basic
Diluted
Dividends declared per share of common stock
2019
10,164.4
1,278.6
21,812.1
12,487.4
3.09
3.07
3.53
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Years Ended December 31,
2018
2016
2017
(Millions of dollars, except per share data)
12,593.2
1,155.0
18,231.7
9,381.0
2.80
2.78
3.245
$
$
$
$
$
$
$
12,173.9
593.5
16,845.9
8,524.3
1.30
1.29
2.72
$
$
$
$
$
$
$
8,920.9
743.5
16,138.8
8,330.6
1.67
1.66
2.46
$
$
$
$
$
$
$
2015
7,763.2
379.2
15,446.1
8,434.2
1.17
1.16
2.43
Changes in commodity prices and sales volumes affect both revenue and cost of sales and fuel, and, therefore, the changes in
revenue in the above table are largely offset in cost of sales and fuel.
In 2019, we completed underwritten public offerings of $1.25 billion and $2.0 billion senior unsecured notes in March and
August, respectively, primarily to fund our capital-growth projects.
Upon adoption of Topic 606 in January 2018, we determined that certain Natural Gas Gathering and Processing segment POP
with fee contracts and Natural Gas Liquids segment exchange services contracts that include the purchase of commodities are
supplier contracts. Contractual fees in these identified contracts are recorded as a reduction of the commodity purchase price in
cost of sales and fuel. In 2017 and prior periods, these fees were recorded as services revenue.
In the fourth quarter 2017, we recorded a one-time noncash charge to net income through income tax expense of
$141.3 million, related to the revaluation of our deferred tax balances and a valuation allowance on certain state net operating
loss and tax credit carryforwards resulting from the enactment of the Tax Cuts and Jobs Act. For more information, see Note L
in the Notes to the Consolidated Financial Statements in this Annual Report.
Also in 2017, we incurred a $20.0 million noncash expense related to our Series E Preferred Stock contribution to the
Foundation and operating costs related to the Merger Transaction of $30.0 million.
We recorded noncash impairment charges of $20.2 million and $264.3 million in 2017 and 2015, respectively.
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 Part I, Item 1, Business, our audited Consolidated
Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.
RECENT DEVELOPMENTS
Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of
Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for additional
information.
Market Conditions - Volumes increased across our system in our Natural Gas Gathering and Processing and Natural Gas
Liquids segments in 2019, compared with 2018, which resulted in higher fee-based earnings, primarily as a result of our
completed capital-growth projects, continued drilling and producer improvements in production due to enhanced completion
techniques, offset partially by natural production declines.
We experienced fluctuating NGL location price differentials due to increased supply, increased demand in the Mid-Continent
region, infrastructure constraints and slower demand growth in the Gulf Coast due primarily to delays in the startup of
petrochemical facilities and constrained NGL export facilities. The Conway-to-Mont Belvieu OPIS price differential for ethane
in ethane/propane mix averaged $0.07 per gallon in 2019, compared with $0.15 per gallon in 2018, which resulted in lower
33
earnings from our optimization and marketing activities in our Natural Gas Liquids segment. We expect narrower NGL
location price differentials in 2020.
Ethane Opportunity - Ethane volumes under long-term contracts delivered to our NGL system averaged 385 MBbl/d in 2019,
compared with 380 MBbl/d in 2018, and have generally been increasing since 2017, primarily as a result of NGL demand
increasing from exports and petrochemical companies completing ethylene production projects and plant expansions. Our
NGL capital-growth projects are expected to help alleviate system constraints, enabling additional NGLs, including ethane, to
reach the Mont Belvieu, Texas, market center.
Northern Border Pipeline, which provides key natural gas takeaway capacity out of the Williston Basin, recently notified
shippers that it plans to place restrictions on the Btu content of the residue natural gas it receives in order to meet downstream
pipeline specifications. When these restrictions take effect, natural gas processors in the Williston Basin may recover
incremental ethane into the NGL stream in order to lower the Btu content of the residue natural gas delivered to Northern
Border Pipeline. As a result, ethane deliveries to our NGL system may increase.
Growth Projects - Our announced large capital-growth projects that have recently been completed or are currently under
construction are outlined in the tables below:
Project
Scope
Natural Gas Gathering and Processing
Demicks Lake I plant and
related infrastructure
Demicks Lake II plant and
related infrastructure
200 MMcf/d processing plant and related gathering
infrastructure in the core of the Williston Basin
Supported by acreage dedications with long-term primarily fee-
based contracts
200 MMcf/d processing plant and related gathering
infrastructure in the core of the Williston Basin
Supported by acreage dedications with long-term primarily fee-
based contracts
200 MMcf/d processing plant expansion and related gathering
infrastructure in the Williston Basin
Supported by acreage dedications with long-term primarily fee-
based contracts
200 MMcf/d processing plant and related gathering
infrastructure in the core of the Williston Basin
Supported by acreage dedications with primarily fee-based
contracts
(a) - Excludes capitalized interest/AFUDC.
Bear Creek plant expansion
and related infrastructure
Demicks Lake III plant and
related infrastructure
Approximate
Costs (a)
(In millions)
$400
Expected
Completion
Completed
October 2019
$410
Completed
January 2020
$405
First Quarter 2021
$305
Third Quarter 2021
34
Project
Natural Gas Liquids
Elk Creek pipeline and related
infrastructure
Arbuckle II pipeline and
related infrastructure
West Texas LPG pipeline
expansion and Arbuckle II
connection
MB-4 fractionator and related
infrastructure
Bakken NGL pipeline
extension
Arbuckle II extension project
and additional gathering
infrastructure
Scope
Approximate
Costs (a)
Expected
Completion
900-mile NGL pipeline from the Williston Basin to the Mid-
Continent region, with capacity of up to 240 MBbl/d, and
related infrastructure
Anchored by long-term contracts
Expansion capability up to 400 MBbl/d with additional pump
facilities
530-mile NGL pipeline from the STACK area to Mont Belvieu,
Texas, with initial capacity up to approximately 400 MBbl/d,
and related infrastructure
Supported by long-term contracts
Expansion capability up to 1 MMBbl/d
Increasing mainline capacity by 80 MBbl/d with additional
pump facilities and pipeline looping
Connecting West Texas LPG pipeline system to the Arbuckle II
pipeline
Supported by long-term dedicated production from six third-
party processing plants expected to produce up to 60 MBbl/d
125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and
related infrastructure, which includes additional NGL storage in
Mont Belvieu
Fully contracted with long-term contracts
75-mile NGL pipeline in the Williston Basin connecting to a
third-party processing plant
Supported by a long-term contract with a minimum volume
commitment
Provide additional takeaway capacity in the STACK area
Allow increasing volumes on the Elk Creek pipeline access to
fractionation capacity at Mont Belvieu, Texas
$1,400
Completed
December 2019 (b)
$1,360
First Quarter 2020
$295
First Quarter 2020
$575
First Quarter 2020 (c)
$100
Fourth Quarter 2020
$240
First Quarter 2021
Arbuckle II pipeline expansion Increasing mainline capacity with additional pump facilities
$60
First Quarter 2021
MB-5 fractionator and related
infrastructure
West Texas LPG pipeline
expansion
Mid-Continent fractionation
facility expansions
West Texas LPG pipeline
expansion
Elk Creek pipeline expansion
Increases capacity to 500 MBbl/d
125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and
related infrastructure, which includes additional NGL storage in
Mont Belvieu
Fully contracted with long-term contracts
Increasing mainline capacity by 40 MBbl/d
Supported by long-term dedicated production from third-party
processing plants expected to produce up to 45 MBbl/d
65 MBbl/d of expansions at our Mid-Continent NGL facilities
Increasing mainline capacity by 100 MBbl/d
Fully contracted with long-term dedicated production from
third-party processing plants
Increasing mainline capacity to 400 MBbl/d with additional
pump facilities
Supported by long-term dedicated production from ONEOK
and third-party processing plants
$750
First Quarter 2021
$145
First Quarter 2021
$150
$310
First Quarter 2021 (d)
Second Quarter 2021
$305
Third Quarter 2021 (e)
(a) - Excludes capitalized interest/AFUDC.
(b) - In July 2019, we completed the southern section of the pipeline from the Powder River Basin to our existing Mid-Continent NGL
facilities. In December 2019, we completed the northern section of the pipeline from the Williston Basin to the Powder River Basin.
(c) - We completed 75 MBbl/d in December 2019, with the remaining 50 MBbl/d to be completed in the first quarter 2020.
(d) - We expect to complete 15 MBbl/d in the third quarter 2020, with the remaining 50 MBbl/d expected to be completed in the first quarter
2021.
(e) - We expect a portion of this incremental capacity to be available as early as first quarter 2021.
Debt Issuances and Repayments - In August 2019, we completed an underwritten public offering of $2.0 billion senior
unsecured notes consisting of $500 million, 2.75% senior notes due 2024; $750 million, 3.4% senior notes due 2029; and $750
million, 4.45% senior notes due 2049. The net proceeds, after deducting underwriting discounts, commissions and offering
expenses, were $1.97 billion and were used for general corporate purposes, including funding of capital expenditures and
repayment of existing indebtedness. Repayments included the redemption of our $300 million, 3.8% senior notes due March
35
2020 at a redemption price of $308 million in September 2019 and the repayment of $250 million of our $1.5 Billion Term
Loan agreement in August 2019.
In March 2019, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $700
million, 4.35% senior notes due 2029 and an additional issuance of $550 million of our existing 5.2% senior notes due 2048.
The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued
interest, were $1.23 billion. During the six months ended June 30, 2019, we drew the remaining $950 million under our
$1.5 Billion Term Loan Agreement. The proceeds were used for general corporate purposes, including repayment of existing
indebtedness and funding capital expenditures.
Also, in March 2019, we repaid our $500 million, 8.625% senior notes at maturity with a combination of cash on hand and
short-term borrowings.
Dividends - During 2019, we paid dividends totaling $3.53 per share, an increase of 9% from the $3.245 per share paid in
2018. In February 2020, we paid a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis), an increase
of 9% compared with the same quarter in the prior year. Our dividend growth is due to the increase in cash flows resulting
from the continued growth of our operations.
FINANCIAL RESULTS AND OPERATING INFORMATION
Consolidated Operations
Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods
indicated:
Financial Results
Revenues
Commodity sales
Services
Total revenues
Cost of sales and fuel (exclusive of items shown
separately below)
Operating costs
Depreciation and amortization
Impairment of long-lived assets
(Gain) loss on sale of assets
Operating income
Equity in net earnings from investments
Impairment of equity investments
Interest expense, net of capitalized interest
Net income
Adjusted EBITDA
Capital expenditures
Years Ended December 31,
2019 vs. 2018
2018 vs. 2017
2019
2018
2017
(Millions of dollars)
Increase (Decrease)
Variances
$
$
$
$
$
$
$
$
$
8,916.1
1,248.3
10,164.4
$
11,395.6
1,197.6
12,593.2
$
9,862.7
2,311.2
12,173.9
6,788.0
982.9
476.5
—
2.6
1,914.4
154.5
$
$
— $
(491.8) $
1,278.6
$
2,580.2
$
3,848.3
$
9,422.7
907.0
428.6
—
(0.6)
1,835.5
158.4
$
$
— $
(469.6) $
$
1,155.0
$
2,447.5
$
2,141.5
9,538.0
822.7
406.3
16.0
(0.9)
1,391.8
159.3
$
$
(4.3) $
(485.7) $
$
593.5
$
1,986.9
$
512.4
(2,479.5) $
50.7
(2,428.8)
(2,634.7)
75.9
47.9
—
(3.2)
78.9
$
(3.9) $
— $
$
$
$
$
22.2
123.6
132.7
1,706.8
1,532.9
(1,113.6)
419.3
(115.3)
84.3
22.3
(16.0)
(0.3)
443.7
(0.9)
(4.3)
(16.1)
561.5
460.6
1,629.1
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel in our Consolidated Statements
of Income, and, therefore, the impact is largely offset between these line items.
2019 vs. 2018 - Operating income increased primarily as a result of the following:
• Natural Gas Gathering and Processing - an increase of $95.5 million due primarily to natural gas volume growth,
offset partially by a decrease of $20.9 million due primarily to lower realized NGL and natural gas prices, net of
hedges;
36
• Natural Gas Liquids - an increase of $148.1 million in exchange services due primarily to higher volumes and average
fee rates, offset partially by a decrease of $60.2 million in optimization and marketing due primarily to wider location
price differentials in the prior year; and
• Natural Gas Pipelines - an increase of $56.5 million from higher transportation services, offset partially by a decrease
of $9.1 million from lower net retained fuel and timing of equity gas sales; offset partially by
an increase of $75.9 million in operating costs due primarily to higher employee-related costs associated with labor
and benefits, spending on routine maintenance projects and ad valorem taxes due to the growth of our operations; and
an increase of $47.9 million in depreciation expense due to capital projects placed in service.
•
•
Net income increased for the year ended December 31, 2019, compared with the same period in 2018, due to the items
discussed above and higher allowance for equity funds used during construction related to our capital-growth projects, offset
partially by higher interest expense related to our underwritten public debt offerings in March and August 2019.
Capital expenditures increased due primarily to spending on our announced capital-growth projects.
Additional information regarding our financial results and operating information is provided in the discussions for each of our
segments.
Selected Financial Results and Operating Information the Year Ended December 31, 2018 vs. 2017 - The consolidated
and segment financial results and operating information for the year ended December 31, 2018, compared with the year ended
December 31, 2017, are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results
of Operations of our 2018 Annual Report on Form 10-K, which is available via the SEC’s website at www.sec.gov and our
website at www.oneok.com.
Natural Gas Gathering and Processing
Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas in the
Williston Basin that we expect will enable us to meet the needs of crude oil and natural gas producers in those areas. See
“Growth Projects” in the “Recent Developments” section for discussion of our announced capital-growth projects.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources”
section.
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and
operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
Financial Results
2019
2018
2017
(Millions of dollars)
Increase (Decrease)
Years Ended December 31,
2019 vs. 2018
2018 vs. 2017
Variances
NGL sales
Condensate sales
Residue natural gas sales
Gathering, compression, dehydration and
processing fees and other revenue
Cost of sales and fuel (exclusive of depreciation
and operating costs)
Operating costs, excluding noncash compensation
adjustments
Equity in net earnings (loss) from investments,
excluding noncash impairment charges
Other
Adjusted EBITDA
Impairment of equity investments
Capital expenditures
$
$
$
$
$
1,024.3
200.1
966.1
$
1,567.2
208.8
1,084.2
$
1,208.0
103.2
856.3
(542.9) $
(8.7)
(118.1)
359.2
105.6
227.9
178.1
174.4
859.1
3.7
(684.7)
(1,302.3)
(2,041.4)
(2,216.4)
(739.1)
(175.0)
(352.8)
(357.7)
(302.6)
(4.9)
(6.3)
(4.5)
702.7
$
— $
$
926.5
0.4
(4.3)
631.6
$
— $
$
694.6
12.1
(1.2)
518.5
$
(4.3) $
$
284.2
(6.7)
(0.2)
71.1
$
— $
$
231.9
55.1
(11.7)
(3.1)
113.1
(4.3)
410.4
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices and sales volumes affect both revenue and cost of sales and fuel, and, therefore, the impact is
largely offset between these line items.
37
2019 vs. 2018 - Adjusted EBITDA increased $71.1 million, primarily as a result of the following:
•
•
•
•
an increase of $95.5 million due primarily to natural gas volume growth in the Williston Basin and STACK and
SCOOP areas, offset partially by natural production declines; and
a decrease of $4.9 million in operating costs due primarily to lower outside services and materials and supplies, offset
partially by higher employee-related costs and ad valorem taxes due primarily to the growth of our operations; offset
partially by
a decrease of $20.9 million due primarily to lower realized NGL and natural gas prices, net of hedges; and
a decrease of $6.7 million due primarily to lower equity in net earnings from investments due to a decrease in supply
volumes in the dry natural gas area of the Powder River Basin.
Capital expenditures increased due primarily to spending on our announced capital-growth projects.
Operating Information (a)
Natural gas gathered (BBtu/d)
Natural gas processed (BBtu/d) (b)
NGL sales (MBbl/d)
Residue natural gas sales (BBtu/d) (b)
Average fee rate ($MMBtu)
(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes at company-owned and third-party facilities.
Years Ended December 31,
2018
2017
2019
2,753
2,555
224
1,201
0.92
$
2,546
2,382
198
1,088
0.90
$
2,211
2,056
187
896
0.86
$
2019 vs. 2018 - Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales volumes increased in
2019, compared with 2018, due primarily to our capital-growth projects and continued producer improvements in production
due to enhanced completion techniques, offset partially by natural production declines.
Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 7A,
Quantitative and Qualitative Disclosures about Market Risk.
Natural Gas Liquids
Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market
centers NGL supply from shale and other resource development areas. Our growth strategy is focused around connecting
diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with NGL
product demand from the petrochemical industry and NGL export demand in the Gulf Coast. Growing crude oil, natural gas
and NGL production together with higher petrochemical and export demand have resulted in us making additional capital
investments to expand our infrastructure and alleviate system constraints. See “Growth Projects” in the “Recent
Developments” section for discussion of our announced capital-growth projects.
We continue to evaluate opportunities to increase the capacity of our gathering, fractionation, storage and distribution assets or
construct new assets to connect supply growth from the Williston and Powder River Basins, Mid-Continent region and Permian
Basin with end-use markets.
In 2019, we connected seven third-party natural gas processing plants and one affiliate natural gas processing plant to our NGL
system, five in the Mid-Continent region, one in the Permian Basin and two in the Rocky Mountain region. In addition, six
third-party natural gas processing plants connected to our system were expanded, two in the Mid-Continent region, two in the
Permian Basin and two in the Rocky Mountain region.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources”
section.
38
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and
operating information for our Natural Gas Liquids segment for the periods indicated:
Years Ended December 31,
2019 vs. 2018
2018 vs. 2017
Variances
Financial Results
2019
2018
2017
(Millions of dollars)
Increase (Decrease)
NGL and condensate sales
Exchange service revenues and other
Transportation and storage revenues
Cost of sales and fuel (exclusive of depreciation
and operating costs)
Operating costs, excluding noncash compensation
adjustments
Equity in net earnings from investments
Other
Adjusted EBITDA
Capital expenditures
$
$
$
$
7,910.8
424.2
197.5
$
10,319.9
415.7
199.0
$
8,998.9
1,430.3
197.0
(2,409.1) $
8.5
(1.5)
1,321.0
(1,014.6)
2.0
(6,690.9)
(9,176.8)
(9,176.5)
(2,485.9)
0.3
(434.4)
65.1
(6.5)
1,465.8
2,796.6
$
$
(378.3)
67.1
(6.0)
1,440.6
1,306.3
$
$
(351.3)
59.9
(3.4)
1,154.9
114.3
$
$
56.1
(2.0)
(0.5)
25.2
1,490.3
$
$
27.0
7.2
(2.6)
285.7
1,192.0
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel, and, therefore, the impact is
largely offset between these line items.
2019 vs. 2018 - Adjusted EBITDA increased $25.2 million, primarily as a result of the following:
•
•
•
an increase of $148.1 million in exchange services due to $150.2 million in higher volumes primarily in the Rocky
Mountain region, the Permian Basin and the STACK and SCOOP areas, and $91.5 million in higher average fee rates
primarily in the Permian Basin and the Rocky Mountain region, offset partially by $64.9 million due primarily to
higher third-party transportation and fractionation costs, $25.0 million due primarily to narrower product price
differentials and $5.8 million related to higher unfractionated NGLs in inventory; offset partially by
a decrease of $60.2 million in optimization and marketing due primarily to a decrease of $93.8 million related to wider
location price differentials in the prior year, particularly in the third quarter 2018, and $5.1 million in lower earnings
related primarily to product price differentials, offset partially by higher marketing earnings of $38.5 million related
primarily to the sale of NGL products previously held in inventory; and
an increase of $56.1 million in operating costs due primarily to higher employee-related costs associated with labor
and benefits due to the growth of our operations, and spending on routine maintenance projects.
Capital expenditures increased due primarily to our announced capital-growth projects.
Operating Information
Raw feed throughput (MBbl/d) (a)
NGLs transported - gathering lines (MBbl/d) (b)
NGLs fractionated (MBbl/d) (c)
Average Conway-to-Mont Belvieu OPIS price differential -
ethane in ethane/propane mix ($/gallon)
Years Ended December 31,
2018
2017
2019
1,079
988
726
1,010
912
715
895
812
621
$
0.07
$
0.15
$
0.05
(a) - Represents physical raw feed volumes on which we charge a fee for transportation and/or fractionation services.
(b) - Includes volumes for consolidated entities only.
(c) - Includes volumes at company-owned and third-party facilities.
2019 vs. 2018 - Raw feed throughput volumes increased primarily in the Rocky Mountain region, the Permian Basin and the
STACK and SCOOP areas as a result of our completed capital-growth projects, continued drilling and producer improvements
in production due to enhanced completion techniques, offset partially by natural production declines and lower volumes in the
Mid-Continent region due primarily to lower ethane volumes.
39
Natural Gas Pipelines
Growth Projects - Our natural gas pipelines primarily serve end users, such as natural gas distribution and electric-generation
companies, that require natural gas to operate their businesses regardless of location price differentials. The development of
shale has continued to increase available natural gas supply, and we expect producers and natural gas processors to require
incremental transportation services in the future as additional supply is developed.
We expanded our natural gas pipeline infrastructure in Oklahoma and the Permian Basin. The projects included an eastbound
expansion of our ONEOK Gas Transportation system by 150 MMcf/d from the STACK and SCOOP areas to an interstate
pipeline delivery point in eastern Oklahoma, a westbound expansion of our ONEOK Gas Transportation system by
100 MMcf/d from the STACK area to multiple interstate pipeline delivery points in western Oklahoma and an expansion of our
WesTex Transmission system by 300 MMcf/d from the Permian Basin to interstate pipeline delivery points in the Texas
Panhandle. Additionally, we completed an expansion project on our Roadrunner joint venture to make the pipeline
bidirectional, which resulted in approximately 1.0 Bcf/d of eastbound transportation capacity from the Delaware Basin to the
Waha area.
See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and
operating information for our Natural Gas Pipelines segment for the periods indicated:
Financial Results
2019
2018
2017
(Millions of dollars)
Increase (Decrease)
Years Ended December 31,
2019 vs. 2018
2018 vs. 2017
Variances
Transportation revenues
Storage revenues
Natural gas sales and other revenues
Cost of sales and fuel (exclusive of depreciation
and operating costs)
Operating costs, excluding noncash compensation
adjustments
Equity in net earnings from investments
Other
Adjusted EBITDA
Capital expenditures
$
$
$
393.7
72.6
5.7
(4.6)
(150.8)
95.7
(3.5)
408.8
99.2
$
$
$
343.0
72.0
16.7
(16.0)
(139.2)
90.8
(1.0)
366.3
119.2
$
$
$
327.9
66.5
25.5
(43.4)
(123.1)
87.3
(0.9)
339.8
95.6
$
$
$
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
2019 vs. 2018 - Adjusted EBITDA increased $42.5 million primarily as a result of the following:
$
50.7
0.6
(11.0)
(11.4)
11.6
4.9
(2.5)
42.5
$
(20.0) $
15.1
5.5
(8.8)
(27.4)
16.1
3.5
(0.1)
26.5
23.6
•
•
•
•
an increase of $56.5 million from higher transportation services due primarily to firm transportation capacity
contracted due to our completed expansion projects; and
an increase of $4.9 million from higher equity in net earnings due primarily to firm transportation capacity contracted
on Roadrunner; offset partially by
an increase of $11.6 million in operating costs due primarily to employee-related costs associated with labor and
benefits and ad valorem taxes due to the growth of our operations; and
a decrease of $9.1 million from lower net retained fuel and timing of equity gas sales.
Capital expenditures decreased due primarily to timing of maintenance projects and capital-growth projects.
Operating Information (a)
Natural gas transportation capacity contracted (MDth/d)
Transportation capacity contracted
(a) - Includes volumes for consolidated entities only.
Years Ended December 31,
2018
2017
2019
7,618
98%
6,846
96%
6,611
94%
2019 vs. 2018 - Natural gas transportation capacity contracted increased due to our completed expansion projects on our
ONEOK Gas Transportation and WesTex Transmission systems, which are both substantially contracted.
40
Roadrunner, in which we have a 50% ownership interest, has contracted all of its westbound capacity through 2041.
Northern Border Pipeline, in which we have a 50% ownership interest, has contracted substantially all of its long-haul
transportation capacity through the fourth quarter 2020.
In June 2019, our subsidiary, Viking Gas Transmission Company, filed a proposed change in rates pursuant to Section 4 of the
Natural Gas Act with the FERC. In February 2020, all parties agreed to a settlement in principle and plan to present it to FERC
for approval. We do not expect the ultimate outcome to impact materially our results of operations.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted
for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds
used during construction, noncash compensation and other noncash items. We believe this non-GAAP financial measure is
useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial
performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare
financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net
income, earnings per share or any other measure of financial performance presented in accordance with GAAP. Additionally,
this calculation may not be comparable with similarly titled measures of other companies.
The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to
adjusted EBITDA for the periods indicated:
(Unaudited)
Reconciliation of net income to adjusted EBITDA
Net income
Add:
Interest expense, net of capitalized interest
Depreciation and amortization
Income taxes
Impairment charges
Noncash compensation expense
Equity AFUDC and other noncash items (a)
Adjusted EBITDA
Reconciliation of segment adjusted EBITDA to adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing
Natural Gas Liquids
Natural Gas Pipelines
Other (b)
Adjusted EBITDA
2019
Years Ended December 31,
2018
(Thousands of dollars)
$
$ 1,155,032
2017
593,519
$ 1,278,577
491,773
476,535
372,414
—
26,699
(65,811)
$ 2,580,187
469,620
428,557
362,903
—
37,954
(6,545)
$ 2,447,521
485,658
406,335
447,282
20,240
13,421
20,398
$ 1,986,853
$
702,650
1,465,765
408,816
2,956
$ 2,580,187
$
631,607
1,440,605
366,251
9,058
$ 2,447,521
$
518,472
1,154,939
339,818
(26,376)
$ 1,986,853
(a) - Year ended December 31, 2017, includes our April 2017 contribution to the Foundation of 20,000 shares of Series E Preferred Stock,
with an aggregate value of $20.0 million.
(b) - Year ended December 31, 2017, includes Merger Transaction costs of $30.0 million.
CONTINGENCIES
See Note N of the Notes to Consolidated Financial Statements in this Annual Report for a discussion of regulatory matters.
Other 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 these litigation matters 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 affect adversely our consolidated results of operations, financial position or
cash flows.
41
LIQUIDITY AND CAPITAL RESOURCES
General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our
$2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources
requirements. In addition, we expect cash outflows related to i) capital expenditures, ii) interest and repayment of debt
maturities and iii) dividends paid to shareholders. We expect our cash outflows related to capital expenditures to decrease in
2020 relative to 2019 due to our completed capital-growth projects. We expect dividends paid to continue to increase due to
earnings growth from capital projects and higher anticipated dividends per share, subject to declaration by our Board of
Directors.
We expect our sources of cash inflows to provide sufficient resources to finance our operations, capital expenditures and
quarterly cash dividends, including expected future dividend increases. Our $2.5 Billion Credit Agreement, which expires in
June 2024, provides significant liquidity to fund capital expenditures and repay existing indebtedness. We may access the
capital markets to issue debt or equity securities as we consider prudent to provide additional liquidity to refinance existing
debt, improve credit metrics or to fund capital expenditures. Although we expect to continue to fund capital projects primarily
with cash from operations, short-term borrowings and long-term debt, we continue to have access to $550 million available
through our “at-the-market” equity program and the ability to issue equity and other securities under our universal shelf
registration statement.
We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. For additional
information on our interest-rate swaps, see Note C of the Notes to Consolidated Financial Statements in this Annual Report.
Cash Management - We use a centralized cash management program that concentrates the cash assets of our operating
subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction
costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our
operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our
consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC
regulations or their operating agreements. Under the cash management program, depending on whether a participating
subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash
to us.
Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities,
distributions received from our equity-method investments, proceeds from our commercial paper program and our $2.5 Billion
Credit Agreement. As of December 31, 2019, we were in compliance with all covenants of the $2.5 Billion Credit Agreement.
At December 31, 2019, we had no borrowings outstanding under our $2.5 Billion Credit Agreement, $220 million of
commercial paper outstanding and $21.0 million of cash and cash equivalents.
We had working capital (defined as current assets less current liabilities) deficits of $550.0 million and $709.8 million as of
December 31, 2019, and December 31, 2018, respectively. Although working capital is influenced by several factors,
including, among other things: (i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures,
(c) scheduled debt payments, and (d) the collection and payment of accounts receivable and payable; and (ii) the volume and
cost of inventory and commodity imbalances; our working capital deficit at December 31, 2019, was driven primarily by short-
term borrowings and accrued interest and at December 31, 2018, by current maturities of long-term debt. We may have
working capital deficits in future periods as we continue to finance our capital-growth projects and repay long-term debt, often
initially with short-term borrowings. Our decision to utilize short-term borrowings rather than long-term debt was due to more
favorable interest rates. We do not expect this working capital deficit to affect adversely our cash flows or operations.
For additional information on our $2.5 Billion Credit Agreement and commercial paper program, see Note F of the Notes to
Consolidated Financial Statements in this Annual Report.
Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our
longer-term financing requirements by issuing long-term notes. Other options to obtain financing include, but are not limited
to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity
securities, asset securitization and the sale and lease-back of facilities.
Debt Issuances - In August 2019, we completed an underwritten public offering of $2.0 billion senior unsecured notes
consisting of $500 million, 2.75% senior notes due 2024; $750 million, 3.4% senior notes due 2029; and $750 million, 4.45%
senior notes due 2049. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were
42
$1.97 billion. The proceeds were used for general corporate purposes, including repayment of existing indebtedness and
funding capital expenditures.
In March 2019, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of
$700 million, 4.35% senior notes due 2029 and an additional issuance of $550 million of our existing 5.2% senior notes due
2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued
interest, were $1.23 billion. The proceeds were used for general corporate purposes, including repayment of existing
indebtedness and funding capital expenditures.
In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which was fully drawn
as of June 30, 2019. We repaid $250 million of our outstanding balance in August 2019 and have $1.25 billion drawn as of
December 31, 2019. Our $1.5 Billion Term Loan Agreement matures in November 2021 and bears interest at LIBOR plus
112.5 basis points based on our current credit ratings. The agreement contains substantially the same covenants as those
contained in our $2.5 Billion Credit Agreement. The proceeds were used for general corporate purposes, including repayment
of existing indebtedness and funding capital expenditures.
Debt Repayments - In September 2019, we redeemed our $300 million, 3.8% senior notes due March 2020 at a redemption
price of $308.0 million, including the outstanding principal, plus accrued and unpaid interest, with cash on hand from our
public offering of $2.0 billion senior unsecured notes in August 2019.
In August 2019, we repaid $250 million of our $1.5 Billion Term Loan agreement with cash on hand.
In March 2019, we repaid our $500 million, 8.625% senior notes at maturity with a combination of cash on hand and short-
term borrowings.
For additional information on our long-term debt, see Note F of the Notes to Consolidated Financial Statements in this Annual
Report.
Capital Expenditures - We classify expenditures that are expected to generate additional revenue, return on investment or
significant operating efficiencies as capital-growth expenditures. Maintenance capital expenditures are those capital
expenditures required to maintain our existing assets and operations and do not generate additional revenues. Maintenance
capital expenditures are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our
assets and to extend their useful lives. Our capital expenditures are financed typically through operating cash flows and short-
and long-term debt.
The following table sets forth our growth and maintenance capital expenditures, excluding AFUDC and capitalized interest, for
the periods indicated:
Capital Expenditures
Natural Gas Gathering and Processing
Natural Gas Liquids
Natural Gas Pipelines
Other
Total capital expenditures
2019
2018
(Millions of dollars)
2017
$
$
926.5
2,796.6
99.2
26.0
3,848.3
$
$
694.6
1,306.3
119.2
21.4
2,141.5
$
$
284.2
114.3
95.6
18.3
512.4
Capital expenditures increased in 2019, compared with 2018, due primarily to capital-growth projects in progress. We expect
our 2020 capital expenditures to decrease relative to 2019 due to our completed capital-growth projects. See discussion of our
announced capital-growth projects in the “Recent Developments” section.
The following table summarizes our 2020 projected growth and maintenance capital expenditures, excluding AFUDC and
capitalized interest:
2020 Projected Capital Expenditures
Growth
Maintenance
Total projected capital expenditures
43
(Millions of dollars)
$2,250-$2,730
$200-$220
$2,450-$2,950
Credit Ratings - Our long-term debt credit ratings as of February 18, 2020, are shown in the table below:
Rating Agency
Moody’s
S&P
Long-Term Rating
Baa3
BBB
Short-Term Rating
Prime-3
A-2
Outlook
Positive
Stable
Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event
affecting our business and industry. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA
ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds
under our $2.5 Billion Credit Agreement and our $1.5 Billion Term Loan Agreement would increase and a potential loss of
access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial
paper program and there has not been a material adverse change in our business, we would continue to have access to our
$2.5 Billion Credit Agreement, which expires in 2024. An adverse credit rating change alone is not a default under our
$2.5 Billion Credit Agreement or our $1.5 Billion Term Loan Agreement. We do not expect a downgrade in our credit rating to
have a material impact on our results of operations.
In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade
in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to
provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to
conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash,
letters of credit or other negotiable instruments.
Dividends - Holders of our common stock share equally in any common stock dividends declared by our Board of Directors,
subject to the rights of the holders of outstanding preferred stock. In 2019, we paid dividends of $3.53 per share, an increase of
9% compared with the prior year. In February 2020, we paid a quarterly dividend of $0.935 per share ($3.74 per share on an
annualized basis), an increase of 9% compared with the same quarter in the prior year.
Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by
our Board of Directors, at a rate of 5.5% per year. In 2019, we paid dividends of $1.1 million for the Series E Preferred Stock.
In February 2020, we paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock.
For the years ended December 31, 2019 and 2018, cash flows from operations exceeded cash dividends paid by $489.2 million
and $851.7 million, respectively. We expect our cash flows from operations to continue to sufficiently fund our cash dividends.
To the extent operating cash flows are not sufficient to fund our dividends, we may utilize short- and long-term debt and
issuances of equity, as necessary or appropriate.
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 affect net income but do not
result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These
reconciling items include depreciation and amortization, impairment charges, allowance for equity funds used during
construction, gain or loss on sale of assets, deferred income taxes, net undistributed earnings from equity-method investments,
share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or
financing activities.
44
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
2019
Years Ended December 31,
2018
(Millions of dollars)
2017
$
$
1,946.8
(3,768.8)
1,831.0
9.0
12.0
21.0
$
$
2,186.7
(2,114.9)
(97.0)
(25.2)
37.2
12.0
$
$
1,315.4
(567.6)
(959.5)
(211.7)
248.9
37.2
Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our
operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of
general economic conditions, changes in supply, changes in demand for the end products that are made with our products or
increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash
flows can also be impacted by changes in our natural gas and NGL inventory balances, which are driven primarily by
commodity prices, supply, demand and the operation of our assets.
2019 vs. 2018 - Cash flows from operating activities, before changes in operating assets and liabilities, increased $130.4
million due primarily to higher earnings resulting from volume growth in the Rocky Mountain region, STACK and SCOOP
areas and the Permian Basin in our Natural Gas Liquids segment and the Williston Basin and STACK and SCOOP areas in our
Natural Gas Gathering and Processing segment, as discussed in “Financial Results and Operating Information.”
The changes in operating assets and liabilities decreased operating cash flows $163.9 million for 2019, compared with an
increase of $206.4 million for 2018. This change is due primarily to the change in the fair value of our risk-management assets
and liabilities; the change in accounts receivable, accounts payable, and other accruals and deferrals resulting from the timing
of receipt of cash from customers and payments to vendors, suppliers and other third parties; and the change in natural gas and
NGLs in storage, which vary both from period to period and with the changes in commodity prices.
Investing Cash Flows
2019 vs. 2018 - Cash used in investing activities increased $1.7 billion due primarily to increased capital expenditures related
to our capital-growth projects.
Financing Cash Flows
2019 vs. 2018 - Cash from financing activities increased $1.9 billion due primarily to issuances of $3.25 billion in senior
unsecured notes, the $700 million net draw on our $1.5 Billion Term Loan Agreement and an increase in proceeds from short-
term borrowings, offset partially by a decrease due to issuances of common stock in 2018.
Cash Flow Analysis for the Year Ended December 31, 2018 vs. 2017 - The cash flow analysis for the year ended
December 31, 2018, compared with the year ended December 31, 2017, is included in Part II, Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations of our 2018 Annual Report on Form 10-K, which is
available via the SEC’s website at www.sec.gov and our website at www.oneok.com.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of new accounting standards is included in Note A 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
45
Financial Statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the
reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our
estimates.
The following is a summary of our most critical accounting policies, which are defined as those estimates and policies most
important to the portrayal of our financial condition and results of operations and requiring management’s most difficult,
subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently
uncertain matters. We have discussed the development and selection of our estimates and critical accounting policies with the
Audit Committee of our Board of Directors.
Derivatives and Risk-management Activities - We utilize derivatives to reduce our market-risk exposure to commodity price
and interest-rate fluctuations and to achieve more predictable cash flows. Our commodity price risk includes basis risk, which
is the difference in price between various locations where commodities are purchased and sold. We record all derivative
instruments at fair value, except for normal purchases and normal sales transactions that are expected to result in physical
delivery. Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists.
Our fair value measurements classified as Level 3 are composed predominantly of exchange-cleared and over-the-counter
derivatives to hedge NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry
Hub. These measurements are based on inputs that may include one or more unobservable inputs, including internally
developed commodity price curves, that incorporate market data from broker quotes and third-party pricing services. Our
commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated
with other market data. We believe any measurement uncertainty at December 31, 2019, is immaterial as our Level 3 fair value
measurements are based on unadjusted pricing information from broker quotes and third-party pricing services.
The accounting for changes in the fair value of a derivative instrument depends on whether it qualifies and has been designated
as part of a hedging relationship. When possible, we implement effective hedging strategies using derivative financial
instruments that qualify as hedges for accounting purposes. We have not used derivative instruments for trading purposes. For
a derivative designated as a cash flow hedge, the gain or loss from a change in fair value of the derivative instrument is
deferred in accumulated other comprehensive income (loss) until the forecasted transaction affects earnings, at which time the
fair value of the derivative instrument is reclassified into earnings.
We assess the effectiveness of hedging relationships at the inception of the hedge by performing an effectiveness test to
determine whether they are highly effective. We subsequently assess qualitative factors. We do not believe that changes in our
fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our
derivatives are accounted for as effective cash flow hedges. However, if a derivative instrument is ineligible for cash flow
hedge accounting or if we fail to appropriately designate it as a cash flow hedge, changes in fair value of the derivative
instrument would be recorded currently in earnings. Additionally, if a cash flow hedge ceases to qualify for hedge accounting
treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative
instrument would be recognized in earnings. For more information on commodity price sensitivity and a discussion of the
market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.
See Notes A, B and C of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of fair
value measurements and derivatives and risk-management activities.
Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill for impairment at
least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time.
As part of our goodwill impairment test, we may 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
the fair value of each of our reporting units is less than its carrying amount. If further testing is necessary or a quantitative test
is elected, we perform a two-step impairment test for goodwill.
Update - Upon adoption of ASU 2017-04 in January 2020, the requirement to calculate the implied fair value of goodwill under
the two-step impairment test was eliminated. See Note A of the Notes to Consolidated Financial Statements in this Annual
Report for more information.
Our qualitative goodwill impairment analysis performed as of July 1, 2019, did not result in an impairment charge nor did our
analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair
value of each of our reporting units is less than the carrying value of its net assets.
46
The following table sets forth our goodwill, by segment, for the periods indicated:
Natural Gas Gathering and Processing
Natural Gas Liquids
Natural Gas Pipelines
Total goodwill
December 31,
December 31,
2018
2019
(Thousands of dollars)
$
$
153,404
371,217
156,375
680,996
$
$
153,404
371,217
156,479
681,100
We assess our long-lived assets, including intangible assets with finite useful lives, 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.
For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity
investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore,
we periodically evaluate the amount at which we carry our equity-method investments to determine whether current events or
circumstances warrant adjustments to our carrying value.
Impairment Charges - We recorded $20.2 million of noncash impairment charges in 2017 related to certain nonstrategic long-
lived assets and equity investments in North Dakota and Oklahoma.
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 Notes A, D, E and M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of
goodwill, long-lived assets and investments in unconsolidated affiliates.
Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment - Our property, plant and equipment
are depreciated using the straight-line method that incorporates management assumptions regarding useful economic lives and
residual values. As we continue to increase capital spending and place additional assets in service, our estimates related to
depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material
effect on our results of operations. At the time we place our assets in service, we believe such assumptions are reasonable;
however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation
expense prospectively. Examples of such circumstances include changes in (i) competition, (ii) laws and regulations that limit
the estimated economic life of an asset, (iii) technology that render an asset obsolete, (iv) expected salvage values and
(v) forecasts of the remaining economic life for the resource basins where our assets are located, if any.
See Note D of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of property, plant
and equipment.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and
environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered, and an amount can be reasonably estimated. We expense legal fees as incurred
and base our legal liability estimates on currently available facts and our assessments of the ultimate outcome or resolution.
Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion
of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets
when their receipt is deemed probable. Our expenditures for environmental evaluation, mitigation, remediation and
compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures
related to environmental matters had no material effect on earnings or cash flows during 2019, 2018 or 2017. Actual results
may differ from our estimates resulting in an impact, positive or negative, on our results of operations.
See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.
47
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, leases and other long-term obligations as of
December 31, 2019. For additional discussion of the debt and lease agreements, see Notes F and O of the Notes to
Consolidated Financial Statements in this Annual Report.
Contractual Obligations
Total
2020
2021
2022
2023
2024
Thereafter
Payments Due by Period
(Millions of dollars)
Senior notes
$ 11,322.4
$
— $
— $
1,447.4
$
925.0
$
500.0
$
8,450.0
Commercial paper borrowings
$1.5 Billion Term Loan Agreement
Guardian Pipeline senior notes
Interest payments on debt
Operating leases
Finance lease
Firm transportation and storage contracts
Financial and physical derivatives
Employee benefit plans
Purchase commitments and other
220.0
1,250.0
21.3
8,754.2
19.6
39.6
398.4
188.1
81.8
312.7
220.0
—
7.7
610.2
2.5
4.5
61.6
168.0
14.1
54.1
—
1,250.0
7.7
601.2
2.1
4.5
48.1
20.1
14.6
53.9
—
—
5.9
—
—
—
—
—
—
—
—
—
530.8
487.2
442.5
6,082.3
2.0
4.5
40.1
—
13.1
53.2
1.9
4.5
36.4
—
14.5
50.8
1.9
4.5
34.3
—
13.8
37.8
9.2
17.1
177.9
—
11.7
62.9
Total
$ 22,608.1
$
1,142.7
$
2,002.2
$
2,097.0
$
1,520.3
$
1,034.8
$ 14,811.1
Senior notes, $1.5 Billion Term Loan Agreement and commercial paper borrowings - Represents the amount of principal due in
each period.
Interest payments on debt - Interest payments are calculated by multiplying long-term debt principal amount by the respective
coupon rates.
Operating leases - Our operating leases primarily include leases for certain buildings, warehouses, office space, pipeline
capacity, land and equipment, including pipeline equipment, rail cars and information technology equipment. As of
December 31, 2019, we entered into an additional operating lease that had not yet commenced with total lease payments of
$87.8 million over a lease term of 10 years, which is excluded from our table above.
Finance lease - We lease certain compression facilities under a finance lease that has a fixed-price purchase option in 2028.
Firm transportation and storage contracts - Our Natural Gas Gathering and Processing and Natural Gas Liquids segments are
party to fixed-price contracts for firm transportation and storage capacity.
Financial and physical derivatives - These are obligations arising from our fixed- and variable-price purchase commitments for
physical and financial commodity derivatives. Estimated future variable-price purchase commitments are based on market
information at December 31, 2019. Actual future variable-price purchase obligations may vary depending on market prices at
the time of delivery. Sales of the related physical volumes and net positive settlements of financial derivatives are not reflected
in the table above.
Employee benefit plans - We contributed $12.1 million to our defined benefit pension plan in January 2020 and expect to make
$2.0 million in contributions to our other postretirement plans in 2020. See Note K of the Notes to Consolidated Financial
Statements in this Annual Report for discussion of our employee benefit plans.
Purchase commitments and other - Purchase commitments include commitments related to our growth capital expenditures and
other contractual commitments. Purchase commitments exclude commodity purchase contracts, which are included in the
“Financial and physical derivatives” amounts.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Annual Report are forward-looking statements as defined under
federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected
operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s
plans and objectives for our future capital-growth projects and other future operations (including plans to construct additional
48
natural gas and NGL pipelines, processing and fractionation facilities and related cost estimates), 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 federal securities legislation and other applicable laws. 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,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,”
“may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” ‘would,” and other words and terms
of similar meaning.
One should not place undue reliance on forward-looking statements. 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:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude
oil; producers’ desire and ability to drill and obtain necessary permits; regulatory compliance; reserve performance;
and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our
facilities;
risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including
production declines that outpace new drilling or extended periods of ethane rejection;
competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of
energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and
biodiesel;
demand for our services and products in the proximity of our facilities;
the ability to market pipeline capacity on favorable terms, including the effects of:
– future demand for and prices of natural gas, NGLs and crude oil;
– competitive conditions in the overall energy market;
– availability of supplies of United States natural gas and crude oil; and
– availability of additional storage capacity;
the effects of weather and other natural phenomena, including climate change, on our operations, demand for our
services and energy prices;
acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’, customers’
or shippers’ facilities;
the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or
changes in the political conditions throughout the world;
economic climate and growth in the geographic areas in which we do business;
the timing and extent of changes in energy commodity prices;
the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and
other projects and required regulatory clearances;
our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all
necessary materials and supplies required for construction, and to construct gathering, processing, storage,
fractionation and transportation facilities without labor or contractor problems;
the profitability of assets or businesses acquired or constructed by us;
the risk of a slowdown in growth or decline in the United States or international economies, including liquidity risks in
United States or foreign credit markets;
risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial
condition of our counterparties;
the uncertainty of estimates, including accruals and costs of environmental remediation;
changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns
about climate change;
the impact of uncontracted capacity in our assets being greater or less than expected;
the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our
pipelines;
the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
49
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
our ability to control construction costs and completion schedules of our pipelines and other projects;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and
other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of
natural gas and natural gas transportation costs;
the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment
and regulatory assets in our state and FERC-regulated rates;
the results of administrative proceedings and litigation, regulatory actions, executive orders, rule changes and receipt
of expected clearances involving any local, state or federal regulatory body, including the FERC, the National
Transportation Safety Board, the PHMSA, the EPA and the CFTC;
difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or
pipelines;
the capital-intensive nature of our businesses;
the mechanical integrity of facilities operated;
risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any
such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such
acquisitions and dispositions;
the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could
emerge or that minor problems could become significant;
the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and
other external factors over which we have no control, including the effect on pension and postretirement expense and
funding resulting from changes in equity and bond market returns;
our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry
conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with
our competitors that have less debt or have other adverse consequences;
actions by rating agencies concerning our credit;
our ability to access capital at competitive rates or on terms acceptable to us;
the impact and outcome of pending and future litigation;
performance of contractual obligations by our customers, service providers, contractors and shippers;
our ability to control operating costs and make cost-saving changes;
the impact of recently issued and future accounting updates and other changes in accounting policies;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
the risk inherent in the use of information systems in our respective businesses and those of our counterparties and
service providers, implementation of new software and hardware, and the impact on the timeliness of information for
financial reporting;
the impact of potential impairment charges; and
the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.
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 affect adversely our future results. These and
other risks are described in greater detail in Part I, Item 1A, Risk Factors, in this Annual Report and in our other filings that we
make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com. All
forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these
factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and 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 and represents an estimate of possible
changes in future earnings that could occur assuming hypothetical future movements in interest rates or commodity prices. Our
views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible
gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in
interest rates or commodity prices and the timing of transactions.
We are exposed to market risk due to commodity price and interest-rate volatility. Market risk is the risk of loss arising from
adverse changes in market rates and prices. We may use financial instruments, including forward sales, swaps, options and
futures, to manage the risks of certain identifiable or anticipated transactions and achieve more predictable cash flows. Our
risk-management function follows established policies and procedures to monitor our natural gas, condensate and NGL
50
marketing activities and interest rates to ensure our hedging activities mitigate market risks. We do not use financial
instruments for trading purposes.
See Note A of the Notes to Consolidated Financial Statements in this Annual Report for discussion on our accounting policies
for our derivative instruments and the impact on our Consolidated Financial Statements.
COMMODITY PRICE RISK
As part of our hedging strategy, we use commodity derivative financial instruments and physical-forward contracts described in
Note C of the Notes to Consolidated Financial Statements in this Annual Report to reduce the impact of near-term price
fluctuations of natural gas, NGLs and condensate.
Although our businesses are primarily fee-based, in our Natural Gas Gathering and Processing segment, we are exposed to
commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee
contracts. Under certain POP with fee contracts, our contractual fees and POP percentage may increase or decrease if
production volumes, delivery pressures or commodity prices change relative to specified thresholds. We are exposed to basis
risk between the various production and market locations where we buy and sell commodities.
The following tables set forth hedging information for our Natural Gas Gathering and Processing segment’s forecasted equity
volumes for the periods indicated:
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu
Condensate (MBbl/d) - WTI-NYMEX
Natural gas (BBtu/d) - NYMEX and basis
Natural gas (BBtu/d) - NYMEX and basis
Year Ending December 31, 2020
Volumes
Hedged
10.3
3.0
125.0
$
$
$
Average Price
0.55 / gallon
54.08 / Bbl
2.39 / MMBtu
Percentage
Hedged
63%
62%
76%
Year Ending December 31, 2021
Volumes
Hedged
Average Price
36.4
$
2.43 / MMBtu
Percentage
Hedged
19%
Our Natural Gas Gathering and Processing segment’s commodity price sensitivity is estimated as a hypothetical change in the
price of NGLs, crude oil and natural gas at December 31, 2019. Condensate sales are typically based on the price of crude oil.
Assuming normal operating conditions, we estimate the following for our forecasted equity volumes:
•
•
•
a $0.01 per gallon change in the composite price of NGLs, excluding ethane, would change adjusted EBITDA for the
years ending December 31, 2020 and 2021, by $2.5 million and $3.0 million, respectively;
a $1.00 per barrel change in the price of crude oil would change adjusted EBITDA for the years ending December 31,
2020 and 2021, by $1.5 million and $1.8 million, respectively; and
a $0.10 per MMBtu change in the price of residue natural gas would change adjusted EBITDA for the years ending
December 31, 2020 and 2021, by $6.1 million and $7.1 million, respectively.
These estimates do not include any effects of hedging or effects on demand for our services or natural gas processing plant
operations that might be caused by, or arise in conjunction with, commodity price fluctuations. For example, a change in the
gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering
and processing financial results for certain contracts.
INTEREST-RATE RISK
We are exposed to interest-rate risk through borrowings under our $2.5 Billion Credit Agreement, $1.5 Billion Term Loan
Agreement, commercial paper program and long-term debt issuances. Future increases in LIBOR or the established
replacement rate, commercial paper rates or bond rates could expose us to increased interest costs on future borrowings. We
manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are
agreements to exchange interest payments at some future point based on specified notional amounts. In 2019, we entered into
$625 million of forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of our forecasted
debt issuances that may result from changes in the benchmark interest rate before the debt is issued. We also settled $1.8
51
billion of our forward-starting interest-rate swaps related to our underwritten public offering of $1.25 billion senior unsecured
notes in March 2019 and $2.0 billion senior unsecured notes in August 2019.
At December 31, 2019 and 2018, we had forward-starting interest-rate swaps with notional amounts totaling $1.8 billion and
$3.0 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At
December 31, 2019 and 2018, we had interest-rate swaps with notional amounts totaling $1.3 billion to hedge the variability of
our LIBOR-based interest payments. All of our interest-rate swaps are designated as cash flow hedges. At December 31, 2019,
we had derivative assets of $0.6 million and derivative liabilities of $201.9 million related to these interest-rate swaps. At
December 31, 2018, we had derivative assets of $19.0 million and derivative liabilities of $99.3 million related to these
interest-rate swaps.
See Note C of the Notes to Consolidated Financial Statements in this Annual Report for more information on our hedging
activities.
COUNTERPARTY CREDIT RISK
We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other
forms of collateral, when appropriate. Certain of our counterparties may be impacted by a relatively low commodity price
environment and could experience financial problems, which could result in nonpayment and/or nonperformance, which could
impact adversely our results of operations.
Customer concentration - In 2019, no single customer represented more than 10% of our consolidated revenues.
Natural Gas Gathering and Processing - Our Natural Gas Gathering and Processing segment derives services revenue
primarily from major and independent crude oil and natural gas producers, which include both large integrated and independent
exploration and production companies. In this segment, our downstream commodity sales customers are primarily utilities,
large industrial companies, marketing companies and our NGL affiliate. We are not typically exposed to material credit risk
with producers under POP with fee contracts as we sell the commodities and remit a portion of the sales proceeds back to the
producer less our contractual fees. In 2019 and 2018, approximately 90% and 95%, respectively, of the downstream
commodity sales in our Natural Gas Gathering and Processing segment were made to investment-grade customers, as rated by
S&P, Moody’s or our comparable internal ratings, or were secured by letters of credit or other collateral.
Natural Gas Liquids - Our Natural Gas Liquids segment’s counterparties are primarily NGL and natural gas gathering and
processing companies; major and independent crude oil and natural gas production companies; utilities; large industrial
companies; natural gasoline distributors; propane distributors; municipalities; and petrochemical, refining and marketing
companies. We charge fees to NGL and natural gas gathering and processing counterparties and NGL pipeline transportation
customers. We are not typically exposed to material credit risk on the majority of our exchange services fees, as we purchase
NGLs from our gathering and processing counterparties and deduct our fee from the amounts we remit. We also earn sales
revenue on the downstream sales of NGL products. In 2019 and 2018, approximately 80% of this segment’s commodity sales
were made to investment-grade customers, as rated by S&P, Moody’s or our comparable internal ratings, or were secured by
letters of credit or other collateral. In addition, the majority of our Natural Gas Liquids segment’s pipeline tariffs provide us the
ability to require security from shippers.
Natural Gas Pipelines - Our Natural Gas Pipelines segment’s customers are primarily local natural gas distribution companies,
electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies. In
2019 and 2018, approximately 85% of our revenues in this segment were from investment-grade customers, as rated by S&P,
Moody’s or our comparable internal ratings, or were secured by letters of credit or other collateral. In addition, the majority of
our Natural Gas Pipelines segment’s pipeline tariffs provide us the ability to require security from shippers.
52
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53
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of ONEOK, Inc.:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of ONEOK, Inc. and its subsidiaries (the “Company”) as of
December 31, 2019 and 2018, and the related consolidated statements of income, of comprehensive income, of changes in
equity and of 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).
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.
Change in Accounting Principle
As discussed in Notes A and P to the consolidated financial statements, the Company changed the manner in which it accounts
for revenue from contracts with customers in 2018.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal
control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included
in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to
express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial
reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight
Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material
respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement
of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
54
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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.
Valuation of Level 3 Commodity Derivative Assets and Liabilities
As described in Notes A, B and C to the consolidated financial statements, the Company’s level 3 commodity derivative assets
and liabilities total $55.6 million and $24.8 million, respectively, as of December 31, 2019. As disclosed by management,
commodity price risk includes basis risk, which is the difference in price between various locations where commodities are
purchased and sold. Management records all derivative instruments at fair value, except for normal purchases and normal sales
transactions that are expected to result in physical delivery. Many of the contracts in its derivative portfolio are executed in
liquid markets where price transparency exists. Fair value measurements classified as Level 3 are comprised predominantly of
exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk between various
transaction locations and the NYMEX Henry Hub. These measurements are based on inputs that may include one or more
unobservable inputs, including internally developed commodity price curves, that incorporate market data from broker quotes
and third-party pricing services. The commodity derivatives are generally valued using forward quotes provided by third-party
pricing services that are validated with other market data.
The principal considerations for our determination that performing procedures relating to the valuation of level 3 commodity
derivative assets and liabilities is a critical audit matter are there was significant estimation by management to determine the
fair value of these derivatives due to the use of internally developed commodity price curves, that incorporate market data from
broker quotes and third-party pricing services. This in turn led to a high degree of subjectivity and effort in evaluating audit
evidence related to the valuation. In addition, the audit effort involved the use of professionals with specialized skill and
knowledge to assist in performing these procedures and evaluating the audit evidence obtained.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall
opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the
valuation of level 3 commodity derivative assets and liabilities, including controls over the Company’s model, significant
assumptions, and data. These procedures also included, among others, the involvement of professionals with specialized skill
and knowledge to assist in developing an independent estimate of the level 3 commodity derivative assets and liabilities and
comparison of the independent estimate to management’s estimate. Developing the independent estimate involved testing the
completeness and accuracy of data used and evaluating management’s assumptions related to the internally developed
commodity price curves.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 25, 2020
We have served as the Company’s auditor since 2007.
55
Years Ended December 31,
2018
(Thousands of dollars, except per share amounts)
2017
2019
$
$
$
$
8,916,047
1,248,320
10,164,367
6,788,040
863,708
476,535
—
119,156
2,575
1,914,353
154,541
—
64,815
27,058
(18,003)
(491,773)
1,650,991
(372,414)
1,278,577
—
1,278,577
1,100
1,277,477
3.09
3.07
$ 11,395,642
1,197,554
12,593,196
9,422,708
803,146
428,557
—
103,922
(601)
1,835,464
158,383
—
7,962
674
(14,928)
(469,620)
1,517,935
(362,903)
1,155,032
3,329
1,151,703
1,100
1,150,603
2.80
2.78
$
$
$
$
$
$
$
9,862,652
2,311,255
12,173,907
9,538,045
724,314
406,335
15,970
98,396
(924)
1,391,771
159,278
(4,270)
107
15,385
(35,812)
(485,658)
1,040,801
(447,282)
593,519
205,678
387,841
767
387,074
1.30
1.29
413,560
415,444
411,485
414,195
297,477
299,780
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
Revenues
Commodity sales
Services
Total revenues (Note P)
Cost of sales and fuel (exclusive of items shown separately below)
Operations and maintenance
Depreciation and amortization
Impairment of long-lived assets (Note D)
General taxes
(Gain) loss on sale of assets
Operating income
Equity in net earnings from investments (Note M)
Impairment of equity investments (Note M)
Allowance for equity funds used during construction
Other income
Other expense
Interest expense (net of capitalized interest of $107,275, $28,062 and $5,510,
respectively)
Income before income taxes
Income taxes (Note L)
Net income
Less: Net income attributable to noncontrolling interests
Net income attributable to ONEOK
Less: Preferred stock dividends
Net income available to common shareholders
Basic earnings per common share (Note I)
Diluted earnings per common share (Note I)
Average shares (thousands)
Basic
Diluted
See accompanying Notes to Consolidated Financial Statements.
56
Years Ended December 31,
2018
(Thousands of dollars)
$
1,155,032
$
2017
593,519
1,278,577
(147,803)
(5,673)
(21,408)
(21,057)
36,870
63,687
(9,696)
4,771
(4,175)
(7,205)
(185,761)
1,092,816
—
1,092,816
$
2,424
38,392
1,193,424
3,329
1,190,095
$
(970)
37,134
630,653
236,704
393,949
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
2019
Net income
Other comprehensive income (loss), net of tax
Change in fair value of derivatives, net of tax of $44,149, $1,694 and $19,006,
respectively
Derivative amounts reclassified to net income, net of tax of $6,058, $(11,013) and
$(26,899), respectively
Change in retirement and other postretirement benefit plan obligations, net of tax of
$2,910, $(1,425) and $(878), respectively
Other comprehensive income (loss) of unconsolidated affiliates, net of tax of $2,152,
$(724) and $145, respectively
Total other comprehensive income (loss), net of tax
Comprehensive income
Less: Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to ONEOK
See accompanying Notes to Consolidated Financial Statements.
$
$
57
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Natural gas and NGLs in storage
Commodity imbalances
Other current assets
Total current assets
Property, plant and equipment
Property, plant and equipment
Accumulated depreciation and amortization
Net property, plant and equipment (Note D)
Investments and other assets
Investments in unconsolidated affiliates (Note M)
Goodwill and intangible assets (Note E)
Other assets
Total investments and other assets
Total assets
December 31, December 31,
2019
2018
(Thousands of dollars)
$
$
20,958
835,121
201,749
304,926
25,267
82,313
1,470,334
11,975
818,958
141,174
296,667
29,050
100,808
1,398,632
22,051,492
3,702,807
18,348,685
18,030,963
3,264,312
14,766,651
861,844
957,833
173,425
1,993,102
21,812,121
969,150
967,142
130,096
2,066,388
18,231,671
$
$
58
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Continued)
Liabilities and equity
Current liabilities
Current maturities of long-term debt (Note F)
Short-term borrowings (Note F)
Accounts payable
Commodity imbalances
Accrued interest
Finance lease liability (Note O)
Other current liabilities
Total current liabilities
December 31, December 31,
2019
2018
(Thousands of dollars)
$
$
7,650
220,000
1,209,900
104,480
190,750
1,949
285,569
2,020,298
507,650
—
1,116,337
110,197
161,377
1,765
211,110
2,108,436
Long-term debt, excluding current maturities (Note F)
12,479,757
8,873,334
Deferred credits and other liabilities
Deferred income taxes (Note L)
Finance lease liability (Note O)
Other deferred credits
Total deferred credits and other liabilities
Commitments and contingencies (Note N)
Equity (Note G)
ONEOK shareholders’ equity:
Preferred stock, $0.01 par value:
authorized and issued 20,000 shares at December 31, 2019, and at December 31, 2018
Common stock, $0.01 par value:
authorized 1,200,000,000 shares; issued 445,016,234 shares and outstanding
413,239,050 shares at December 31, 2019; issued 445,016,234 shares and outstanding
411,532,606 shares at December 31, 2018
Paid-in capital
Accumulated other comprehensive loss (Note H)
Retained earnings
Treasury stock, at cost: 31,777,184 shares at December 31, 2019, and 33,483,628 shares at
December 31, 2018
Total equity
Total liabilities and equity
See accompanying Notes to Consolidated Financial Statements.
536,063
24,296
525,756
1,086,115
219,731
26,244
424,383
670,358
—
—
4,450
7,403,895
(374,000)
—
4,450
7,615,138
(188,239)
—
(808,394)
6,225,951
21,812,121
$
(851,806)
6,579,543
18,231,671
$
59
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60
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
1,278,577
$
1,155,032
$
593,519
2019
Years Ended December 31,
2018
(Thousands of dollars)
2017
Depreciation and amortization
Impairment charges
Noncash contribution of preferred stock, net of tax
Equity in net earnings from investments
Distributions received from unconsolidated affiliates
Deferred income taxes
Share-based compensation expense
Allowance for equity funds used during construction
Other, net
Changes in assets and liabilities:
Accounts receivable
Natural gas and NGLs in storage
Accounts payable
Commodity imbalances, net
Accrued interest
Risk-management assets and liabilities
Other assets and liabilities, net
Cash provided by operating activities
Investing activities
476,535
—
—
(154,541)
163,476
372,729
37,147
(64,815)
1,567
(19,688)
(8,259)
(62,946)
(1,934)
29,373
(86,268)
(14,174)
1,946,779
428,557
—
—
(158,383)
170,528
361,010
31,664
(7,962)
(132)
383,993
38,456
(320,132)
(44,302)
26,068
117,717
4,605
2,186,719
Capital expenditures (less allowance for equity funds used during construction)
Contributions to unconsolidated affiliates
(3,848,349)
(4,028)
(2,141,475)
(1,748)
Distributions received from unconsolidated affiliates in excess of cumulative
earnings
Other, net
Cash used in investing activities
94,168
(10,549)
(3,768,758)
26,757
1,578
(2,114,888)
Financing activities
Dividends paid
Distributions to noncontrolling interests
Borrowing (repayment) of short-term borrowings, net
Issuance of long-term debt, net of discounts
Debt financing costs
Repayment of long-term debt
Issuance of common stock
Acquisition of noncontrolling interests
Other, net
Cash provided by (used in) financing activities
Change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized
Cash paid for income taxes, net of refunds
See accompanying Notes to Consolidated Financial Statements.
61
(1,457,628)
—
220,000
4,185,435
(29,747)
(1,057,348)
29,040
—
(58,790)
1,830,962
8,983
11,975
20,958
435,165
2,690
$
$
$
(1,335,058)
(3,500)
(614,673)
1,795,773
(13,441)
(932,650)
1,203,981
(195,000)
(2,481)
(97,049)
(25,218)
37,193
11,975
418,244
2,225
$
$
$
$
$
$
406,335
20,240
12,600
(159,278)
167,372
437,917
26,262
(107)
3,155
(330,521)
(202,259)
261,305
43,699
22,795
37,617
(25,239)
1,315,412
(512,393)
(87,861)
28,742
3,879
(567,633)
(829,414)
(276,260)
(495,604)
1,190,496
(11,425)
(994,776)
471,358
—
(13,836)
(959,461)
(211,682)
248,875
37,193
432,210
6,633
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
ONEOK Shareholders’ Equity
January 1, 2017
Cumulative effect adjustment for adoption of
ASU 2016-09 (a)
Net income
Other comprehensive income (loss)
Preferred stock issued
Preferred stock dividends - $38.35 per share
(Note G)
Common stock issued
Common stock dividends - $2.72 per share
(Note G)
Distributions to noncontrolling interests
Acquisition of noncontrolling interests (Note G)
Other, net
December 31, 2017
Cumulative effect adjustment for adoption of
ASUs (b)
Net income
Other comprehensive income (loss) (Note H)
Preferred stock dividends - $55.00 per share
(Note G)
Common stock issued
Common stock dividends - $3.245 per share
(Note G)
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Acquisition of noncontrolling interests (Note G)
Other, net
December 31, 2018
Cumulative effect adjustment for adoption of
ASU 2016-02 (Note A)
Net income
Other comprehensive income (loss) (Note H)
Preferred stock dividends - $55.00 per share
(Note G)
Common stock issued
Common stock dividends - $3.53 per share
(Note G)
Other, net
December 31, 2019
Common
Stock Issued
Preferred
Stock Issued
Common
Stock
Preferred
Stock
(Thousands of dollars)
— $
$
2,458
(Shares)
245,811,180
— $
—
—
—
—
—
8,434,223
—
—
168,920,831
—
423,166,234
—
—
—
—
21,850,000
—
—
—
—
—
445,016,234
—
—
—
—
—
—
—
—
20,000
—
—
—
—
—
20,000
—
—
—
—
—
—
—
—
—
—
20,000
—
—
—
—
—
Paid-in
Capital
1,234,314
—
—
—
20,000
(767)
456,537
(367,578)
—
5,228,580
17,792
6,588,878
—
—
—
—
1,183,321
(144,805)
—
—
(21,220)
8,964
7,615,138
—
—
—
—
(7,667)
—
—
—
—
—
85
—
—
1,689
—
4,232
—
—
—
—
218
—
—
—
—
—
4,450
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
445,016,234
—
—
20,000
$
—
—
4,450
$
—
—
— $
(180,421)
(23,155)
7,403,895
62
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Continued)
ONEOK Shareholders’ Equity
Accumulated
Other
Comprehensive
Loss
Retained
Earnings
$
(154,350) $
Treasury
Stock
(Thousands of dollars)
(893,677) $
— $
Noncontrolling
Interests in
Consolidated
Subsidiaries
Total
Equity
—
—
6,108
—
—
—
—
—
(40,288)
—
(188,530)
(38,101)
—
38,392
—
—
—
—
—
—
—
(188,239)
—
—
(185,761)
73,368
387,841
—
—
—
—
(461,209)
—
—
—
—
39,803
1,151,703
—
(1,100)
—
(1,190,406)
—
—
—
—
—
(67)
1,278,577
—
—
—
—
—
—
16,964
—
—
—
—
(876,713)
—
—
—
—
24,907
—
—
—
—
—
(851,806)
—
—
—
—
—
(1,100)
—
—
43,412
3,240,170
$
3,428,915
—
205,678
31,026
—
—
—
—
(276,260)
(3,043,519)
390
157,485
17
3,329
—
—
—
—
(3,500)
16,449
(173,780)
—
—
—
—
—
—
—
73,368
593,519
37,134
20,000
(767)
473,586
(828,787)
(276,260)
2,146,462
18,182
5,685,352
1,719
1,155,032
38,392
(1,100)
1,208,446
(1,335,211)
(3,500)
16,449
(195,000)
8,964
6,579,543
(67)
1,278,577
(185,761)
(1,100)
35,745
January 1, 2017
Cumulative effect adjustment for adoption of
ASU 2016-09 (a)
Net income
Other comprehensive income (loss)
Preferred stock issued
Preferred stock dividends - $38.35 per share
(Note G)
Common stock issued
Common stock dividends - $2.72 per share
(Note G)
Distributions to noncontrolling interests
Acquisition of noncontrolling interests (Note G)
Other, net
December 31, 2017
Cumulative effect adjustment for adoption of
ASUs (b)
Net income
Other comprehensive income (loss) (Note H)
Preferred stock dividends - $55.00 per share
(Note G)
Common stock issued
Common stock dividends - $3.245 per share
(Note G)
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Acquisition of noncontrolling interests (Note G)
Other, net
December 31, 2018
Cumulative effect adjustment for adoption of
ASU 2016-02 (Note A)
Net income
Other comprehensive income (loss) (Note H)
Preferred stock dividends - $55.00 per share
(Note G)
Common stock issued
Common stock dividends - $3.53 per share
(Note G)
Other, net
December 31, 2019
—
—
(374,000) $
(1,277,410)
—
— $
—
—
(808,394) $
$
—
—
— $
(1,457,831)
(23,155)
6,225,951
(a) - Includes adjustment increasing beginning retained earnings in the first quarter 2017 of $73.4 million to recognize previously
unrecognized cumulative excess tax benefits related to share-based payments on a modified retrospective basis.
(b) - Includes cumulative effect for adoption of the following: ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”;
ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities”; and ASU 2018-02,
“Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other
Comprehensive Income.”
See accompanying Notes to Consolidated Financial Statements.
63
ONEOK, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations - We are a corporation incorporated under the laws of the state of Oklahoma.
Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota, Montana,
Wyoming, Kansas and Oklahoma. Raw natural gas is typically gathered at the wellhead, compressed and transported through
pipelines to our processing facilities. Processed natural gas, usually referred to as residue natural gas, is then recompressed and
delivered to natural gas pipelines, storage facilities and end users. The NGLs separated from the raw natural gas are delivered
through NGL pipelines to fractionation facilities for further processing.
Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL
products, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston,
Powder River and DJ Basins. We provide midstream services to producers of NGLs and deliver those products to the two
primary market centers, one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas.
The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas
Panhandle are connected to our NGL gathering systems. We own or have an ownership interest in FERC-regulated NGL
gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and
Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated NGL
distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect
our Mid-Continent assets with Midwest markets, including Chicago, Illinois.
Our Natural Gas Pipelines segment provides interstate and intrastate transportation and storage services to end users through its
wholly owned assets and its 50% ownership interests in Northern Border Pipeline and Roadrunner. Our interstate pipelines are
regulated by the FERC and are located in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee,
Oklahoma, Texas and New Mexico. Our intrastate natural gas pipeline and storage assets are located in Oklahoma, Kansas and
Texas. Our assets connect major natural gas producing basins and market hubs with end-use customers.
Consolidation - Our Consolidated Financial Statements include our accounts and the accounts of our subsidiaries over which
we have control or are the primary beneficiary. All intercompany balances and transactions have been eliminated in
consolidation.
Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant
influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition
cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive
income. For the investments we account for under the equity method, the premium or excess cost over underlying fair value of
net assets is referred to as equity-method goodwill. Impairment of equity investments is recorded when the impairments are
other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying
Consolidated Balance Sheets. See Note M for disclosures of our unconsolidated affiliates.
Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements
of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate
since the date of our initial investment. The amount of cumulative distributions paid to us that exceeds our cumulative
proportionate share of income in each period represents a return of investment and is classified as an investing activity on our
Consolidated Statements of Cash Flows.
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 amounts on our Consolidated Financial Statements. Items that may be estimated include, but are not limited
to, the economic useful life of assets, fair value of assets, liabilities and equity-method investments, obligations under employee
benefit plans, provisions for uncollectible accounts receivable, expenses for services received but for which no invoice has been
received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other
recorded or disclosed amounts. In addition, a portion of our revenues and cost of sales and fuel are recorded based on current
month prices and estimated volumes. The estimates are reversed in the following month and recorded with actual volumes and
prices.
64
We evaluate our estimates on an ongoing basis using historical experience, consultation with experts and other methods we
consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the
estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the
period when the facts that give rise to the revision become known.
Fair Value Measurements - For our fair value measurements, we utilize market prices, third-party pricing services, present
value methods and standard option valuation models to determine the price we would receive from the sale of an asset or the
transfer of a liability in an orderly transaction at the measurement date. 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.
Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists. Our financial
commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing broker account
with daily margin requirements. We validate our valuation inputs with third-party information and settlement prices from other
sources, where available.
We compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets
and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from the implied
forward LIBOR yield curve. The fair value of our forward-starting interest-rate swaps are determined using financial models
that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements. We
consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using
counterparty-specific bond yields. Although we use our best estimates to determine the fair value of the derivative contracts we
have executed, the ultimate market prices realized could differ materially from our estimates.
Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or
disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the
hierarchy are described below:
• Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets.
These balances are composed predominantly of exchange-traded derivative contracts for natural gas and crude oil.
• Level 2 - fair value measurements are based on significant observable pricing inputs, including quoted prices for
similar assets and liabilities in active markets and inputs from third-party pricing services supported with
corroborative evidence. These balances are composed of over-the-counter interest-rate derivatives.
• Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including
internally developed commodity price curves that incorporate market data from broker quotes and third-party pricing
services. These balances are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge
NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry Hub. Our
commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are
validated with other market data. We believe any measurement uncertainty at December 31, 2019, is immaterial as
our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party
pricing services. We do not believe that our Level 3 fair value estimates have a material impact on our results of
operations, as our derivatives are accounted for as hedges.
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 B for our fair value measurements disclosures.
Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash
and have original maturities of three months or less.
Revenue Recognition - Revenues are recognized when control of the promised goods or services is transferred to our
customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or
services. Our payment terms vary by customer and contract type, including requiring payment before products or services are
delivered to certain customers. However, the term between customer prepayments, completion of our performance obligations,
invoicing and receipt of payment due is not significant.
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A significant portion of supply volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments are
under contracts that include the purchase of commodities. Therefore, upon adoption of Topic 606, the contractual fees we
charge on these contracts are considered a reduction of the commodity purchase price in cost of sales and fuel. In 2017 and
prior periods, we recorded these fees as services revenue. See “Cost of Sales and Fuel” below for a description of these
arrangements.
Performance Obligations and Revenue Sources - Revenues sources are disaggregated in Note Q and are derived from
commodity sales and services revenues, as described below:
Commodity Sales (all segments) - We contract to deliver residue natural gas, condensate, unfractionated NGLs and/or NGL
products to customers at a specified delivery point. Our sales agreements may be daily or longer-term contracts for a specified
volume. We consider the sale and delivery of each unit of a commodity an individual performance obligation as the customer
is expected to control, accept and benefit from each unit individually. We record revenue when the commodity is delivered to
the customer as this represents the point in time when control of the product is transferred to the customer. Revenue is recorded
based on the contracted selling price, which is generally index-based and settled monthly.
Services
Gathering only contracts (Natural Gas Gathering and Processing segment) - Under this type of contract, we charge fees for
providing midstream services, which include gathering and treating our customer’s natural gas. Our performance obligation
begins with delivery of raw natural gas to our system. This service is treated as one performance obligation that is satisfied
over time. We use the output method based on delivery of product to our system as the measure of progress, as our services are
performed simultaneously.
POP with fee contracts with producer take-in-kind rights (Natural Gas Gathering and Processing segment) - Under this type of
contract, we do not control the stream of unprocessed natural gas that we receive at the wellhead due to the producer’s take-in-
kind rights. We purchase a portion of the raw natural gas stream, charge fees for providing midstream services, which include
gathering, treating, compressing and processing our customer’s natural gas. After performing these services, we return
primarily the residue natural gas to the producer, sell the remaining commodities and remit a portion of the commodity sales
proceeds to the producer less our contractual fees. Our performance obligation begins with delivery of raw natural gas to our
system. This service is treated as one performance obligation that is satisfied over time. We use the output method based on
delivery of product to our system as the measure of progress, as our services are performed simultaneously.
Transportation and exchange contracts (Natural Gas Liquids segment) - Under this type of contract, we charge fees for
providing midstream services, which may include a bundled combination of gathering, transporting and/or fractionation of our
customer’s NGLs. Our performance obligation begins with delivery of unfractionated NGLs or NGL products to our system.
These services represent a series of distinct services that are treated as one performance obligation that is satisfied over time.
We use the output method based on delivery of product to our system as the measure of progress, as our services are performed
simultaneously. For transportation services under a tariff on our NGL transportation pipelines, fees are recorded upon
redelivery to our customer at the completion of the transportation services.
Storage contracts (Natural Gas Liquids and Natural Gas Pipelines segments) - We reserve a stated storage capacity and inject/
withdraw/store commodities for our customer. The capacity reservation and injection/withdrawal/storage services are
considered a bundled service, as we integrate them into one stand-ready obligation provided on a daily basis over the life of the
agreement and satisfied over time. Fixed capacity reservation fees are allocated and evenly recognized in revenue. Capacity
reservation fees that vary based on a stated or implied economic index and correspond with the costs to provide our services are
recognized in revenue as invoiced to our customers. For contracts that do not include a capacity reservation, transportation,
injection and withdrawal fees are recognized in revenue as those services are provided and are dependent on the volume
transported, injected or withdrawn by our customer, which is at our customer’s discretion. We use the output method based on
the passage of time to measure satisfaction of the performance obligation associated with our daily stand-ready services.
Firm service transportation contracts (Natural Gas Pipelines segment) - We reserve a stated transportation capacity and
transport commodities for our customer. The capacity reservation and transportation services are considered a bundled service,
as we integrate them into one stand-ready obligation provided on a daily basis over the life of the agreement and satisfied over
time. Fixed capacity reservation fees are allocated and evenly recognized in revenue. Capacity reservation fees that vary based
on a stated or implied economic index and correspond with the costs to provide our services are recognized in revenue based on
a daily effective fee rate. If the capacity reservation fees vary solely as a contract feature, contract assets or liabilities are
recorded for the difference between the amount recorded in revenue and the amount billed to the customer. Transportation fees
are recognized in revenue as those services are provided and are dependent on the volume transported by our customer, which
66
is at our customer’s discretion. We use the output method based on the passage of time to measure satisfaction of the
performance obligation associated with our daily stand-ready services.
Interruptible transportation contracts (Natural Gas Pipelines segment) - We agree to transport natural gas on our pipelines
between the customer’s specified nomination and delivery points if capacity is available after satisfying firm transportation
service obligations. The transaction price is based on the transportation fees times the volumes transported. These fees may
change over time based on an index or other factors provided in the agreement. We use the output method based on delivery of
product to the customer to measure satisfaction of the performance obligation. The total consideration for delivered volumes is
recorded in revenue at the time of delivery, when the customer obtains control.
See Note P for our revenue disclosures.
Contract Assets and Contract Liabilities - Contract assets and contract liabilities are recorded when the amount of revenue
recognized from a contract with a customer differs from the amount billed to the customer and recorded in accounts receivable.
Our contract asset balances at the beginning and end of the period primarily relate to our firm service transportation contracts
with tiered rates. Our contract liabilities primarily represent deferred revenue on contributions in aid of construction received
from customers for which revenue is recognized over the contract periods, which range from 5 to 10 years, and deferred
revenue on NGL storage contracts for which revenue is recognized over a one-year term.
Cost of Sales and Fuel - Cost of sales and fuel primarily includes (i) the cost of purchased commodities, including NGLs,
natural gas and condensate, (ii) fees incurred for third-party transportation, fractionation and storage of commodities, (iii) fuel
and power costs incurred to operate our own facilities that gather, process, transport and store commodities, and (iv) an offset
from the contractual fees deducted from the cost of purchased commodities under the contract types below:
POP with fee contracts with no producer take-in-kind rights (Natural Gas Gathering and Processing segment) - We purchase
raw natural gas and charge contractual fees for providing midstream services, which include gathering, treating, compressing
and processing the producer’s natural gas. After performing these services, we sell the commodities and return a portion of the
commodity sales proceeds to the producer less our contractual fees.
Purchase with fee (Natural Gas Liquids segment) - Under this type of contract, we purchase raw, unfractionated NGLs at an
index price and charge fees for providing midstream services, which may include a bundled combination of gathering,
transporting and/or fractionation of our customer’s NGLs.
Operations and Maintenance - Operations and maintenance primarily includes (i) payroll and benefit costs, (ii) third-party
costs for operations, maintenance and integrity management, regulatory compliance and environmental and safety, and
(iii) other business related service costs.
Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services
rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis
and require security, including prepayments and other forms of collateral, when appropriate. Outstanding customer receivables
are reviewed regularly for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon
management’s estimate of collectability at each balance sheet date. At December 31, 2019 and 2018, our allowance for
doubtful accounts was not material.
Update - Upon adoption of ASU 2016-13 in January 2020, we are required to present accounts receivable net of an allowance
for credit losses to reflect the net amount expected to be collected. This assessment is based on historical information, current
conditions and supportable forecasts. See “Recently Issued Accounting Standards Update” table below for more information.
Inventory - The values of current natural gas and NGLs in storage are determined using the lower of weighted-average cost or
net realizable value. Noncurrent natural gas and NGLs are classified as property and valued at cost. Materials and supplies are
valued at average cost.
Commodity Imbalances - Commodity imbalances represent amounts payable or receivable for NGL exchange contracts and
natural gas pipeline imbalances and are valued at market prices. Under the majority of our NGL exchange agreements, we
physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the
exchange counterparty. In turn, we deliver NGL products back to the customer and charge them gathering, transportation and
fractionation fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a
net exchange receivable or payable position with the counterparties. These net exchange receivables and payables are generally
67
settled with movements of NGL products rather than with cash. Natural gas pipeline imbalances are settled in cash or in-kind,
subject to the terms of the pipelines’ tariffs or by agreement.
Derivatives and Risk Management - We utilize derivatives to reduce our market-risk exposure to commodity price and
interest-rate fluctuations and to achieve more predictable cash flows. We record all derivative instruments at fair value, with
the exception of normal purchases and normal sales transactions that are expected to result in physical delivery. Commodity
price and interest-rate volatility may have a significant impact on the fair value of derivative instruments as of a given date.
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. 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
Normal purchases and
normal sales
Mark-to-market
Cash flow hedge
Recognition and Measurement
Balance Sheet
Income Statement
- Fair value not recorded
- Change in fair value not recognized in earnings
- Recorded at fair value
- The gain or loss on the
derivative instrument is reported initially as a
component of accumulated other
comprehensive income (loss)
- Change in fair value recognized in earnings
- The gain or loss on the derivative instrument is
reclassified out of accumulated other
comprehensive income (loss) into earnings
when the forecasted transaction affects earnings
- The gain or loss on the derivative instrument is
recognized in earnings
Fair value hedge
- Recorded at fair value
- Change in fair value of the hedged item is
recorded as an adjustment to book value
- Change in fair value of the hedged item is
recognized in earnings
To reduce our exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, forward
purchases and sales, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and
condensate. Interest-rate swaps are used from time to time to manage interest-rate risk. Under certain conditions, we designate
our derivative instruments as a hedge of exposure to changes in fair values or cash flows. We formally document all
relationships between hedging instruments and hedged items, as well as risk-management objectives and strategies for
undertaking various hedge transactions, and methods for assessing and testing correlation and hedge effectiveness. We
specifically identify the forecasted transaction that has been designated as the hedged item in a cash flow hedge relationship.
We assess the effectiveness of hedging relationships at inception of the hedge by performing an effectiveness analysis on our
fair value and cash flow hedging relationships to determine whether the hedge relationships are highly effective. Subsequently
we perform qualitative assessments. We also document our normal purchases and normal sales transactions that we expect to
result in physical delivery and that we elect to exempt from derivative accounting treatment.
The realized revenues and purchase costs of our derivative instruments not considered held for trading purposes and derivatives
that qualify as normal purchases or normal sales that are expected to result in physical delivery are reported on a gross basis.
Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same category as the
cash flows from the related hedged items in our Consolidated Statements of Cash Flows.
See Notes B and C for disclosures of our fair value measurements and risk-management and hedging activities.
Property, Plant and Equipment - Our properties are stated at cost, including AFUDC and capitalized interest. In some cases,
the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains
and losses from sales or transfers of nonregulated properties or an entire operating unit or system of our regulated properties are
recognized in income. Maintenance and repairs are charged directly to expense.
The interest portion of AFUDC and capitalized interest represent the cost of borrowed funds used to finance construction
activities for regulated and nonregulated projects, respectively. We capitalize interest costs during the construction or upgrade
of qualifying assets. These costs are recorded as a reduction to interest expense. The equity portion of AFUDC represents the
capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost
of our regulated properties and as a credit to the allowance for equity funds used during construction.
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. For our regulated assets, these depreciation studies are
68
completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented
prospectively when the new rates are approved. For our nonregulated assets, if it is determined that the estimated economic life
changes, the changes are made prospectively. Changes in the estimated economic lives of our property, plant and equipment
could have a material effect on our financial position or results of operations.
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 D for our property, plant and equipment disclosures.
Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill for impairment at
least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time.
Our qualitative goodwill impairment analysis performed as of July 1, 2019, did not result in an impairment charge nor did our
analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair
value of each of our reporting units is less than the carrying value of its net assets.
As part of our goodwill impairment test, we may 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
the fair value of each of our reporting units is less than its carrying amount. If further testing is necessary or a quantitative test
is elected, we perform a two-step impairment test for goodwill. In the first step, an initial assessment is made by comparing the
fair value of a reporting unit with its book value, including goodwill. If the fair value is less than the book value, an
impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we
calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the
reporting unit from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds the
implied fair value of the goodwill, we will record an impairment charge.
Update - Upon adoption of ASU 2017-04 in January 2020, the requirement to calculate the implied fair value of goodwill under
the two-step impairment test was eliminated. See “Recently Issued Accounting Standards Update” table below for more
information.
To estimate the fair value of our reporting units, 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 EBITDA multiples to forecasted EBITDA. The multiples
used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows for
a reporting unit over a period of years.
We assess our long-lived assets for impairment whenever events or changes in circumstances indicate that an asset’s carrying
amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the
undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is
indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived
asset.
For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity
investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore,
we periodically evaluate the amount at which we carry our equity-method investments to determine whether current events or
circumstances warrant adjustments to our carrying values.
See Notes D, E and M for our long-lived assets, goodwill and intangible assets and investments in unconsolidated affiliates
disclosures.
Regulation - Depending on the specific service provided, our natural gas transmission pipelines, NGL pipelines and certain
natural gas storage facilities are subject to rate regulation and/or accounting requirements by one or more of the FERC, OCC,
KCC and RRC. Accordingly, portions of our Natural Gas Liquids and Natural Gas Pipelines segments follow the accounting
and reporting guidance for regulated operations. In our Consolidated Financial Statements and our Notes to Consolidated
Financial Statements, regulated operations are defined pursuant to Financial Accounting Standards Board’s (FASB) ASC 980,
Regulated Operations. During the rate-making process for certain of our assets, 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
69
to defer recognition of certain costs and permitting recovery of the amounts through rates over time as opposed to expensing
such costs as incurred. Certain examples of types of regulatory guidance include costs for fuel and losses, acquisition costs,
contributions in aid of construction, charges for depreciation, and gains or losses on disposition of assets. 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 amounts we may charge our 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 (i) established by
independent, third-party regulators and (ii) set at levels that will recover our costs when considering the demand and
competition for our services.
Retirement and Other Postretirement Employee Benefits - We have defined benefit retirement plans covering certain
employees and former employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to
certain employees hired prior to 2017 who retire with at least five years of service. The expense and liability related to these
plans is calculated using statistical and other factors that attempt to anticipate future events. These factors include assumptions
about the discount rate, expected return on plan assets, rate of future compensation increases, mortality and employment length.
In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in
changes in the costs and liabilities we recognize.
See Note K for our retirement and other postretirement employee benefits disclosures.
Income Taxes - Deferred income taxes are provided 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. Generally, the effect of a change in tax rates on deferred tax assets and liabilities is recognized in
income in the period that includes the enactment date of the rate change.
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. During 2019, 2018 and 2017, we had no uncertain tax positions that required the
establishment of a material reserve.
We utilize the “with-and-without” approach for intra-period tax allocation for purposes of allocating total tax expense (or
benefit) for the year among the various financial statement components.
We file numerous consolidated and separate income tax returns with federal tax authorities of the United States along with the
tax authorities of several states. We are not under any United States federal audits or statute waivers at this time.
See Note L for our income taxes disclosures.
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 of our natural
gas gathering and processing, NGL and natural gas pipeline facilities are subject to agreements or regulations that give rise to
our asset retirement obligations for removal or other disposition costs associated with retiring the assets in place upon the
discontinued use of the assets. 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, primarily certain pipeline assets, because the settlement dates are
indeterminable given our expected continued use of the assets with proper maintenance. We expect our pipeline assets, for
which we are unable to estimate reasonably the fair value of the asset retirement obligation, will continue in operation as long
as supply and demand for natural gas and NGLs exist. Based on the widespread use of natural gas for heating and cooking
activities for residential users and electric-power generation for commercial users, as well as use of NGLs by the petrochemical
industry, we expect supply and demand to exist for the foreseeable future.
For our assets that we are able to make an estimate, the fair value of the liability is added to the carrying amount of the
associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end
of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount
of the liability, we will recognize a gain or loss on settlement. The depreciation and accretion expense are immaterial to our
Consolidated Financial Statements.
70
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and
environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred
and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution.
Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of
a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when
their receipt is deemed probable. Our expenditures for environmental evaluation, mitigation, remediation and compliance to
date have not been significant in relation to our financial position or results of operations, and our expenditures related to
environmental matters had no material effect on earnings or cash flows during 2019, 2018 and 2017. Actual results may differ
from our estimates resulting in an impact, positive or negative, on earnings.
See Note N for additional discussion of contingencies.
Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate
forfeiture rates based on historical forfeitures under our share-based payment plans.
See Note J for our share-based payments disclosures.
Earnings per Common Share - Basic EPS is calculated based on the daily weighted-average number of shares of common
stock outstanding during the period, vested restricted and performance units that have been deferred and share awards deferred
under the compensation plan for nonemployee directors. Diluted EPS is calculated based on the daily weighted-average
number of shares of common stock outstanding during the period plus potentially dilutive components. The dilutive
components are calculated based on the dilutive effect for each quarter. For fiscal-year periods, the dilutive components for
each quarter are averaged to arrive at the fiscal year-to-date dilutive component.
See Note I for our earnings per share disclosures.
Segment Reporting - Our chief operating decision-maker reviews the financial performance of each of our three segments, as
well as our financial performance as a whole, on a regular basis. Adjusted EBITDA by segment is utilized in this evaluation.
We believe this financial measure is useful to investors because it and similar measures are used by many companies in our
industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate
our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA for each
segment is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges,
income taxes, allowance for equity funds used during construction, noncash compensation expense, and other noncash items.
This calculation may not be comparable with similarly titled measures of other companies.
See Note Q for our segments disclosures.
Reclassifications - Certain reclassifications have been made in the prior-year financial statements to conform to the current-
year presentation.
71
Recently Issued Accounting Standards Update - Changes to GAAP are established by the FASB in the form of ASUs to the
FASB Accounting Standards Codification. We consider the applicability and impact of all ASUs. ASUs not listed below were
assessed and determined to be either not applicable or clarifications of ASUs previously issued or listed below. The following
tables provide a brief description of recent accounting pronouncements and our analysis of the effects on our financial
statements:
Standard
Description
Standards that were adopted as of December 31, 2019
Date of
Adoption
Effect on the Financial Statements or Other
Significant Matters
ASU 2016-02, “Leases
(Topic 842)”
The standard requires the recognition
of lease assets and lease liabilities by
lessees for those leases classified as
operating leases under previous GAAP.
It also requires qualitative disclosures
along with specific quantitative
disclosures by lessees and lessors to
meet the objective of enabling users of
financial statements to assess the
amount, timing and uncertainty of cash
flows arising from leases.
ASU 2018-07,
“Compensation - Stock
Compensation (Topic 718):
Improvements to
Nonemployee Share-Based
Payment Accounting”
The standard aligns the measurement
and classification guidance for share-
based payments to nonemployees with
the guidance for share-based payments
to employees, with certain exceptions.
Standards that are not yet adopted as of December 31, 2019
ASU 2016-13, “Financial
Instruments - Credit Losses
(Topic 326): Measurement
of Credit Losses on
Financial Instruments”
ASU 2017-04, “Intangibles-
Goodwill and Other (Topic
350): Simplifying the Test
for Goodwill Impairment”
ASU 2019-12, “Income
Taxes (Topic 740):
Simplifying the Accounting
for Income Taxes”
The standard requires a financial asset
(or a group of financial assets)
measured at amortized cost basis to be
presented net of the allowance for
credit losses to reflect the net carrying
value at the amount expected to be
collected on the financial asset; and the
initial allowance for credit losses for
purchased financial assets, including
available-for-sale debt securities, to be
added to the purchase price rather than
being reported as a credit loss expense.
The standard simplifies the subsequent
measurement of goodwill by
eliminating the requirement to calculate
the implied fair value of goodwill under
step 2. Instead, an entity will recognize
an impairment charge for the amount
by which the carrying amount exceeds
the reporting unit’s fair value. The
standard does not change step zero or
step 1 assessments.
The standard simplifies certain
concepts in Topic 740, Income Taxes.
First
quarter
2019
First
quarter
2019
First
quarter
2020
First
quarter
2020
First
quarter
2021
We adopted this standard on January 1, 2019, using
the modified retrospective method and the optional
transition method to record the adoption impact
through a cumulative adjustment to equity. On
January 1, 2019, we recorded an immaterial
cumulative effect for the adoption of the new
standard and recorded $17.5 million of right-of-use
assets and $17.4 million of lease liabilities related to
operating leases that were not previously recorded
on our Consolidated Balance Sheets. Our finance
lease assets and liabilities at January 1, 2019, of
$28.1 million and $28.0 million, respectively, did
not change as a result of adopting this standard. See
Note O for additional disclosures.
The impact of adopting this standard was not
material.
We adopted this standard in January 2020, and the
impact of adopting this standard was not material.
We adopted this standard in January 2020, and the
impact of adopting this standard was not material.
We do not expect the adoption of this standard to
materially impact us.
72
B.
FAIR VALUE MEASUREMENTS
Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods
indicated:
Derivative assets
Commodity contracts
Financial contracts
Interest-rate contracts
Total derivative assets
Derivative liabilities
Commodity contracts
Financial contracts
Interest-rate contracts
Total derivative liabilities
$
$
$
$
December 31, 2019
Level 1
Level 2
Level 3
Total - Gross Netting (a)
Total - Net
(Thousands of dollars)
10,892
—
10,892
$
$
— $
581
581
$
55,557
—
55,557
$
$
66,449
581
67,030
$
$
(28,588) $
—
(28,588) $
37,861
581
38,442
(4,811) $
—
— $
(201,941)
(4,811) $ (201,941) $
(24,785) $
—
(24,785) $
(29,596) $
(201,941)
(231,537) $
28,588
—
28,588
$
$
(1,008)
(201,941)
(202,949)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities
when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31,
2019, we held no cash and posted $8.8 million of cash with various counterparties, which is included in other current assets in our
Consolidated Balance Sheet.
Derivative assets
Commodity contracts
Financial contracts
Physical contracts
Interest-rate contracts
Total derivative assets
Derivative liabilities
Commodity contracts
Financial contracts
Interest-rate contracts
Total derivative liabilities
$
$
$
$
December 31, 2018
Level 1
Level 2
Level 3
Total - Gross Netting (a)
Total - Net
(Thousands of dollars)
10,812
—
—
10,812
$
$
— $
—
19,005
19,005
$
69,165
1,142
—
70,307
$
$
79,977
1,142
19,005
100,124
$
$
(32,739) $
—
—
(32,739) $
47,238
1,142
19,005
67,385
(2,916) $
—
(2,916) $
— $
(99,260)
(99,260) $
(29,823) $
—
(29,823) $
(32,739) $
(99,260)
(131,999) $
32,739
—
32,739
$
$
—
(99,260)
(99,260)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities
when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31,
2018, we held no cash and posted $0.8 million of cash with various counterparties, which is included in other current assets in our
Consolidated Balance Sheet.
73
The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:
Derivative Assets (Liabilities)
Net assets (liabilities) at beginning of period
Total changes in fair value:
Gains (losses) included in net income (a)
Settlements included in net income (a)
New Level 3 derivatives included in other comprehensive income (loss) (b)
Unrealized change included in other comprehensive income (loss) (b)
Net assets (liabilities) at end of period
Years Ended
December 31,
2019
2018
(Thousands of dollars)
$
40,484
$
(32,838)
—
(40,344)
30,627
5
30,772
$
(140)
29,141
37,106
7,215
40,484
$
(a) - Included in commodity sales revenues/cost of sales and fuel in our Consolidated Statements of Income.
(b) - Included in change in fair value of derivatives in our Consolidated Statements of Comprehensive Income.
During the years ended December 31, 2019 and 2018, there were no transfers in or out of Level 3 of the fair value hierarchy.
Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable
and short-term borrowings is equal to book value due to the short-term nature of these items. Our cash and cash equivalents are
composed of bank and money market accounts and are classified as Level 1. Our short-term borrowings are classified as
Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the
commercial paper market.
The estimated fair value of our consolidated long-term debt, including current maturities, was $13.8 billion and $9.6 billion at
December 31, 2019 and 2018, respectively. The book value of our consolidated long-term debt, including current maturities,
was $12.5 billion and $9.4 billion at December 31, 2019 and 2018, respectively. The estimated fair value of the aggregate
senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The
estimated fair value of our consolidated long-term debt is classified as Level 2.
C.
RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES
Risk-management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of
contractual terms under which these commodities are processed, purchased and sold. We are also subject to the risk of interest-
rate fluctuation in the normal course of business. We use physical-forward purchases and sales and financial derivatives to
secure a certain price for a portion of our natural gas, condensate and NGL products; to reduce our exposure to commodity
price and interest-rate fluctuations; and to achieve more predictable cash flows. We follow established policies and procedures
to assess risk and approve, monitor and report our risk-management activities. We have not used these instruments for trading
purposes.
Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse
changes in the price of natural gas, NGLs and condensate. We may use the following commodity derivative instruments to
reduce the near-term commodity price risk associated with a portion of the forecasted sales of these commodities:
•
•
•
Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement
under the provisions of exchange regulations;
Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, crude oil or
NGLs for future physical delivery. These contracts are typically nontransferable and can only be canceled with the
consent of both parties;
Swaps - Exchange of one or more payments based on the value of one or more commodities. These instruments
transfer the financial risk associated with a future change in value between the counterparties of the transaction,
without also conveying ownership interest in the asset or liability; and
• Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of
a commodity at a fixed price within a specified period of time. Options may either be standardized and exchange-
traded or customized and nonexchange-traded.
We may also use other instruments including collars to mitigate commodity price risk. A collar is a combination of a purchased
put option and a sold call option, which places a floor and a ceiling price for commodity sales being hedged.
74
In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion
of the commodity sales proceeds associated with our POP with fee contracts. Under certain POP with fee contracts, our fees
and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to
specified thresholds. We also are exposed to basis risk between the various production and market locations where we buy and
sell commodities. As part of our hedging strategy, we use the previously described commodity derivative financial instruments
and physical-forward contracts to reduce the impact of price fluctuations related to natural gas, NGLs and condensate.
In our Natural Gas Liquids segment, we are primarily exposed to commodity price risk resulting from the relative values of the
various NGL products to each other, the value of NGLs in storage and the relative value of NGLs to natural gas. We are also
exposed to location price differential risk as a result of the relative value of NGL purchases at one location and sales at another
location, primarily related to our optimization and marketing business. As part of our hedging strategy, we utilize physical-
forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to NGLs.
In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate pipelines
consume natural gas in operations and retain natural gas from our customers for operations or as part of our fee for services
provided. When the amount consumed in operations differs from the amount provided by our customers, our pipelines must
buy or sell natural gas, or store or use natural gas from inventory, which can expose this segment to commodity price risk
depending on the regulatory treatment for this activity. To the extent that commodity price risk in our Natural Gas Pipelines
segment is not mitigated by fuel cost-recovery mechanisms, we may use physical-forward sales or purchases to reduce the
impact of natural gas price fluctuations. At December 31, 2019 and 2018, there were no financial derivative instruments with
respect to our natural gas pipeline operations.
Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps.
Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. In
2019, we entered into $625 million of forward-starting interest-rate swaps to hedge the variability of interest payments on a
portion of our forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued.
We also settled $1.8 billion of our forward-starting interest-rate swaps related to our underwritten public offering of $1.25
billion senior unsecured notes in March 2019 and $2.0 billion senior unsecured notes in August 2019.
At December 31, 2019 and 2018, we had forward-starting interest-rate swaps with notional amounts totaling $1.8 billion and
$3.0 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At
December 31, 2019 and 2018, we had interest-rate swaps with notional amounts totaling $1.3 billion to hedge the variability of
our LIBOR-based interest payments. All of our interest-rate swaps are designated as cash flow hedges.
Fair Values of Derivative Instruments - All derivatives measured at fair value at December 31, 2019 and 2018, were
designated as hedging instruments. See Note B for a discussion of the inputs associated with our fair value measurements.
The following table sets forth the fair values of our derivative instruments presented on a gross basis for the periods indicated:
Location in our
Consolidated Balance
Sheets
December 31, 2019
December 31, 2018
Assets
(Liabilities)
Assets
(Thousands of dollars)
(Liabilities)
Derivatives designated as hedging instruments
Commodity contracts (a)
Financial contracts
Other current assets
$
64,858
$
(26,997) $
78,891
$
(31,793)
Physical contracts
Interest-rate contracts
Other assets/other deferred
credits
Other current assets
Other current assets/other
current liabilities
Other assets/other deferred
credits
1,591
—
(2,599)
—
1,086
1,142
(946)
—
—
(90,161)
19,005
(15,012)
581
(111,780)
—
(84,248)
Total derivatives designated as hedging
instruments
$
67,030
$ (231,537) $
100,124
$ (131,999)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis when a legally enforceable master-
netting arrangement exists between the counterparty to a derivative contract and us.
75
Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative
instruments held for the periods indicated:
December 31, 2019
Contract
Type
Purchased/
Payor
Sold/
Receiver
December 31, 2018
Sold/
Receiver
Purchased/
Payor
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
-Natural gas (Bcf)
-Crude oil and NGLs (MMBbl)
Basis
-Natural gas (Bcf)
Interest-rate contracts (Billions of dollars)
Futures and swaps
Futures, forwards
and swaps
Futures and swaps
Swaps
$
—
7.9
—
3.1
(59.0)
(17.4)
(59.0)
$
— $
—
6.5
—
4.3
$
(29.9)
(13.8)
(29.9)
—
These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to
which the positions offset one another and, consequently, do not reflect our actual exposure to market or credit risk.
Cash Flow Hedges - The following table sets forth the unrealized change in fair value of cash flow hedges in other
comprehensive income (loss) for the periods indicated:
Derivatives in Cash Flow Hedging Relationships
2019
Commodity contracts
Interest-rate contracts
Total unrealized change in fair value of cash flow hedges in other comprehensive
income (loss)
$
$
Years Ended December 31,
2018
(Thousands of dollars)
$
$
53,217
(60,584)
38,819
(230,771)
2017
(40,577)
163
(191,952) $
(7,367) $
(40,414)
The following table sets forth the effect of cash flow hedges on net income for the periods indicated:
Derivatives in Cash Flow
Hedging Relationships
Location of Gain (Loss) Reclassified from
Accumulated Other Comprehensive Loss into
Net Income
2019
Commodity contracts
Interest-rate contracts
Commodity sales revenues/cost of sales and fuel
Interest expense
Total change in fair value of cash flow hedges reclassified from accumulated other
comprehensive loss into net income on derivatives
$
$
Years Ended December 31,
2018
(Thousands of dollars)
(29,596) $
(18,287)
$
50,345
(23,230)
2017
(69,561)
(21,025)
27,115
$
(47,883) $
(90,586)
Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our
Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe
minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including
credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of
standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single
counterparty. We use internally developed credit ratings for counterparties that do not have a credit rating.
Our financial commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing
broker account with daily margin requirements. However, we may enter into financial derivative instruments that contain
provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on our
senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could
request collateralization on derivative instruments in net liability positions. There were no financial derivative instruments with
contingent features related to credit risk at December 31, 2019.
The counterparties to our derivative contracts typically consist of major energy companies, financial institutions and
commercial and industrial end users. This concentration of counterparties may affect our overall exposure to credit risk, either
positively or negatively, in that the counterparties may be affected similarly by changes in economic, regulatory or other
76
conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our
financial position or results of operations as a result of counterparty nonperformance.
At December 31, 2019, the net credit exposure from our derivative assets is with investment-grade companies in the financial
services sector.
D.
PROPERTY, PLANT AND EQUIPMENT
The following table sets forth our property, plant and equipment by property type, for the periods indicated:
Nonregulated
Gathering pipelines and related equipment
Processing and fractionation and related equipment
Storage and related equipment
Transmission pipelines and related equipment
General plant and other
Construction work in process
Regulated
Storage and related equipment
Natural gas transmission pipelines and related equipment
NGL transmission pipelines and related equipment
General plant and other
Construction work in process
Property, plant and equipment
Accumulated depreciation and amortization - nonregulated
Accumulated depreciation and amortization - regulated
Net property, plant and equipment
Estimated Useful
Lives (Years)
December 31,
2019
December 31,
2018
(Thousands of dollars)
5 to 40
3 to 40
3 to 54
5 to 54
2 to 60
—
5 to 25
5 to 77
5 to 88
2 to 50
—
$
$
4,316,936
4,439,332
684,635
797,678
610,013
1,645,663
9,180
1,552,546
6,126,056
66,507
1,802,946
22,051,492
(2,471,649)
(1,231,158)
18,348,685
$
$
3,851,043
4,171,072
656,455
782,258
547,424
797,182
8,987
1,475,789
4,677,599
61,136
1,002,018
18,030,963
(2,168,855)
(1,095,457)
14,766,651
The average depreciation rates for our regulated property are set forth, by segment, in the following table for the periods
indicated:
Natural Gas Liquids
Natural Gas Pipelines
Years Ended December 31,
2018
1.9%
2.1%
2019
2.0%
2.1%
2017
1.9%
2.1%
We incurred costs for construction work in process that had not been paid at December 31, 2019, 2018 and 2017, of $544.8
million, $388.3 million and $92.4 million, respectively. Such amounts are not included in capital expenditures (less AFUDC
and capitalized interest) on the Consolidated Statements of Cash Flows.
Impairment Charges - In 2017, following a review of nonstrategic assets for potential divestiture, we recorded $16.0 million
of noncash impairment charges related to certain nonstrategic gathering and processing assets located in North Dakota.
E.
GOODWILL AND INTANGIBLE ASSETS
Goodwill - The following table sets forth our goodwill, by segment, for the periods indicated:
Natural Gas Gathering and Processing
Natural Gas Liquids
Natural Gas Pipelines
Total goodwill
77
December 31,
December 31,
2019
2018
(Thousands of dollars)
$
$
153,404
371,217
156,375
680,996
$
$
153,404
371,217
156,479
681,100
Intangible Assets - Our intangible assets relate primarily to contracts acquired through acquisitions in our Natural Gas
Gathering and Processing and Natural Gas Liquids segments, which are being amortized over periods of 15 to 40 years.
Amortization expense for intangible assets was $11.9 million in 2019, 2018 and 2017, and the aggregate amortization expense
for each of the next five years is estimated to be $11.9 million. The following table reflects the gross carrying amount and
accumulated amortization of intangible assets for the periods presented:
Gross intangible assets
Accumulated amortization
Net intangible assets
F.
DEBT
The following table sets forth our consolidated debt for the periods indicated:
Commercial paper outstanding, bearing a weighted-average interest rate of 2.16% as of December 31,
2019
Senior unsecured obligations:
$500,000 at 8.625% due March 2019
$300,000 at 3.8% due March 2020
$1,500,000 term loan, rate of 2.70% and 3.63% as of December 31, 2019 and 2018, respectively, due
November 2021
$700,000 at 4.25% due February 2022
$900,000 at 3.375 % due October 2022
$425,000 at 5.0 % due September 2023
$500,000 at 7.5% due September 2023
$500,000 at 2.75% due September 2024
$500,000 at 4.9 % due March 2025
$500,000 at 4.0% due July 2027
$800,000 at 4.55% due July 2028
$100,000 at 6.875% due September 2028
$700,000 at 4.35% due March 2029
$750,000 at 3.4% due September 2029
$400,000 at 6.0% due June 2035
$600,000 at 6.65% due October 2036
$600,000 at 6.85% due October 2037
$650,000 at 6.125% due February 2041
$400,000 at 6.2% due September 2043
$700,000 at 4.95% due July 2047
$1,000,000 at 5.2% due July 2048
$750,000 at 4.45% due September 2049
Guardian Pipeline
Weighted average 7.85% due December 2022
Total debt
Unamortized portion of terminated swaps
Unamortized debt issuance costs and discounts
Current maturities of long-term debt
Short-term borrowings (a)
Long-term debt
December 31,
December 31,
2018
2019
(Thousands of dollars)
$
$
414,345
(137,508)
276,837
$
$
411,650
(125,608)
286,042
December 31,
December 31,
2019
2018
(Thousands of dollars)
$
220,000
$
—
—
—
1,250,000
547,397
900,000
425,000
500,000
500,000
500,000
500,000
800,000
100,000
700,000
750,000
400,000
600,000
600,000
650,000
400,000
700,000
1,000,000
750,000
500,000
300,000
550,000
547,397
900,000
425,000
500,000
—
500,000
500,000
800,000
100,000
—
—
400,000
600,000
600,000
650,000
400,000
700,000
450,000
—
21,307
12,813,704
15,032
(121,329)
(7,650)
(220,000)
12,479,757
$
$
28,957
9,451,354
16,750
(87,120)
(507,650)
—
8,873,334
(a) - Individual issuances of commercial paper under our commercial paper program generally mature in 90 days or less.
78
$2.5 Billion Credit Agreement - In May 2019, we extended the term of our $2.5 Billion Credit Agreement by one year to
June 2024. Our $2.5 Billion Credit Agreement is a revolving credit facility and contains certain financial, operational and legal
covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as
defined in our $2.5 Billion Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from
certain lender-approved capital expansion projects) of no more than 5.0 to 1 at December 31, 2019. If we consummate one or
more acquisitions in which the aggregate purchase is $25 million or more, the allowable ratio of indebtedness to adjusted
EBITDA will increase to 5.5 to 1 for the quarter in which the acquisition is completed and the following two quarters.
Thereafter, the covenant will decrease to 5.0 to 1.
Our $2.5 Billion Credit Agreement includes a $100 million sublimit for the issuance of standby letters of credit and a $200
million sublimit for swingline loans. Under the terms of our $2.5 Billion Credit Agreement, we may request an increase in the
size of the facility to an aggregate of $3.5 billion by either commitments from new lenders or increased commitments from
existing lenders. Our $2.5 Billion Credit Agreement contains provisions for an applicable margin rate and an annual facility
fee, both of which adjust with changes in our credit ratings. Based on our current credit ratings, borrowings, if any, will accrue
at LIBOR plus 110 basis points, and the annual facility fee is 15 basis points. At December 31, 2019, our ratio of indebtedness
to adjusted EBITDA was 4.1 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit Agreement.
At December 31, 2019 and 2018, we had letters of credit issued totaling $4.7 million and $1.4 million, respectively, and no
borrowings outstanding under our $2.5 Billion Credit Agreement.
Senior Unsecured Obligations - All notes are senior unsecured obligations, ranking equally in right of payment with all of our
existing and future unsecured senior indebtedness, and are structurally subordinate to any of the existing and future debt and
other liabilities of any nonguarantor subsidiaries.
Issuances - In August 2019, we completed an underwritten public offering of $2.0 billion senior unsecured notes consisting of
$500 million, 2.75% senior notes due 2024; $750 million, 3.4% senior notes due 2029; and $750 million, 4.45% senior notes
due 2049. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.97 billion.
The proceeds were used for general corporate purposes, including repayment of existing indebtedness and funding capital
expenditures.
In March 2019, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $700
million, 4.35% senior notes due 2029 and an additional issuance of $550 million of our existing 5.2% senior notes due 2048.
The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued
interest, were $1.23 billion. The proceeds were used for general corporate purposes, including repayment of existing
indebtedness and funding capital expenditures.
In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which was fully drawn
as of June 30, 2019. We repaid $250 million of our outstanding balance in August 2019 and have $1.25 billion drawn as of
December 31, 2019. Our $1.5 Billion Term Loan Agreement matures in November 2021 and bears interest at LIBOR plus
112.5 basis points based on our current credit ratings. The agreement contains an option, which may be exercised up to two
times, to extend the term of the loan, in each case, for an additional one-year term subject to approval of the banks. Our
$1.5 Billion Term Loan Agreement allows prepayment of all or any portion outstanding, without penalty or premium, and
contains substantially the same covenants as those contained in our $2.5 Billion Credit Agreement. The proceeds were used for
general corporate purposes, including repayment of existing indebtedness and funding capital expenditures.
In July 2018, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $800 million,
4.55% senior notes due 2028 and $450 million, 5.2% senior notes due 2048. The net proceeds, after deducting underwriting
discounts, commissions and offering expenses, were $1.23 billion. The proceeds were used for general corporate purposes,
which included repayment of existing indebtedness and funding capital expenditures.
In July 2017, we completed an underwritten public offering of $1.2 billion senior unsecured notes consisting of $500 million,
4.0% senior notes due 2027, and $700 million, 4.95% senior notes due 2047. The net proceeds, after deducting underwriting
discounts, commissions and offering expenses, were $1.2 billion. The proceeds were used for general corporate purposes,
which included repayment of existing indebtedness and funding capital expenditures.
Repayments - In September 2019, we redeemed our $300 million, 3.8% senior notes due March 2020 at a redemption price of
$308.0 million, including the outstanding principal, plus accrued and unpaid interest, with cash on hand from our public
offering of $2.0 billion senior unsecured notes in August 2019. In connection with this early redemption, we incurred a $2.7
79
million loss on extinguishment of debt, which is included in other expense in our Consolidated Statements of Income for the
year ended December 31, 2019.
In August 2019, we repaid $250 million of our $1.5 Billion Term Loan agreement with cash on hand.
In March 2019, we repaid our $500 million, 8.625% senior notes at maturity with a combination of cash on hand and short-
term borrowings.
In 2018, we repaid our $425 million, 3.2% senior notes due September 2018 with cash on hand and the remaining $500 million
of the ONEOK Partners Term Loan Agreement due 2019 with a combination of cash on hand and short-term borrowings.
In 2017, we repaid ONEOK Partners’ $400 million, 2.0% senior notes due in October 2017 and repaid $500 million of the
ONEOK Partners Term Loan Agreement due 2019 with a combination of cash on hand and short-term borrowings and
redeemed our 6.5% senior notes due 2028 at a redemption price of $87.0 million with cash on hand.
The aggregate maturities of long-term debt outstanding as of December 31, 2019, for the years 2020 through 2024 are shown
below:
2020
2021
2022
2023
2024
$
$
$
$
$
Senior
Unsecured
Obligations
Guardian
Pipeline
(Millions of dollars)
$
7.7
$
7.7
$
5.9
— $
— $
— $
$
$
$
$
1,250.0
1,447.4
925.0
500.0
Total
7.7
1,257.7
1,453.3
925.0
500.0
Covenants - Our senior notes are governed by indentures containing covenants, including among other provisions, limitations
on our ability to place liens on our property or assets and to sell and leaseback our property. The indentures governing our
6.875% senior notes due 2028 include an event of default upon acceleration of other indebtedness of $15 million or more, and
the indentures governing the remainder of our senior notes include 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% in aggregate
principal amount of the outstanding senior notes to declare those senior notes immediately due and payable in full. The
indenture for the 7.5% notes due 2023 also contains a provision that allows the holders of the notes to require ONEOK to offer
to repurchase all or any part of their notes if a change of control and a credit rating downgrade occur at a purchase price of
101% of the principal amount, plus accrued and unpaid interest, if any.
We may redeem our senior notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the
principal amount, plus accrued and unpaid interest and a make-whole premium. We may redeem the balance of our senior
notes due 2022, 2023, 2024, 2025, 2027, 2028 (4.55%), 2029, 2041, 2043, 2047, 2048 and 2049 at a redemption price equal to
the principal amount, plus accrued and unpaid interest, starting one to six months before the maturity date as stipulated in the
respective contract terms. Our senior notes are senior unsecured obligations, ranking equally in right of payment with all of our
existing and future unsecured senior indebtedness.
Guardian Pipeline Senior Notes - These senior notes were issued under a master shelf agreement dated November 8, 2001,
with certain financial institutions. Principal payments are due quarterly through 2022. Guardian Pipeline’s senior notes contain
financial covenants that require the maintenance of certain financial ratios as defined in the master shelf agreement based on
Guardian Pipeline’s financial position and results of operations. Upon any breach of these covenants, all amounts outstanding
under the master shelf agreement may become due and payable immediately. At December 31, 2019, Guardian Pipeline was in
compliance with its financial covenants.
Other - We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent
with the terms of the respective debt instrument.
Debt Guarantees - ONEOK, ONEOK Partners and the Intermediate Partnership have cross guarantees in place for our and
ONEOK Partners’ indebtedness.
80
G.
EQUITY
Noncontrolling Interests - As a result of the Merger Transaction in 2017, we and our subsidiaries own 100% of ONEOK
Partners. The earnings of ONEOK Partners that are attributed to its units held by the public until June 30, 2017, are reported as
“Net income attributable to noncontrolling interest” in our accompanying Consolidated Statements of Income. ONEOK
Partners’ cash distributions paid prior to the Merger Transaction are reported as “Distributions to noncontrolling interests” in
our accompanying Consolidated Statements of Changes in Equity.
In July 2018, we acquired the remaining 20% interest in WTLPG for $195 million with cash on hand. We are now the sole
owner of the West Texas LPG pipeline system.
Series A and B Convertible Preferred Stock - There are no shares of Series A or Series B Preferred Stock currently issued or
outstanding.
Series E Preferred Stock - In April 2017, through a wholly owned subsidiary, we contributed 20,000 shares of newly issued
Series E Preferred Stock, having an aggregate value of $20 million, to the Foundation for use in charitable and nonprofit
causes. The contribution was recorded as a $20 million noncash expense in 2017, which represents a noncash financing
activity, and is included in other expense in our Consolidated Statements of Income.
Equity Issuances - In January 2018, we completed an underwritten public offering of 21.9 million shares of our common stock
at a public offering price of $54.50 per share, generating net proceeds of $1.2 billion. We used the net proceeds from this
offering to fund capital expenditures and for general corporate purposes, which included repaying a portion of our outstanding
indebtedness.
In July 2017, we established an “at-the-market” equity program for the offer and sale from time to time of our common stock
up to an aggregate amount of $1 billion. The program allows us to offer and sell our common stock at prices we deem
appropriate through a sales agent. Sales of our common stock may be made by means of ordinary brokers’ transactions on the
NYSE, in block transactions, or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and
sell common stock under the program. No shares were sold through our “at-the-market” equity program in 2019 or 2018.
During the year ended December 31, 2017, we sold 8.4 million shares of common stock through our “at-the-market” equity
program that resulted in net proceeds of $448.3 million. The net proceeds from these issuances were used for general corporate
purposes, including repayment of outstanding indebtedness and to fund capital expenditures.
Dividends - Holders of our common stock share equally in any dividend declared by our Board of Directors, subject to the
rights of the holders of outstanding preferred stock. Dividends paid totaled $1.5 billion, $1.3 billion and $829.4 million for
2019, 2018 and 2017, respectively. In addition to the increase in dividends paid per share outlined in the table below, dividends
paid increased due to the increase in number of shares outstanding as a result of the closing of the Merger Transaction and our
equity issuances. The following table sets forth the quarterly dividends per share paid on our common stock in the periods
indicated:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Total
Years Ended December 31,
2018
2017
2019
$
$
0.860
0.865
0.890
0.915
3.53
$
$
0.770
0.795
0.825
0.855
3.245
$
$
0.615
0.615
0.745
0.745
2.72
Additionally, in February 2020, we paid a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis),
which was paid to shareholders of record as of January 27, 2020.
The Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by
our Board of Directors, at a rate of 5.5% per year. We paid dividends for the Series E Preferred Stock of $1.1 million in both
2019 and 2018 and $0.6 million in 2017. We paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock in
February 2020.
81
H.
ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the balance in accumulated other comprehensive loss for the periods indicated:
Risk-
Management
Assets/Liabilities (a)
Retirement and
Other
Postretirement
Benefit Plan
Obligations (a) (b)
Risk-
Management
Assets/Liabilities of
Unconsolidated
Affiliates (a)
(Thousands of dollars)
Accumulated
Other
Comprehensive
Loss (a)
January 1, 2018
Beginning balance adjustments (c)
Other comprehensive income (loss) before
reclassifications
Amounts reclassified to net income
Other comprehensive income (loss)
attributable to ONEOK
Impact of adoption of ASU 2018-02 (d)
December 31, 2018
Other comprehensive loss before
reclassifications
Amounts reclassified to net income
Other comprehensive income (loss)
December 31, 2019
$
$
(81,915) $
3,078
(105,411) $
(805)
(1,204) $
(2,273)
(5,673)
36,870
31,197
(17,020)
(64,660)
(147,803)
(21,057)
(168,860)
(233,520) $
(8,116)
12,887
4,771
(20,340)
(121,785)
(19,490)
9,794
(9,696)
(131,481) $
2,396
28
2,424
(741)
(1,794)
(7,275)
70
(7,205)
(8,999) $
(188,530)
—
(11,393)
49,785
38,392
(38,101)
(188,239)
(174,568)
(11,193)
(185,761)
(374,000)
(a) All amounts are presented net of tax.
(b) Includes amounts related to supplemental executive retirement plan.
(c) Reclassifications were made between categories to conform to current presentation.
(d) We elected to adopt this guidance in the first quarter 2018, which allows a reclassification from accumulated other comprehensive
income/loss to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act. After adopting and applying this
guidance, our accumulated other comprehensive loss balance does not include stranded taxes resulting from the Tax Cuts and Jobs Act.
The following table sets forth information about the balance of accumulated other comprehensive loss at December 31, 2019,
representing unrealized gains (losses) related to risk-management assets and liabilities:
Commodity derivative instruments expected to be realized within the next 24 months (b)
Settled interest-rate swaps to be recognized over the life of the long-term, fixed-rate debt (c)
Risk-
Management
Assets/Liabilities (a)
(Thousands of dollars)
28,119
$
(106,592)
Interest-rate swaps with future settlement dates expected to be amortized over the life of long-term debt
Accumulated other comprehensive loss at December 31, 2019
$
(155,047)
(233,520)
(a) - All amounts are presented net of tax.
(b) - Based on December 31, 2019, commodity prices, we will realize $28.9 million in net gains, net of tax, over the next 12 months and $0.8
million in net loss, net of tax, thereafter.
(c) - Losses of $20.3 million, net of tax, will be reclassified into earnings during the next 12 months as the hedged items affect earnings.
The remaining amounts in accumulated other comprehensive loss relate primarily to our retirement and other postretirement
benefit plan obligations, which are expected to be amortized over the average remaining service period of employees
participating in these plans.
82
The following table sets forth the effect of reclassifications from accumulated other comprehensive loss to net income for the
periods indicated:
Details about Accumulated Other
Comprehensive Loss Components
Risk-management assets/liabilities
Commodity contracts
Interest-rate contracts
Noncontrolling interests
Retirement and other postretirement benefit plan
obligations (a)
Amortization of net loss
Amortization of unrecognized prior service
credit
Risk-management assets/liabilities of
unconsolidated affiliates
Interest-rate contracts
Noncontrolling interests
Total reclassifications for the period attributable
to ONEOK
$
$
$
$
2019
Years Ended December 31,
2018
(Thousands of dollars)
2017
Affected Line Item in the
Consolidated Statements of Income
$
$
$
50,345
(23,230)
27,115
(6,058)
21,057
(29,596) $
(18,287)
(47,883)
11,013
(36,870)
—
21,057
$
—
(36,870) $
Commodity sales revenues/ cost of
sales and fuel
Interest expense
Income before income taxes
Income taxes
(69,561)
(21,025)
(90,586)
26,899
(63,687) Net income
Less: Net income attributable
(18,146)
noncontrolling interests
(45,541) Net income attributable to ONEOK
$
(12,946) $
(18,398) $
(15,265) Other income (expense)
227
(12,719)
2,925
(9,794) $
1,662
(16,736)
3,849
(12,887) $
1,662 Other income (expense)
Income before income taxes
Income taxes
(13,603)
5,441
(8,162) Net income attributable to ONEOK
(91) $
21
(70)
—
(70) $
(36) $
8
(28)
—
(28) $
Equity in net earnings from
investments
Income taxes
(367)
97
(270) Net income
Less: Net income attributable to
(106)
noncontrolling interests
(164) Net income attributable to ONEOK
11,193
$
(49,785) $
(53,867) Net income attributable to ONEOK
(a) - These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note K
for additional detail of our net periodic benefit cost.
I.
EARNINGS PER SHARE
The following tables set forth the computation of basic and diluted EPS for the periods indicated:
Year Ended December 31, 2019
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
Basic EPS
Net income available for common stock
Diluted EPS
$
1,277,477
413,560
$
3.09
Effect of dilutive securities
Net income available for common stock and common stock equivalents
—
1,277,477
$
1,884
415,444
$
3.07
83
Year Ended December 31, 2018
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
Basic EPS
Net income attributable to ONEOK available for common stock
$
1,150,603
411,485
$
2.80
Diluted EPS
Effect of dilutive securities
Net income attributable to ONEOK available for common stock and common stock
equivalents
—
2,710
$
1,150,603
414,195
$
2.78
Year Ended December 31, 2017
Income
Shares
Per Share
Amount
(Thousands, except per share amounts)
Basic EPS
Net income attributable to ONEOK available for common stock
$
387,074
297,477
$
1.30
Diluted EPS
Effect of dilutive securities
Net income attributable to ONEOK available for common stock and common stock
equivalents
—
2,303
$
387,074
299,780
$
1.29
J.
SHARE-BASED PAYMENTS
The ONEOK, Inc. Equity Compensation Plan (ECP) and the ONEOK, Inc. Long-Term Incentive Plan (LTIP) historically
provided 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. The ECP was terminated immediately
following the issuance of new awards in February 2018. The awards issued prior to the termination remain subject to the terms
of the ECP and the applicable award agreement. Similarly, the LTIP was terminated in May 2018, and the awards issued under
the LTIP prior to the termination date remain subject to the terms of the LTIP and the applicable award agreement. In May
2018, our shareholders approved the ONEOK, Inc. Equity Incentive Plan (EIP), which has been used for all new equity awards
since such date. We have reserved 8.5 million shares of common stock for issuance under the EIP and at December 31, 2019,
we had 7.6 million shares available for issuance under the plan. This calculation of available shares reflects shares issued and
estimated shares expected to be issued upon vesting of outstanding awards granted under the EIP, excluding estimated
forfeitures expected to be returned to the plan.
Restricted Stock Units - We have granted restricted stock units to key employees that vest at the end of a three-year period and
entitle the grantee to receive shares of our common stock. 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. Restricted stock unit awards granted accrue
dividend equivalents in the form of additional restricted stock units prior to vesting. Compensation expense is recognized on a
straight-line basis over the vesting period of the award.
Performance Unit Awards - We have granted performance unit awards to key employees that vest at the end of a three-year
period. Upon vesting, a holder of outstanding performance units is entitled to receive a number of shares of our common stock
equal to a percentage (0% to 200%) of the performance units granted, based on our total shareholder return over the vesting
period, compared with the total shareholder return of a peer group of other energy companies over the same period.
Performance unit awards are measured at fair value on the grant date based on a Monte Carlo model and adjusted for estimated
forfeitures. Performance stock unit awards granted accrue dividend equivalents in the form of additional performance units
prior to vesting. Compensation expense is recognized on a straight-line basis over the vesting period of the award.
Stock Compensation for Non-Employee Directors
The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) and the LTIP historically provided for
the granting of nonstatutory stock options, stock bonus awards, including performance unit awards and restricted stock awards.
The DSCP was terminated in May 2018 and replaced by the EIP. Under the EIP, awards may be granted by the Executive
Compensation Committee at any time, until grants have been made for all shares authorized under the EIP. The maximum
84
number of shares of common stock and cash-based awards that can be issued to a participant under the EIP during any year is
limited to $0.8 million in value as of the grant date. No performance unit awards or restricted stock awards have been made to
nonemployee directors under the EIP, LTIP or DSCP. There are no options outstanding under the EIP, LTIP or DSCP.
General
For all awards outstanding, we used a 3% forfeiture rate based on historical forfeitures under our share-based payment plans.
We currently use treasury stock to satisfy our share-based payment obligations.
Compensation expense for our share-based payment plans was $46.5 million, $33.2 million and $27.7 million during 2019,
2018 and 2017, respectively, before related tax benefits of $31.7 million, $12.2 million and $11.1 million, respectively.
Restricted Stock Unit Activity
As of December 31, 2019, we had $15.4 million of total unrecognized compensation cost related to our 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 our restricted stock unit awards:
Nonvested December 31, 2018
Granted
Released to participants
Forfeited
Nonvested December 31, 2019
Weighted-average grant date fair value (per share)
Fair value of units granted (thousands of dollars)
Grant date fair value of units vested (thousands of dollars)
Performance Unit Activity
Number of
Units
Weighted
Average Price
$
1,025,193
262,399
$
(541,871) $
(46,731) $
$
698,990
34.68
58.07
19.73
49.61
54.05
2019
2018
2017
$
$
$
58.07
15,238
10,691
$
$
$
46.94
13,907
9,552
$
$
$
45.11
12,685
7,258
As of December 31, 2019, we had $23.5 million of total unrecognized compensation cost related to the nonvested performance
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 the performance unit awards and the assumptions used in the valuations at the
respective grant dates:
Nonvested December 31, 2018
Granted
Released to participants
Forfeited
Nonvested December 31, 2019
Volatility (a)
Dividend yield
Risk-free interest rate
Number of
Units
Weighted
Average Price
$
1,243,643
338,427
$
(636,628) $
(7,621) $
$
937,821
44.08
68.02
23.59
39.54
66.67
2019
27.10%
5.05%
2.47%
2018
39.20%
5.49%
2.44%
2017
40.59%
4.68%
1.49%
(a) - Volatility was based on historical volatility over three years using daily stock price observations.
Weighted-average grant date fair value (per share)
Fair value of units granted (thousands of dollars)
Grant date fair value of units vested (thousands of dollars)
2019
2018
2017
$
$
$
68.02
23,020
15,018
$
$
$
59.57
22,081
12,545
$
$
$
56.65
17,621
8,704
85
Employee Stock Purchase Plan
We have reserved a total of 11.6 million shares of common stock for issuance under our ONEOK, Inc. Employee Stock
Purchase Plan (the ESPP). Subject to certain exclusions, all employees are eligible to participate in the ESPP. Employees can
choose to have up to 10% of their base pay withheld from each paycheck during the offering period to purchase our common
stock, subject to terms and limitations of the plan. The purchase price of the stock is 85% of the lower of its grant date or
exercise date market price. Approximately 62%, 60% and 58% of employees participated in the plan in 2019, 2018 and 2017,
respectively. Under the plan, we sold 171,590 shares at $51.24 per share in 2019, 165,877 shares at $45.53 per share in 2018
and 151,803 shares at $44.20 per share in 2017.
Employee Stock Award Program
Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of
our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above
$13 per share, and one additional share of common stock when the per-share closing price of our common stock on the NYSE
was at or above each one dollar increment above $13. The total number of shares of our common stock available for issuance
under this program is 900,000. Shares issued to employees under this program during 2019 and 2018 totaled 14,022 and 2,553,
respectively. Compensation expense related to the Employee Stock Award Program was $1.0 million and $0.2 million for 2019
and 2018, respectively. No shares were issued to employees under this program during 2017. As of the date of this report, the
next award will be issued when our common stock closes at or above $78.
Deferred Compensation Plan for Non-Employee Directors
The ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors provides our nonemployee directors the option to
defer all or a portion of their compensation for their service on our Board of Directors. Under the plan, directors may elect
either a cash deferral option or a phantom stock option. Under the cash deferral option, directors may elect to defer the receipt
of all or a portion of their annual retainer fees, which will be credited with interest during the deferral period. Under the
phantom stock option, directors may defer all or a portion of their annual retainer fees and receive such fees on a deferred basis
in the form of shares of common stock under our EIP, which earn the equivalent of dividends declared on our common stock.
Shares are distributed to nonemployee directors at the fair market value of our common stock at the date of distribution.
K.
EMPLOYEE BENEFIT PLANS
Retirement and Other Postretirement Benefit Plans
Retirement Plans - We have a defined benefit pension plan covering certain employees and former employees hired prior to
January 1, 2005. Employees hired after December 31, 2004, and employees who accepted a one-time opportunity to opt out of
our defined benefit pension plan historically were covered by our Profit Sharing Plan, which was merged into our 401(k) Plan
as of December 31, 2018. In addition, we have a supplemental executive retirement plan for the benefit of certain officers. No
new participants in our supplemental executive retirement plan have been approved since 2005, and effective January 2014, the
plan was formally closed to new participants. We fund our retirement 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 Postretirement Benefit Plans - We sponsor health and welfare plans that provide postretirement medical and life
insurance benefits to employees hired prior to 2017 who retire with at least five years of full-time service. The postretirement
medical plan for pre-Medicare participants is contributory with retiree contributions adjusted periodically and contains other
cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for Medicare-eligible participants
is an account-based plan under which participants may elect to purchase private insurance policies under a private exchange
and/or seek reimbursement of other eligible medical expenses.
86
Obligations and Funded Status - The following table sets forth our retirement and other postretirement benefit plans benefit
obligations and fair value of plan assets for the periods indicated:
Change in benefit obligation
Benefit obligation, beginning of period
Service cost
Interest cost
Plan participants’ contributions
Actuarial loss (gain)
Benefits paid
Benefit obligation, end of period
Change in plan assets
Fair value of plan assets, beginning of period
Actual return on plan assets
Employer contributions
Plan participants’ contributions
Benefits paid
Fair value of plan assets, end of period
Balance at December 31
Current liabilities
Noncurrent liabilities
Balance at December 31
Retirement Benefits
December 31,
Other Postretirement Benefits
December 31,
2019
2018
2019
(Thousands of dollars)
2018
$
$
$
$
$
466,994
7,825
20,528
—
55,954
(16,452)
534,849
$
481,615
7,339
17,659
—
(24,345)
(15,274)
466,994
290,684
58,060
14,500
—
(16,452)
346,792
(188,057) $
306,008
(12,350)
12,300
—
(15,274)
290,684
(176,310) $
(4,616) $
(4,514) $
(183,441)
(188,057) $
(171,796)
(176,310) $
$
46,840
468
2,038
1,142
5,101
(3,280)
52,309
30,800
8,087
2,000
1,142
(2,969)
39,060
(13,249) $
— $
(13,249)
(13,249) $
57,938
845
2,108
1,050
(10,233)
(4,868)
46,840
34,133
(998)
1,100
1,050
(4,485)
30,800
(16,040)
—
(16,040)
(16,040)
The table above includes the supplemental executive retirement plan obligation. ONEOK has investments included in other
assets on the Consolidated Balance Sheets, which totaled $98.9 million and $87.7 million at December 31, 2019 and 2018,
respectively, for the purpose of funding the obligation. These assets are not assets of the supplemental executive retirement
plan and are excluded from the table above.
The accumulated benefit obligation for our retirement plans was $498.8 million and $434.4 million at December 31, 2019 and
2018, respectively.
The actuarial gains and losses impacting our benefit obligations for our retirement and other postretirement benefit plans are
due primarily to changes in the discount rate assumptions discussed in the “Actuarial Assumptions” section below.
Components of Net Periodic Benefit Cost - The following table sets forth the components of net periodic benefit cost for our
retirement and other postretirement benefit plans for the periods indicated:
Retirement Benefits
Years Ended December 31,
2018
2017
2019
Other Postretirement Benefits
Years Ended December 31,
2018
2017
2019
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Amortization of net loss
Net periodic benefit cost
(Thousands of dollars)
$
$
7,825
20,528
(23,600)
—
12,649
17,402
$
$
7,339
17,659
(23,917)
—
17,060
18,141
$
$
6,896
18,645
(21,376)
—
13,586
17,751
$
$
468
2,038
(2,285)
(227)
297
291
$
$
845
2,108
(2,690)
(1,662)
1,338
$
(61) $
662
2,261
(2,257)
(1,662)
1,679
683
87
Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income
(loss) related to our retirement and other postretirement benefits for the periods indicated:
Retirement Benefits
Years Ended December 31,
2018
2019
2017
Other Postretirement Benefits
Years Ended December 31,
2018
2017
2019
Net gain (loss)
Prior service cost
Amortization of prior service credit
Amortization of net loss
Deferred income taxes (a)
Total recognized in other comprehensive income (loss)
$ (25,389) $ (16,351) $ (16,572) $
(601)
—
12,649
3,068
—
—
17,060
(18,928)
$ (10,273) $ (18,219) $
(Thousands of dollars)
700
—
(227)
297
(177)
593
—
—
13,586
(960)
(3,946) $
$
$
6,545
—
(1,662)
1,338
(2,831)
3,390
$
$
(328)
—
(1,662)
1,679
82
(229)
(a) - Year ended December 31, 2018, includes the impact of adopting ASU 2018-02, “Income Statement - Reporting Comprehensive Income
(Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.”
The table below sets 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:
Prior service credit (cost)
Accumulated loss
Accumulated other comprehensive loss
Deferred income taxes
Accumulated other comprehensive loss, net of tax
Retirement Benefits
December 31,
Other Postretirement Benefits
December 31,
2019
$
$
(601) $
(172,952)
(173,553)
46,354
(127,199) $
2018
2019
(Thousands of dollars)
— $
— $
(160,212)
(160,212)
43,286
(116,926) $
(4,110)
(4,110)
1,389
(2,721) $
2018
227
(5,108)
(4,881)
1,567
(3,314)
Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit
obligations for retirement and other postretirement benefits for the periods indicated:
Discount rate
Compensation increase rate
Retirement Benefits
December 31,
Other Postretirement Benefits
December 31,
2019
3.50%
3.70%
2018
4.50%
3.65%
2019
3.50%
NA
2018
4.50%
NA
The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods
indicated:
Discount rate - retirement plans
Discount rate - other postretirement plans
Expected long-term return on plan assets
Compensation increase rate
Years Ended December 31,
2018
3.75%
3.75%
8.00%
3.00%
2019
4.50%
4.50%
7.50%
3.65%
2017
4.50%
4.25%
7.75%
3.10%
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 determine our discount rates annually utilizing portfolios of high quality bonds matched to the estimated benefit cash flows
of our retirement and other postretirement benefit plans. Bonds selected to be included in the portfolios are only those rated by
S&P or Moody’s as an AA or Aa2 rating or better and exclude callable bonds, bonds with less than a minimum issue size, yield
outliers and other filtering criteria to remove unsuitable bonds.
88
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
7.00%
5.00%
2024
2018
6.50%
5.00%
2022
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. The investment policy for our defined benefit pension plan follows a glide
path approach toward liability-driven investing that shifts a higher portfolio weighting to fixed income as the plan’s funded
status increases. The purpose of liability-driven investing is to structure the asset portfolio to more closely resemble the
pension liability and thereby more effectively hedge against changes in the liability. The plan’s current investments include a
diverse blend of various domestic and international equities, investments in various classes of debt securities, real estate and
hedge funds. The target allocation for the assets of our retirement plan as of December 31, 2019, is as follows:
Domestic and international equities
Long duration fixed income
Return-seeking credit
Hedge funds
Real estate funds
Total
42%
30%
11%
10%
7%
100%
As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed
above.
The following tables set forth the plan assets by fair value category as of the measurement date for our defined benefit pension
and other postretirement benefit plans:
Pension Benefits
December 31, 2019
Asset Category
Level 1
Level 2
Level 3
Subtotal
Measured at
NAV (d)
Total
(Thousands of dollars)
$
Investments:
Equity securities (a)
Real estate funds
Government obligations
Corporate obligations (b)
Common/collective trusts
Cash
Other investments (c)
Fair value of plan assets
$
47
—
—
—
—
63
—
110
$
$
— $
—
—
—
3,263
—
—
3,263
$
— $
—
—
—
—
—
—
— $
47
—
—
—
3,263
63
—
3,373
$
$
149,985
23,885
50,708
85,898
—
—
32,943
343,419
$
$
150,032
23,885
50,708
85,898
3,263
63
32,943
346,792
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category represents alternative investments in limited partnerships, which can be redeemed with a 30-day notice with no further
restrictions. There are no unfunded capital commitments.
(d) - Plan asset investments measured at fair value using the net asset value per share.
89
Pension Benefits
December 31, 2018
Asset Category
Level 1
Level 2
Level 3
Subtotal
Measured at
NAV (d)
Total
(Thousands of dollars)
$
Investments:
Equity securities (a)
Real estate funds
Government obligations
Corporate obligations (b)
Common/collective trusts
Cash
Other investments (c)
Fair value of plan assets
$
58
—
—
—
—
95
—
153
$
$
— $
—
—
—
3,961
—
—
3,961
$
— $
—
—
—
—
—
—
— $
58
—
—
—
3,961
95
—
4,114
$
$
116,790
20,569
48,913
69,377
—
—
30,921
286,570
$
$
116,848
20,569
48,913
69,377
3,961
95
30,921
290,684
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category represents alternative investments in limited partnerships, which can be redeemed with a 30-day notice with no further
restrictions. There are no unfunded capital commitments.
(d) - Plan asset investments measured at fair value using the net asset value per share.
Other Postretirement Benefits
December 31, 2019
Asset Category
Level 1
Level 2
Level 3
Total
Investments:
Equity securities (a)
Money market funds
Insurance and group annuity contracts
Fair value of plan assets
(Thousands of dollars)
$
$
2,043
—
—
2,043
$
$
— $
2,428
34,589
37,017
$
— $
—
—
— $
2,043
2,428
34,589
39,060
(a) - This category represents securities of the respective market sector from diverse industries.
Other Postretirement Benefits
December 31, 2018
Asset Category
Level 1
Level 2
Level 3
Total
Investments:
Equity securities (a)
Money market funds
Insurance and group annuity contracts
Fair value of plan assets
(Thousands of dollars)
$
$
1,792
1
—
1,793
$
$
— $
413
28,594
29,007
$
— $
—
—
— $
1,792
414
28,594
30,800
(a) - This category represents securities of the respective market sector from diverse industries.
Contributions - During 2019, we made $14.5 million in contributions to our defined benefit pension plan and $2.0 million in
contributions to our other postretirement benefit plans. We contributed $12.1 million to our defined benefit pension plan in
January 2020 and expect to make $2.0 million in contributions to our other postretirement plans in the remainder of 2020.
90
Pension and Other Postretirement Benefit Payments - Benefit payments for our defined benefit pension and other
postretirement benefit plans for the period ending December 31, 2019, were $16.5 million and $3.3 million, respectively. The
following table sets forth the defined benefit pension and other postretirement benefits payments expected to be paid in 2020
through 2029:
Benefits to be paid in:
2020
2021
2022
2023
2024
2025 through 2029
Pension
Benefits
Other
Postretirement
Benefits
(Thousands of dollars)
$
$
$
$
$
$
18,277
19,252
20,202
21,170
22,228
123,959
$
$
$
$
$
$
3,422
3,399
3,519
3,454
3,446
16,385
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 covering all employees, and employee contributions are discretionary. We historically
maintained a profit-sharing plan for all employees hired after December 31, 2004, which was merged into our 401(k) Plan as of
December 31, 2018, and ceased to exist as a separate plan. We match 100% of employee 401(k) contributions up to 6% of each
participant’s eligible compensation, subject to certain limits, and generally make a quarterly profit sharing contribution equal to
1% of each profit-sharing participant’s eligible compensation during the quarter and an annual discretionary profit-sharing
contribution. Our contributions made to the plan, including profit-sharing contributions, were $30.4 million, $28 million and
$21.1 million in 2019, 2018 and 2017, respectively.
Nonqualified Deferred Compensation Plan - The 2019 Nonqualified Deferred Compensation Plan and its predecessor
nonqualified deferred compensation plans (collectively, the NQDC Plan) provide select employees, as approved by our Chief
Executive Officer, with the option to defer portions of their compensation and provide nonqualified deferred compensation
benefits that are not available due to limitations on employer and employee contributions to qualified defined contribution
plans under the federal tax laws. The NQDC Plan also provides benefits in excess of applicable tax limits for certain
participants in the defined benefit pension plan who are not participants in the supplemental executive retirement plan. Our
contributions to the plan were not material in 2019, 2018 and 2017.
L.
INCOME TAXES
The following table sets forth our provision for income taxes for the periods indicated:
Current tax expense (benefit)
Federal
State
Total current tax expense (benefit)
Deferred tax expense
Federal
State
Total deferred tax expense
Total provision for income taxes
2019
Years Ended December 31,
2018
(Thousands of dollars)
2017
$
$
(1,278) $
963
(315)
327,806
44,923
372,729
372,414
$
260
1,633
1,893
319,551
41,459
361,010
362,903
$
$
295
1,670
1,965
376,728
68,589
445,317
447,282
91
The following table is a reconciliation of our income tax provision for the periods indicated:
Income before income taxes
Less: Net income attributable to noncontrolling interests
Net income attributable to ONEOK before income taxes
Federal statutory income tax rate
Provision for federal income taxes
State income taxes, net of federal benefit
Deferred tax rate change, inclusive of valuation allowance
Excess tax benefits from share-based compensation
Other, net
Income tax provision
2019
Years Ended December 31,
2018
(Thousands of dollars)
$
$
$ 1,650,991
—
1,650,991
1,517,935
3,329
1,514,606
2017
1,040,801
205,678
835,123
21.0%
21.0%
35.0%
346,708
34,545
11,340
(20,983)
804
372,414
$
318,067
38,668
5,552
(4,644)
5,260
362,903
$
292,293
16,197
141,283
—
(2,491)
447,282
$
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
Federal net operating loss
State net operating loss and benefits
Derivative instruments
Other
Total deferred tax assets
Valuation allowance for state net operating loss and tax credits
Carryforward expected to expire prior to utilization
Net deferred tax assets
Deferred tax liabilities
Excess of tax over book depreciation
Investment in partnerships (a)
Total deferred tax liabilities
Net deferred tax assets (liabilities)
(a) Due primarily to excess of tax over book depreciation.
December 31,
December 31,
2019
2018
(Thousands of dollars)
$
$
$
99,510
858,030
171,779
83,710
12,769
1,225,798
(94,794)
1,131,004
84,631
1,582,436
1,667,067
(536,063) $
91,587
420,318
108,004
22,108
13,378
655,395
(73,820)
581,575
73,113
728,193
801,306
(219,731)
In December 2017, the Tax Cuts and Jobs Act was signed into law. The Tax Cuts and Jobs Act made extensive changes to the
U.S. tax laws and included provisions that, beginning in 2018, reduced the U.S. corporate tax rate to 21% from 35%, increased
expensing for capital investment, limited the interest deduction, and limited the use of net operating losses to offset future
taxable income. We revalued our deferred tax assets and liabilities as required at enactment. At that time, our net deferred tax
assets represented expected corporate tax benefits in the future. The reduction in the federal corporate tax rate reduced these
benefits, which resulted in a one-time noncash charge to net income through income tax expense of $141.3 million, inclusive of
the valuation allowance described below, recorded in the fourth quarter 2017.
Tax benefits related to certain state net operating loss, tax credit carryforwards and charitable contribution carryforwards will
begin expiring in 2020. Due to the Tax Cuts and Jobs Act and the impact of increased expensing for capital investment, we
believe that it is more likely than not that the tax benefits of certain carryforwards will not be utilized prior to their expirations;
therefore, we recorded a valuation allowance of $11.3 million, $5.6 million and $54.1 million through net income related to
these tax benefits in 2019, 2018 and 2017, respectively.
92
M.
UNCONSOLIDATED AFFILIATES
Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the
periods indicated:
Northern Border Pipeline
Overland Pass Pipeline
Roadrunner
Other
Investments in unconsolidated affiliates (a)
(a) - Equity-method goodwill (Note A) was $38.8 million at December 31, 2019 and 2018.
Net
Ownership
Interest
50%
50%
50%
Various
December 31,
December 31,
2019
2018
(Thousands of dollars)
$
$
307,209
417,473
80,816
56,346
861,844
$
$
381,623
429,295
93,857
64,375
969,150
Equity in Net Earnings from Investments and Impairments - The following table sets forth our equity in net earnings from
investments for the periods indicated:
Northern Border Pipeline
Overland Pass Pipeline
Roadrunner
Other
Equity in net earnings from investments
Impairment of equity investments
$
$
$
68,871
63,698
26,839
(4,867)
154,541
$
— $
67,854
65,887
22,993
1,649
158,383
$
— $
2019
Years Ended December 31,
2018
(Thousands of dollars)
$
$
2017
68,153
60,067
19,150
11,908
159,278
(4,270)
Impairment Charges - In 2017, following a review of nonstrategic assets for potential divestiture, we recorded $4.3 million of
noncash impairment charges related to a nonstrategic equity investment located in Oklahoma, which was later sold.
Unconsolidated Affiliates Financial Information - The following tables set forth summarized combined financial information
of our unconsolidated affiliates for the periods indicated:
Balance Sheet
Current assets
Property, plant and equipment, net
Other noncurrent assets
Current liabilities
Long-term debt
Other noncurrent liabilities
Accumulated other comprehensive income (loss)
Owners’ equity
December 31,
December 31,
2018
2019
(Thousands of dollars)
$
$
$
$
$
$
$
$
149,564
$
2,314,631
$
13,252
$
88,142
$
581,327
$
76,685
$
(28,373) $
$
1,759,666
158,723
2,413,662
16,273
83,057
480,731
47,826
2,053
1,974,991
93
Income Statement
Revenues
Operating expenses
Net income
Distributions paid to us (a)
2019
Years Ended December 31,
2018
(Thousands of dollars)
2017
$
$
$
$
634,135
291,210
315,274
257,644
$
$
$
$
637,762
276,373
337,694
197,285
$
$
$
$
639,102
277,121
347,692
196,114
(a) As determined by the Northern Border Pipeline Management Committee, we received an additional distribution of $50.0 million from
Northern Border Pipeline during the year ended December 31, 2019.
We incurred expenses in transactions with unconsolidated affiliates of $164.7 million, $153.9 million and $156.1 million for
2019, 2018 and 2017, respectively, primarily related to Overland Pass Pipeline and Northern Border Pipeline. Accounts
payable to our equity-method investees at December 31, 2019 and 2018, were $13.5 million and $14.7 million, respectively.
Northern Border Pipeline - The Northern Border Pipeline partnership agreement provides that distributions to Northern
Border Pipeline’s partners are to be made on a pro rata basis according to each partner’s percentage interest. The Northern
Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or
suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border
Pipeline Management Committee. Cash distributions are equal to 100% of distributable cash flow as determined from
Northern Border Pipeline’s financial statements based upon EBITDA less interest expense and maintenance capital
expenditures. Loans or other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit
agreement. In 2019 and 2018, we made no contributions to Northern Border Pipeline. In 2017, we made equity contributions
of $83 million to Northern Border Pipeline.
Northern Border Pipeline entered into a settlement with shippers that was approved by the FERC in February 2018. The
settlement provides for tiered rate reductions beginning January 1, 2018, that reduced tariff rates 12.5% by January 2020,
compared with previous tariff rates and requires new rates to be established by January 2024. We do not expect the impact of
lower tariff rates on Northern Border Pipeline’s earnings and cash distributions to be material to us.
Overland Pass Pipeline - The Overland Pass Pipeline agreement provides that distributions to Overland Pass Pipeline’s
members are to be made on a pro rata basis according to each member’s percentage interest. The Overland Pass Pipeline
Company Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of,
the cash distributions from Overland Pass Pipeline requires the unanimous approval of the Overland Pass Pipeline Company
Management Committee. Cash distributions are equal to 100% of available cash as defined in the limited liability company
agreement.
Roadrunner - The Roadrunner agreement provides that distributions to members are made on a pro rata basis according to
each member’s ownership interest. As the operator, we have been delegated the authority to determine such distributions in
accordance with, and on the frequency set forth in, the Roadrunner agreement. Cash distributions are equal to 100% of
available cash, as defined in the limited liability company agreement. In 2019, 2018 and 2017, our contributions to Roadrunner
were not material.
We have an operating agreement with Roadrunner that provides for reimbursement or payment to us for management services
and certain operating costs. Reimbursements and payments from Roadrunner included in operating income in our Consolidated
Statements of Income for the years ended December 31, 2019, 2018 and 2017, were not material.
94
N.
COMMITMENTS AND CONTINGENCIES
Commitments - Firm transportation and storage contracts are fixed-price contracts that provide us with firm transportation and
storage capacity. The following table sets forth our firm transportation and storage contract payments for the periods indicated:
2020
2021
2022
2023
2024
Thereafter
Total
Firm
Transportation
and Storage
Contracts
(Millions of
dollars)
$
$
61.6
48.1
40.1
36.4
34.3
177.9
398.4
Environmental Matters and Pipeline Safety - The operation of pipelines, plants and other facilities for the gathering,
processing, transportation and storage of natural gas, NGLs, condensate and other products is subject to numerous and complex
laws and regulations pertaining to health, safety and the environment. As an owner and/or operator of these facilities, we must
comply with laws and regulations that relate to air and water quality, hazardous and solid waste management and disposal,
cultural resource protection and other environmental matters. The cost of planning, designing, constructing and operating
pipelines, plants and other facilities must incorporate compliance with these laws and regulations and safety standards. Failure
to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement
measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial
requirements and the issuance of injunctions or restrictions on operation or construction. Management believes that, based on
currently known information, compliance with these laws and regulations will not affect adversely our results of operations,
financial condition or cash flows.
Legal Proceedings - Gas Index Pricing Litigation - As previously reported, we and our affiliate, ONEOK Energy Services
Company, L.P., along with several other energy companies, were named as defendants in multiple lawsuits arising from alleged
market manipulation or false reporting of natural gas prices to natural gas-index publications alleged to have occurred prior to
2003.
In September 2019, we settled Sinclair Oil Corporation v. ONEOK Energy Services Company, L.P. (filed in the United States
District Court for the District of Wyoming) for an immaterial amount with cash on hand. This was the last remaining case
arising from the Gas Index Pricing Litigation.
Other Legal Proceedings - We are a party to various other litigation matters and claims that have arisen in the normal course of
our operations. While the results of these litigation matters 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 affect adversely our consolidated results of operations, financial position or
cash flows.
O.
LEASES
Adoption of ASC Topic 842: Leases - We adopted Topic 842 using the modified retrospective method and the optional
transition method to record the adoption impact through a cumulative-effect adjustment to retained earnings as of January 1,
2019. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not
adjusted and continue to be reported under the accounting standards in effect for those periods.
Practical Expedients and Policies Elected - We applied the short-term policy election, which allows us to exclude from
recognition leases with an initial term of 12 months or less. We elected the hindsight expedient, which allows us to use
hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which among other things,
allows us to carry forward the historical lease classification; and the land easement expedient, which allows us to apply the
guidance prospectively at adoption for land easements on existing agreements.
95
Adoption - Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Consolidated Balance
Sheet of $17.5 million and $17.4 million, respectively, as of January 1, 2019. The difference between the lease assets and lease
liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact
of adopting the standard. Our accounting for finance leases did not change. Adoption of Topic 842 did not materially impact
our Consolidated Financial Statements.
Leases - We lease certain buildings, warehouses, office space, pipeline capacity, land and equipment, including pipeline
equipment, rail cars, and information technology equipment. Our lease payments are generally straight-line and the exercise of
lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in a lease term if we are
reasonably certain to exercise available renewal options. Our lease agreements do not include any residual value guarantees or
material restrictive covenants.
Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own an office building and a parking
garage and lease excess space in these facilities to affiliates and others. Our consolidated lease income is not material.
The following table sets forth supplemental information about our cash flows:
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for operating leases
Financing cash flows for finance lease
Right-of-use assets obtained in exchange for operating lease liabilities (noncash)
Year Ended
December 31, 2019
(Thousands of dollars)
$
$
$
6,213
1,764
4,097
The following table sets forth information about our lease assets and liabilities included in our Consolidated Balance Sheet for
the period indicated:
Leases
Assets
Operating leases
Finance lease
Finance lease
Total leased assets
Liabilities
Current
Operating leases
Finance lease
Noncurrent
Operating leases
Finance lease
Total lease liabilities
Location in our Consolidated
Balance Sheet
December 31, 2019
(Thousands of dollars)
Other assets
Property, plant and equipment
Accumulated depreciation
Other current liabilities
Finance lease liability
Other deferred credits
Finance lease liability
$
$
$
$
15,147
28,286
(1,320)
42,113
1,883
1,949
13,509
24,296
41,637
96
The following table sets forth information about our leases for the period indicated:
Location in our
Consolidated
Statement of Income
Year Ended
December 31, 2019
Lease Cost
(Thousands of
dollars)
Operations and
maintenance
Depreciation and
amortization
Interest expense
$
$
6,803
1,131
2,721
10,655
At December 31, 2019
Weighted-Average
Remaining
Lease Term
Weighted-Average
Discount
Rate (a)
(Years)
10.4
8.8
4.58%
10.00%
Operating leases
Finance lease
Amortization of lease assets
Interest on lease liabilities
Total lease cost
(a) - Our weighted-average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the
remaining term of the lease.
The following table sets forth the maturity of our lease liabilities as of December 31, 2019:
2020
2021
2022
2023
2024
2025 and beyond
Total lease payments
Less: Interest
Present value of lease liabilities
Finance
Lease
Operating
Leases
(Millions of dollars)
4.5
4.5
4.5
4.5
4.5
17.1
39.6
13.4
26.2
$
$
2.5
2.1
2.0
1.9
1.9
9.2
19.6
4.2
15.4
$
$
Our future lease payments presented under the previous accounting standard as of December 31, 2018, are not materially
different than those presented above.
As of December 31, 2019, we have entered into an additional operating lease that had not yet commenced with an estimated
present value of $75.6 million and a lease term of 10 years, which is excluded from our maturities table above and our lease
right-of-use assets and liabilities.
P.
REVENUES
Accounting Policies - See Note A for revenue recognition accounting policies.
97
Contract Assets and Contract Liabilities - The following tables set forth the changes in our contract asset and contract
liability balances for the periods indicated:
Contract Assets
Balance at January 1, 2018 (a)
Amounts invoiced in excess of revenue recognized
Net additions
Balance at December 31, 2018 (b)
Amounts invoiced in excess of revenue recognized
Net additions
Balance at December 31, 2019 (c)
(Millions of dollars)
6.4
$
(0.9)
0.7
6.2
(1.7)
0.5
5.0
$
(a) - Balance includes $0.9 million of current assets.
(b) - Contract assets of $1.7 million and $4.5 million are included in other current assets and other assets, respectively, in our Consolidated
Balance Sheet.
(c) - Contract assets of $1.3 million and $3.7 million are included in other current assets and other assets, respectively, in our Consolidated
Balance Sheet.
Contract Liabilities
Balance at January 1, 2018 (a)
Revenue recognized included in beginning balance
Net additions
Balance at December 31, 2018 (b)
Revenue recognized included in beginning balance
Net additions
Balance at December 31, 2019 (c)
(Millions of dollars)
33.3
$
(19.5)
17.9
31.7
(15.6)
41.0
57.1
$
(a) - Balance includes $19.5 million of current liabilities.
(b) - Contract liabilities of $15.6 million and $16.1 million are included in other current liabilities and other deferred credits, respectively, in
our Consolidated Balance Sheet.
(c) - Contract liabilities of $22.2 million and $34.9 million are included in other current liabilities and other deferred credits, respectively, in
our Consolidated Balance Sheet.
In 2019, net additions for contract liabilities relate primarily to deferred revenue on contributions in aid of construction
received from customers and NGL storage contracts.
Receivables from Customers and Revenue Disaggregation - Substantially all of the balances in accounts receivable on our
Consolidated Balance Sheets at December 31, 2019, and December 31, 2018, relate to customer receivables. Revenues sources
are disaggregated in Note Q.
Practical Expedients - We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original
expected length of one year or less and (ii) variable consideration on contracts for which we recognize revenue at the amount to
which we have the right to invoice for services performed.
Transaction Price Allocated to Unsatisfied Performance Obligations - The following table presents aggregate value
allocated to unsatisfied performance obligations as of December 31, 2019, and the amounts we expect to recognize in revenue
in future periods, related primarily to firm transportation and storage contracts with remaining contract terms ranging from one
month to 24 years:
Expected Period of Recognition in Revenue
2020
2021
2022
2023
2024 and beyond
Total estimated transaction price allocated to unsatisfied performance obligations
(Millions of dollars)
343.5
$
290.4
214.8
166.4
807.2
1,822.3
$
The table above excludes variable consideration allocated entirely to wholly unsatisfied performance obligations, wholly
unsatisfied promises to transfer distinct goods or services that are part of a single performance obligation and consideration we
determine to be fully constrained. Information on the nature of the variable consideration excluded and the nature of the
98
performance obligations to which the variable consideration relates can be found in the description of the major contract types
discussed in Note A. The amounts we determined to be fully constrained relate to future sales obligations under long-term
sales contracts where the transaction price is not known and minimum volume agreements, which we consider to be fully
constrained until invoiced.
Q.
SEGMENTS
Segment Descriptions - Our operations are divided into three reportable business segments, as follows:
•
•
•
our Natural Gas Gathering and Processing segment gathers, treats and processes natural gas;
our Natural Gas Liquids segment gathers, treats, fractionates and transports NGLs and stores, markets and distributes
NGL products; and
our Natural Gas Pipelines segment operates regulated interstate and intrastate natural gas transmission pipelines and
natural gas storage facilities.
Other and eliminations consist of corporate costs, the operating and leasing activities of our headquarters building and related
parking facility and eliminations necessary to reconcile our reportable segments to our Consolidated Financial Statements.
Accounting Policies - The accounting policies of the segments are described in Note A.
For each of the years ended December 31, 2019, 2018 and 2017, we had no single customer from which we received 10% or
more of our consolidated revenues.
Operating Segment Information - The following tables set forth certain selected financial information for our operating
segments for the periods indicated:
Year Ended December 31, 2019
NGL and condensate sales
Residue natural gas sales
Gathering, processing and exchange services revenue
Transportation and storage revenue
Other
Total revenues (c)
Cost of sales and fuel (exclusive of depreciation and operating costs)
Operating costs
Equity in net earnings from investments
Noncash compensation expense and other
Segment adjusted EBITDA
Depreciation and amortization
Investments in unconsolidated affiliates
Total assets
Capital expenditures
Natural Gas
Gathering and
Processing
Natural Gas
Liquids (a)
Natural Gas
Pipelines (b)
Total
Segments
1,224,378
966,149
164,299
—
13,813
2,368,639
(1,302,310)
(368,352)
(6,292)
10,965
702,650
$
$
— $
$
(Thousands of dollars)
7,910,833
—
414,238
197,483
9,962
8,532,516
(6,690,918)
(456,892)
65,123
15,936
1,465,765
1,244
—
466,266
4,477
471,987
(4,628)
(157,230)
95,710
2,977
408,816
$
9,135,211
967,393
578,537
663,749
28,252
11,373,142
(7,997,856)
(982,474)
154,541
29,878
2,577,231
$
(196,132) $
(219,519) $
$
$
439,393
34,426
$
$ 12,551,476
6,795,744
$
2,796,604
$
926,489
(472,901)
(57,250) $
$
388,025
861,844
$ 21,441,292
2,094,072
3,822,314
$
99,221
$
$
$
$
$
$
(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations
had revenues of $1.4 billion, of which $1.2 billion related to sales within the segment, and cost of sales and fuel of $496.8 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated
operations had revenues of $285.3 million and cost of sales and fuel of $20.0 million.
(c) - Intersegment revenues for the Natural Gas Gathering and Processing segment totaled $1.2 billion. Intersegment revenues for the Natural
Gas Liquids and Natural Gas Pipelines segments were not material.
99
Year Ended December 31, 2019
Reconciliations of total segments to consolidated
NGL and condensate sales
Residue natural gas sales
Gathering, processing and exchange services revenue
Transportation and storage revenue
Other
Total revenues (a)
Total
Segments
Other and
Eliminations
(Thousands of dollars)
Total
$
9,135,211
967,393
578,537
663,749
28,252
$ 11,373,142
$ (1,190,424) $
7,944,787
965,975
578,537
648,103
26,965
$ (1,208,775) $ 10,164,367
(1,418)
—
(15,646)
(1,287)
Cost of sales and fuel (exclusive of depreciation and operating costs)
Operating costs
Depreciation and amortization
Equity in net earnings from investments
Investments in unconsolidated affiliates
Total assets
Capital expenditures
$ (7,997,856) $
(982,474) $
$
(472,901) $
$
$
154,541
$
$
$
861,844
$
$ 21,441,292
$
3,822,314
$
1,209,816
(390) $
(3,634) $
— $
— $
370,829
26,035
$ (6,788,040)
(982,864)
(476,535)
154,541
861,844
$ 21,812,121
3,848,349
$
(a) - Noncustomer revenue for the year ended December 31, 2019, totaled $139.6 million related primarily to gains from derivatives on
commodity contracts.
Year Ended December 31, 2018
NGL and condensate sales
Residue natural gas sales
Gathering, processing and exchange services revenue
Transportation and storage revenue
Other
Total revenues (c)
Cost of sales and fuel (exclusive of depreciation and operating costs)
Operating costs
Equity in net earnings from investments
Noncash compensation expense and other
Segment adjusted EBITDA
Depreciation and amortization
Investments in unconsolidated affiliates
Total assets
Capital expenditures
Natural Gas
Gathering and
Processing
Natural Gas
Liquids (a)
Natural Gas
Pipelines (b)
Total
Segments
(Thousands of dollars)
$
$
$
$
$
$
1,775,991
1,084,162
163,194
—
11,230
3,034,577
(2,041,448)
(368,939)
410
7,007
631,607
$ 10,319,847
—
404,897
199,018
10,816
10,934,578
(9,176,813)
(394,115)
67,126
9,829
1,440,605
$
$
$
— $ 12,095,838
1,093,934
568,091
613,987
29,040
14,400,890
(11,234,245)
(907,313)
158,383
20,748
2,438,463
9,772
—
414,969
6,994
431,735
(15,984)
(144,259)
90,847
3,912
366,251
$
(196,090) $
$
42,630
$
6,078,473
$
694,611
(174,007) $
$
451,040
$
9,663,640
$
1,306,341
(425,215)
(55,118) $
$
475,480
969,150
$ 17,873,782
2,131,669
2,120,137
$
119,185
(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations
had revenues of $1.2 billion, of which $1.1 billion related to sales within the segment, and cost of sales and fuel of $506.0 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated
operations had revenues of $266.6 million and cost of sales and fuel of $26.0 million.
(c) - Intersegment revenues for the Natural Gas Gathering and Processing segment totaled $1.8 billion. Intersegment revenues for the Natural
Gas Liquids and Natural Gas Pipelines segments were not material.
100
Year Ended December 31, 2018
Reconciliations of total segments to consolidated
NGL and condensate sales
Residue natural gas sales
Gathering, processing and exchange services revenue
Transportation and storage revenue
Other
Total revenues (a)
Cost of sales and fuel (exclusive of depreciation and operating costs)
Operating costs
Depreciation and amortization
Equity in net earnings from investments
Investments in unconsolidated affiliates
Total assets
Capital expenditures
Total
Segments
Other and
Eliminations
(Thousands of dollars)
Total
$ 12,095,838
1,093,934
568,091
613,987
29,040
$ 14,400,890
$ (1,794,342) $ 10,301,496
1,091,102
568,070
603,437
29,091
$ (1,807,694) $ 12,593,196
(2,832)
(21)
(10,550)
51
$ (11,234,245) $
(907,313) $
$
(425,215) $
$
$
158,383
$
$
$
969,150
$
$ 17,873,782
$
2,120,137
$
$ (9,422,708)
1,811,537
(907,068)
245
$
(428,557)
(3,342) $
158,383
— $
969,150
— $
$ 18,231,671
2,141,475
$
357,889
21,338
(a) - Noncustomer revenue for the year ended December 31, 2018, totaled $(16.2) million related primarily to losses from derivatives on
commodity contracts.
Year Ended December 31, 2017
Sales to unaffiliated customers
Intersegment revenues
Total revenues
Cost of sales and fuel (exclusive of depreciation and operating costs)
Operating costs
Equity in net earnings from investments
Other
Segment adjusted EBITDA
Depreciation and amortization
Impairment of long-lived assets and equity investments
Investments in unconsolidated affiliates
Total assets
Capital expenditures
Natural Gas
Gathering and
Processing
Natural Gas
Liquids (a)
Natural Gas
Pipelines (b)
Total
Segments
(Thousands of dollars)
$
$
$
$
$
$
$
1,750,655
1,275,919
3,026,574
(2,216,355)
(307,376)
12,098
3,531
518,472
$ 10,009,576
616,628
10,626,204
(9,176,494)
(358,278)
59,876
3,631
1,154,939
$
$
$
411,490
8,442
419,932
(43,424)
(125,308)
87,304
1,314
339,818
$ 12,171,721
1,900,989
14,072,710
(11,436,273)
(790,962)
159,278
8,476
2,013,229
$
(184,923) $
(20,240) $
$
55,841
$
5,495,163
$
284,205
(167,277) $
— $
$
$
$
457,467
8,782,700
114,267
(403,225)
(51,025) $
(20,240)
— $
$
1,003,156
$ 16,332,883
494,036
$
489,848
2,055,020
95,564
(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations
had revenues of $1.2 billion, of which $1.0 billion related to sales within the segment, and cost of sales and fuel of $497.4 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated
operations had revenues of $264.9 million and cost of sales and fuel of $44.0 million.
101
Year Ended December 31, 2017
Reconciliations of total segments to consolidated
Sales to unaffiliated customers
Intersegment revenues
Total revenues
Cost of sales and fuel (exclusive of depreciation and operating costs)
Operating costs
Depreciation and amortization
Impairment of long-lived assets and equity investments
Equity in net earnings from investments
Investments in unconsolidated affiliates
Total assets
Capital expenditures
Total
Segments
Other and
Eliminations
(Thousands of dollars)
Total
$ 12,171,721
1,900,989
$ 14,072,710
$
2,186
(1,900,989)
$ 12,173,907
—
$ (1,898,803) $ 12,173,907
$ (11,436,273) $
(790,962) $
$
(403,225) $
$
(20,240) $
$
$
159,278
$
$
$
1,003,156
$
$ 16,332,883
$
494,036
$
1,898,228
(31,748) $
(3,110) $
$ (9,538,045)
(822,710)
(406,335)
(20,240)
159,278
1,003,156
$ 16,845,937
512,393
$
— $
— $
— $
513,054
18,357
Reconciliation of net income to total segment adjusted EBITDA
Net income
Add:
Interest expense, net of capitalized interest
Depreciation and amortization
Income taxes
Impairment charges
Noncash compensation expense
Other corporate costs and noncash items (a)
Total segment adjusted EBITDA
$
$
2019
Years Ended December 31,
2018
(Thousands of dollars)
$
1,155,032
$
1,278,577
2017
593,519
491,773
476,535
372,414
—
26,699
(68,767)
2,577,231
$
469,620
428,557
362,903
—
37,954
(15,603)
2,438,463
$
485,658
406,335
447,282
20,240
13,421
46,774
2,013,229
(a) - The year ended December 31, 2019, includes higher equity AFUDC related to our capital-growth projects compared with 2018 and
2017. The year ended December 31, 2017, includes our April 2017 $20.0 million contribution of Series E Preferred Stock to the Foundation
and costs related to the Merger Transaction of $30.0 million.
R.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Year Ended December 31, 2019
Total revenues
Operating income
Net income
Net income available to common shareholders
Earnings per share total
Basic
Diluted
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Thousands of dollars, except per share amounts)
$
$
$
$
$
$
2,779,958
468,742
337,208
336,933
0.82
0.81
$
$
$
$
$
$
2,457,575
476,146
311,963
311,688
0.75
0.75
$
$
$
$
$
$
2,263,228
482,151
309,155
308,880
0.75
0.74
$
$
$
$
$
$
2,663,606
487,314
320,251
319,976
0.77
0.77
102
Year Ended December 31, 2018
Total revenues
Operating income
Net income
Net income available to common shareholders
Earnings per share total
Basic
Diluted
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Thousands of dollars except per share amounts)
$
$
$
$
$
$
3,102,077
419,699
266,049
264,233
0.65
0.64
$
$
$
$
$
$
2,960,529
448,366
282,179
280,773
0.68
0.68
$
$
$
$
$
$
3,393,890
495,534
313,916
312,984
0.76
0.75
$
$
$
$
$
$
3,136,700
471,865
292,888
292,613
0.71
0.70
S.
SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
ONEOK and ONEOK Partners are issuers of certain public debt securities. We, ONEOK Partners and the Intermediate
Partnership have cross guarantees in place for the indebtedness of ONEOK and ONEOK Partners. The Intermediate
Partnership holds all of ONEOK Partners’ interests and equity in its subsidiaries, as well as a 50% interest in Northern Border
Pipeline. In lieu of providing separate financial statements for each subsidiary issuer and guarantor, we have included the
accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have
presented each of the parent and subsidiary issuers in separate columns in this single set of condensed consolidating financial
statements.
For purposes of the following footnote:
• we are referred to as “Parent Issuer and Guarantor”;
• ONEOK Partners is referred to as “Subsidiary Issuer and Guarantor”;
•
•
the Intermediate Partnership is referred to as “Guarantor Subsidiary”; and
the “Non-Guarantor Subsidiaries” are all subsidiaries other than the Guarantor Subsidiary and Subsidiary Issuer and
Guarantor.
The following supplemental condensed consolidating financial information is presented on an equity-method basis reflecting
the separate accounts of ONEOK, ONEOK Partners and the Intermediate Partnership, the combined accounts of the Non-
Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and our consolidated amounts for the
periods indicated.
103
Condensed Consolidating Statements of Income
Year Ended December 31, 2019
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
(Millions of dollars)
Revenues
Commodity sales
Services
Total revenues
Cost of sales and fuel (exclusive of items
shown separately below)
Operating expenses
(Gain) loss on sale of assets
Operating income
Equity in net earnings from investments
Other income (expense), net
Interest expense, net
Income before income taxes
Income taxes
Net income
Less: Preferred stock dividends
Net income available to common
shareholders
Net income
Other comprehensive income (loss), net of
tax
$
$
$
— $
—
—
— $
—
—
— $
—
—
8,916.1
1,250.4
10,166.5
—
—
—
—
1,898.7
34.4
(287.4)
1,645.7
(367.1)
1,278.6
1.1
1,277.5
1,278.6
$
$
—
—
—
—
1,906.2
305.7
(308.3)
1,903.6
—
1,903.6
—
1,903.6
1,903.6
$
$
—
—
2.7
(2.7)
1,908.9
308.3
(308.3)
1,906.2
—
1,906.2
—
1,906.2
1,906.2
$
$
6,788.0
1,461.5
(0.1)
1,917.1
116.3
42.1
(204.4)
1,871.1
(5.3)
1,865.8
—
1,865.8
1,865.8
Total
8,916.1
1,248.3
10,164.4
6,788.0
1,459.4
2.6
1,914.4
154.5
73.9
(491.8)
1,651.0
(372.4)
1,278.6
1.1
$
— $
(2.1)
(2.1)
—
(2.1)
—
—
(5,675.6)
(616.6)
616.6
(5,675.6)
—
(5,675.6)
—
$
$
(5,675.6) $
1,277.5
(5,675.6) $
1,278.6
(183.8)
(2.6)
(20.9)
(20.5)
42.0
(185.8)
Comprehensive income
$
1,094.8
$
1,901.0
$
1,885.3
$
1,845.3
$
(5,633.6) $
1,092.8
104
Year Ended December 31, 2018
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
Total
(Millions of dollars)
Revenues
Commodity sales
Services
Total revenues
Cost of sales and fuel (exclusive of items
shown separately below)
Operating expenses
Gain on sale of assets
Operating income
Equity in net earnings from investments
Other income (expense), net
Interest expense, net
Income before income taxes
Income taxes
Net income
Less: Net income attributable to
noncontrolling interests
Net income attributable to ONEOK
Less: Preferred stock dividends
Net income available to common
shareholders
Net income
Other comprehensive income (loss), net of
tax
Comprehensive income
Less: Comprehensive income attributable to
noncontrolling interests
Comprehensive income attributable to
ONEOK
$
$
$
— $
—
—
— $
—
—
— $
—
—
$
11,395.6
1,199.7
12,595.3
— $ 11,395.6
1,197.6
12,593.2
(2.1)
(2.1)
—
(0.6)
—
0.6
1,655.6
29.6
(179.4)
1,506.4
(354.7)
1,151.7
—
1,151.7
1.1
1,150.6
1,151.7
(39.5)
1,112.2
$
$
—
—
—
—
1,660.5
315.1
(315.1)
1,660.5
—
1,660.5
—
1,660.5
—
1,660.5
1,660.5
101.1
1,761.6
$
$
—
—
—
—
1,660.5
315.1
(315.1)
1,660.5
—
1,660.5
—
1,660.5
—
1,660.5
1,660.5
85.9
1,746.4
$
$
9,422.7
1,338.3
(0.6)
1,834.9
116.3
(36.0)
(290.2)
1,625.0
(8.2)
1,616.8
3.3
1,613.5
—
1,613.5
1,616.8
62.6
1,679.4
—
(2.1)
—
—
(4,934.5)
(630.2)
630.2
(4,934.5)
—
(4,934.5)
—
(4,934.5)
—
9,422.7
1,335.6
(0.6)
1,835.5
158.4
(6.4)
(469.6)
1,517.9
(362.9)
1,155.0
3.3
1,151.7
1.1
$
$
(4,934.5) $
1,150.6
(4,934.5) $
1,155.0
(171.7)
(5,106.2)
38.4
1,193.4
—
—
—
3.3
—
3.3
$
1,112.2
$
1,761.6
$
1,746.4
$
1,676.1
$
(5,106.2) $
1,190.1
105
$
$
$
Revenues
Commodity sales
Services
Total revenues
Cost of sales and fuel (exclusive of items
shown separately below)
Operating expenses
Impairment of long-lived assets
Gain on sale of assets
Operating income
Equity in net earnings from investments
Impairment of equity investments
Other income (expense), net
Interest expense, net
Income before income taxes
Income taxes
Net income
Less: Net income attributable to
noncontrolling interests
Net income attributable to ONEOK
Less: Preferred stock dividends
Net income available to common
shareholders
Net income
Other comprehensive income (loss), net of
tax
Comprehensive income
Less: Comprehensive income attributable to
noncontrolling interests
Comprehensive income attributable to
ONEOK
Year Ended December 31, 2017
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
(Millions of dollars)
— $
—
—
— $
—
—
— $
—
—
9,862.7
2,313.2
12,175.9
—
—
—
—
—
1,215.7
—
353.1
(353.1)
1,215.7
—
1,215.7
—
1,215.7
—
1,215.7
1,215.7
13.2
1,228.9
$
$
—
9.2
—
—
(9.2)
1,224.9
—
353.1
(353.1)
1,215.7
—
1,215.7
—
1,215.7
—
1,215.7
1,215.7
27.9
1,243.6
$
$
9,538.0
1,204.0
16.0
(0.9)
1,418.8
100.7
(4.3)
(8.0)
(348.6)
1,158.6
32.9
1,191.5
4.3
1,187.2
—
1,187.2
1,191.5
34.5
1,226.0
—
17.8
—
—
(17.8)
1,236.6
—
(12.3)
(137.1)
1,069.4
(480.2)
589.2
201.4
387.8
0.8
387.0
589.2
17.4
606.6
232.4
$
$
Total
9,862.7
2,311.2
12,173.9
9,538.0
1,229.0
16.0
(0.9)
1,391.8
159.3
(4.3)
(20.3)
(485.7)
1,040.8
(447.3)
593.5
205.7
387.8
0.8
$
— $
(2.0)
(2.0)
—
(2.0)
—
—
—
(3,618.6)
—
(706.2)
706.2
(3,618.6)
—
(3,618.6)
—
(3,618.6)
—
$
$
(3,618.6) $
387.0
(3,618.6) $
593.5
(55.9)
(3,674.5)
37.1
630.6
236.7
—
—
4.3
—
$
374.2
$
1,228.9
$
1,243.6
$
1,221.7
$
(3,674.5) $
393.9
106
Condensed Consolidating Balance Sheets
December 31, 2019
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
Total
(Millions of dollars)
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Natural gas and NGLs in storage
Other current assets
Total current assets
Property, plant and equipment
Property, plant and equipment
Accumulated depreciation and
amortization
Net property, plant and equipment
Investments and other assets
Investments
Intercompany notes receivable
Other assets
Total investments and other assets
Total assets
Liabilities and equity
Current liabilities
Current maturities of long-term debt
Short-term borrowings
Accounts payable
Other current liabilities
Total current liabilities
Intercompany payables
$
$
21.0
—
—
—
12.4
33.4
166.6
99.5
67.1
— $
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
6,732.6
8,950.9
139.9
15,823.4
$ 15,923.9
4,101.4
6,903.2
—
11,004.6
$ 11,004.6
11,466.3
—
—
11,466.3
$ 11,466.3
$
$
— $
220.0
23.8
243.8
487.6
—
— $
—
—
63.3
63.3
— $
—
—
—
—
— $
835.1
201.7
304.9
95.2
1,436.9
21,884.9
3,603.3
18,281.6
769.9
—
992.1
1,762.0
21,480.5
7.7
—
1,186.1
275.6
1,469.4
$
$
— $
—
—
—
—
—
21.0
835.1
201.7
304.9
107.6
1,470.3
—
—
—
22,051.5
3,702.8
18,348.7
861.8
(22,208.4)
—
(15,854.1)
1,131.3
(0.7)
(38,063.2)
1,993.1
(38,063.2) $ 21,812.1
— $
—
—
—
—
7.7
220.0
1,209.9
582.7
2,020.3
—
7,364.9
8,489.2
(15,854.1)
—
Long-term debt, excluding current
maturities
8,421.1
4,045.1
Deferred credits and other liabilities
Deferred income taxes
Other deferred credits
Total deferred credits and other
liabilities
Commitments and contingencies
417.1
372.1
789.2
—
—
—
—
—
—
—
13.5
—
12,479.7
119.7
177.9
297.6
(0.7)
—
536.1
550.0
(0.7)
1,086.1
Equity
Total liabilities and equity
6,226.0
$ 15,923.9
6,896.2
$ 11,004.6
4,101.4
$ 11,466.3
$
11,210.8
21,480.5
$
(22,208.4)
6,226.0
(38,063.2) $ 21,812.1
107
December 31, 2018
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
Total
(Millions of dollars)
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Natural gas and NGLs in storage
Other current assets
Total current assets
Property, plant and equipment
Property, plant and equipment
Accumulated depreciation and
amortization
Net property, plant and equipment
Investments and other assets
Investments
Intercompany notes receivable
Other assets
Total investments and other assets
Total assets
Liabilities and equity
Current liabilities
$
$
12.0
—
—
—
29.1
41.1
145.5
92.0
53.5
— $
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
6,153.5
5,308.6
115.9
11,578.0
$ 11,672.6
3,548.1
7,701.5
—
11,249.6
$ 11,249.6
9,721.6
1,528.0
—
11,249.6
$ 11,249.6
$
Current maturities of long-term debt
Accounts payable
Other current liabilities
Total current liabilities
$
— $
31.3
123.2
154.5
$
500.0
—
81.0
581.0
— $
—
—
—
— $
819.0
141.2
296.7
100.6
1,357.5
17,885.5
3,172.3
14,713.2
791.1
—
982.3
1,773.4
17,844.1
7.7
1,085.0
280.2
1,372.9
$
$
— $
—
—
—
—
—
12.0
819.0
141.2
296.7
129.7
1,398.6
—
—
—
18,031.0
3,264.3
14,766.7
969.2
(19,245.1)
—
(14,538.1)
1,097.2
(1.0)
(33,784.2)
2,066.4
(33,784.2) $ 18,231.7
— $
—
—
—
507.7
1,116.3
484.4
2,108.4
Intercompany payables
—
—
7,701.5
6,836.6
(14,538.1)
—
Long-term debt, excluding current
maturities
4,510.7
4,341.4
Deferred credits and other liabilities
Deferred income taxes
Other deferred credits
Total deferred credits and other
liabilities
Commitments and contingencies
112.3
315.6
427.9
—
—
—
—
—
—
—
21.2
—
8,873.3
108.4
135.2
243.6
(1.0)
—
(1.0)
219.7
450.8
670.5
Equity
Total liabilities and equity
6,579.5
$ 11,672.6
6,327.2
$ 11,249.6
3,548.1
$ 11,249.6
$
9,369.8
17,844.1
$
(19,245.1)
6,579.5
(33,784.2) $ 18,231.7
108
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2019
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
Total
(Millions of dollars)
Operating activities
Cash provided by operating activities
$
1,010.1
$
1,332.9
$
68.9
$
2,198.9
$
(2,664.0) $
1,946.8
Investing activities
Capital expenditures
Other investing activities
Cash provided by (used in) investing
activities
Financing activities
Dividends paid
Intercompany borrowings (advances), net
Short-term borrowings, net
Issuance of long-term debt, net of
discounts
Repayment of long-term debt
Issuance of common stock
Other, net
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
(25.6)
—
(25.6)
(1,457.6)
(3,618.6)
220.0
4,185.4
(249.6)
29.0
(84.1)
—
—
—
—
74.6
74.6
(1,332.0)
801.8
—
(1,332.0)
1,188.5
—
—
(800.0)
—
(2.7)
—
—
—
—
(3,822.7)
4.9
(3,817.8)
—
1,628.3
—
—
(7.7)
—
(1.7)
—
—
—
2,664.0
—
—
—
—
—
—
(975.5)
9.0
(1,332.9)
—
(143.5)
—
1,618.9
—
2,664.0
—
(3,848.3)
79.5
(3,768.8)
(1,457.6)
—
220.0
4,185.4
(1,057.3)
29.0
(88.5)
1,831.0
9.0
12.0
—
—
—
—
12.0
$
21.0
$
— $
— $
— $
— $
21.0
109
Year Ended December 31, 2018
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
Total
(Millions of dollars)
Operating activities
Cash provided by operating activities
$
1,325.1
$
1,344.7
$
67.9
$
2,113.0
$
(2,664.0) $
2,186.7
Investing activities
Capital expenditures
Other investing activities
Cash provided by (used in) investing
activities
Financing activities
Dividends paid
Distributions to noncontrolling interests
Intercompany borrowings (advances), net
Repayment of short-term borrowings, net
Issuance of long-term debt, net of
discounts
Repayment of long-term debt
Issuance of common stock
Acquisition of noncontrolling interests
Other, net
Cash 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
(18.8)
—
(18.8)
(1,335.1)
—
(2,154.4)
(614.7)
1,795.8
—
1,204.0
(195.0)
(32.1)
(1,331.5)
(25.2)
—
—
—
(1,332.0)
—
912.3
—
—
(925.0)
—
—
—
(1,344.7)
—
—
15.3
15.3
(1,332.0)
—
1,248.8
—
—
—
—
—
—
(83.2)
—
37.2
—
—
(2,122.7)
11.3
(2,111.4)
—
(3.5)
(6.7)
—
—
(7.7)
—
—
16.3
(1.6)
—
—
—
—
—
2,664.0
—
—
—
—
—
—
—
—
2,664.0
—
(2,141.5)
26.6
(2,114.9)
(1,335.1)
(3.5)
—
(614.7)
1,795.8
(932.7)
1,204.0
(195.0)
(15.8)
(97.0)
(25.2)
—
37.2
$
12.0
$
— $
— $
— $
— $
12.0
110
Year Ended December 31, 2017
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries and
Other
Total
(Millions of dollars)
Operating activities
Cash provided by operating activities
$
947.4
$
1,348.3
$
59.0
$
1,353.7
$
(2,393.0) $
1,315.4
Investing activities
Capital expenditures
Contributions to unconsolidated affiliates
Other investing activities
Cash used in investing activities
Financing activities
Dividends paid
Distributions to noncontrolling interests
Intercompany borrowings (advances), net
Borrowing (repayment) of short-term
borrowings, net
Issuance of long-term debt, net of
discounts
Repayment of long-term debt
Issuance of common stock
Other, net
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
—
—
—
—
—
—
—
—
—
(83.0)
14.8
(68.2)
(829.4)
—
(2,500.7)
(1,332.0)
—
2,001.2
(1,332.0)
—
1,340.8
614.7
(1,110.3)
1,190.5
(87.1)
471.4
(18.1)
—
(900.0)
—
(7.2)
(1,158.7)
(211.3)
(1,348.3)
—
248.5
—
—
—
—
—
—
8.8
(0.4)
0.4
(512.4)
(4.9)
17.9
(499.4)
—
(5.3)
(841.3)
—
—
(7.7)
—
—
—
—
—
—
2,664.0
(271.0)
—
—
—
—
—
—
(854.3)
—
2,393.0
—
(512.4)
(87.9)
32.7
(567.6)
(829.4)
(276.3)
—
(495.6)
1,190.5
(994.8)
471.4
(25.3)
(959.5)
(211.7)
—
—
248.9
$
37.2
$
— $
— $
— $
— $
37.2
111
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 Rules 13a-15(e) and 15d-15(e) 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, 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.
112
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 Committee Procedures
Information concerning the Nominating Committee procedures is set forth in our 2020 definitive Proxy Statement and is
incorporated herein by this reference.
Audit Committee
Information concerning the Audit Committee is set forth in our 2020 definitive Proxy Statement and is incorporated herein by
this reference.
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.
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.
113
Equity Compensation Plan Information
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2019:
Number of Securities
to be Issued
Upon Exercise of
Outstanding Options,
Warrants and Rights
(a)
2,076,295
350,029
2,426,324
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(b) (3)
$
$
$
64.33
75.67
65.96
Number of Securities
Remaining Available For
Future Issuance Under
Equity Compensation
Plans (Excluding
Securities in Column (a))
(c)
8,960,329
—
8,960,329
Plan Category
Equity compensation plans
approved by security holders (1)
Equity compensation plans
not approved by security holders (2)
Total
(1) - Includes shares granted under our Employee Stock Purchase Plan and Employee Stock Award Program and restricted stock incentive
unit awards and performance unit awards granted under our former Long-Term Incentive Plan, our former Equity Compensation Plan
and our Equity Incentive Plan. For a brief description of the material features of these plans, see Note J of the Notes to Consolidated
Financial Statements in this Annual Report. Column (a) includes shares based on 100% of the performance units vesting at the end of
the three-year performance period. Column (c) includes 1,211,710, 133,075 and 7,615,544 shares available for future issuance under our
Employee Stock Purchase Plan, Employee Stock Award Program and Equity Incentive Plan, respectively.
(2) - Includes our NQDC Plan, Deferred Compensation Plan for Non-Employee Directors and our former Stock Compensation Plan for Non-
Employee Directors. For a brief description of the material features of these plans, see Note J of the Notes to Consolidated Financial
Statements in this Annual Report.
(3) - Compensation deferred into our common stock under our former Equity Compensation Plan and our 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 $75.67, which represents the 2019 year-end closing price of our common
stock on the NYSE.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Information on certain relationships and related transactions and director independence is set forth in our 2020 definitive Proxy
Statement and is incorporated herein by this reference.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning the principal accountant’s fees and services is set forth in our 2020 definitive Proxy Statement and is
incorporated herein by this reference.
114
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV
(1) Financial Statements
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended
December 31, 2019, 2018 and 2017
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2019, 2018 and 2017
Consolidated Balance Sheets as of December 31, 2019 and 2018
Consolidated Statements of Cash Flows for the years ended
December 31, 2019, 2018 and 2017
Consolidated Statements of Changes in Equity for the years ended
December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
Page No.
54-55
56
57
58-59
61
62-63
64-111
(2) Financial Statements Schedules
All schedules have been omitted because of the absence of conditions under which they are required.
(3) Exhibits
2
2.1
3
3.1
4
4.1
Separation and Distribution Agreement, dated as of January 14, 2014, by and between ONE Gas, Inc. and
ONEOK, Inc. (incorporated by reference to Exhibit 2.1 to ONEOK, Inc.’s Current Report on Form 8-K filed
January 15, 2014 (File No. 1-13643)).
Agreement and Plan of Merger, dated as of January 31, 2017, by and among ONEOK, Inc., New Holdings
Subsidiary, LLC, ONEOK Partners, L.P. and ONEOK Partners GP, L.L.C. (incorporated by reference from
Exhibit 2.1 to ONEOK Inc.’s Current Report on Form 8-K filed February 1, 2017 (File No.1-13643)).
Amended and Restated Certificate of Incorporation of ONEOK, Inc., dated July 3, 2017, as amended
(incorporated by reference from Exhibit 3.2 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2017, filed November 1, 2017 (File No. 1-13643)).
Amended and Restated Bylaws of ONEOK, Inc. (incorporated by reference from Exhibit 3.1 to ONEOK,
Inc.’s Current Report on Form 8-K filed September 20, 2018 (File No. 1-13643)).
Certificate of Designation for Convertible Preferred Stock of WAI, Inc. (now ONEOK, Inc.) filed
November 21, 2008 (incorporated by reference from Exhibit 3.1 to ONEOK, Inc.’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2012, filed August 1, 2012 (File No. 1-13643)).
Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc. filed November 21,
2008 (incorporated by reference from Exhibit No. 3.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for
the quarter ended June 30, 2012, filed August 1, 2012 (File No. 1-13643)).
115
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
Fifth Supplemental Indenture, dated as of June 30, 2017, by and among ONEOK, Inc., ONEOK Partners,
L.P., ONEOK Partners Intermediate Limited Partnership and The Bank of New York Mellon Trust, as trustee
(incorporated by reference from Exhibit 4.1 to ONEOK Inc.’s Current Report on Form 8-K filed July 3,
2017 (File No. 1-13643)).
Form of Common Stock Certificate (incorporated by reference from Exhibit 1 to ONEOK, Inc.’s
Registration Statement on Form 8-A filed November 21, 1997 (File No. 1-13643)).
Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas, as trustee
(incorporated by reference from Exhibit 4.1 to ONEOK, Inc.’s Registration Statement on Form S-3 filed
August 26, 1998 (File No. 333-62279)).
Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank, as trustee (incorporated by
reference from Exhibit 4.1 to Amendment No. 1 to ONEOK, Inc.’s Registration Statement on Form S-3 filed
December 28, 2001 (File No. 333-65392)).
First Supplemental Indenture dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas,
as trustee, with respect to the 6.50% Senior Insured Quarterly Notes due 2028 (incorporated by reference
from Exhibit 5(a) to ONEOK, Inc.’s Current Report on Form 8-K/A filed October 2, 1998 (File No.
1-13643)).
Second Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and Chase Bank of
Texas, as trustee, with respect to the 6.875% Debentures due 2028 (incorporated by reference from Exhibit
5(b) to ONEOK, Inc.’s Current Report on Form 8-K/A filed October 2, 1998 (File No. 1-13643)).
Third Supplemental Indenture, dated as of June 30, 2017, by and among ONEOK, Inc., ONEOK Partners,
L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee
(incorporated by reference from Exhibit 4.2 to ONEOK Inc.’s Current Report on Form 8-K filed July 3,
2017 (File No. 1-13643)).
Thirteenth Supplemental Indenture, dated March 20, 2015, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.80% Senior
Notes due 2020 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed on March 20, 2015 (File No. 1-12202)).
Fourteenth Supplemental Indenture, dated March 20, 2015, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 4.90% Senior
Notes due 2025 (incorporated by reference to Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed on March 20, 2015 (File No. 1-12202)).
Fourth Supplemental Indenture, dated as of July 13, 2017, by and among ONEOK, Inc., ONEOK Partners,
L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee,
with respect to the 4.00% Senior Notes due 2027 (incorporated by reference from Exhibit 4.1 to ONEOK
Inc.’s Current Report on Form 8-K filed July 13, 2017 (File No. 1-13643)).
Fifth Supplemental Indenture, dated as of July 13, 2017, by and among ONEOK, Inc., ONEOK Partners,
L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee,
with respect to the 4.95% Senior Notes due 2047 (incorporated by reference from Exhibit 4.2 to ONEOK
Inc.’s Current Report on Form 8-K filed July 13, 2017 (File No. 1-13643)).
Fifteenth Supplemental Indenture, dated as of June 30, 2017, by and among ONEOK Partners, L.P.,
ONEOK, Inc., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee
(incorporated by reference from Exhibit 4.1 to ONEOK, Partners, L.P.’s Current Report on Form 8-K filed
July 3, 2017 (File No. 1-12202)).
116
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
Certificate of Designation, Preferences and Rights of Series E Non-Voting Perpetual Preferred Stock of
ONEOK, Inc. filed April 20, 2017 (incorporated by reference from Exhibit No. 3.1 to ONEOK, Inc.’s
Current Report on Form 8-K filed April 20, 2017 (File No. 1-13643)).
Third Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank, as trustee,
with respect to the 6.00% Senior Notes due 2035 (incorporated by reference from Exhibit 4.3 to ONEOK,
Inc.’s Current Report on Form 8-K filed June 17, 2005 (File No. 1-13643)).
Tenth Supplemental Indenture, dated September 12, 2013, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.200% Senior
Notes due 2018 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed September 12, 2013 (File No. 1-12202)).
Eleventh Supplemental Indenture, dated September 12, 2013, among ONEOK Partners, L.P., ONEOK
Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the
5.000% Senior Notes due 2023 (incorporated by reference to Exhibit 4.3 to ONEOK Partners, L.P.’s Current
Report on Form 8-K filed September 12, 2013 (File No. 1-12202)).
Twelfth Supplemental Indenture, dated September 12, 2013, among ONEOK Partners, L.P., ONEOK
Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the
6.200% Senior Notes due 2043 (incorporated by reference to Exhibit 4.4 to ONEOK Partners, L.P.’s Current
Report on Form 8-K filed September 12, 2013 (File No. 1-12202)).
Indenture, dated September 25, 2006, between ONEOK Partners, L.P. and Wells Fargo Bank, N.A., as
trustee (incorporated by reference to Exhibit 4.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K
filed September 26, 2006 (File No. 1-12202)).
Eighth Supplemental Indenture, dated September 13, 2012, among ONEOK Partners, L.P., ONEOK
Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the
2.000% Senior Notes due 2017 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s
Current Report on Form 8-K filed September 13, 2012 (File No. 1-12202)).
Third Supplemental Indenture, dated September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.65% Senior
Notes due 2036 (incorporated by reference to Exhibit 4.4 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed September 26, 2006 (File No. 1-12202)).
Fourth Supplemental Indenture, dated September 28, 2007, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.85% Senior
Notes due 2037 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed September 28, 2007 (File No. 1-12202)).
Fifth Supplemental Indenture, dated March 3, 2009, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 8.625% Senior
Notes due 2019 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed March 3, 2009 (File No. 1-12202)).
Ninth Supplemental Indenture, dated September 13, 2012, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.375% Senior
Notes due 2022 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed September 13, 2012 (File No. 1-12202)).
117
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36
Form of Class B unit certificate of ONEOK Partners, L.P. (incorporated by reference to Exhibit 4.1 to
Northern Border Partners, L.P.’s Current Report on Form 8-K filed April 12, 2006 (File No. 1-12202)).
Seventh Supplemental Indenture, dated January 26, 2011, among ONEOK Partners, L.P., ONEOK Partners
Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.125% Senior
Notes due 2041 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed January 26, 2011 (File No. 1-12202)).
Indenture, dated January 26, 2012, among ONEOK, Inc. and U.S. Bank National Association, as trustee
(incorporated by reference to Exhibit 4.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 26,
2012 (File No. 1-13643)).
First Supplemental Indenture, dated January 26, 2012, among ONEOK, Inc. and U.S. Bank National
Association, as trustee, with respect to the 4.25% Senior Notes due 2022 (incorporated by reference to
Exhibit 4.2 to ONEOK, Inc.’s Current Report on Form 8-K filed January 26, 2012 (File No. 1-13643)).
Second Supplemental Indenture, dated August 21, 2015, between ONEOK, Inc. and U.S. Bank National
Association, as trustee, with respect to the 7.50% Notes due 2023 (incorporated by reference to Exhibit 4.1
to ONEOK, Inc.’s Current Report on Form 8-K filed August 21, 2015 (File No. 1-13643)).
Fourth Supplemental Indenture, dated as of June 30, 2017, by and among ONEOK, Inc., ONEOK Partners,
L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee,
with respect to the 6.00% Senior Notes due 2035 (incorporated by reference from Exhibit 4.3 to ONEOK
Inc.’s Current Report on Form 8-K filed July 3, 2017 (File No. 1-13643)).
Sixth Supplemental Indenture, dated as of July 2, 2018, among ONEOK, Inc., ONEOK Partners, L.P.,
ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with
respect to the 4.55% Senior Notes due 2028 (incorporated by reference from Exhibit No. 4.1 to ONEOK,
Inc.’s Current Report on Form 8-K filed July 2, 2018 (File No. 1-13643)).
Seventh Supplemental Indenture, dated as of July 2, 2018, among ONEOK, Inc., ONEOK Partners, L.P.,
ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with
respect to the 5.20% Senior Notes due 2048 (incorporated by reference from Exhibit No. 4.2 to ONEOK,
Inc.’s Current Report on Form 8-K filed July 2, 2018 (File No. 1-13643)).
Eighth Supplemental Indenture, dated as of March 13, 2019, among ONEOK, Inc., ONEOK Partners, L.P.,
ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with
respect to the 4.35% Senior Notes due 2029 (incorporated by reference from Exhibit No. 4.2 to ONEOK,
Inc.’s Current Report on Form 8-K filed March 13, 2019 (File No. 1-13643)).
Ninth Supplemental Indenture, dated as of March 13, 2019, among ONEOK, Inc., ONEOK Partners, L.P.,
ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with
respect to the 5.20% Senior Notes due 2048 (incorporated by reference from Exhibit No. 4.3 to ONEOK,
Inc.’s Current Report on Form 8-K filed March 13, 2019 (File No. 1-13643)).
Tenth Supplemental Indenture, dated as of August 15, 2019, among ONEOK, Inc., ONEOK Partners, L.P.,
ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with
respect to the 2.75% Senior Notes due 2024 (incorporated by reference from Exhibit No. 4.1 to ONEOK,
Inc.’s Current Report on Form 8-K filed August 15, 2019 (File No. 1-13643)).
Eleventh Supplemental Indenture, dated as of August 15, 2019, among ONEOK, Inc., ONEOK Partners,
L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee,
with respect to the 3.40% Senior Notes due 2029 (incorporated by reference from Exhibit No. 4.2 to
ONEOK, Inc.’s Current Report on Form 8-K filed August 15, 2019 (File No. 1-13643)).
118
4.37
4.38
10
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Twelfth Supplemental Indenture, dated as of August 15, 2019, among ONEOK, Inc., ONEOK Partners, L.P.,
ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with
respect to the 4.45% Senior Notes due 2049 (incorporated by reference from Exhibit No. 4.3 to ONEOK,
Inc.’s Current Report on Form 8-K filed August 15, 2019 (File No. 1-13643)).
Description of securities.
ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to ONEOK, Inc.’s
Annual Report on Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002 (File
No. 1-13643).
ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by reference from
Exhibit 99 to ONEOK, Inc.’s Registration Statement on Form S-8 filed January 25, 2001 (File
No. 333-54274)).
ONEOK, Inc. Supplemental Executive Retirement Plan terminated and frozen December 31, 2004
(incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed
December 20, 2004 (File No. 1-13643)).
ONEOK, Inc. 2005 Supplemental Executive Retirement Plan, as amended and restated, dated December 18,
2008 (incorporated by reference from Exhibit 10.3 to ONEOK, Inc.’s Annual Report on Form 10-K for the
fiscal year ended December 31, 2008, filed February 25, 2009 (File No. 1-13643)).
Credit Agreement, dated as of April 18, 2017, among ONEOK, Inc., Citibank, N.A., as administrative agent,
a swingline lender, a letter of credit issuer and a lender, and the other lenders, swingline lenders and letter of
credit issuers parties thereto (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report
on Form 8-K filed April 19, 2017 (File No. 1-13643)).
Form of Indemnification Agreement between ONEOK, Inc. and ONEOK, Inc. officers and directors, as
amended (incorporated by reference from Exhibit 10.5 to ONEOK, Inc.’s Annual Report on Form 10-K for
the fiscal year ended December 31, 2014, filed February 25, 2015 (File No. 1-13643)).
Amended and Restated ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit
10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed May 27, 2009 (File No. 1-13643)).
ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan, as amended and restated December 16,
2004 (incorporated by reference from Exhibit 10.3 to ONEOK, Inc.’s Current Report on Form 8-K filed
December 20, 2004 (File No. 1-13643)).
ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan, as amended and restated, dated
December 18, 2008 (incorporated by reference from Exhibit 10.8 to ONEOK, Inc.’s Annual Report on Form
10-K for the fiscal year ended December 31, 2008, filed February 25, 2009 (File No. 1-13643)).
ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated, dated
December 18, 2008 (incorporated by reference from Exhibit 10.9 to ONEOK, Inc.’s Annual Report on
Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009 (File No. 1-13643)).
10.10
First Amendment to the Term Loan Agreement, dated as of April 18, 2017, among ONEOK Partners, L.P.,
Mizuho Bank, Ltd., as administrative agent and a lender, and the other lenders parties thereto (including the
Amended and Restated Term Loan Agreement attached as an annex thereto) (incorporated by reference to
Exhibit 10.1 to the Current Report on Form 8-K, filed by ONEOK Partners, L.P. on April 19, 2017 (File No.
1-12202)).
119
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
Guaranty Agreement, dated as of June 30, 2017, by and between ONEOK Partners, L.P. and ONEOK
Partners Intermediate Limited Partnership, in favor of Citibank, N.A., as administrative agent, under the
Credit Agreement, dated as of April 18, 2017, by and among ONEOK, Inc., Citibank, N.A. and the other
lenders parties thereto (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on
Form 8-K filed July 3, 2017 (File No. 1-13643)).
Extension Agreement, dated as of June 18, 2018, among ONEOK, Inc., Citibank, N.A., as administrative
agent, a swingline lender, a letter of credit issuer and a lender, and the other lenders, swingline lenders and
letter of credit issuers parties thereto (incorporated by reference from Exhibit No. 10.1 to ONEOK, Inc.’s
Current Report on Form 8-K filed June 18, 2018 (File No. 1-13643)).
First Amendment and Extension Agreement, dated as of May 24, 2019, among ONEOK, Inc., Citibank,
N.A., as administrative agent, a swingline lender, a letter of credit issuer and a lender, and the other lenders,
swingline lenders and letter of credit issuers parties thereto (incorporated by reference from Exhibit No. 10.1
to ONEOK, Inc.’s Current Report on Form 8-K filed May 29, 2019 (File No. 1-13643)).
Amended and Restated Limited Liability Company Agreement of Overland Pass Pipeline Company LLC
entered into between ONEOK Overland Pass Holdings, L.L.C. and Williams Field Services Company, LLC
dated May 31, 2006 (incorporated by reference to Exhibit 10.6 to ONEOK Partners, L.P.’s Quarterly Report
on Form 10-Q for the quarter ended June 30, 2006, filed August 4, 2006 (File No. 1-12202)).
Form of ONEOK, Inc. Officer Change in Control Severance Plan (incorporated by reference from
Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed July 22, 2011 (File No. 1-13643)).
Guaranty Agreement, dated as of June 30, 2017, by ONEOK, Inc. in favor of Mizuho Bank, Ltd., as
administrative agent, under the Term Loan Agreement, dated as of January 8, 2016, as amended by the First
Amendment to the Term Loan Agreement, dated as of April 18, 2017, by and among ONEOK Partners, L.P.,
Mizuho Bank, Ltd. and the other lenders parties thereto (incorporated by reference from Exhibit 10.2 to
ONEOK, Inc.’s Current Report on Form 8-K filed July 3, 2017 (File No. 1-13643)).
Form of 2018 Restricted Unit Stock Award Agreement dated February 21, 2018 (incorporated by reference
to Exhibit 10.17 to ONEOK, Inc.’s Annual Report on Form 10-K filed on February 27, 2018 (File No.
1-13643)).
Form of 2018 Performance Unit Award Agreement dated February 21, 2018 (incorporated by reference to
Exhibit 10.18 to ONEOK, Inc.’s Annual Report on Form 10-K filed on February 27, 2018 (File No.
1-13643)).
Form of 2017 Restricted Unit Stock Award Agreement dated February 22, 2017 (incorporated by reference
to Exhibit 10.57 to ONEOK, Inc.’s Annual Report on Form 10-K filed on February 28, 2017 (File No.
1-13643)).
Form of 2017 Performance Unit Award Agreement dated February 22, 2017 (incorporated by reference to
Exhibit 10.58 to ONEOK, Inc.’s Annual Report on Form 10-K filed on February 28, 2017 (File
No. 1-13643)).
Term Loan Agreement, dated as of January 8, 2016, among ONEOK Partners, L.P., Mizuho Bank, Ltd., as
administrative agent and a lender, and the other lenders parties thereto (incorporated by reference to
Exhibit 10.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on January 12, 2016 (File
No. 1-12202)).
120
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
Guaranty Agreement, dated as of January 8, 2016, by ONEOK Partners Intermediate Limited Partnership in
favor of Mizuho Bank, Ltd., as administrative agent, under the above-referenced Term Loan Agreement
(incorporated by reference to Exhibit 10.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on
January 12, 2016 (File No. 1-12202)).
Term Loan Agreement, dated as of November 19, 2018, among ONEOK, Inc., Mizuho Bank, Ltd., as
administrative agent and a lender, and the other lenders parties thereto (incorporated by reference from
Exhibit No. 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed November 21, 2018 (File No.
1-13643)).
Guaranty Agreement, dated as of November 19, 2018, by ONEOK Partners Intermediate Limited
Partnership and ONEOK Partners, L.P. in favor of Mizuho Bank, Ltd., as administrative agent, under the
above-referenced Term Loan Agreement (incorporated by reference from Exhibit No. 10.2 to ONEOK,
Inc.’s Current Report on Form 8-K filed November 21, 2018 (File No. 1-13643)).
ONEOK, Inc. Equity Incentive Plan (incorporated by reference to Appendix A to ONEOK, Inc.’s definitive
proxy statement on Schedule 14A filed on April 5, 2018 (File No. 1-13643)).
ONEOK, Inc. Profit Sharing Plan, dated January 1, 2005 (incorporated by reference from Exhibit 99 to
ONEOK, Inc.’s Registration Statement on Form S-8 filed December 30, 2004 (File No. 333-121769)).
ONEOK, Inc. Equity Compensation Plan, as amended and restated, dated December 18, 2008 (incorporated
by reference from Exhibit 10.44 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended
December 31, 2008, filed February 25, 2009 (File No. 1-13643)).
Tax Matters Agreement, dated as of January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc.
(incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 15,
2014 (File No. 1-13643)).
Transition Services Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc.
(incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Current Report on Form 8-K filed January 15,
2014 (File No. 1-13643)).
Employee Matters Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc.
(incorporated by reference to Exhibit 10.3 to ONEOK, Inc.’s Current Report on Form 8-K filed January 15,
2014 (File No. 1-13643)).
Form of 2019 Restricted Unit Award Agreement, dated February 20, 2019 (incorporated by reference to
Exhibit 10.54 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018,
filed February 26, 2019 (File No. 1-13643)).
Form of 2019 Performance Unit Award Agreement, dated February 20, 2019 (incorporated by reference to
Exhibit 10.55 to ONEOK Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018,
filed February 26, 2019 (File No. 1-13643)).
Form of 2016 Restricted Unit Award Agreement, dated February 17, 2016 (incorporated by reference to
Exhibit 10.57 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015,
filed February 23, 2016 (File No. 1-13643)).
Form of 2016 Performance Unit Award Agreement, dated February 17, 2016 (incorporated by reference to
Exhibit 10.58 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015,
filed February 23, 2016 (File No. 1-13643)).
10.35
Form of 2020 Restricted Unit Award Agreement.
121
10.36
Form of 2020 Performance Unit Award Agreement.
10.37
ONEOK, Inc. Employee Stock Purchase Plan as amended and restated effective May 23, 2012 (incorporated
by reference to Exhibit 10.2 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2012, filed August 1, 2012 (File No. 1-13643)).
10.38
Form of First Amendment to 2019 Performance Unit Award Agreement.
10.39
Form of First Amendment to 2018 Performance Unit Award Agreement.
21
23
31.1
31.2
32.1
32.2
Required information concerning the registrant’s subsidiaries.
Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.
Certification of Terry K. Spencer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Walter S. Hulse III pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Terry K. Spencer 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 Walter S. Hulse III pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
101.INS
Inline 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
Inline XBRL Taxonomy Extension Schema Document.
101.CAL
Inline XBRL Taxonomy Calculation Linkbase Document.
101.DEF
Inline XBRL Taxonomy Extension Definitions Document.
101.LAB
Inline XBRL Taxonomy Label Linkbase Document.
101.PRE
Inline XBRL Taxonomy Presentation Linkbase Document.
104
Cover Page Interactive Data File (formatted in Inline XBRL 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 at 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 Changes in Equity for the years ended December 31, 2019, 2018 and 2017;
and (vii) Notes to Consolidated Financial Statements.
ITEM 16.
FORM 10-K SUMMARY
None.
122
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
ONEOK, Inc.
Registrant
Date: February 25, 2020
By:
/s/ Walter S. Hulse III
Walter S. Hulse III
Chief Financial Officer, Treasurer and
Executive Vice President, Strategic Planning
and Corporate Affairs
(Principal 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 25th day of February 2020.
/s/ Terry K. Spencer
Terry K. Spencer
President, Chief Executive Officer and
Director
/s/ Mary M. Spears
Mary M. Spears
Vice President and
Chief Accounting Officer
/s/ Julie H. Edwards
Julie H. Edwards
Director
/s/ Randall J. Larson
Randall J. Larson
Director
/s/ Jim W. Mogg
Jim W. Mogg
Director
/s/ Gary D. Parker
Gary D. Parker
Director
/s/ John W. Gibson
John W. Gibson
Chairman of the Board
/s/ Walter S. Hulse III
Walter S. Hulse III
Chief Financial Officer, Treasurer and
Executive Vice President, Strategic
Planning and Corporate Affairs
/s/ Brian L. Derksen
Brian L. Derksen
Director
/s/ Mark W. Helderman
Mark W. Helderman
Director
/s/ Steven J. Malcolm
Steven J. Malcolm
Director
/s/ Pattye L. Moore
Pattye L. Moore
Director
/s/ Eduardo A. Rodriguez
Eduardo A. Rodriguez
Director
123
BOARD OF DIRECTORS
Brian L. Derksen
Retired Global Deputy Chief Executive Officer, Deloitte Touche Tohmatsu Limited
Dallas, Texas
Julie H. Edwards
Former Chief Financial Officer, Southern Union Company;
Former Chief Financial Officer, Frontier Oil Corporation
Houston, Texas
Jim W. Mogg
Retired Chairman, DCP Midstream GP, L.L.C.
Hydro, Oklahoma
Pattye L. Moore
Former Chairman, Red Robin Gourmet Burgers;
Former President, Sonic Corp.
Broken Arrow, Oklahoma
John W. Gibson
Chairman of the Board and Retired Chief Executive Officer, ONEOK, Inc.
Tulsa, Oklahoma
Gary D. Parker
President, Moffitt, Parker & Company, Inc.
Muskogee, Oklahoma
Mark W. Helderman
Retired Managing Director and Co-Portfolio Manager, Sasco Capital Inc.
Cleveland, Ohio
Eduardo A. Rodriguez
President, Strategic Communications Consulting Group
El Paso, Texas
Randall J. Larson
Retired Chief Executive Officer, TransMontaigne Partners L.P.
Tucson, Arizona
Terry K. Spencer
President and Chief Executive Officer, ONEOK, Inc.
Tulsa, Oklahoma
Steven J. Malcolm
Retired Chairman, President and Chief Executive Officer, The Williams Companies, Inc.
Tulsa, Oklahoma
OFFICERS
Positions and ages as of
February 27, 2020
Terry K. Spencer, 60
President and Chief Executive Officer
Sheridan C. Swords, 50
Senior Vice President, Natural Gas Liquids
Robert F. Martinovich, 62
Executive Vice President and Chief Administrative Officer
Charles M. Kelley, 61
Senior Vice President, Natural Gas
Walter S. Hulse III, 56
Chief Financial Officer, Treasurer and Executive Vice President,
Strategic Planning and Corporate Affairs
Kevin L. Burdick, 55
Executive Vice President and Chief Operating Officer
Stephen B. Allen, 46
Senior Vice President, General Counsel and Assistant Secretary
Mary M. Spears, 40
Vice President and Chief Accounting Officer
Eric Grimshaw, 67
Vice President, Associate General Counsel and Secretary
CORPORATE INFORMATION
ANNUAL MEETING
The 2020 annual meeting of shareholders will be held Wednesday, May 20, 2020,
at 9 a.m. Central Daylight Time at ONEOK Plaza, 100 West Fifth Street, Tulsa, OK.
CREDIT RATINGS
S&P Global Ratings
Moody’s Investors Service
OKE
BBB (stable)
Baa3 (positive)
AUDITORS
PricewaterhouseCoopers LLP
Two Warren Place
6120 South Yale Avenue, Suite 1850
Tulsa, OK 74136
INVESTOR RELATIONS
Andrew Ziola, vice president – investor relations and corporate affairs, by phone at
918-588-7683 or by email at aziola@oneok.com.
Megan Patterson, manager – investor relations, by phone at 918-561-5325 or by
email at mpatterson@oneok.com.
DIRECT STOCK PURCHASE AND DIVIDEND REINVESTMENT PLAN
ONEOK’s Direct Stock Purchase and Dividend Reinvestment Plan provides investors
the opportunity to purchase shares of common stock without payment of any
brokerage fees or service charges and to reinvest dividends automatically.
CORPORATE WEBSITE
www.oneok.com
TRANSFER AGENT, REGISTRAR AND DIVIDEND DISBURSING AGENT
EQ Shareowner Services
P.O. Box 64854
St. Paul, MN 55164-0854
866-235-0232
www.shareowneronline.com
MIX
Paper from
responsible sources
FSC® C103375
100 West Fifth Street
Tulsa, Oklahoma 74103-4298
Post Office Box 871
Tulsa, Oklahoma 74102-0871
www.oneok.com