W I L L I S T O N B A S I N
D E M I C K S L A K E
E L K C R E E K
P O W D E R R I V E R B A S I N
C O N W AY,
K A N S A S
S TA C K A N D S C O O P P L AY S
W E S T T E X A S L P G
A R B U C K L E I I
P E R M I A N B A S I N
R O A D R U N N E R
M O N T B E LV I E U ,
T E X A S
CONNECTIONS.
Basins. Assets. Markets. Relationships.
2 0 1 8 A N N U A L R E P O R T
CONNECTIONS ARE CENTRAL
TO OUR SUCCESS.
Whether we’re physically connecting customers to our integrated
network of assets; connecting our assets to one another; or connecting
with our stakeholders by building relationships – the connections
we’ve made throughout our company’s history have strengthened and
sustained us through the many ups and downs in the energy business.
Thankfully, 2018 wasn’t simply a good year for ONEOK … it was an
exceptional year of exciting growth opportunities and realized potential.
Over the course of 2018, we announced approximately $5.5 billion in
additional natural gas liquids (NGL) and natural gas projects, bringing the
total investment in our current capital-growth program to more than
$6 billion. These projects are anchored by long-term, fee-based contracts,
volume commitments and/or acreage dedications.
A $6 billion growth program is impressive by most standards, but it’s the
capital discipline and attractive returns we expect from these projects
that are reflective of our core strategy to provide high-quality midstream
services to our customers while creating long-term shareholder value.
Once completed, these projects will significantly increase capacity in some
of the most prolific shale plays in the country where we already operate an
extensive network of assets. We expect this investment in our business to
be the foundation for even stronger returns to our investors and position
us to not only continue to provide but also expand the reliable services our
customers expect and need both in the near and long term.
In addition to executing on the capital-growth projects announced in
2018, we:
• Significantly improved over 2017 our environment, safety and health
(ESH) performance, meeting or exceeding our 2018 targets, which
translated into fewer injuries, fewer vehicle incidents and a reduced
impact to the environment because of our operational performance.
• Increased NGL volumes gathered and natural gas volumes processed
across our system by 12 percent and 16 percent, respectively,
compared with 2017.
• Completed construction of more than $500 million of capital-growth
projects, including expansions of our West Texas LPG system,
Sterling III Pipeline and Canadian Valley plant.
• Increased operating income and adjusted earnings before interest,
taxes, depreciation and amortization (adjusted EBITDA) by 32 percent
and 23 percent, respectively, compared with 2017.
• Increased our dividends paid in 2018 to $3.245 per share, a
19 percent increase compared with 2017.
• Achieved full-year dividend coverage of nearly 1.37 times.
• Ended the year with a strong balance sheet and a debt-to-EBITDA
ratio of 3.83 times on a trailing 12-month basis, compared with
4.6 times at the end of 2017.
This performance further strengthens our businesses as we evaluate
future opportunities while remaining focused on sustaining our
investment-grade balance sheet by operating and investing in a
disciplined manner that delivers strong returns for our stakeholders.
1
In addition to the 2018 achievements already mentioned, we’re proud
to have been named Best of the Best – Great Companies to Work For by
Oklahoma Magazine; awarded the Horizon Award by the Sidney, Montana,
Area Chamber of Commerce and Agriculture; given the Gas Processors
Association’s Environmental Excellence Award for our MB-1 fractionation
facility in Mont Belvieu, Texas; and recognized as a Veteran Employer
Champion by the Oklahoma Veteran Employer Champion Network.
It’s been an outstanding year on all fronts – financially, operationally,
commercially and from an ESH standpoint. The successes of 2018 are
attributable to our talented, diverse and committed employees whom we
thank for not only executing on our vision but also doing so in a manner that
exemplifies our core values – ethics, quality, diversity, value and service.
Our employees continue to work safely, reliably and in an
environmentally sustainable manner that ensures the integrity of
our assets and company, and we are very proud of what they’ve
accomplished this year.
Thank you to our board of directors for its guidance and support
as we navigate this exciting time for our company. We continue to
refresh our board of directors as demonstrated by the election of
Mark Helderman to the board in February 2019. Mark recently retired
from Sasco Capital Inc., an independent, institutional investment firm,
and his experience and expertise will further strengthen the board and
benefit our shareholders.
And finally, thank you to our investors for your continued trust and
investment in ONEOK. 2019 will be a year of execution, as we bring more
of our announced projects online that are expected to drive significant
earnings growth in the years to come and look for new opportunities
both in the U.S. and abroad. It will take the hard work of everyone to
complete these projects on time and on budget, but we will continue
to challenge ourselves to think of new and innovative ways to solve
problems and build long-lasting connections.
John W. Gibson
Chairman
March 5, 2019
Terry K. Spencer
President and Chief Executive Officer
LETTER TO OUR INVESTORS O
N
E
O
K
,
I
N
C
.
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8
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Paper from
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FSC® C103375
W I L L I S T O N B A S I N
D E M I C K S L A K E
P O W D E R R I V E R B A S I N
E L K C R E E K
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.
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
Mid-Continent, Permian and Rocky Mountain regions with key market centers and an extensive network of natural gas gathering, processing, storage and transportation assets.
2018 FINANCIAL PERFORMANCE
C O N W AY,
K A N S A S
S TA C K A N D S C O O P P L AY S
OPERATING INCOME
(MILLIONS OF DOLLARS)
ADJUSTED EBITDA
(MILLIONS OF DOLLARS )
2018
2017
2016
2015
$1,835.5
$996.2
$1,295.8
$1,391.8
2018
2017
2016
2015
$1,579.5
$1,849.9
$1,986.9
$2,447.5
MARKET CAP
27
BILLION
YIELD
5∙2%
Market cap and yield as of March 5, 2019
W E S T T E X A S L P G
A R B U C K L E I I
DIVIDEND GROWTH
TOTAL SHAREHOLDER RETURN*
P E R M I A N B A S I N
R O A D R U N N E R
M O N T B E LV I E U ,
T E X A S
100 West Fifth Street
Tulsa, Oklahoma 74103-4298
Post Office Box 871
Tulsa, Oklahoma 74102-0871
www.oneok.com
CONNECTIONS.
Basins. Assets. Markets. Relationships.
2 0 1 8 A N N U A L R E P O R T
2018
2017
2016
2015
$2.43
$2.46
$2.72
$3.245
29%
50%
13%
30%
6%
5-YEAR
-25%
3-YEAR
1-YEAR
-15%
-4%
ONEOK
ONEOK Peer Group
S&P 500 Index
160%
ONEOK
ONEOK Peer Group
S&P 500 Index
ONEOK
ONEOK Peer Group
S&P 500 Index
%
0
5
-
%
5
2
-
%
0
%
5
2
%
0
5
%
5
7
%
0
0
1
%
5
2
1
%
0
5
1
%
5
7
1
%
0
0
2
As of Dec. 31, 2018
*Total return represents share-price appreciation and the reinvestment of dividends.
N A T U R A L G A S S T O R A G E &
E N D - U S E M A R K E T S
Natural Gas
Pipeline
NGL Gathering
Pipeline
Ethane
Propane
Isobutane
Normal Butane
Natural Gasoline
FEE-BASED
EARNINGS
IN 2018
Natural Gas
Gathering
Residue Gas
Raw Feed NGLs
W E L L H E A D
N A T U R A L G A S
P R O C E S S I N G
P L A N T
Petrochemical
Refining
Heating
Exports
N G L S T O R A G E &
M A R K E T C E N T E R
NEARLY
90%
OPERATIONS
NGL RAW FEED THROUGHPUT
in thousand barrels per day (MBbl/d)
BOARD OF DIRECTORS
Retired Global Deputy Chief Executive Officer, Deloitte Touche Tohmatsu Limited
Retired Chairman, DCP Midstream GP, L.L.C.
Former Chief Financial Officer, Southern Union Company;
Former Chief Financial Officer, Frontier Oil Corporation
Chairman, Red Robin Gourmet Burgers;
Former President, Sonic Corp.
Broken Arrow, Oklahoma
Chairman of the Board and Retired Chief Executive Officer, ONEOK, Inc.
President, Moffitt, Parker & Company, Inc.
Retired Managing Director and Co-Portfolio Manager, Sasco Capital Inc.
President, Strategic Communications Consulting Group
Retired Chief Executive Officer, TransMontaigne Partners L.P.
President and Chief Executive Officer, ONEOK, Inc.
Retired Chairman, President and Chief Executive Officer, The Williams Companies, Inc.
Jim W. Mogg
Hydro, Oklahoma
Pattye L. Moore
Gary D. Parker
Muskogee, Oklahoma
Eduardo A. Rodriguez
El Paso, Texas
Terry K. Spencer
Tulsa, Oklahoma
Brian L. Derksen
Dallas, Texas
Julie H. Edwards
Houston, Texas
John W. Gibson
Tulsa, Oklahoma
Mark W. Helderman
Cleveland, Ohio
Randall J. Larson
Tucson, Arizona
Steven J. Malcolm
Tulsa, Oklahoma
OFFICERS Positions and ages as of
February 27, 2019
Terry K. Spencer, 59
President and Chief Executive Officer
Robert F. Martinovich, 61
Executive Vice President and Chief Administrative Officer
Sheridan C. Swords, 49
Senior Vice President, Natural Gas Liquids
Chief Financial Officer and Executive Vice President, Strategic Planning
Senior Vice President, Natural Gas
Charles M. Kelley, 60
Derek S. Reiners, 47
Senior Vice President, Finance, and Treasurer
Walter S. Hulse III, 55
and Corporate Affairs
Kevin L. Burdick, 54
Executive Vice President and Chief Operating Officer
Stephen B. Allen, 45
Senior Vice President, General Counsel and Assistant Secretary
Sheppard F. Miers III, 50
Vice President and Chief Accounting Officer
Eric Grimshaw, 66
Vice President, Associate General Counsel and Corporate Secretary
OUR ASSETS
MIDSTREAM INDUSTRY
Local Distribution Companies
Electric Generation
Large Industrials
Liquefied Natural Gas Exports
M O N T A N A
A
N O R T H
D A K O T A
WILLISTON BASIN
M I N N E S O T A
W Y O M I N G
B
POWDER RIVER
BASIN
S O U T H D A K O T A
I O W A
N E B R A S K A
C O L O R A D O
K A N S A S
W I S C O N S I N
NGL Distribution Pipeline
N G L F R A C T I O N A T O R
I N D I A N A
I L L I N O I S
N E W M E X I C O
C
D
STACK &
SCOOP PLAYS
M I S S O U R I
K E N T U C K Y
O K L A H O M A
T E N N E S S E E
A R K A N S A S
LEGEND
G
H
PERMIAN BASIN
T E X A S
F
E
I
L O U I S I A N A
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
GROWTH PROJECTS
A
B
C
D
E
F
G
H
I
2019 Guidance
2018
2017
2016
895
836
1,080 -
1,165
1,010
2019 Guidance
2018
2017
2016
1,552
1,409
1,800 -
2,000
1,808
NATURAL GAS PROCESSED
in million cubic feet per day (MMcf/d)
The 2019 annual meeting of shareholders will be held Wednesday, May 22, 2019,
at 9 a.m. Central Daylight Time at ONEOK Plaza, 100 West Fifth Street, Tulsa, OK.
Moody’s Investors Service
CORPORATE INFORMATION
ONEOK ANNUAL MEETING
AUDITORS
PricewaterhouseCoopers LLP
Two Warren Place
6120 South Yale Avenue, Suite 1850
Tulsa, OK 74136
CREDIT RATINGS
S&P Global Ratings
INVESTOR RELATIONS
OKE
BBB (stable)
Baa3 (stable)
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
CORPORATE WEBSITE
the opportunity to purchase shares of common stock without payment of any
brokerage fees or service charges and to reinvest dividends automatically.
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
Demicks Lake Plants I & II (IN PROGRESS) Elk Creek Pipeline (IN PROGRESS)Canadian Valley Plant Expansion (COMPLETED)ONEOK Gas Transportation Expansions (COMPLETED)Sterling III Pipeline Expansion (COMPLETED)Arbuckle II Pipeline & Expansion (IN PROGRESS)West Texas LPG System Expansion I (COMPLETED) & II (IN PROGRESS)Roadrunner and ONEOK WesTex Expansion (COMPLETED)MB-4 & MB-5 NGL Fractionators and Storage (IN PROGRESS) OUR ASSETS
MIDSTREAM INDUSTRY
Natural Gas
Gathering
Residue Gas
Raw Feed NGLs
W E L L H E A D
N A T U R A L G A S
P R O C E S S I N G
P L A N T
Natural Gas
Pipeline
N A T U R A L G A S S T O R A G E &
E N D - U S E M A R K E T S
NGL Gathering
Pipeline
Local Distribution Companies
Electric Generation
Large Industrials
Liquefied Natural Gas Exports
W I S C O N S I N
NGL Distribution Pipeline
N G L F R A C T I O N A T O R
Petrochemical
Refining
Heating
Exports
N G L S T O R A G E &
M A R K E T C E N T E R
Ethane
Propane
Isobutane
Normal Butane
Natural Gasoline
NEARLY
90%
OPERATIONS
NGL RAW FEED THROUGHPUT
in thousand barrels per day (MBbl/d)
2019 Guidance
2018
2017
2016
895
836
1,080 -
1,165
1,010
FEE-BASED
EARNINGS
IN 2018
NATURAL GAS PROCESSED
in million cubic feet per day (MMcf/d)
The 2019 annual meeting of shareholders will be held Wednesday, May 22, 2019,
at 9 a.m. Central Daylight Time at ONEOK Plaza, 100 West Fifth Street, Tulsa, OK.
Moody’s Investors Service
2019 Guidance
2018
2017
2016
1,552
1,409
1,800 -
2,000
1,808
M O N T A N A
M I N N E S O T A
A
N O R T H
D A K O T A
WILLISTON BASIN
S O U T H D A K O T A
W Y O M I N G
B
POWDER RIVER
BASIN
I O W A
N E B R A S K A
I N D I A N A
I L L I N O I S
C O L O R A D O
K A N S A S
M I S S O U R I
K E N T U C K Y
O K L A H O M A
T E N N E S S E E
A R K A N S A S
LEGEND
N E W M E X I C O
G
H
STACK &
SCOOP PLAYS
C
D
F
PERMIAN BASIN
T E X A S
L O U I S I A N A
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
E
I
F
G
H
I
GROWTH PROJECTS
A
B
C
D
E
BOARD OF DIRECTORS
Retired Global Deputy Chief Executive Officer, Deloitte Touche Tohmatsu Limited
Retired Chairman, DCP Midstream GP, L.L.C.
Former Chief Financial Officer, Southern Union Company;
Former Chief Financial Officer, Frontier Oil Corporation
Chairman, Red Robin Gourmet Burgers;
Former President, Sonic Corp.
Broken Arrow, Oklahoma
Chairman of the Board and Retired Chief Executive Officer, ONEOK, Inc.
President, Moffitt, Parker & Company, Inc.
Retired Managing Director and Co-Portfolio Manager, Sasco Capital Inc.
President, Strategic Communications Consulting Group
Retired Chief Executive Officer, TransMontaigne Partners L.P.
President and Chief Executive Officer, ONEOK, Inc.
Retired Chairman, President and Chief Executive Officer, The Williams Companies, Inc.
Jim W. Mogg
Hydro, Oklahoma
Pattye L. Moore
Gary D. Parker
Muskogee, Oklahoma
Eduardo A. Rodriguez
El Paso, Texas
Terry K. Spencer
Tulsa, Oklahoma
Brian L. Derksen
Dallas, Texas
Julie H. Edwards
Houston, Texas
John W. Gibson
Tulsa, Oklahoma
Mark W. Helderman
Cleveland, Ohio
Randall J. Larson
Tucson, Arizona
Steven J. Malcolm
Tulsa, Oklahoma
OFFICERS Positions and ages as of
February 27, 2019
Terry K. Spencer, 59
President and Chief Executive Officer
Robert F. Martinovich, 61
Executive Vice President and Chief Administrative Officer
Sheridan C. Swords, 49
Senior Vice President, Natural Gas Liquids
Chief Financial Officer and Executive Vice President, Strategic Planning
Senior Vice President, Natural Gas
Charles M. Kelley, 60
Derek S. Reiners, 47
Senior Vice President, Finance, and Treasurer
Walter S. Hulse III, 55
and Corporate Affairs
Kevin L. Burdick, 54
Executive Vice President and Chief Operating Officer
Stephen B. Allen, 45
Senior Vice President, General Counsel and Assistant Secretary
Sheppard F. Miers III, 50
Vice President and Chief Accounting Officer
Eric Grimshaw, 66
Vice President, Associate General Counsel and Corporate Secretary
CORPORATE INFORMATION
ONEOK ANNUAL MEETING
AUDITORS
PricewaterhouseCoopers LLP
Two Warren Place
6120 South Yale Avenue, Suite 1850
Tulsa, OK 74136
CREDIT RATINGS
S&P Global Ratings
INVESTOR RELATIONS
OKE
BBB (stable)
Baa3 (stable)
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
CORPORATE WEBSITE
the opportunity to purchase shares of common stock without payment of any
brokerage fees or service charges and to reinvest dividends automatically.
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
Demicks Lake Plants I & II (IN PROGRESS) Elk Creek Pipeline (IN PROGRESS)Canadian Valley Plant Expansion (COMPLETED)ONEOK Gas Transportation Expansions (COMPLETED)Sterling III Pipeline Expansion (COMPLETED)Arbuckle II Pipeline & Expansion (IN PROGRESS)West Texas LPG System Expansion I(COMPLETED) & II (IN PROGRESS)Roadrunner and ONEOK WesTex Expansion (COMPLETED)MB-4 & MB-5 NGL Fractionators and Storage (IN PROGRESS) MB-4 Fractionator Construction >
$6
BILLION IN
GROWTH PROJECTS
ANNOUNCED
AND EVALUATING NEW OPPORTUNITIES AND MARKETS
E L K C R E E K
As a midstream service provider, integration and connections enable the
full-service capability we provide across our 38,000-mile network of NGL
and natural gas pipelines to our customers who rely on our assets to process
and move production from the wellhead to market centers.
In 2018, we announced attractive-return organic growth projects that will
provide critical pipeline, fractionation and processing capacity for customers
as production continues to increase, particularly in our natural gas liquids
segment, where we are seeing continued NGL growth projections in the
Williston Basin, Powder River Basin, STACK and SCOOP plays, and the
Permian Basin, as well as increasing demand for NGLs on the Gulf Coast
and abroad.
In 2018, we gathered more than 900,000 barrels per day (bpd) of NGLs, a
12 percent increase compared with 2017, from more than 175 processing
plants across our system. Needed NGL transportation capacity came online
with the expansions of the Sterling III Pipeline and the West Texas LPG
system farther west in the Permian Basin, both completed in the fourth
quarter 2018, with a second expansion of West Texas LPG already underway.
Two major, long-haul NGL pipelines also are under construction. The
Elk Creek Pipeline will have an initial capacity of up to 240,000 bpd, of
which we expect the southern section to be in service as early as the
third quarter 2019. The Arbuckle II Pipeline will have an initial capacity of
up to 400,000 bpd, which we expect to be completed in early 2020, with
plans already to expand to 500,000 bpd.
As NGL supply increases, we continue to expand fractionation facilities
and storage to accommodate new volumes. Once our new MB-4 and
MB-5 fractionators and related infrastructure are complete, which we
expect to occur in the first quarter of 2020 and 2021, respectively, our
total fractionation capacity at our Mont Belvieu and Mid-Continent facilities
will exceed 1 million bpd.
And, as part of our growth strategy, we continue to evaluate new
opportunities and markets for NGLs that complement our existing assets,
including international export options.
P O W D E R R I V E R B A S I N
W I L L I S T O N B A S I N
2
GROWTH PROJECTS: NATURAL GAS LIQUIDS
PROJECT
DESCRIPTION
LOCATION
APPROXIMATE COST EXPECTED COMPLETION
West Texas LPG
Pipeline expansion
Sterling III Pipeline
expansion and
Arbuckle connection
Elk Creek Pipeline
and infrastructure
120-mile pipeline lateral extension
with 110,000 bpd of capacity
Permian Basin
$200 million*
Complete
60,000 bpd pipeline expansion,
increasing capacity to 250,000 bpd
Mid-Continent to
Gulf Coast
$130 million
Complete
900-mile pipeline with initial capacity
of up to 240,000 bpd
Williston Basin to
Mid-Continent (Bushton)
$1.4 billion
Fourth quarter 2019**
Arbuckle II Pipeline
and infrastructure
530-mile pipeline with initial capacity
of up to 400,000 bpd
Mid-Continent to
Mont Belvieu
$1.36 billion
First quarter 2020
MB-4 fractionator
and infrastructure
West Texas LPG
Pipeline expansion and
Arbuckle II connection
MB-5 fractionator
and infrastructure
Arbuckle II Pipeline
extension and
infrastructure
Arbuckle II
Pipeline expansion
125,000 bpd fractionator
Mont Belvieu
$575 million
First quarter 2020
80,000 bpd mainline expansion
with addition of pump facilities and
pipeline looping, and connection to
Arbuckle II Pipeline
Permian Basin
$295 million
First quarter 2020
125,000 bpd fractionator
Mont Belvieu
$750 million
First quarter 2021
Additional takeaway capacity in the
STACK area
100,000 bpd mainline expansion,
increasing capacity to 500,000 bpd
with addition of pump facilities
Mid-Continent (STACK)
$240 million
First quarter 2021
Texas
$60 million
First quarter 2021
* Reflects total project cost. In July 2018, ONEOK acquired the remaining 20 percent interest in the West Texas LPG Pipeline Limited Partnership.
** Southern section of the pipeline expected to be in service as early as the third quarter 2019.
M I D - C O N T I N E N T
Elk Creek Pipeline Construction >
3
Our success in 2018 was not limited, however, to our natural gas liquids
business. We also saw tremendous growth in our natural gas gathering
and processing and natural gas pipelines segments supported by the
completion of several key projects.
In the Mid-Continent region, the completion of the Canadian Valley
plant expansion added approximately 200 million cubic feet per day
(MMcf/d) of capacity, increasing our natural gas processing capacity
to approximately 1.2 billion cubic feet per day (Bcf/d). Our Oklahoma
operations are supported by more than 300,000 acres of dedication
in the STACK and SCOOP plays.
In the Williston Basin, we expect the Demicks Lake I processing plant to
reach full capacity soon after it is completed, which we expect to occur
later this year, followed by Demicks Lake II, expected in early 2020.
These processing plants will add 400 MMcf/d of natural gas processing
capacity and bring our total in the basin to 1.4 Bcf/d – supported by
more than 3 million acres of dedication in the Williston Basin.
We connected nearly 750 wells to our natural gas gathering systems in
2018 and invested in upgrades, additional compression and expansions
to our existing infrastructure, which led to double-digit volume growth
compared with 2017. We operate more than 19,000 miles of natural gas
gathering pipelines systemwide and remain the largest independent operator
of natural gas gathering and processing facilities in the Williston Basin.
The increase in volumes from natural gas processing operations
overall resulted in additional takeaway needs from our natural
gas pipelines segment, which transports natural gas and delivers
it to market centers.
Arbuckle II Pipeline Construction >
4
Canadian Valley Plant Expansion >
M I D - C O N T I N E N T
In 2018 and the first quarter of 2019, our natural gas pipelines
business completed infrastructure expansions that added more
than 1.5 Bcf/d of transportation capacity in the Permian Basin
and Mid-Continent region. These projects were anchored by firm,
long-term commitments, enhancing the segment’s earnings portfolio
that already was nearly 100 percent fee-based.
Both our NGL and natural gas growth projects in the Permian Basin
are part of a broader strategy to capitalize on the potential of our
legacy West Texas LPG system, ONEOK WesTex Transmission system
and Roadrunner Pipeline to position ourselves for future long-term,
capital-efficient expansions.
A R B U C K L E I I
THESE COMPLETED GROWTH PROJECTS ADD:
800
1∙5
MMCF/D OF NATURAL GAS
PROCESSING CAPACITY
BCF/D OF NATURAL GAS
TRANSPORTATION CAPACITY
S TA C K & S C O O P P L AY S
GROWTH PROJECTS: NATURAL GAS GATHERING AND PROCESSING
PROJECT
DESCRIPTION
LOCATION
APPROXIMATE COST
EXPECTED COMPLETION
Additional processing
capacity
200 MMcf/d long-term processing
services agreement with a third party
Mid-Continent (STACK)
$40 million
Complete
Canadian Valley
plant expansion
and infrastructure
Demicks Lake I plant
and infrastructure
Demicks Lake II plant
and infrastructure
200 MMcf/d processing plant
expansion, increasing capacity to
more than 400 MMcf/d
Mid-Continent (STACK)
$160 million
Complete
200 MMcf/d processing plant
Williston Basin
$400 million
Fourth quarter 2019
200 MMcf/d processing plant
Williston Basin
$410 million
First quarter 2020
GROWTH PROJECTS: NATURAL GAS PIPELINES
PROJECT
DESCRIPTION
LOCATION
EXPECTED COMPLETION
M O N T B E LV I E U
ONEOK Gas Transportation
westbound expansion
ONEOK Gas Transportation
eastbound expansion
ONEOK WesTex
Transmission expansion
Roadrunner Gas
Transmission
bidirectional pipeline*
*50 percent owned
100 MMcf/d expansion to interstate pipeline delivery points
Mid-Continent (STACK) to
western Oklahoma
Complete
150 MMcf/d expansion to an interstate pipeline delivery point
300 MMcf/d expansion to interstate pipeline delivery points
Approximately 1 Bcf/d of eastbound transportation capacity
Mid-Continent
(STACK and SCOOP)
to eastern Oklahoma
Permian Basin to
Texas Panhandle
Delaware Basin to
Waha area
Complete
Complete
Complete
5
ONEOK FINANCIAL HIGHLIGHTS
Years ended Dec. 31
2018
2017
2016
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
Earnings per share from net income available to ONEOK1
Dividends paid
Market price range
High
Low
Year-end
$
$
$
$
$
$
$
$
$
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
$
$
$
$
$
$
$
$
$
1,295.8
743.5
352.0
16,138.8
210,681,661
1.66
2.46
59.03
19.62
57.41
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)
Net income
Interest expense, net of capitalized interest
Depreciation and amortization
Income tax expense
Impairment charges
Noncash compensation expense
Other noncash items and equity AFUDC2
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
2018
2017
$
1,155.0
$
593.5
$
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
$
$
$
$
$
$
$
$
$
$
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
$
$
$
$
$
2016
743.5
469.7
391.6
212.4
-
32.0
0.7
1,849.9
(469.7)
(112.4)
(139.7)
196.7
(2.5)
1,322.3
-
(541.9)
780.4
(517.1)
263.3
2.460
1.51
2 2017 includes ONEOK’s April 2017 noncash contribution to the ONEOK Foundation of 20,000 shares of Series E Preferred Stock, with an aggregate
value of $20 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.
6
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; and
• 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 many 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 our financial performance and to compare our financial performance with the performance of other companies within our industry. Adjusted EBITDA,
ONEOK 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.
ONEOK also has disclosed in this annual report forward-looking estimates for projected adjusted EBITDA multiples expected to be generated by the announced capital-growth projects. Adjusted EBITDA multiples for
the announced capital-growth projects reflect the expected adjusted EBITDA to be generated by the projects relative to the capital investment being made.
A reconciliation of estimated adjusted EBITDA multiples to GAAP net income is not provided because the GAAP net income generated by the projects is not available without unreasonable efforts.
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 natural gas liquids pipelines and processing 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,” “estimate,” “expect,” “project,” "will," "would," “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,”
“might,” “potential,” “scheduled” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements. 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:
• 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;
the capital intensive nature of our businesses;
the profitability of assets or businesses acquired or constructed by us;
•
•
• our ability to make cost-saving changes in operations;
•
•
•
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;
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 impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to obtain necessary permits; reserve performance; and capacity
constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
•
the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;
• difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;
•
• 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 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;
•
the results of administrative proceedings and litigation, regulatory actions, 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 CFTC;
• our ability to access capital at competitive rates or on terms acceptable to us;
•
•
•
•
•
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;
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 and outcome of pending and future litigation;
the timing and extent of changes in energy commodity prices;
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 Canadian and United States natural gas and crude oil; and
– availability of additional storage capacity;
• performance of contractual obligations by our customers, service providers, contractors and shippers;
•
• 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 timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
storage, fractionation and transportation facilities without labor or contractor problems;
the mechanical integrity of facilities operated;
•
• demand for our services in the proximity of our facilities;
• our ability to control operating costs;
• acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities;
• economic climate and growth in the geographic areas in which we do business;
•
•
•
•
•
the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
the impact of recently issued and future accounting updates and other changes in accounting policies;
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;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
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 impact of uncontracted capacity in our assets being greater or less than expected;
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 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 impact of potential impairment charges;
the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
•
•
•
•
•
•
• our ability to control construction costs and completion schedules of our pipelines and other projects; 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 have material adverse
effects on 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.
Form 10-K
Elk Creek Pipeline Construction >
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018.
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)
73-1520922
(I.R.S. Employer Identification No.)
100 West Fifth Street, Tulsa, OK
(Address of principal executive offices)
74103
(Zip Code)
Registrant’s telephone number, including area code (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Common stock, par value of $0.01
(Title of each class)
New York Stock Exchange
(Name of each exchange on which registered)
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 X 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 X.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been
subject to such filing requirements for the past 90 days. Yes X No __
Indicate by check mark whether the registrant has submitted electronically 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 X No __
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§ 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. __
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 X
Emerging growth company___
Smaller reporting company __
Non-accelerated filer __
Accelerated filer __
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.__
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes__ No X.
Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on June 30, 2018, was
$28.3 billion.
On February 19, 2019, the Company had 411,611,382 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 22, 2019, are incorporated by reference in Part III.
ONEOK, Inc.
2018 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
18
34
34
34
34
34
36
36
57
60
123
123
123
123
124
124
125
125
126
135
136
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
Bbl/d
BBtu/d
Bcf
Bcf/d
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
MMBtu
MMcf/d
Moody’s
Natural Gas Act
Natural Gas Policy Act
NGL(s)
NGL products
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, 2018
Accounting Standards Update
Barrels, 1 barrel is equivalent to 42 United States gallons
Barrels per day
Billion British thermal units per day
Billion cubic feet
Billion cubic feet per day
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 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
NYMEX
NYSE
OCC
ONEOK
ONEOK Partners
ONEOK Partners Term Loan Agreement
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
OPIS
OSHA
January 8, 2016, as amended
Oil Price Information Service
Occupational Safety and Health Administration
3
PHMSA
United States Department of Transportation Pipeline and Hazardous Materials
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
Safety Administration
Percent of Proceeds
Quarterly Report(s) on Form 10-Q
Roadrunner Gas Transmission, LLC, a 50 percent-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,” “estimate,” “expect,” “project,” “intend,” “plan,”
“believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and
other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on
reasonable assumptions, we can give no assurance that such expectations 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 a corporation 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 natural gas
liquids systems, connecting NGL supply in the Mid-Continent, Permian and Rocky Mountain 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.
EXECUTIVE SUMMARY
Merger Transaction - On June 30, 2017, we completed the acquisition of all of the outstanding common units of ONEOK
Partners that we did not already own. Prior to June 30, 2017, we and our subsidiaries owned all of the general partner interest,
which included incentive distribution rights, and a portion of the limited partner interest, which together represented a
41.2 percent ownership interest in ONEOK Partners. The earnings of ONEOK Partners that are attributed to its units held by
the public during the six months ended June 30, 2017, are reported as “Net income attributable to noncontrolling interests” in
our Consolidated Statement of Income. Our general partner incentive distribution rights effectively terminated at the closing of
the Merger Transaction.
Business Update and Market Conditions - We operate primarily fee-based businesses in each of our three reportable
segments, and our consolidated earnings were nearly 90 percent fee-based in 2018. We are connected to supply in growing
basins and have significant basin diversification, including the Williston, Permian, Powder River and DJ Basins and the
STACK and SCOOP areas. 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. Our exposure to volumetric
risk can result from declining well productivity, reduced drilling activity, severe weather disruptions, operational outages and
ethane rejection. Commodity prices decreased in the fourth quarter 2018 and are expected to fluctuate in 2019. However, we
do not expect supply volumes in our three business segments to be materially impacted.
Volumes increased across our operating regions in our Natural Gas Gathering and Processing and Natural Gas Liquids
segments in 2018, compared with 2017, as a result of improved crude oil prices, producers experiencing improved drilling
economics and continued improvements in production due to enhanced completion techniques. In addition, we experienced
increased demand for NGL products from petrochemical and NGL export facilities in the Gulf Coast. We have spent
approximately $2 billion of our announced $6 billion of capital-growth projects that include NGL pipelines, NGL fractionators
and natural gas processing plants supported by a combination of long-term primarily fee-based contracts, volume commitments
and/or acreage dedications. Our NGL projects in the Gulf Coast also allow flexibility to construct additional NGL
fractionators, storage and potentially, new export facilities in the future. We expect these projects to meet the needs of natural
gas processors and producers and the petrochemical industry that require additional midstream infrastructure to accommodate
increasing supply and demand in the areas in which we operate.
For most of 2018, we benefited from favorable NGL price differentials as available pipeline and fractionation capacity in and
between the Conway, Kansas, and Mont Belvieu, Texas, market centers tightened due to growing NGL supply from the Mid-
Continent and Rocky Mountain regions, combined with increased petrochemical and NGL export demand in the Gulf Coast,
resulting in higher earnings from our Natural Gas Liquids segment’s optimization and marketing activities. In the fourth
quarter 2018, these differentials narrowed resulting from seasonality of supply and demand in the Mid-Continent region, lower
commodity prices and additional pipeline and fractionation capacity resulting from operational efficiencies. While we expect
NGL price differentials to be volatile in 2019, we expect that they will be wider than historical norms due to additional demand
in the Gulf Coast, additional NGL supply growth in the Mid-Continent region and continuing fractionation and pipeline
constraints. We expect these wider NGL price differentials to continue until announced NGL pipeline and fractionation
infrastructure projects, including our Arbuckle II pipeline, are completed in early 2020.
Rocky Mountain Region - We expect each of our business segments 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, our gathering and
processing capacity of 1.1 Bcf/d in this region allows us to capture natural gas from the more than 1 million acres dedicated to
us in the core of the Williston Basin and approximately 3 million acres throughout the entire basin. Natural gas gathered and
5
processed volumes in this region increased in 2018, compared with 2017, due primarily to new supply and completion of
growth projects. With continued volume growth expected due to improved drilling economics and producer efficiencies, we
are constructing our Demicks Lake I and Demicks Lake II natural gas processing plants. These projects will provide an
additional 400 MMcf/d of processing capacity in the core of the Williston Basin, helping producers meet North Dakota’s
natural gas capture targets and adding incremental NGLs to our NGL gathering system and supplying natural gas to our
50 percent-owned Northern Border Pipeline. Our Demicks Lake I plant is expected to reach capacity soon after its completion
in the fourth quarter 2019 due to more than 250 MMcf/d of natural gas currently flaring on our dedicated acreage due primarily
to lack of processing capacity. In our Natural Gas Liquids segment, the volume growth in this region has resulted in the
Overland Pass pipeline, of which we own 50 percent, and our Bakken NGL pipeline operating at or near full capacities. We are
constructing our Elk Creek pipeline to support expected supply growth and provide needed infrastructure to transport NGLs out
of the region to the Mid-Continent with connectivity to the Gulf Coast. We expect the southern section of our Elk Creek
pipeline to be in service as early as the third quarter 2019, which would allow NGL production from the Powder River Basin to
be transported on this section of pipeline before the entire Elk Creek pipeline project is complete. As a result, we expect
capacity will be available on our Bakken NGL pipeline to transport additional NGL volumes from the Williston Basin.
STACK and SCOOP - As producers continue to develop the STACK and SCOOP areas in Oklahoma, we expect increased
demand for our services from producers that need incremental takeaway capacity for natural gas and NGLs out of the Mid-
Continent region. In our Natural Gas Gathering and Processing segment, natural gas gathered and processed volumes increased
in 2018, compared with 2017, due to increased producer activity in these areas, where we have sizable acreage dedications. In
response to this increased activity, we completed the 200 MMcf/d expansion of our Canadian Valley natural gas processing
plant, which increased our total processing capacity to 1.2 Bcf/d in these areas. In our Natural Gas Liquids segment, we are the
largest NGL takeaway provider in the STACK and SCOOP areas, where NGL volumes significantly increased in 2018,
compared with 2017. To accommodate these volumes, we completed the expansion of our existing Sterling III pipeline and are
constructing our Arbuckle II pipeline to support expected supply growth and transport NGLs to the Gulf Coast market. We also
announced plans to construct an extension of our Arbuckle II pipeline further north along with additional NGL gathering
infrastructure, as well as an expansion of our Arbuckle II pipeline by 100 MBbl/d to a total capacity of 500 MBbl/d. In our
Natural Gas Pipelines segment, we are connected to more than 30 natural gas processing plants in Oklahoma. In the first
quarter 2018, we completed the 100 MMcf/d expansion of our ONEOK Gas Transportation pipeline to provide increased
westbound transportation services from the STACK area. An additional 100 MMcf/d westbound expansion from the STACK
area to multiple interstate pipeline delivery points in western Oklahoma was also completed in 2018. In the first quarter 2019,
we expect to complete an additional expansion to our ONEOK Gas Transportation pipeline with 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 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, which was recently
extended into the core of the Delaware Basin through construction of a 120-mile pipeline lateral and a 40 MBbl/d expansion of
the mainline. In September 2018, we announced a second expansion of our West Texas LPG pipeline system, which will
increase the mainline capacity out of the Permian Basin by 80 MBbl/d as well as connect our West Texas LPG pipeline with our
Arbuckle II pipeline, which is currently under construction. These projects are expected to position our West Texas LPG
pipeline system for significant future 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 supply to Mexico and transport natural gas to other markets in the region. We completed the
expansion of our WesTex Transmission system by 300 MMcf/d from the Permian Basin to interstate pipeline delivery points in
the Texas Panhandle. We also completed an expansion project on our Roadrunner joint venture to make the pipeline
bidirectional, which will result in approximately 1.0 Bcf/d of eastbound transportation capacity from the Delaware Basin to the
Waha area.
Gulf Coast - Demand for NGLs is expected to continue 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.
NGL supply growth and new NGL pipelines recently completed or being constructed, including our Elk Creek pipeline,
Arbuckle II pipeline 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. Following the completion of MB-4
and MB-5, we expect our Gulf Coast NGL fractionation capacity to be approximately 600 MBbl/d and more than
1 million Bbl/d across our entire system. Our MB-5 project also includes system expansions that provide infrastructure
6
capacity to support additional assets as we continue to evaluate opportunities for fractionation, storage and 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, 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
issues continue 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;
• Maintain prudent financial strength and flexibility while growing our fee-based earnings, dividends per share and cash
flows from operations in excess of dividends paid - we operate primarily fee-based businesses in each of our three
reportable segments. We continue to invest in organic growth projects to expand in our existing operating regions and
provide a broad range of services to crude oil and natural gas producers and end-use markets. In 2018, we paid
dividends of $3.245 per share, an increase of 19 percent compared with the prior year. Our dividend increase and
expected future dividend growth is due primarily to our growth projects. We have spent approximately $2 billion of
our announced $6 billion of capital-growth projects that are supported by a combination of long-term primarily fee-
based contracts, minimum volume commitments and acreage dedications;
• Manage our balance sheet and maintain investment-grade credit ratings - we seek to maintain investment-grade credit
ratings. We expect to benefit from increasing cash flows from operations in 2019. At December 31, 2018, we had
$2.5 billion of borrowing capacity available under our $2.5 Billion Credit Agreement and $950 million of borrowings
available under our $1.5 Billion Term Loan Agreement; 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.
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. 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 sold and delivered through natural gas liquids pipelines to fractionation facilities for further processing.
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 to more than 1.0 Bcf/d 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.
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Sources of Earnings - Earnings for this segment are derived primarily from commodity sales and service contracts. 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. The
following are our types of services 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 60 percent and 62 percent of
supply volumes in this segment for 2018 and 2017, respectively. Upon adoption of Topic 606, the contractual fees we
charge producers on these POP with fee contracts are recorded as a reduction to the commodity purchase price in cost
of sales and fuel. In 2017 and prior periods, we recorded these fees as services revenue.
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 36 percent and 34 percent of supply volumes in this segment for 2018 and 2017,
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 percent of supply volumes in
this segment in 2018 and 2017.
Property - Our Natural Gas Gathering and Processing segment owns the following assets:
•
•
•
11,500 miles and 7,700 miles of natural gas gathering pipelines in the Mid-Continent and Rocky Mountain regions,
respectively;
ten natural gas processing plants with 1.0 Bcf/d of processing capacity in the Mid-Continent region, and 11 natural gas
processing plants with 1.1 Bcf/d of processing capacity in the Rocky Mountain region; and
15 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Rocky Mountain
region.
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 constructing our Demicks Lake I and Demicks Lake II natural gas processing plants. These projects
will provide an additional 400 MMcf/d of processing capacity in the core of the Williston Basin.
Utilization - The utilization rates for our natural gas processing plants were 83 percent and 79 percent for 2018 and 2017,
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 percent ownership in Bighorn Gas Gathering, which gathers coal-bed methane produced in the Powder River
Basin;
37 percent ownership in Fort Union Gas Gathering, which gathers coal-bed methane produced in the Powder River
Basin and delivers it to the interstate pipeline system;
35 percent 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 percent 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
8
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.
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, where 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 natural gas liquids 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 natural gas liquids 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. The majority of the pipeline-connected natural gas processing plants in
Oklahoma, Kansas and the Texas Panhandle are connected to our natural gas liquids gathering systems. We own and operate
truck- and rail-loading and -unloading facilities connected to our natural gas liquids fractionation and pipeline assets.
Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal
butane and natural gasoline. The NGLs that are separated from the natural gas stream at natural gas processing plants remain in
a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are
separated into NGL products. These NGL products are then stored or distributed to our customers, such as petrochemical
manufacturers, heating fuel users, ethanol producers, refineries, exporters and propane distributors.
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 exchange services, transportation and storage services, and optimization
and marketing, which are defined 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 natural gas liquids 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. Upon adoption of Topic 606, the contractual fees we charge are now recorded as a reduction to the commodity
purchase price in cost of sales and fuel. In 2017 and prior periods, we recorded these fees as exchange services revenue. To the
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extent we hold unfractionated NGLs in inventory, the related contractual fees previously recorded in services revenue when
NGLs were received on our system will not be recognized until the unfractionated inventory is fractionated and sold.
Property - Our Natural Gas Liquids segment owns the following assets:
Region/Asset
Gathering Pipelines (a)
Rocky Mountain Region
Mid-Continent Region
West Texas LPG System
Total
Distribution Pipelines (b)
Sterling Pipelines
ONEOK North System
Other
Total
(a) - Includes 4,545 miles of FERC-regulated pipelines with peak capacity of 683 MBbl/d.
(b) - Includes 4,290 miles of FERC-regulated pipelines with peak capacity of 1,200 MBbl/d.
Region/Asset
Facilities
Gulf Coast Region Fractionators (a)
Mid-Continent Region Fractionators (a)
Isomerization Unit
Ethane/Propane Splitter
Total
Storage and Terminals
NGL Storage
ONEOK North System Terminals
Total
Miles of
Pipeline
Capacity
(MBbl/d)
846
3,760
2,849
7,455
1,804
1,704
949
4,457
135
1,161
285
1,581
458
213
595
1,266
Number of
Facilities
Capacity
(MBbl/d)
3
4
1
1
9
6
8
14
278
521
9
40
848
(MMBbl)
22.2
1.0
23.2
(a) - Includes interest in our proportional share of operating capacity.
In addition, we lease 3.8 MMBbl of combined NGL storage capacity at facilities in Kansas and Texas and have access to
60 MBbl/d of natural gas liquids fractionation capacity in the Gulf Coast through a fractionation service agreement.
We are in the process of constructing the following assets:
Region/Asset
Gathering Pipelines
Rocky Mountain Region
Mid-Continent Region
West Texas LPG System
Total
Facilities
Gulf Coast Region Fractionators (two locations)
Miles of
Pipeline
Capacity
(MBbl/d)
900
530
—
1,430
240
500
80
820
250
Utilization - The utilization rates for our various assets, including leased assets, have been impacted by ethane rejection. The
utilization rates for 2018 and 2017, respectively, were as follows:
•
•
our natural gas liquids gathering pipelines were 78 percent and 75 percent;
our natural gas liquids distribution pipelines were 59 percent and 57 percent; and
10
•
our natural gas liquids fractionators were 85 percent and 74 percent.
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 percent ownership interest in Overland Pass Pipeline Company, which operates an interstate natural gas liquids
pipeline system extending 760 miles, originating in Wyoming and Colorado and terminating in Kansas;
50 percent ownership interest in Chisholm Pipeline Company, which operates an interstate natural gas liquids pipeline
system extending 185 miles from origin points in Oklahoma and terminating in Kansas; and
50 percent ownership interest in Heartland Pipeline Company, which operates a terminal and pipeline system that
transports refined petroleum products in Kansas, Nebraska and Iowa.
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 natural gas liquids pipelines are regulated by various state and
federal government agencies. Our interstate natural gas liquids 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 natural gas liquids 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 percent 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.
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
11
•
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
right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity
is available.
Upon adoption of Topic 606, we record retained fuel charges as a reduction to cost of sales and fuel that would have been
recorded as transportation or storage revenue prior to adoption.
We own natural gas storage facilities located in Texas and Oklahoma that are connected to our intrastate natural gas pipelines.
We also have underground natural gas storage facilities in Kansas.
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;
5,200 miles of state-regulated intrastate transmission pipelines with peak transportation capacity of 4.1 Bcf/d; and
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.
Utilization - Our natural gas pipelines were 96 and 94 percent subscribed in 2018 and 2017, respectively, and our natural gas
storage facilities were 64 percent subscribed in both 2018 and 2017, respectively.
Unconsolidated Affiliates - Our Natural Gas Pipelines segment includes the following unconsolidated affiliates:
•
•
50 percent 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 percent 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 will have 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
12
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
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 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, and we are responding by constructing assets, such as our announced
Demicks Lake I and Demicks Lake II natural gas processing plants. 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 continues 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. End-
users of residue natural gas include large commercial and industrial customers, natural gas and electric utilities serving
individual consumers and similar international markets through liquefied natural gas (LNG) exports.
Commodity Prices - Our earnings are primarily fee-based in all three of our segments. In our Natural Gas Gathering and
Processing segment, we are exposed to limited 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 market 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, and 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 market 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;
(ii) interruptible contracts or when existing firm contracts expire and are subject to renegotiation with customers that have
competitive alternatives, which affect our transportation revenues; and (iii) 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.
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
generators 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.
13
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 provide
midstream services across our operating regions, which may affect commodity prices and compete with and could displace
supply volumes from the Mid-Continent and Rocky Mountain regions and 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
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.
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 505,000 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 materially 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.
14
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 and climate change 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 natural gas liquids 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 greatly 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 or to purchase allowances for such emissions. However, we cannot predict precisely what form these future
regulations will take, the stringency of the regulations or when they will become effective. 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.
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.
Since 2015, PHMSA has issued notices of proposed rule-making for hazardous liquid pipeline safety regulations, natural gas
transmission and gathering lines and underground natural gas storage facilities, none of which have become final. 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, 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.
15
Our 2017 total emissions reported pursuant to EPA requirements were approximately 50 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 costs, fees or expenses on any of
these emissions.
We closely 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
complete Site Security Plans and possible physical security enhancements. We do not expect the Site Security Plans and
possible security enhancement costs 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, 2019, we employed 2,684 people.
16
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
Age
Business Experience in Past Five Years
66
2011 to present
Chairman of the Board, ONEOK
2007 to 2017
Chairman of the Board, ONEOK Partners
2007 to 2014
Chief Executive Officer, ONEOK and ONEOK Partners
Terry K. Spencer
59
2014 to present
President and Chief Executive Officer, ONEOK
President and Chief Executive Officer
2014 to 2017
President and Chief Executive Officer, ONEOK Partners
2014 to present Member of the Board of Directors, ONEOK
2014 to 2017
Member of the Board of Directors, ONEOK Partners
2012 to 2014
President, ONEOK and ONEOK Partners
Robert F. Martinovich
Executive Vice President and Chief
Administrative Officer
61
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
2013 to 2014
Executive Vice President, Operations, ONEOK and ONEOK Partners
Walter S. Hulse III
55
2017 to present
Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs,
ONEOK
Chief Financial Officer, Executive Vice President,
Strategic Planning and Corporate Affairs
2015 to 2017
Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK and ONEOK
Partners
Kevin L. Burdick
54
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
2012 to 2015
Managing Member, Spinnaker Strategic Advisory Services, LLC
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
Wesley J. Christensen
65
2014 to present
Senior Vice President, Operations, ONEOK
Senior Vice President, Operations
2011 to 2017
Senior Vice President, Operations, ONEOK Partners
Charles M. Kelley
60
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
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
2008 to 2014
Senior Vice President, Energy Services, ONEOK
Sheridan C. Swords
49
2013 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
Derek S. Reiners
47
2017 to present
Senior Vice President, Finance and Treasurer, ONEOK
Senior Vice President, Finance and Treasurer
2013 to 2017
Senior Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners
Stephen B. Allen
45
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
Sheppard F. Miers III
50
2013 to present
Vice President and Chief Accounting Officer, ONEOK
Vice President and Chief Accounting Officer
2013 to 2017
Vice President and Chief Accounting Officer, 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
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, 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.
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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.
RISKS INHERENT IN OUR BUSINESS
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 connected to, and dependent on the level of production from, natural gas
and crude oil wells, from which production will naturally decline 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 plants, 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:
•
•
•
•
•
•
•
demand and prices for natural gas, NGLs and crude oil;
producers’ access to capital;
producers’ finding and development costs of reserves;
producers’ desire and ability to obtain necessary permits in a timely manner;
natural gas field characteristics and production performance;
surface access, requirements to secure drilling rights and infrastructure issues; and
capacity constraints on natural gas, crude oil and natural gas liquids 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 have a material adverse effect on 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 near certain market areas that we serve may compete with natural
gas originating in production areas connected to our systems. For example, the Marcellus Shale may cause natural gas 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 at rates sufficient to maintain
current revenues and cash flows. In addition, supply volumes from other natural gas production areas may compete with and
displace volumes from the Mid-Continent, Permian, Rocky Mountains and Canadian supply sources in certain of our markets.
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 result in lower transportation revenues, which could have a material adverse impact on our business,
financial condition, results of operations and cash flows.
Market volatility and capital availability could affect adversely our business.
The capital and global credit markets have experienced volatility and disruption in the past. In many cases during these
periods, the capital markets have exerted downward pressure on equity values and reduced the credit capacity for certain
companies. Much of our business is capital intensive, and our ability to grow is dependent, in part, upon our ability to access
capital at rates and on terms we determine to be attractive. Similar or more severe levels of global market disruption and
volatility may have an adverse effect on us resulting from, but not limited to, disruption of our access to capital and credit
18
markets, difficulty in obtaining financing necessary to expand facilities or acquire assets, increased financing costs and
increasingly restrictive covenants. If we are unable to access capital at competitive rates, our strategy of enhancing the
earnings potential of our existing assets, including through capital-growth projects and acquisitions of complementary assets or
businesses, may be affected adversely. A number of factors could affect adversely our ability to access capital, including:
(i) general economic conditions; (ii) capital market conditions; (iii) market prices for natural gas, NGLs and other
hydrocarbons; (iv) the overall health of the energy and related industries; (v) ability to maintain investment-grade credit ratings;
(vi) share price and (vii) capital structure. If our ability to access capital becomes constrained significantly, our interest costs
and cost of equity will likely increase and could affect adversely our financial condition and future results of operations.
Our operating results may be affected materially and adversely by unfavorable economic and market conditions.
Economic conditions worldwide have from time to time contributed to slowdowns in 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 products and services. 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
customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. If global economic and
market conditions (including volatility in commodity markets) or economic conditions in the United States or other key
markets remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business,
financial condition, results of operations and liquidity.
Increased competition could have a significant adverse financial impact on our business.
The natural gas and natural gas liquids industries are expected to remain highly competitive. The demand for natural gas
and NGLs is primarily a function of commodity prices, including prices for alternative energy sources, customer usage rates,
weather, economic conditions and service costs. Our ability to compete also depends on a number of other factors,
including competition from other companies for our existing customers; the efficiency, quality and reliability of the services
we provide; and competition for throughput at our gathering systems, pipelines, processing plants, fractionators and storage
facilities.
Increased regulation of exploration and production activities, including hydraulic fracturing and disposal of waste
water, could result in reductions or delays in drilling and completing new crude oil and natural gas wells, which could
impact adversely our earnings by decreasing the volumes of natural gas and NGLs transported on our or our joint
ventures’ natural gas and natural gas liquids pipelines.
The natural gas industry is relying increasingly on natural gas 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 impose operational delays, increase operating costs and additional regulatory burdens on exploration and
production operators, which could reduce their production of unprocessed natural gas and, in turn, affect adversely our
revenues and results of operations by decreasing the volumes of unprocessed natural gas and NGLs gathered, treated,
processed, fractionated and transported on our or our joint ventures’ natural gas and natural gas liquids pipelines, which
primarily gather unprocessed natural gas from areas where the use of hydraulic fracturing is prevalent.
In the competition for supply, we may have significant levels of excess capacity on our natural gas and natural gas
liquids pipelines, processing, fractionation and storage assets.
Our natural gas and natural gas liquids pipelines, processing, fractionation and storage assets compete with other pipelines,
processing, fractionation and storage facilities 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 pipelines, processing, fractionation
and in our storage assets, which could have a material adverse impact on our results of operations and cash flows.
19
We may not be able to replace, extend or add additional contracted volumes on favorable terms, or at all, which could
affect our financial condition, the amount of cash available to pay dividends and our ability to grow.
Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such
contracts, add additional customers and suppliers or otherwise increase the contracted volumes of natural gas and NGLs
provided to us by current producers, our financial condition, growth plans and the amount of cash available to pay dividends
could be affected adversely. Our ability to replace, extend or add additional customer or supplier contracts, or increase
contracted volumes of natural gas and NGLs from current producers, on favorable terms, or at all, is subject to a number of
factors, some of which are beyond our control, including:
•
the level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, fuel
oils or nuclear energy;
natural gas and NGL prices, demand, availability; and
•
• margins in our markets.
We may face opposition to the construction or operation of our pipelines and facilities from various groups.
We may face opposition to the construction or operation of our pipelines and facilities from environmental groups, landowners,
tribal groups, local groups and other advocates. Such opposition could take many forms, including 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
business. For example, constructing our pipelines often involves securing consent from individual landowners to access their
property; one or more landowners may resist our efforts, which could lead to delays in the construction of assets for a period of
time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or terrorism could cause
significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any
such event that delays or interrupts the construction or operation of assets or revenues generated by our existing operations, or
which causes us to make significant expenditures not covered by insurance, could affect adversely our financial condition,
results of operations, cash flows and our share price.
Growing our business by constructing new pipelines and plants 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.
One of the ways we may grow our businesses is through the construction of new pipelines and new gathering, processing,
storage and fractionation facilities and through modifications to our existing pipelines and existing gathering, processing,
storage and fractionation facilities. The construction and modification of pipelines and gathering, processing, storage and
fractionation facilities may face the following risks:
•
projects may require significant capital expenditures, which may exceed our estimates, and involves numerous
regulatory, environmental, political, legal and weather-related uncertainties;
•
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
•
•
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
production growth does not materialize; 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 materially and adversely our results of operations, financial condition 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
20
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 have a material adverse effect on our results of operations and financial condition.
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:
•
•
• market uncertainty;
•
•
•
•
• weather conditions;
•
•
•
•
•
•
•
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.
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
have a material adverse effect on our earnings 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.
Our operations are subject to operational hazards and unforeseen interruptions, which could affect materially and
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 natural gas
liquids gathering, transportation and distribution pipelines, storage facilities and processing and fractionation plants. Operating
risks include, but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes and the
performance of pipeline 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 or other similar events beyond our control. It is also
possible that our facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might 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 revenues generated by us 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 have a material adverse
effect on our financial position, cash flows and results of operations. 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.
21
We may not be able to develop and execute growth projects and acquire new assets, which could result in reduced
dividends to our shareholders.
Our ability to maintain and grow our dividends paid to our shareholders depends on the growth of our existing businesses and
strategic acquisitions. Our ability to make strategic acquisitions and investments will depend on:
•
•
•
•
the extent to which acquisitions and investment opportunities become available;
our success in bidding for the opportunities that do become available;
regulatory approval, if required, of the acquisitions or investments on favorable terms; and
our access to capital, including our ability to use our equity in acquisitions or investments, and the terms upon which
we obtain capital.
Our ability to develop and execute growth projects will depend on our ability to implement business development opportunities
and finance such activities on economically acceptable terms.
If we are unable to make strategic acquisitions and investments, integrate successfully businesses that we acquire with our
existing business, or develop and execute our growth projects, our future growth will be limited, which could impact adversely
our results of operations and cash flows and, accordingly, result in reduced cash dividends over time.
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.
Mergers between our customers, suppliers and competitors could result in lower volumes being gathered, processed,
fractionated, transported or stored on our assets, thereby reducing the amount of cash we generate.
Mergers between our existing customers, suppliers and our competitors could provide strong economic incentives for the
combined entities to utilize their existing gathering, processing, fractionation and/or transportation systems instead of ours in
those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from
these counterparties, and we could experience difficulty in replacing those lost volumes. A reduction in volumes could result
not only in lower net income but also in a decline in cash flows, which would reduce our ability to pay cash dividends to our
shareholders.
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
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rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could
have a material adverse effect on our financial condition, results of operations and cash flows.
Terrorist attacks directed at our facilities could affect adversely our business.
The United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be
future targets of terrorist organizations. These developments may subject our operations to increased risks. Any future terrorist
attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material
adverse effect on our business.
Any reduction in our credit ratings could affect materially and adversely our business, financial condition, liquidity and
results of operations.
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, in its judgment, circumstances in the future so warrant. Specifically, 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.
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. 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 we 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 have a
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material adverse impact on our business, results of operations, financial condition 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.
Our established risk-management policies and procedures may not be effective, and employees may violate our risk-
management policies.
We have developed and implemented a comprehensive set of policies and procedures that involve both our senior management
and our Audit Committee to assist us in managing risks associated with, among other things, the marketing, trading and risk-
management activities associated with our business segments. Our risk-management policies and procedures are intended to
align strategies, processes, people, information technology and business knowledge so that risk is managed throughout the
organization. As conditions change and become more complex, current risk measures may fail to assess adequately the relevant
risk due to changes in the market and the presence of risks previously unknown to us. Additionally, if employees fail to adhere
to our policies and procedures or if our policies and procedures are not effective, potentially because of future conditions or
risks outside of our control, we may be exposed to greater risk than we had intended. Ineffective risk-management policies and
procedures or violation of risk-management policies and procedures could have an adverse effect on our earnings, financial
position or cash flows.
Our businesses are subject to market and credit risks.
We are exposed to market and credit risks in all of our operations. To reduce the impact of commodity price fluctuations, we
may use derivative instruments, such as swaps, puts, futures and forwards, to hedge anticipated purchases and sales of natural
gas, NGLs, crude oil and firm transportation commitments. Interest-rate swaps are also used to manage interest-rate risk.
However, derivative instruments do not eliminate the risks. Specifically, such risks include commodity price changes, market
supply shortages, interest-rate changes and counterparty default. The impact of these variables could result in our inability to
fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts, or increased
interest expense.
We do not hedge fully against 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 cash flows and future 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 with respect to our natural gas and NGL
transportation businesses;
the seasonal price differentials in natural gas and NGLs related to our storage operations; 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, puts, futures, forwards and options. However, we do not hedge fully against commodity price changes, and we
therefore retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased
revenue and increased costs.
Our use of financial instruments and physical-forward transactions to hedge market-risk exposure to commodity price
and interest-rate fluctuations may result in reduced income.
We utilize financial instruments and physical-forward transactions to mitigate our exposure to interest rate and commodity
price fluctuations. 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
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rate exceeds the variable rate. Hedging arrangements for forecasted sales are used to reduce our exposure to commodity price
fluctuations and limit the benefit we would otherwise receive if market prices for natural gas, crude oil and NGLs exceed the
stated price in the hedge instrument for these commodities.
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. From time to time we use interest-rate derivatives to hedge interest obligations on specific
debt issuances, including anticipated debt issuances.
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 comprised 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.
Our $2.5 Billion Credit Agreement and our $1.5 Billion Term Loan Agreement include language to determine a replacement
rate for LIBOR, if necessary. However, if LIBOR ceases to exist, we may need to renegotiate future agreements, if any,
extending beyond 2021 that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard
that is established. There is currently no definitive information regarding the future utilization of LIBOR or of any particular
replacement rate. As such, the potential effect on us cannot yet be determined.
Demand for natural gas and for certain of our NGL products and services is highly weather sensitive and seasonal.
The demand for natural gas and for certain of our NGL products, such as propane, is weather sensitive and seasonal, with a
portion of revenues derived from sales for heating during the winter months. Weather conditions influence directly the volume
of, among other things, natural gas and propane delivered to customers. Deviations in weather from normal levels and the
seasonal nature of certain of our segments can create variations in earnings and short-term cash requirements.
Energy efficiency and technological advances may affect the demand for natural gas and NGLs and affect adversely our
operating results.
More strict local, state and federal energy-conservation measures in the future or technological advances in heating, including
installation of improved insulation and the development of more efficient furnaces, energy generation or other devices could
affect the demand for natural gas and NGLs and affect adversely our results of operations and cash flows.
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 or tax requirements;
providing data security; and
handling other processing 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 employee causes our operational systems to fail, either as a result of inadvertent error or by
deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may
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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 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 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.
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, which would harm our business and cost of capital.
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 interests.
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 have a material and adverse effect on our reputation, business,
financial condition, cash flows and results of operations.
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Pipeline safety laws and regulations may impose significant costs and liabilities.
Pipeline safety legislation that was signed into law in 2012, the 2011 Pipeline Safety Act, directed the Secretary of
Transportation to promulgate new safety regulations for natural gas and hazardous liquids pipelines, including expanded
integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system
installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming the
maximum allowable pressure of certain gas transmission pipelines. The 2011 Pipeline Safety Act also increased the
maximum penalty for violation of pipeline safety regulations from $0.1 million to $0.2 million per violation per day and also
from $1 million to $2 million for a related series of violations.
The 2011 Pipeline Safety Act, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act or rules implementing
such acts could cause us to incur capital and operating expenditures for pipeline replacements or repairs, additional
monitoring equipment or more frequent inspections or testing of our pipeline facilities, preventive or mitigating measures and
other tasks that could result in higher operating costs or capital expenditures as necessary to comply with such standards,
which costs could be significant.
See further discussion in the “Regulatory, Environmental and Safety Matters” section.
Compliance with environmental regulations that we are subject to may be difficult and costly.
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 our 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 clean-up costs,
which could affect materially our results of operations and cash flows. In addition, emissions controls and/or other regulatory
or permitting mandates under the federal Clean Air Act and other similar federal and state laws could require unexpected
capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised
or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in
increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from
customers, could have a material adverse effect on our business, financial condition, cash flows and results of operations.
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
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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 costs or may not provide sufficient coverage in the event an
environmental claim is made against us. Our business may be affected materially and 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 materially and adversely our products and activities, and
federal and state agencies could impose additional safety requirements, all of which could affect materially our profitability.
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 may require us either to limit GHG emissions
associated with our operations or to purchase allowances for such emissions. However, we cannot predict precisely what form
these future regulations will take, the stringency of the regulations or when they will become effective. Several legislative bills
have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously
considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called
“caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions, even
though the technology is not currently available for efficient reduction, or to purchase allowances for such emissions.
Emissions also could be taxed independently of limits.
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.
Future legislation and/or regulation designed to reduce GHG emissions 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, cash flows or financial condition could be
affected adversely if such costs are not recovered through regulated rates or otherwise passed on to our customers.
We continue to monitor legislative and regulatory developments in this area and otherwise take efforts to limit GHG emissions
from our facilities, including methane. Although the regulation of GHG emissions may have a material impact on our
operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.
We may be subject to physical and financial risks associated with climate change.
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. To the extent financial markets
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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. Our business could be affected by the potential
for lawsuits against GHG emitters, based on links drawn between GHG emissions and climate change.
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:
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.
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 operations.
We cannot guarantee that state or federal regulators 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.
Failure to comply with all applicable state or federal statutes, rules and regulations and orders could bring substantial penalties
and fines. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act
to impose penalties for current violations of up to $1 million per day for each violation.
Finally, we cannot give any assurance regarding future state or federal regulations under which we will operate or the effect
such regulations could have on our business, financial condition, results of operations and cash flows.
Our regulated pipelines’ transportation rates are subject to review and possible adjustment by federal and state
regulators.
Under the Natural Gas Act, which is applicable to interstate natural gas pipelines, and the Interstate Commerce Act, which is
applicable to crude oil and natural gas liquids pipelines, our interstate transportation rates, which are regulated by the FERC,
must be just and reasonable and not unduly discriminatory.
If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the
tariff rate increase is approved and the time that the rate increase actually goes into effect. Furthermore, competition from
other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The
regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of
services subject to their jurisdiction. New initiatives or orders may affect adversely the rates charged for our services.
Finally, shippers may protest our pipeline tariff filings, and the FERC and or state regulatory agency may investigate tariff
rates. Further, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to
be in excess of a just and reasonable level. In addition, shippers may challenge by complaint the lawfulness of tariff rates that
have become final and effective. The FERC and/or state regulatory agencies also may investigate tariff rates absent shipper
complaint. Any finding that approved rates exceed a just and reasonable level on the natural gas pipelines would take effect
prospectively. In a complaint proceeding challenging natural gas liquids pipeline rates, if the FERC determines existing rates
exceed a just and reasonable level, it could require the payment of reparations to complaining shippers for up to two years
prior to the complaint. Any such action by the FERC or a comparable action by a state regulatory agency could affect
adversely our pipeline businesses’ ability to charge rates that would cover future increases in costs, or even to continue to
collect rates that cover current costs, and provide for a reasonable return. We can provide no assurance that our pipeline
systems will be able to recover all of their costs through existing or future rates.
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We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs are
dependent on regulatory action.
Federal, state and local agencies have jurisdiction over many of our activities, including regulation by the FERC of our
interstate pipeline assets. The profitability of our regulated operations is dependent on our ability to pass through costs related
to providing energy and other commodities to our customers by filing periodic rate cases. The regulatory environment
applicable to our regulated businesses could impair our ability to recover costs historically absorbed by our customers.
We are unable to predict the impact that the future regulatory activities of these agencies will have on our operating results.
Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial
condition, cash flows and results of operations.
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, which
could affect operations and cash flows available for dividends to our shareholders.
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 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 have an
adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the
demand for our products and services, which could affect adversely our operations and cash flows available for dividends to
our shareholders.
We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these
regulations could affect adversely our business, financial position, results of operations and cash flows.
The workplaces associated with our facilities are subject to the requirements of OSHA and comparable state statutes that
regulate the protection of the health and safety of workers. The failure to comply with OSHA requirements or general industry
standards, including keeping adequate records or monitoring occupational exposure to regulated substances, could expose us to
civil or criminal liability, enforcement actions, and regulatory fines and penalties and could have a material adverse effect on
our business, financial position, results of operations 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 natural gas liquids 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 throughout our natural gas and natural gas liquids
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 can occur on
our systems, which could negatively affect our business, financial position, results of operations and cash flows.
Many of our pipeline and storage 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 materially and adversely our results of
operations, financial position or cash flows, as well as our ability to pay cash dividends.
30
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
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 percent) 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, 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.
We do not operate all of our joint-venture assets nor do we employ directly all of the persons responsible for providing
us with 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 operating results.
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 provider.
Some or all of these services may be outsourced to third parties, and a failure to perform by these third-party providers could
lead to delays in or interruptions of these services. We may have to contract elsewhere for these 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 negatively affect our business
and operating results. Our reliance on others to operate joint-venture assets, together with our limited ability to control certain
costs, could harm our business and results of operations.
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.
Our indebtedness and guarantee obligations could impair our financial condition and our ability to fulfill our
obligations.
As of December 31, 2018, we had total indebtedness of $9.4 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;
•
31
•
•
•
•
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 Operation. 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, 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 our existing and future secured indebtedness as well as to any existing and future
indebtedness of our subsidiaries that do not guarantee the senior notes.
Our debt securities are effectively subordinated to claims of our secured creditors, and the guarantees are effectively
subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Although
many of our operating subsidiaries have guaranteed such 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 senior notes
and ONEOK Partners’ senior notes. Such events of default would entitle the trustee or the holders of 25 percent 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 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.
Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. 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 hold that the direct obligations of the guarantor could be
superior to the obligations under that cross guarantee.
32
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 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, 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 have a material adverse effect on 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 impact adversely our business, financial condition and liquidity.
TAX RISKS
Federal, state and local jurisdictions may challenge our tax return positions.
The positions taken in our federal and state tax return filings require significant judgments, use of estimates and the
interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts
of deductible and taxable items. Despite management’s belief that our tax return positions are fully supportable, certain
positions may be successfully challenged by federal, state and local jurisdictions.
Changes in guidance and regulation related to the Tax Cuts and Jobs Act legislation may impact us.
Since the Tax Cuts and Jobs Act was enacted, additional guidance in the form of notices and proposed regulations which
interpret various aspects of the legislation have been issued. Additionally, the legislation could be subject to potential
amendments and technical corrections. We continue to monitor proposed regulations and other guidance related to the Tax
Cuts and Jobs Act and will continue to apply applicable guidance and rule-making as it becomes available. Any future
33
interpretations, regulations, amendments or corrections could have an adverse impact on our financial condition, results of
operations and cash flows.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
PROPERTIES
A description of our properties is included in Item 1, Business.
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 19, 2019, there were 14,223 holders of record of our 411,611,382 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 in this Annual
Report.
34
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, 2013, and ending on
December 31, 2018.
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, 2013, and at the End of Every Year Through December 31, 2018.
2014
2015
Cumulative Total Return
Years Ended December 31,
2016
2017
2018
ONEOK, Inc.
S&P 500 Index
ONEOK Peer Group (a)
Alerian Energy Infrastructure Index (b)
$
$
$
$
94.68
113.68
122.75
113.90
$
$
$
$
49.84
115.24
74.58
71.60
$
$
$
$
124.28
129.02
97.94
102.60
$
$
$
$
121.69
157.17
90.23
103.10
$
$
$
$
129.34
150.27
75.23
84.68
(a) - The ONEOK Peer Group is comprised of the following companies: Buckeye Partners, L.P.; DCP Midstream, LP; Enbridge Inc.; Energy
Transfer LP.; EnLink Midstream Partners, LP; 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 40 North American energy
infrastructure companies who are engaged in midstream activities involving energy commodities.
35
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for the periods indicated:
Revenues
Net income
Net income attributable to ONEOK
Total assets
Long-term debt, including current maturities
Earnings per share - total
Basic
Diluted
Dividends declared per share of common stock
2018
12,593.2
1,155.0
1,151.7
18,231.7
9,381.0
2.80
2.78
3.245
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Years Ended December 31,
2017
2015
2016
(Millions of dollars, except per share data)
12,173.9
593.5
387.8
16,845.9
8,524.3
1.30
1.29
2.72
$
$
$
$
$
$
$
$
8,920.9
743.5
352.0
16,138.8
8,330.6
1.67
1.66
2.46
$
$
$
$
$
$
$
$
7,763.2
379.2
245.0
15,446.1
8,434.2
1.17
1.16
2.43
$
$
$
$
$
$
$
$
2014
12,195.1
663.1
314.1
15,261.8
7,160.8
1.50
1.49
2.125
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. Therefore, contractual fees in these identified contracts are now 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. For more
information, see Note O in the Notes to the Consolidated Financial Statements.
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.
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, $264.3 million and $76.4 million in 2017, 2015 and 2014,
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.
Merger Transaction - On June 30, 2017, we completed the acquisition of all of the outstanding common units of ONEOK
Partners that we did not already own. Prior to June 30, 2017, we and our subsidiaries owned all of the general partner interest,
which included incentive distribution rights, and a portion of the limited partner interest, which together represented a
41.2 percent ownership interest in ONEOK Partners. The earnings of ONEOK Partners that are attributed to its units held by
the public during the six months ended June 30, 2017, are reported as “Net income attributable to noncontrolling interests” in
our Consolidated Statement of Income. Our general partner incentive distribution rights effectively terminated at the closing of
the Merger Transaction.
Market Conditions - Volumes increased across our operating regions in our Natural Gas Gathering and Processing and Natural
Gas Liquids segments in 2018, compared with 2017, as a result of improved crude oil prices, producers experiencing improved
drilling economics and continued improvements in production due to enhanced completion techniques. While commodity
36
prices decreased in the fourth quarter 2018 and are expected to fluctuate in 2019, we do not expect a material impact on supply
volumes across our business segments.
For most of 2018, we benefited from favorable NGL price differentials as available pipeline and fractionation capacity in and
between the Conway, Kansas, and Mont Belvieu, Texas, market centers tightened due to growing NGL supply from the Mid-
Continent and Rocky Mountain regions, combined with increased petrochemical and NGL export demand in the Gulf Coast,
resulting in higher earnings from our Natural Gas Liquids segment’s optimization and marketing activities. In the fourth
quarter 2018, these differentials narrowed resulting from seasonality of supply and demand in the Mid-Continent region, lower
commodity prices and additional pipeline and fractionation capacity resulting from operational efficiencies. While we expect
NGL price differentials to be volatile in 2019, we expect that they will be wider than historical norms due to additional demand
in the Gulf Coast, additional NGL supply growth in the Mid-Continent region and continuing fractionation and pipeline
constraints. We expect these wider NGL price differentials to continue until announced NGL pipeline and fractionation
infrastructure projects, including our Arbuckle II pipeline, are completed in early 2020.
Ethane Opportunity - Ethane volumes delivered to our NGL system have been increasing since 2016, primarily as a result of
NGL demand increasing from exports and petrochemical companies completing ethylene production projects and plant
expansions. Ethane volumes across our system increased to 380 MBbl/d in 2018, compared with 315 MBbl/d in 2017. 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. We expect the amount of ethane delivered to our system to continue to fluctuate
as NGL supply continues to increase, petrochemical companies complete expansion projects and exports increase.
Growth Projects - Increased producer activity and supply growth across our assets have increased demand for midstream
infrastructure. We are responding to this growing demand by constructing assets to meet the needs of natural gas processors
and producers across our operating regions, including the Williston, Permian, Powder River and DJ Basins and the STACK and
SCOOP areas. We also expect additional demand for our services to support increased demand for NGL products from the
petrochemical industry and NGL exporters, and increased demand for natural gas from exports and power plants, some of
which rely on natural gas when renewable energy is not available.
We have spent approximately $2 billion of our announced $6 billion of additional capital-growth projects, including NGL
pipelines, NGL fractionators and natural gas processing plants, that are designed to serve the expected growth and needs of
natural gas processors and producers and the petrochemical industry. We expect these growth projects to provide long-term
fee-based earnings and incremental cash flows. We have contracted for, and taken delivery of, a substantial amount of the steel
pipe required for our pipeline projects from vendors located predominately in the United States. In addition to our large
capital-growth projects discussed below, we are expanding our natural gas pipeline infrastructure in the Permian Basin and
Oklahoma to provide additional natural gas takeaway capacity in these regions. Our announced large capital-growth projects
are outlined in the tables below:
Project
Scope
Natural Gas Gathering and Processing
Additional STACK processing
capacity
Canadian Valley expansion
and related infrastructure
Demicks Lake I plant and
related infrastructure
Demicks Lake II plant and
related infrastructure
200 MMcf/d processing capacity through long-term processing
services agreement
30-mile natural gas gathering pipeline
200 MMcf/d processing plant expansion in the STACK area and
related gathering infrastructure
Increases capacity to more than 400 MMcf/d
20 MBbl/d additional NGL volume
Supported by acreage dedications, long-term primarily fee-
based contracts and minimum volume commitments
200 MMcf/d processing plant and related 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 infrastructure in the
core of the Williston Basin
Supported by acreage dedications with long-term primarily fee-
based contracts
Approximate
Costs (a)
(In millions)
$40
Completion Date
Complete
160
Complete
400
Fourth Quarter 2019
410
First Quarter 2020
Total Natural Gas Gathering and Processing
$1,010
37
Project
Natural Gas Liquids
West Texas LPG pipeline
expansion
Sterling III pipeline expansion
and Arbuckle connection
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
Arbuckle II extension project
and additional gathering
infrastructure
Scope
120-mile pipeline lateral extension with capacity of 110 MBbl/d
in the Permian Basin
Supported by long-term dedicated NGL production from two
planned third-party natural gas processing plants
60 MBbl/d NGL pipeline expansion
Increases capacity to 250 MBbl/d
Includes additional NGL gathering system expansions
Supported by long-term third-party contracts
900-mile NGL pipeline from the Williston Basin to the Mid-
Continent region, with initial capacity of 240 MBbl/d, and
related infrastructure
Anchored by long-term contracts supported primarily by
minimum volume commitments
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 400 MBbl/d, and related
infrastructure
Supported by long-term contracts
Expansion capability up to 1,000 MBbl/d
Increasing mainline capacity by 80 MBbl/d with additional
pump facilities and pipeline looping
Connecting West Texas LPG pipeline system to the previously
announced 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
Provide additional takeaway capacity in the STACK area
Allow increasing volumes on our Elk Creek pipeline access to
fractionation capacity at Mont Belvieu
Approximate
Costs (a)
(In millions)
$200 (b)
Completion Date
Complete
130
Complete
1,400
Fourth Quarter 2019 (c)
1,360
First Quarter 2020
295
First Quarter 2020
575
First Quarter 2020
240
First Quarter 2021
Arbuckle II pipeline expansion Increasing capacity by 100 MBbl/d with additional pump
60
First Quarter 2021
facilities
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
MB-5 fractionator and related
infrastructure
Total Natural Gas Liquids
Total
750
First Quarter 2021
$5,010
$6,020
(a) - Excludes capitalized interest/AFUDC.
(b) - Reflects total project cost. In July 2018, we acquired the remaining 20 percent interest in WTLPG.
(c) - We expect the southern section of the pipeline to be in service as early as the third quarter 2019.
Debt Issuances - In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which
is available to be drawn until May 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. As of
December 31, 2018, we had borrowings totaling $550 million outstanding under our $1.5 Billion Term Loan Agreement, which
were used for general corporate purposes, including repayment of existing indebtedness.
In July 2018, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $800 million,
4.55 percent senior notes due 2028 and $450 million, 5.2 percent 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.
38
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.
Dividends - During 2018, we paid dividends totaling $3.245 per share, an increase of 19 percent from the $2.72 per share paid
in 2017. In February 2019, we paid a quarterly dividend of $0.86 per share ($3.44 per share on an annualized basis), an
increase of 12 percent compared with the same quarter in the prior year. In 2018, 83 percent of our dividend payments to
investors were a return of capital. Our dividend growth is due to the increase in cash flows resulting from the continued growth
of our operations.
Tax Cuts and Jobs Act - In December 2017 the Tax Cuts and Jobs Act made extensive changes to the U.S. tax laws, including
provisions that reduce the highest U.S. corporate tax rate to 21 percent from 35 percent, increase expensing for capital
investment, and limit the interest deduction and use of net operating losses to offset future taxable income. Because tax
expense can be, but is not always, a component of the rates charged by interstate natural gas pipelines, FERC issued a final rule
requiring each interstate natural gas pipeline to submit a filing addressing any impact of the Tax Cuts and Jobs Act on its
FERC-regulated rates. The applicable filings were completed for each of our wholly owned and equity investment interstate
natural gas pipelines, and we expect no material impact to our results of operations.
Revenue Recognition - We adopted Topic 606 on January 1, 2018, using the modified retrospective method. Results for
reporting periods beginning after January 1, 2018, are presented under Topic 606, while prior periods are not adjusted and
continue to be reported under the accounting standards in effect for those periods. The primary impact to our financial results
is a classification change between line items in our Consolidated Income Statement, with an immaterial impact on net income.
Based on the new guidance, 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.
Therefore, contractual fees in these identified contracts are now recorded as a reduction of the commodity purchase price in
cost of sales and fuel rather than as services revenue. To the extent we hold inventory related to these purchases, the related
fees previously recorded in services revenue will not be recognized until the inventory is sold. The adoption of Topic 606 did
not materially impact our reported operating income, net income or adjusted EBITDA.
39
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 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,
2017
2016
2018
Variances
2018 vs. 2017
Increase (Decrease)
Variances
2017 vs. 2016
Increase (Decrease)
(Millions of dollars)
$ 11,395.6
1,197.6
12,593.2
$
9,862.7
2,311.2
12,173.9
$
6,858.5
2,062.4
8,920.9
$
1,532.9
(1,113.6)
419.3
16 % $
(48)%
3 %
3,004.2
248.8
3,253.0
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
6,496.1
747.0
391.6
—
(9.6)
1,295.8
139.7
$
$
— $
(469.7) $
$
743.5
$
1,849.9
$
624.6
(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
$
$
$
$
$
$
$
(1)%
10 %
5 %
(100)%
(33)%
32 % $
(1)% $
(100)% $
(3)% $
95 % $
23 % $
*
$
3,041.9
75.7
14.7
16.0
(8.7)
96.0
19.6
4.3
16.0
(150.0)
137.0
(112.2)
44 %
12 %
36 %
47 %
10 %
4 %
*
(91)%
7 %
14 %
*
3 %
(20)%
7 %
(18)%
* Percentage change is greater than 100 percent or is not meaningful.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices, sales volumes and the impact of the adoption of Topic 606, as described in Note O of the Notes
to Consolidated Financial Statements in this Annual Report, 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.
2018 vs. 2017 - Operating income increased primarily as a result of the following:
•
•
•
•
•
•
an increase of $342.9 million due to Natural gas and NGL volume growth, primarily in the Williston Basin and
STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids segments;
an increase of $150.4 million due to higher optimization and marketing earnings primarily from wider location price
differentials in our Natural Gas Liquids segment;
an increase of $36.4 million from higher transportation services due primarily to increased interruptible volumes and
firm transportation capacity contracted in our Natural Gas Pipelines segment; and
an increase of $16.0 million resulting from the impact of noncash impairment charges in 2017 related to nonstrategic
long-lived assets in our Natural Gas Gathering and Processing segment; offset partially by
an increase in operating costs of $84.3 million due primarily to higher employee-related costs associated with labor
and benefits, higher materials, supplies, outside services, noncash compensation and spending on routine maintenance
projects, offset partially by the $30.0 million impact of the Merger Transaction included in 2017 operating costs; and
an increase in depreciation expense of $22.3 million due to capital projects placed in service.
Net income increased due to the items discussed above, a one-time noncash charge through income tax expense of
$141.3 million in 2017, related to 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 and $20.0 million of
noncash expenses related to our Series E Preferred Stock contribution to the Foundation made in 2017.
Capital expenditures increased due primarily to spending on our announced capital-growth projects.
40
2017 vs. 2016 - Operating income increased primarily as a result of the following:
•
•
•
•
•
•
•
•
an increase of $147.5 million due to natural gas and NGL volume growth in the Williston Basin and STACK and
SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids segments;
an increase of $44.0 million due to restructured contracts resulting in higher fee revenues from increased average fee
rates and a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts in
our Natural Gas Gathering and Processing segment;
an increase of $26.9 from higher transportation services due to higher firm transportation capacity contracted in our
Natural Gas Pipelines segment; and
an increase of $13.5 due to higher optimization and marketing earnings due to higher optimization volumes and wider
location price differentials in our Natural Gas Liquids segment; offset partially by
an increase in operating costs of $45.7 million due to higher labor and employee-related costs associated with benefit
plans, routine maintenance projects and higher ad valorem taxes;
an increase in operating costs of $30.0 million due to Merger Transaction costs in 2017;
a decrease of $16.0 million due to noncash impairment charges related to nonstrategic long-lived assets in our Natural
Gas Gathering and Processing segment; and
a decrease of $11.9 million due to lower net realized natural gas prices and condensate prices, net of hedges in our
Natural Gas Gathering and Processing segment.
Net income was further impacted by a one-time noncash charge through income tax expense of $141.3 million, related to
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 and $20.0 million of noncash expenses related to our
Series E Preferred Stock contribution to the Foundation.
Equity in net earnings from investments increased due primarily to higher firm transportation revenues related to Roadrunner’s
Phase II capacity, which was placed in service in October 2016. Roadrunner is fully subscribed under long-term firm demand
charge contracts.
Capital expenditures decreased due primarily to growth projects placed in service in 2016 in our Natural Gas Gathering and
Processing segment.
Additional information regarding our financial results and operating information is provided in the following discussion for
each of our segments.
Natural Gas Gathering and Processing
Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas,
including the Bakken Shale and Three Forks formations in the Williston Basin and the STACK and SCOOP areas, 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.
41
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
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 from investments,
excluding noncash impairment charges
Other
Adjusted EBITDA
Impairment of equity investments
Capital expenditures
Years Ended December 31,
2017
2016
2018
Variances
2018 vs. 2017
Increase (Decrease)
Variances
2017 vs. 2016
Increase (Decrease)
(Millions of dollars)
$
1,567.2
208.8
1,084.2
$
1,208.0
103.2
856.3
$
$
586.0
58.3
690.6
359.2
105.6
227.9
30 % $
*
27 %
622.0
44.9
165.7
*
77 %
24 %
174.4
859.1
716.7
(684.7)
(80)%
142.4
20 %
(2,041.4)
(2,216.4)
(1,331.5)
(175.0)
(8)%
884.9
66 %
(357.7)
(302.6)
(283.4)
55.1
18 %
19.2
7 %
0.4
(4.3)
631.6
$
— $
$
694.6
12.1
(1.2)
518.5
$
(4.3) $
$
284.2
$
$
$
10.7
(0.6)
446.8
$
— $
$
410.5
(11.7)
(3.1)
113.1
(4.3)
410.4
(97)%
*
22 % $
(100)% $
*
$
1.4
(0.6)
71.7
4.3
(126.3)
13 %
(100)%
16 %
*
(31)%
* Percentage change is greater than 100 percent or is not meaningful.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices and sales volumes and the impact of the adoption of Topic 606, as described in Note O of the
Notes to Consolidated Financial Statements in this Annual Report, affect both revenue and cost of sales and fuel, and, therefore,
the impact is largely offset between these line items.
2018 vs. 2017 - Adjusted EBITDA increased $113.1 million, primarily as a result of the following:
•
•
•
•
an increase of $159.2 million due primarily to natural gas volume growth in the Williston Basin and the STACK and
SCOOP areas, offset partially by natural production declines; and
an increase of $22.3 million due primarily to higher realized NGL and condensate prices, net of hedges, offset partially
by lower realized natural gas prices, net of hedges; offset partially by
an increase of $55.1 million in operating costs due primarily to increased materials and supplies and outside services
related to the growth of our operations and higher employee-related costs associated with labor and benefits; and
a decrease of $11.7 million due primarily to lower equity in net earnings from investments due to a decrease in supply
volumes in the coal-bed methane area of the Powder River Basin.
Capital expenditures increased due to our announced capital-growth projects and increased well connections.
2017 vs. 2016 - Adjusted EBITDA increased $71.7 million, primarily as a result of the following:
•
•
•
•
•
an increase of $66.0 million due primarily to natural gas volume growth in the Williston Basin and the STACK and
SCOOP areas, offset partially by natural production declines and the impact of severe winter weather in the first
quarter 2017; and
an increase of $44.0 million due primarily to restructured contracts resulting in higher fee revenues from increased
average fee rates, offset partially by a lower percentage of proceeds retained from the sale of commodities under our
POP with fee contracts; offset partially by
an increase of $19.2 million in operating costs due primarily to higher employee-related costs associated with labor
and benefits and the growth of our operations;
a decrease of $11.9 million due primarily to lower realized natural gas and condensate prices, net of hedges; and
a decrease of $8.0 million due to contract settlements in 2016.
Capital expenditures decreased due to growth projects placed in service in 2016.
42
Operating Information (a)
Natural gas gathered (BBtu/d)
Natural gas processed (BBtu/d) (b)
NGL sales (MBbl/d)
Residue natural gas sales (BBtu/d)
Average fee rate ($MMBtu)
(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes at company-owned and third-party facilities.
Years Ended December 31,
2017
2016
2018
2,546
2,382
198
1,088
0.90
$
2,211
2,056
187
896
0.86
$
2,034
1,882
156
865
0.76
$
Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales volumes increased in 2018, compared with
2017, due primarily to the following:
•
•
•
producers focusing their drilling and completion in the most productive areas with favorable economics where we
have significant gathering and processing assets; and
continued producer improvements in production due to enhanced completion techniques; offset partially by
natural production declines.
Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales increased in 2017, compared with 2016,
due to the completion of growth projects and new supply in the Williston Basin and the STACK and SCOOP areas, offset
partially by natural production declines on existing wells and the impact of severe winter weather in the first quarter 2017.
The quantity and composition of NGLs and natural gas are expected to continue to change with anticipated production
increases across our supply basins, new processing plants placed in service and increased ethane recovery.
Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 7A,
Quantitative and Qualitative Disclosures about Market Risk.
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 and
$4.3 million of noncash impairment charges related to a nonstrategic equity investment located in Oklahoma.
Natural Gas Liquids
Growth Projects - Our growth strategy in our Natural Gas Liquids segment is focused around the crude oil and NGL-rich
natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the
Mid-Continent region and the Permian Basin. Crude oil, natural gas and NGL production from this activity; higher
petrochemical industry demand for NGL products; and increased exports have resulted in our making additional capital
investments to expand our infrastructure to bring these commodities from supply basins to market.
Our Natural Gas Liquids segment invests in NGL-related projects to transport, fractionate, store and deliver to the market NGL
supply from shale and other resource development areas across our asset base and alleviate expected infrastructure constraints
between the Mid-Continent and Gulf Coast market centers and to meet increasing petrochemical industry and NGL export
demand in the Gulf Coast. 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 2018, we connected five third-party natural gas processing plants to our NGL system in the STACK and SCOOP areas, one
in the Rocky Mountain region and one in the Permian Basin. Two natural gas processing plants, one third-party and one in our
Natural Gas Gathering and Processing segment, also were expanded in the STACK and SCOOP areas of the Mid-Continent
region.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources”
section.
43
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:
Financial Results
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
Years Ended December 31,
2017
2016
2018
Variances
2018 vs. 2017
Increase (Decrease)
Variances
2017 vs. 2016
Increase (Decrease)
(Millions of dollars)
$ 10,319.9
415.7
199.0
$
8,998.9
1,430.3
197.0
$
6,152.5
1,327.5
195.7
$
1,321.0
(1,014.6)
2.0
15 % $
(71)%
1 %
2,846.4
102.8
1.3
46 %
8 %
1 %
(9,176.8)
(9,176.5)
(6,321.4)
0.3
— %
2,855.1
45 %
(378.3)
67.1
(6.0)
1,440.6
1,306.3
$
$
(351.3)
59.9
(3.4)
1,154.9
114.3
$
$
(326.1)
54.5
(3.1)
1,079.6
105.9
$
$
27.0
7.2
(2.6)
285.7
1,192.0
$
$
8 %
12 %
(76)%
25 % $
*
$
25.2
5.4
(0.3)
75.3
8.4
8 %
10 %
(10)%
7 %
8 %
* Percentage change is greater than 100 percent.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices and sales volumes and the impact of the adoption of Topic 606, as described in Note O of the
Notes to Consolidated Financial Statements in this Annual Report, affect both revenues and cost of sales and fuel, and,
therefore, the impact is largely offset between these line items.
2018 vs. 2017 - Adjusted EBITDA increased $285.7 million, primarily as a result of the following:
•
•
•
•
•
an increase of $164.6 million in exchange services due to $183.7 million in higher volumes primarily in the STACK
and SCOOP areas and the Williston Basin and $52.3 million in higher average fee rates in the Mid-Continent region
and Permian Basin, offset partially by $56.6 million in higher third-party fractionation and rail transportation costs and
$19.8 million in higher power costs due to increased volumes;
an increase of $150.4 million in optimization and marketing due primarily to wider location price differentials, which
includes the $15.0 million unfavorable impact of higher NGL products in inventory at the end of the year due to
facility maintenance in the fourth quarter 2018. We expect the earnings benefit on physical-forward sales of this
inventory in the first quarter 2019; and
an increase of $7.2 million in equity in net earnings from investments due primarily to higher volumes delivered to the
Overland Pass pipeline; offset partially by
an increase of $27.0 million in operating costs due primarily to higher employee-related costs associated with labor
and benefits, spending on routine maintenance projects and higher ad valorem taxes, offset partially by the impact of
Hurricane Harvey on operating costs in 2017; and
a decrease of $6.8 million in transportation and storage services due primarily to lower storage capacity contracted
with third parties in the Mid-Continent region.
Capital expenditures increased due primarily to spending on our announced capital-growth projects.
2017 vs. 2016 - Adjusted EBITDA increased $75.3 million, primarily as a result of the following:
•
•
•
•
an increase of $81.5 million in exchange services due primarily to higher volumes in the Williston Basin, the STACK
and SCOOP areas and the Powder River Basin and ethane recovery; offset partially by lower volumes in the Granite
Wash and Barnett Shale and reduced volumes related to Hurricane Harvey;
an increase of $13.5 million in our optimization and marketing activities due primarily to higher optimization volumes
and wider location price differentials; and
an increase of $5.4 million in equity in net earnings from investments due primarily to higher volumes delivered to the
Overland Pass pipeline from our Bakken NGL pipeline and higher volumes and increased ethane recovery from plants
connected to the Overland Pass pipeline; offset partially by
an increase of $25.2 million in operating costs due primarily to routine maintenance projects, higher ad valorem taxes,
higher employee-related costs associated with labor and benefits, and additional operating costs related to Hurricane
Harvey.
44
Capital expenditures increased due primarily to increased routine growth and maintenance projects.
Operating Information
Raw feed throughput (MBbl/d) (a)
NGLs transported - gathering lines (MBbl/d) (b)
NGLs fractionated (MBbl/d) (c)
Average Conway-to-Mont Belvieu OPIS price differential -
ethane in ethane/propane mix ($/gallon)
Years Ended December 31,
2017
2016
2018
1,010
912
715
895
812
621
836
770
586
$
0.15
$
0.05
$
0.03
(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.
2018 vs. 2017 - Volumes increased primarily from the STACK and SCOOP areas and Williston Basin. While overall volumes,
including ethane, increased, a portion of the contractual fees associated with those volumes gathered and fractionated was
previously being earned under contracts with minimum volume obligations.
2017 vs. 2016 - Volumes increased primarily from the STACK and SCOOP areas and Williston Basin resulting from plant
connections, increased supply and increased ethane recovery, which was offset partially by decreased volumes from the Barnett
Shale and Granite Wash. Volumes also increased from the Permian Basin. While overall volumes and ethane recovery
increased, a portion of the fees associated with those volumes gathered and fractionated was previously being earned under
contracts with minimum volume obligations.
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 and other resource areas 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 are expanding our natural gas pipeline infrastructure in Oklahoma and the Permian Basin. The projects include 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 will result 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.
45
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
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
Years Ended December 31,
2017
2016
2018
Variances
2018 vs. 2017
Increase (Decrease)
Variances
2017 vs. 2016
Increase (Decrease)
(Millions of dollars)
$
333.7
60.3
37.7
$
323.7
59.2
37.0
$
288.5
60.0
30.9
10.0
1.1
0.7
3 % $
2 %
2 %
(16.0)
(43.4)
(30.6)
(27.4)
(63)%
(139.2)
90.8
(1.0)
366.3
119.2
$
$
(123.1)
87.3
(0.9)
339.8
95.6
$
$
(114.7)
74.4
4.6
313.1
96.3
$
$
16.1
3.5
(0.1)
26.5
23.6
13 %
4 %
(11)%
8 % $
25 % $
$
$
$
35.2
(0.8)
6.1
12.8
8.4
12.9
(5.5)
26.7
(0.7)
12 %
(1)%
20 %
42 %
7 %
17 %
*
9 %
(1)%
* Percentage change is greater than 100 percent.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
As a result of the adoption of Topic 606, we record retained fuel charges as a reduction to cost of sales and fuel that would have
been recorded as revenue prior to adoption and therefore the impact is offset between these line items.
2018 vs. 2017 - Adjusted EBITDA increased $26.5 million primarily as a result of the following:
•
•
•
an increase of $36.4 million from transportation services due primarily to increased interruptible volumes and firm
transportation capacity contracted; and
an increase of $7.1 million in natural gas storage services due primarily to higher rates and capacity contracted; offset
partially by
an increase of $16.1 million in operating costs due primarily to employee-related costs associated with labor and
benefits and timing of routine maintenance projects.
Capital expenditures increased due primarily to timing of maintenance projects and our announced capital-growth projects.
2017 vs. 2016 - Adjusted EBITDA increased $26.7 million primarily as a result of the following:
•
•
•
•
an increase of $26.9 million from higher transportation services due primarily to increased firm transportation
contracted capacity; and
an increase of $12.9 million in equity in net earnings from investments due primarily to higher firm transportation
revenues on Roadrunner; offset partially by
an increase of $8.4 million in operating costs due primarily to routine maintenance projects and higher employee-
related costs associated with labor and benefits; and
a decrease of $6.3 million due primarily to gains on sales of excess natural gas in storage in 2016.
Operating Information (a)
Natural gas transportation capacity contracted (MDth/d)
Transportation capacity subscribed
(a) - Includes volumes for consolidated entities only.
Years Ended December 31,
2017
2016
2018
6,846
96%
6,611
94%
6,345
92%
Roadrunner, in which we have a 50 percent ownership interest, has contracted all of its westbound capacity through 2041. We
made contributions of $65 million to Roadrunner in 2016. During the years ended December 31, 2018 and 2017, our
contributions to Roadrunner were not material.
Northern Border Pipeline, in which we have a 50 percent ownership interest, has contracted substantially all of its long-haul
transportation capacity through the fourth quarter 2020. We made contributions of $83 million to Northern Border Pipeline in
2017. During the years ended December 31, 2018 and 2016, we made no contributions to Northern Border Pipeline.
46
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 will reduce rates 12.5 percent by January 2020,
compared with previous 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 equity earnings and cash distributions to be material to us.
In compliance with the FERC final rule, Northern Border Pipeline completed the required filing related to the Tax Cuts and
Jobs Act, and we do not expect the impact on tariff rates to be material to us.
In March 2018, the FERC initiated a review of Midwestern Gas Transmission Company’s rates pursuant to Section 5 of the
Natural Gas Act. The parties reached agreement on the terms of a settlement that provides for an approximate 7 percent
reduction in transportation rates. The revised rates became effective September 1, 2018, and the settlement agreement was
approved by the FERC in January 2019. We do not expect the impact of the revised rates to be material to us.
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. Prior periods have been adjusted to conform to
current presentation. 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 unit 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
Other noncash items and equity AFUDC (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
2018
Years Ended December 31,
2017
(Thousands of dollars)
$
593,519
$
2016
743,499
$ 1,155,032
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
469,651
391,585
212,406
—
31,981
796
$ 1,849,918
$
631,607
1,440,605
366,251
9,058
$ 2,447,521
$
518,472
1,154,939
339,818
(26,376)
$ 1,986,853
$
446,778
1,079,619
313,137
10,384
$ 1,849,918
(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 and
developments concerning the Gas Index Pricing Litigation.
47
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 have a material adverse effect on our consolidated results of operations,
financial position or cash flows.
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 and dividends
paid to increase due to our announced capital-growth projects and higher anticipated dividends per share, subject to board of
directors’ approval.
We expect our sources of cash inflow 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 and the remaining
$950 million available to be drawn on our $1.5 Billion Term Loan Agreement provide 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. With $1.6 billion of equity issued in 2017 and January 2018, we have satisfied our expected equity financing needs
for our announced capital-growth projects.
We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, interest-rate swaps and treasury lock
contracts. 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, our $2.5 Billion
Credit Agreement and the remaining $950 million available to be drawn on our $1.5 Billion Term Loan Agreement. As of
December 31, 2018, we were in compliance with all covenants of the $2.5 Billion Credit Agreement and the $1.5 Billion Term
Loan Agreement.
At December 31, 2018, we had $12.0 million of cash and cash equivalents and $2.5 billion of borrowing capacity under the
$2.5 Billion Credit Agreement.
We had working capital (defined as current assets less current liabilities) deficits of $709.8 million and $902.9 million as of
December 31, 2018, and December 31, 2017, respectively. Although working capital is influenced by several factors,
including, among other things: (i) the timing of (a) scheduled debt payments, (b) the collection and payment of accounts
receivable and payable, and (c) equity and debt issuances, and (ii) the volume and cost of inventory and commodity
imbalances, our working capital deficit at December 31, 2018, was driven primarily by current maturities of long-term debt,
with December 31, 2017, also impacted by short-term borrowings. 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. We do
not expect this working capital deficit to have an adverse impact to 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.
48
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 and Upcoming Maturities - In November 2018, we entered into the $1.5 Billion Term Loan Agreement with a
syndicate of banks, which is available to be drawn until May 2019. The $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. The $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 the $2.5 Billion
Credit Agreement. As of December 31, 2018, we had borrowings totaling $550 million outstanding under the $1.5 Billion
Term Loan Agreement, which were used for general corporate purposes, including repayment of existing indebtedness.
In July 2018, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $800 million,
4.55 percent senior notes due 2028, and $450 million, 5.2 percent 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.
We expect to repay the $500 million, 8.625 percent senior notes due in March 2019, with a combination of cash on hand and/or
short- or long-term borrowings.
Debt Repayments - In August 2018, we repaid the $425 million, 3.2 percent senior notes due September 2018 with cash on
hand. In January 2018 we repaid the remaining $500 million balance outstanding on the ONEOK Partners Term Loan
Agreement due 2019 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.
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. 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. During the year ended
December 31, 2018, no shares were sold through our “at-the-market” equity program.
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, short- and
long-term debt and the issuance of equity.
49
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
2018
2017
(Millions of dollars)
2016
$
$
694.6
1,306.3
119.2
21.4
2,141.5
$
$
284.2
114.3
95.6
18.3
512.4
$
$
410.5
105.9
96.3
11.9
624.6
Capital expenditures increased in 2018, compared with 2017, due primarily to capital-growth projects in progress. Capital
expenditures decreased in 2017, compared with 2016, due primarily to the completion of several large projects. We expect our
2019 projected capital expenditures to increase relative to 2018 due to our announced capital-growth projects. See discussion
of our announced capital-growth projects in the “Recent Developments” section.
The following table summarizes our 2019 projected growth and maintenance capital expenditures, excluding AFUDC and
capitalized interest:
2019 Projected Capital Expenditures
Growth
Maintenance
Total projected capital expenditures
(Millions of dollars)
$2,500-$3,700
$160-$200
$2,660-$3,900
Credit Ratings - Our long-term debt credit ratings as of February 19, 2019, 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
Stable
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 the $2.5 Billion Credit Agreement and $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 $1.5 Billion
Term Loan Agreement until fully drawn or through May 2019, as well as our $2.5 Billion Credit Agreement, which expires in
2023. 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 2018, we paid dividends of $3.245 per share, an increase
of 19 percent compared with the prior year. In February 2019, we paid a quarterly dividend of $0.86 per share ($3.44 per share
on an annualized basis), an increase of 12 percent 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 percent per year. In 2018, we paid dividends of $1.1 million for the Series E Preferred
Stock. In February 2019, we paid dividends totaling $0.3 million for the Series E Preferred Stock.
For the years ended December 31, 2018 and 2017, cash flows from operations exceeded cash dividends paid by $866.1 million
and $486.0 million, respectively. We expect our cash flows from operations to continue to sufficiently fund our cash dividends.
50
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.
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
2018
Years Ended December 31,
2017
(Millions of dollars)
2016
$
$
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
$
$
1,353.2
(615.4)
(586.5)
151.3
97.6
248.9
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.
2018 vs. 2017 - Cash flows from operating activities, before changes in operating assets and liabilities, increased to $2.0 billion
for 2018, compared with $1.5 billion for 2017. This increase is due primarily to higher earnings resulting from volume growth
in the Williston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids
segments and higher optimization and marketing earnings due primarily to wider location price differentials in our Natural Gas
Liquids segment, as discussed in “Financial Results and Operating Information.”
The changes in operating assets and liabilities increased operating cash flows $206.4 million for 2018, compared with a
decrease of $192.6 million for 2017. This change is due primarily to the change in natural gas and NGLs in storage, which
vary from period to period and vary with changes in commodity prices; 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 the fair value of our risk-management assets and liabilities.
2017 vs. 2016 - Cash flows from operating activities, before changes in operating assets and liabilities, increased to $1.5 billion
for 2017, compared with $1.4 billion for 2016. This increase is due primarily to higher revenues resulting from volume growth
in the Williston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids
segments, higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment, higher
transportation services due to increased firm demand charge contracted capacity in our Natural Gas Pipelines segment and
higher optimization and marketing earnings due primarily to higher optimization volumes and wider location price differentials
in our Natural Gas Liquids segment, as discussed in “Financial Results and Operating Information.”
The changes in operating assets and liabilities decreased operating cash flows $192.6 million for 2017, compared with a
decrease of $40.8 million for 2016. This change is due primarily to the change in natural gas and NGLs in storage, which
varies from period to period and varies with changes in commodity prices, the change in accounts receivable, accounts payable,
51
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 risk-management assets and liabilities.
Investing Cash Flows
2018 vs. 2017 - Cash used in investing activities increased $1.5 billion due primarily to increased capital expenditures related
to our announced capital-growth projects.
2017 vs. 2016 - Cash used in investing activities decreased $47.8 million due primarily to projects placed in service in 2016,
offset partially by lower distributions received from unconsolidated affiliates in excess of cumulative earnings, lower proceeds
from sale of assets and higher contributions to our unconsolidated affiliates.
Financing Cash Flows
2018 vs. 2017 - Cash used in financing activities decreased $862.5 million due primarily to issuance of common stock, the
$550 million draw on our $1.5 Billion Term Loan Agreement and decreased distributions to noncontrolling interests resulting
from the Merger Transaction, offset partially by repayment of short-term borrowings, increased dividends and the acquisition of
the remaining 20 percent interest in WTLPG.
2017 vs. 2016 - Cash used in financing activities increased $373.0 million due primarily to repayment of short-term borrowings
and increased dividends, offset partially by the issuance of common stock through our “at-the-market” equity program and
decreased distributions to noncontrolling interests resulting from the Merger Transaction.
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
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. We record all derivative instruments at fair value,
except for normal purchases and normal sales transactions that are expected to result in physical delivery. While many of the
contracts in our derivative portfolio are executed in liquid markets where price transparency exists, some contracts are executed
in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price
transparency that requires management’s judgment and assumptions to estimate fair values. Fair value measurements classified
as Level 3 are based on inputs that may include one or more unobservable inputs, including internally developed natural gas
basis and NGL price curves that incorporate observable and unobservable market data from broker quotes and third-party
pricing services. These balances are comprised predominantly of exchange-cleared and over-the-counter derivatives for natural
gas basis and NGLs. 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, 2018, 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
52
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.
Our qualitative goodwill impairment analysis performed as of July 1, 2018, 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.
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,
2017
2018
(Thousands of dollars)
$
$
153,404
371,217
156,479
681,100
$
$
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 our 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.
53
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 2018, 2017 or 2016. 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.
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, 2018. For additional discussion of the debt agreements, see Note F of the Notes to Consolidated Financial
Statements in this Annual Report.
Contractual Obligations
Total
2019
2020
2021
2022
2023
Thereafter
Payments Due by Period
(Millions of dollars)
Senior notes
$
8,872.4
$
500.0
$
300.0
$
— $
1,447.4
$
925.0
$
5,700.0
$1.5 Billion Term Loan Agreement (a)
Guardian Pipeline senior notes
Interest payments on debt
Operating leases
Capital lease
Firm transportation and storage contracts
Financial and physical derivatives
Employee benefit plans
Purchase commitments and other
550.0
29.0
6,325.4
23.2
44.1
202.4
229.1
86.9
190.1
—
7.7
463.4
6.9
4.5
63.7
224.8
16.5
56.0
—
7.7
447.0
2.2
4.5
51.6
4.3
14.0
56.5
550.0
7.7
442.1
1.9
4.5
35.7
—
18.4
34.4
—
5.9
399.2
1.7
4.5
22.4
—
18.5
14.9
—
—
—
—
355.5
4,218.2
1.5
4.5
17.3
—
19.5
13.9
9.0
21.6
11.7
—
—
14.4
Total
$ 16,552.6
$
1,343.5
$
887.8
$
1,094.7
$
1,914.5
$
1,337.2
$
9,974.9
(a) - In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which is available to be drawn
until May 2019 and matures in November 2021. As of December 31, 2018, we had borrowings totaling $550 million outstanding under our
$1.5 Billion Term Loan Agreement.
Senior notes and $1.5 Billion Term Loan Agreement - 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.
54
Operating leases - Our operating leases primarily include leases for office space, pipeline equipment, rail cars and information
technology equipment.
Capital lease - We lease certain compression facilities under a capital 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, 2018. 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 $14.5 million to our defined benefit pension plan in January 2019 and expect to make
$2.0 million in contributions to our other postretirement plans in 2019. 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
natural gas and natural gas liquids pipelines and processing 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,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,”
“guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements. 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:
•
•
•
•
•
•
•
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;
the capital intensive nature of our businesses;
the profitability of assets or businesses acquired or constructed by us;
our ability to make cost-saving changes in operations;
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;
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;
55
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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 obtain necessary permits; reserve performance; and capacity constraints on the
pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or
pipelines;
the effects of weather and other natural phenomena, including climate change, on our operations, demand for our
services and energy prices;
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 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;
the results of administrative proceedings and litigation, regulatory actions, 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 CFTC;
our ability to access capital at competitive rates or on terms acceptable to us;
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;
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 and outcome of pending and future litigation;
the timing and extent of changes in energy commodity prices;
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 Canadian and United States natural gas and crude oil; and
– availability of additional storage capacity;
performance of contractual obligations by our customers, service providers, contractors and shippers;
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 mechanical integrity of facilities operated;
demand for our services in the proximity of our facilities;
our ability to control operating costs;
acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’
facilities;
economic climate and growth in the geographic areas in which we do business;
the risk of a prolonged slowdown in growth or decline in the United States or international economies, including
liquidity risks in United States or foreign credit markets;
the impact of recently issued and future accounting updates and other changes in accounting policies;
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;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
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 impact of uncontracted capacity in our assets being greater or less than expected;
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 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 impact of potential impairment charges;
56
•
•
•
the risk inherent in the use of information systems in our respective businesses, implementation of new software and
hardware, and the impact on the timeliness of information for financial reporting;
our ability to control construction costs and completion schedules of our pipelines and other projects; 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 have material adverse effects on 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
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
Year Ending December 31, 2019
Volumes
Hedged
7.6
2.7
82.0
$
$
$
Average Price
0.71 / gallon
58.55 / Bbl
2.30 / MMBtu
Percentage
Hedged
75%
92%
81%
57
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu
Condensate (MBbl/d) - WTI-NYMEX
Natural gas (BBtu/d) - NYMEX and basis
Year Ending December 31, 2020
Volumes
Hedged
2.0
0.8
39.1
$
$
$
Average Price
0.61 / gallon
55.25 / Bbl
2.46 / MMBtu
Percentage
Hedged
22%
26%
49%
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, 2018. 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, 2019 and 2020, by $1.6 million and $1.7 million, respectively;
a $1.00 per-barrel change in the price of crude oil would change adjusted EBITDA for the years ending December 31,
2019 and 2020, by $1.5 million and $1.6 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, 2019 and 2020, by $3.9 million and $3.6 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 our $2.5 Billion Credit Agreement, $1.5 Billion Term Loan Agreement,
commercial paper program and long-term debt issuances. Future increases in LIBOR, corporate commercial paper rates or
corporate 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, interest-rate swaps and treasury lock contracts. Interest-rate swaps are agreements to
exchange interest payments at some future point based on specified notional amounts. In 2018, we entered into $2.8 billion of
forward-starting interest-rate swaps and treasury lock contracts 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 and $1.3 billion
of forward-starting interest-rate swaps used to hedge the variability of our LIBOR-based interest payments. We also settled
$1.0 billion of our forward-starting interest-rate swaps and treasury lock contracts related to our underwritten public offering of
$1.25 billion senior unsecured notes completed in July 2018, and $500 million of our interest-rate swaps in January 2018 used
to hedge our LIBOR-based interest payments.
At December 31, 2018 and 2017, we had forward-starting interest-rate swaps with notional amounts totaling $3.0 billion and
$1.3 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At
December 31, 2018 and 2017, we had interest-rate swaps with notional amounts totaling $1.3 billion and $500 million,
respectively, 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, 2018, we had derivative assets of $19 million and derivative liabilities of $99 million
related to these interest-rate swaps. At December 31, 2017, we had derivative assets of $50 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 2018, no single customer represented more than 10 percent of our consolidated revenues.
58
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 2018 and 2017, approximately 95 percent 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 natural gas liquids 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 2018 and 2017, approximately 80 percent 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
2018 and 2017, approximately 85 percent and 90 percent, respectively, 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.
59
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, 2018 and December 31, 2017, and the related consolidated statements of income, comprehensive income,
changes in equity and cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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, 2018 and December 31, 2017, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated
Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Notes A and O 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
60
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Tulsa, OK
February 26, 2019
We have served as the Company’s auditor since 2007.
61
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
Revenues
Commodity sales
Services
Total revenues
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 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 $28,062, $5,510 and $10,591,
respectively)
Income before income taxes
Income taxes (Note L)
Income from continuing operations
Income (loss) from discontinued operations, net of tax
Net income
Less: Net income attributable to noncontrolling interests
Net income attributable to ONEOK
Less: Preferred stock dividends
Net income available to common shareholders
Amounts available to common shareholders:
Income from continuing operations
Income (loss) from discontinued operations
Net income
Basic earnings per common share:
Income from continuing operations (Note I)
Income (loss) from discontinued operations
Net income
Diluted earnings per common share:
Income from continuing operations (Note I)
Income (loss) from discontinued operations
Net income
Average shares (thousands)
Basic
Diluted
See accompanying Notes to Consolidated Financial Statements.
62
Years Ended December 31,
2017
(Thousands of dollars, except per share amounts)
2016
2018
$ 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
—
1,155,032
3,329
1,151,703
1,100
1,150,603
1,150,603
—
1,150,603
2.80
—
2.80
2.78
—
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
—
593,519
205,678
387,841
767
387,074
387,074
—
387,074
1.30
—
1.30
1.29
—
1.29
$
$
$
$
$
$
$
$
6,858,456
2,062,478
8,920,934
6,496,124
658,233
391,585
—
88,849
(9,635)
1,295,778
139,690
—
209
6,091
(14,161)
(469,651)
957,956
(212,406)
745,550
(2,051)
743,499
391,460
352,039
—
352,039
354,090
(2,051)
352,039
1.68
(0.01)
1.67
1.67
(0.01)
1.66
411,485
414,195
297,477
299,780
211,128
212,383
Years Ended December 31,
2017
(Thousands of dollars)
$
593,519
$
2016
743,499
1,155,032
(5,673)
(21,408)
(30,300)
36,870
63,687
(6,977)
4,771
(4,175)
(16,693)
2,424
38,392
1,193,424
3,329
1,190,095
$
(970)
37,134
630,653
236,704
393,949
$
(1,505)
(55,475)
688,024
363,093
324,931
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
2018
Net income
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on derivatives, net of tax of $1,694, $19,006 and $5,452
respectively
Realized (gains) losses on derivatives recognized in net income, net of tax of
$(11,013), $(26,899) and $230, respectively
Change in pension and postretirement benefit plan liability, net of tax of $(1,425),
$(878) and $11,128, respectively
Other comprehensive income (loss) on investments in unconsolidated affiliates, net
of tax of $(724), $145 and $270, 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.
$
$
63
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Natural gas and natural gas liquids 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)
Deferred income taxes (Note L)
Other assets
Total investments and other assets
Total assets
December 31, December 31,
2018
2017
(Thousands of dollars)
$
$
11,975
818,958
141,174
296,667
29,050
100,808
1,398,632
37,193
1,202,951
90,301
342,293
38,712
53,008
1,764,458
18,030,963
3,264,312
14,766,651
15,559,667
2,861,541
12,698,126
969,150
967,142
—
130,096
2,066,388
18,231,671
1,003,156
993,460
205,907
180,830
2,383,353
$ 16,845,937
$
64
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
Other current liabilities
Total current liabilities
Long-term debt, excluding current maturities (Note F)
Deferred credits and other liabilities
Deferred income taxes (Note L)
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, 2018, and at December 31, 2017
Common stock, $0.01 par value:
authorized 1,200,000,000 shares; issued 445,016,234 shares and outstanding
411,532,606 shares at December 31, 2018; issued 423,166,234 shares and outstanding
388,703,543 shares at December 31, 2017
Paid-in capital
Accumulated other comprehensive loss (Note H)
Retained earnings
Treasury stock, at cost: 33,483,628 shares at December 31, 2018, and
34,462,691 shares at December 31, 2017
Total ONEOK shareholders’ equity
Noncontrolling interests in consolidated subsidiaries
Total equity
Total liabilities and equity
See accompanying Notes to Consolidated Financial Statements.
December 31, December 31,
2018
2017
(Thousands of dollars)
$
$
507,650
—
1,118,102
110,197
161,377
211,110
2,108,436
432,650
614,673
1,140,571
164,161
135,309
179,971
2,667,335
8,873,334
8,091,629
219,731
450,627
670,358
52,697
348,924
401,621
—
—
4,450
7,615,138
(188,239)
—
(851,806)
6,579,543
4,232
6,588,878
(188,530)
—
(876,713)
5,527,867
—
157,485
6,579,543
18,231,671
5,685,352
16,845,937
$
$
65
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66
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:
$
1,155,032
$
593,519
$
743,499
2018
Years Ended December 31,
2017
(Thousands of dollars)
2016
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
Pension and postretirement benefit expense, net of contributions
Allowance for equity funds used during construction
Gain on sale of assets
Changes in assets and liabilities:
Accounts receivable
Natural gas and natural gas liquids 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
Capital expenditures (less allowance for equity funds used during construction)
Contributions to unconsolidated affiliates
Distributions received from unconsolidated affiliates in excess of cumulative
earnings
Proceeds from sale of assets
Cash used in investing activities
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 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
See accompanying Notes to Consolidated Financial Statements.
$
$
$
67
428,557
—
—
(158,383)
170,528
361,010
31,664
469
(7,962)
(601)
383,993
38,456
(320,132)
(44,302)
26,068
117,717
4,605
2,186,719
(2,141,475)
(1,748)
26,757
1,578
(2,114,888)
(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
4,079
(107)
(924)
(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
$
$
$
391,585
—
—
(139,690)
144,673
211,638
40,563
11,643
(209)
(9,635)
(285,806)
(11,950)
287,632
45,971
(16,529)
(78,136)
17,971
1,353,220
(624,634)
(68,275)
52,044
25,420
(615,445)
(517,601)
(549,419)
563,937
1,000,000
(2,770)
(1,108,040)
21,971
—
5,403
(586,519)
151,256
97,619
248,875
461,208
361
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
ONEOK Shareholders’ Equity
Common
Stock Issued
Preferred
Stock Issued
Common
Stock
(Shares)
January 1, 2016
Net income
Other comprehensive income (loss)
Common stock issued
Common stock dividends - $2.46 per share
(Note G)
Distributions to noncontrolling interests
Other
December 31, 2016
Cumulative effect adjustment for adoption of
ASU 2016-09
Net income
Other comprehensive income (loss) (Note H)
Preferred stock issued
Preferred stock dividends (Note G)
Common stock issued
Common stock dividends - $2.72 per share
(Note G)
Distributions to noncontrolling interests
Acquisition of ONEOK Partners’
noncontrolling interests (Note A)
Other
December 31, 2017
Cumulative effect adjustment for adoption of
ASUs (Note A)
Net income
Other comprehensive income (loss) (Note H)
Preferred stock dividends (Note G)
Common stock issued
Common stock dividends - $3.245 per share
(Note G)
Distributions to noncontrolling interests
Contributions from noncontrolling interests
245,811,180
—
—
—
—
—
—
245,811,180
—
—
—
—
—
8,434,223
—
—
168,920,831
—
423,166,234
—
—
—
—
21,850,000
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
20,000
—
—
—
—
—
—
20,000
—
—
—
—
—
—
—
—
Preferred
Stock
(Thousands of dollars)
— $
—
—
—
$
2,458
—
—
—
—
—
—
2,458
—
—
—
—
—
85
—
—
1,689
—
4,232
—
—
—
—
218
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Paid-in
Capital
1,378,444
—
—
2,331
(165,562)
—
19,101
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
Acquisition of noncontrolling interests (Note G)
Other
December 31, 2018
—
—
445,016,234
—
—
20,000
$
—
—
4,450
$
—
—
— $
68
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Continued)
ONEOK Shareholders’ Equity
January 1, 2016
Net income
Other comprehensive income (loss)
Common stock issued
Common stock dividends - $2.46 per share
(Note G)
Distributions to noncontrolling interests
Other
December 31, 2016
Cumulative effect adjustment for adoption of
ASU 2016-09
Net income
Other comprehensive income (loss) (Note H)
Preferred stock issued
Preferred stock dividends (Note G)
Common stock issued
Common stock dividends - $2.72 per share
(Note G)
Distributions to noncontrolling interests
Acquisition of ONEOK Partners’
noncontrolling interests (Note A)
Other
December 31, 2017
Cumulative effect adjustment for adoption of
ASUs (Note A)
Net income
Other comprehensive income (loss) (Note H)
Preferred stock dividends (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
December 31, 2018
$
$
Accumulated
Other
Comprehensive
Loss
Retained
Earnings
Noncontrolling
Interests in
Consolidated
Subsidiaries
— $
Treasury
Stock
(Thousands of dollars)
(917,862) $
—
—
24,185
352,039
—
—
(352,039)
—
—
—
73,368
387,841
—
—
—
—
(461,209)
—
—
—
—
39,803
1,151,703
—
(1,100)
—
—
—
—
(893,677)
—
—
—
—
—
16,964
—
—
—
—
(876,713)
—
—
—
—
24,907
Total
Equity
3,766,336
743,499
(55,475)
26,516
(517,601)
(549,419)
15,059
3,428,915
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
$
3,430,538
391,460
(28,367)
—
—
(549,419)
(4,042)
3,240,170
—
205,678
31,026
—
—
—
—
(276,260)
(3,043,519)
390
157,485
17
3,329
—
—
—
(127,242) $
—
(27,108)
—
—
—
—
(154,350)
—
—
6,108
—
—
—
—
—
(40,288)
—
(188,530)
(38,101)
—
38,392
—
—
—
—
—
—
—
(188,239) $
(1,190,406)
—
—
—
—
— $
—
—
—
—
—
(851,806) $
—
(3,500)
16,449
(173,780)
—
— $
(1,335,211)
(3,500)
16,449
(195,000)
8,964
6,579,543
See accompanying Notes to Consolidated Financial Statements.
69
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, and our
common stock is listed on the NYSE under the trading symbol “OKE.”
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 natural gas liquids 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 Oklahoma, Kansas, the Texas Panhandle and the
Williston Basin are connected to our natural gas liquids gathering systems. We own or have an ownership interest in FERC-
regulated natural gas liquids 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 natural gas liquids 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 percent 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
and Texas. Our assets connect major natural gas producing basins and market hubs with end-use customers.
Merger Transaction - On June 30, 2017, we completed the acquisition of all of the outstanding common units of ONEOK
Partners that we did not already own at a fixed exchange ratio of 0.985 of a share of our common stock for each ONEOK
Partners common unit. We issued 168.9 million shares of our common stock to third-party common unitholders of ONEOK
Partners in exchange for all of the 171.5 million outstanding common units of ONEOK Partners that we previously did not
own. As a result of the completion of the Merger Transaction, common units of ONEOK Partners are no longer publicly
traded.
As we controlled ONEOK Partners and continue to control ONEOK Partners after the Merger Transaction, the change in our
ownership interest was accounted for as an equity transaction, and no gain or loss was recognized in our Consolidated
Statements of Income resulting from the Merger Transaction. The Merger Transaction was a taxable exchange to the ONEOK
Partners unitholders resulting in a book/tax difference in the basis of the underlying assets acquired. We recorded a deferred
tax asset of $2.1 billion, computed as the net of the equity value exchanged of $8.8 billion and noncontrolling interests of $3.0
billion at a tax rate of 37 percent, based on a tax allocation of the transaction value.
Prior to June 30, 2017, we and our subsidiaries owned all of the general partner interest, which included incentive distribution
rights, and a portion of the limited partner interest, which together represented a 41.2 percent ownership interest in 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. Our general
partner incentive distribution rights effectively terminated at the closing of the Merger Transaction.
Effective with the close of the Merger Transaction, we, ONEOK Partners and the Intermediate Partnership issued, to the extent
not already in place, guarantees of the indebtedness of ONEOK and ONEOK Partners.
70
Supplemental Cash Flow Information - Our noncash balance sheet activity at June 30, 2017, related to the Merger
Transaction was as follows (in millions):
Common stock
Paid-in capital
Accumulated other comprehensive loss
Noncontrolling interests in consolidated subsidiaries
Deferred income taxes
$
$
$
$
$
1.7
5,228.6
(40.3)
(3,043.5)
(2,146.5)
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 estimated volumes and prices. The estimates are reversed in the following month and recorded with actual volumes and
prices.
We evaluate these 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.
While many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists, some
contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in
limited price transparency that requires management’s judgment and assumptions to estimate fair values. For certain
transactions, we may utilize modeling techniques using NYMEX-settled pricing data and implied forward LIBOR curves.
Inputs into our fair value estimates include commodity-exchange prices, data obtained from third-party pricing services,
LIBOR and other liquid money-market instrument rates. 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
71
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 comprised 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 comprised 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 natural gas basis and NGL price curves that incorporate observable and unobservable market data
from broker quotes and third-party pricing services. These balances are comprised predominantly of exchange-cleared
and over-the-counter derivatives for natural gas basis and NGLs. 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, 2018, 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.
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 P 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.
72
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
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 O for our revenue disclosures.
Contract Assets and Contract Liabilities - Upon adoption of Topic 606 in January 2018, 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 NGL storage contracts for which revenue is recognized over a one-year term and deferred revenue on
73
contributions in aid of construction received from customers for which revenue is recognized over the contract period. In 2017
and prior periods, we recorded these reimbursements as reductions to property, plant and equipment.
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, and
(iii) fuel and power costs incurred to operate our own facilities that gather, process, transport and store commodities.
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. Upon adoption of Topic 606, the contractual fees we
charge producers on these POP with fee contracts are recorded as a reduction to the commodity purchase price in cost of sales
and fuel. In 2017 and prior periods, we recorded these fees as services revenue.
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. Upon adoption of Topic 606, the contractual fees we charge
processors on these exchanges services contracts that include the purchase of commodities are recorded as a reduction to the
commodity purchase price in cost of sales and fuel. In 2017 and prior periods, we recorded these fees as services revenue.
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, 2018 and 2017, our allowance for
doubtful accounts was not material.
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 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.
74
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 and treasury lock contracts 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 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
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 billed. For our nonregulated assets, if it is determined that the estimated economic life
75
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, 2018, 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.
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, natural gas liquids pipelines
and storage facilities are subject to rate regulation and 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 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
76
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 pension and 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 2018, 2017 and 2016, 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, natural gas liquids 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 natural gas liquids exists. 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 natural gas liquids
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.
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
77
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 2018, 2017 and 2016. 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.
Prior periods have been adjusted to conform to current presentation. This calculation may not be comparable with similarly
titled measures of other companies.
See Note P for our segments disclosures.
Reclassifications - Certain reclassifications have been made in the prior-year financial statements to conform to the current-
year presentation.
Discontinued Operations - Beginning in 2017, the results of operations and financial position of our former energy services
business are no longer reflected as discontinued operations in our Consolidated Financial Statements and Notes to the
Consolidated Financial Statements, as they are not material.
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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 listed below. The following tables provide a brief
description of recent accounting pronouncements and our analysis of the effects on our financial statements:
Date of
Adoption
Effect on the Financial Statements or Other
Significant Matters
First
quarter
2018
We adopted this standard on January 1, 2018, using
the modified retrospective method. We recognized
the cumulative effect of adopting the new revenue
standard as an increase to beginning retained
earnings of $1.7 million. Results for reporting
periods beginning after January 1, 2018, are
presented under the new standard, while prior
periods are not adjusted and continue to be reported
under the accounting standards in effect for those
periods. The adoption of Topic 606 was not
material to our net income; however, a significant
portion of amounts historically presented as services
revenues are now presented as a reduction to cost of
sales and fuel. See Note O for discussion of these
changes and additional disclosures.
First
quarter
2018
We do not have any equity investments classified as
available-for-sale or accounted for using the cost
method; therefore, the impact of adopting of this
standard was not material.
First
quarter
2018
First
quarter
2018
First
quarter
2018
The impact of adopting this standard was not
material.
We adopted this standard on January 1, 2018, and
utilized the practical expedient to estimate the
impact on the prior comparative period information
presented. Immaterial reclassifications have been
made to prior comparative period information to
reflect the current period presentation. Prior to
adoption, we expensed all components of the net
periodic benefit costs for our pension and
postretirement benefit plans in operations and
maintenance expense. We now record only the
service component of the net periodic benefit costs
in operations and maintenance expense, with the
remainder being recorded in other expense. There
was no change to net income from the adoption of
this standard.
We adopted this standard in the first quarter 2018
and recorded an immaterial cumulative-effect
adjustment to the opening balance of retained
earnings and other comprehensive income to
eliminate the separate measurement of hedge
ineffectiveness. See Note C for changes to
disclosures due to adopting this standard.
Standard
Description
Standards that were adopted as of December 31, 2018
ASU 2014-09, “Revenue
from Contracts with
Customers (Topic 606)”
ASU 2016-01, “Financial
Instruments-Overall
(Subtopic 825-10):
Recognition and
Measurement of Financial
Assets and Financial
Liabilities”
The standard outlines the principles an
entity must apply to measure and
recognize revenue for entities that enter
into contracts to provide goods or
services to their customers. The core
principle is that an entity should
recognize revenue at an amount that
reflects the consideration to which the
entity expects to be entitled in
exchange for transferring goods or
services to a customer. The
amendment also requires more
extensive disaggregated revenue
disclosures in interim and annual
financial statements.
The standard requires all equity
investments, other than those accounted
for using the equity method of
accounting or those that result in
consolidation of the investee, to be
measured at fair value with changes in
fair value recognized in net income,
eliminates the available-for-sale
classification for equity securities with
readily determinable fair values and
eliminates the cost method for equity
investments without readily
determinable fair values.
ASU 2016-15, “Statement
of Cash Flows (Topic 230):
Classification of Certain
Cash Receipts and Cash
Payments”
The standard clarifies the classification
of certain cash receipts and cash
payments on the statement of cash
flows where diversity in practice has
been identified.
ASU 2017-07,
“Compensation -
Retirement Benefits (Topic
715): Improving the
Presentation of Net Periodic
Pension Cost and Net
Periodic Postretirement
Benefit Cost”
The standard requires the service cost
component of net benefit cost to be
reported in the same line item or items
as other compensation costs from
services rendered by the pertinent
employees during the period. The
other components of net benefit cost
are required to be presented in the
income statement separately from the
service cost component and outside a
subtotal of income from operations.
ASU 2017-12, “Derivatives
and Hedging (Topic 815):
Targeted Improvements to
Accounting for Hedging
Activities”
The standard more closely aligns hedge
accounting with companies’ existing
risk-management strategies by
expanding the strategies eligible for
hedge accounting, relaxing the timing
requirements of hedge documentation
and effectiveness assessments,
permitting in certain cases, the use of
qualitative assessments on an ongoing
basis to assess hedge effectiveness, and
requiring new disclosures and
presentation.
79
Standard
Description
Standards that were adopted as of December 31, 2018 (continued)
Date of
Adoption
Effect on the Financial Statements or Other
Significant Matters
This standard allows a reclassification
from accumulated other comprehensive
income to retained earnings for
stranded tax effects resulting from the
Tax Cuts and Jobs Act.
First
quarter
2018
We adopted this standard in the first quarter 2018
using the portfolio approach and recorded a $38.1
million adjustment to retained earnings and
accumulated other comprehensive income to
eliminate the stranded tax effects resulting from the
Tax Cuts and Jobs Act.
ASU 2018-02, “Income
Statement - Reporting
Comprehensive Income
(Topic 220):
Reclassification of Certain
Tax Effects from
Accumulated Other
Comprehensive Income”
ASU 2018-13, “Fair Value
Measurement (Topic 820)”
ASU 2018-14,
“Compensation -
Retirement Benefits -
Defined Benefit Plans -
General (Topic 715-20)”
The standard modifies certain
disclosure requirements for fair value
measurements in Topic 820.
The standard modifies the disclosure
requirements for employers
that sponsor defined benefit pension or
other postretirement plans.
Standards that are not yet adopted as of December 31, 2018
ASU 2016-02, “Leases
(Topic 842)”
ASU 2018-07,
“Compensation - Stock
Compensation (Topic 718):
Improvements to
Nonemployee Share-Based
Payment Accounting”
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”
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.
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.
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.
80
Fourth
quarter
2018
Fourth
quarter
2018
First
quarter
2019
First
quarter
2019
First
quarter
2020
The impact of adopting this standard was not
material.
The impact of adopting this standard was not
material.
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. We
recorded an immaterial cumulative effect for the
adoption of the new standard and recorded
approximately $17.0 million of right-of-use assets
and lease liabilities related to operating leases that
were not previously recorded on our Consolidated
Balance Sheets. Our finance lease assets and
liabilities of $28.1 million and $28.0 million,
respectively, did not change as a result of adopting
this standard. We also implemented accounting
software and developed internal controls designed to
ensure compliance with the standard and the
completeness and accuracy of our data.
We do not expect the adoption of this standard to
materially impact us.
We do not expect the adoption of this standard to
materially impact us.
First
quarter
2020
We do not expect the adoption of this standard to
materially impact us.
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
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 Sheets 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 Sheets.
Derivative assets
Commodity contracts
Financial contracts
Interest-rate contracts
Total derivative assets
Derivative liabilities
Commodity contracts
Financial contracts
Physical contracts
Total derivative liabilities
$
$
$
$
December 31, 2017
Level 1
Level 2
Level 3
Total - Gross Netting (a)
Total - Net
(Thousands of dollars)
4,252
—
4,252
$
$
— $
49,960
49,960
$
20,203
—
20,203
$
$
24,455
49,960
74,415
$
$
(24,455) $
—
(24,455) $
—
49,960
49,960
(5,708) $
—
(5,708) $
— $
—
— $
(48,260) $
(4,781)
(53,041) $
(53,968) $
(4,781)
(58,749) $
53,936
—
53,936
$
$
(32)
(4,781)
(4,813)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets 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,
2017, we held no cash and posted $49.7 million of cash with various counterparties, including $29.5 million of cash collateral that is
offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $20.2 million of cash
collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheets.
81
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 realized/unrealized gains (losses):
Included in earnings (a)
Included in other comprehensive income (loss) (b)
Net assets (liabilities) at end of period
Years Ended
December 31,
2018
2017
(Thousands of dollars)
(32,838) $
(23,319)
(140)
73,462
40,484
$
212
(9,731)
(32,838)
$
$
(a) - Included in commodity sales revenues in our Consolidated Statements of Income.
(b) - Included in unrealized gains (losses) on derivatives in our Consolidated Statement of Comprehensive Income.
Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity. During the years ended
December 31, 2018 and 2017, gains or losses included in earnings attributable to the change in unrealized gains or losses
relating to assets and liabilities still held at the end of each reporting period were not material.
During the years ended December 31, 2018 and 2017, 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
comprised 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 $9.6 billion and $9.3 billion at
December 31, 2018 and 2017, respectively. The book value of our consolidated long-term debt, including current maturities,
was $9.4 billion and $8.5 billion at December 31, 2018 and 2017, 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.
82
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.
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, 2018 and 2017, 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, interest-rate swaps, and
treasury lock contracts. Interest-rate swaps are agreements to exchange interest payments at some future point based on
specified notional amounts. In 2018, we entered into $2.8 billion of forward-starting interest-rate swaps and treasury lock
contracts 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. In addition, we entered into $1.3 billion of forward-starting
interest-rate swaps to hedge the variability of our LIBOR based interest payments. Also in 2018, we settled $1.0 billion of our
forward-starting interest-rate swaps and treasury lock contracts related to our underwritten public offering of $1.25 billion
senior unsecured notes completed in July 2018, and $500 million of our interest-rate swaps in January 2018 used to hedge our
LIBOR-based interest payments.
At December 31, 2018 and 2017, we had forward-starting interest-rate swaps with notional amounts totaling $3.0 billion and
$1.3 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At
December 31, 2018 and 2017, we had interest-rate swaps with notional amounts totaling $1.3 billion and $500 million,
respectively, to hedge the variability of our LIBOR-based interest payments. All of our interest-rate swaps are designated as
cash flow hedges.
83
Fair Values of Derivative Instruments - The following table sets forth the fair values of our derivative instruments presented
on a gross basis for the periods indicated:
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts
Physical contracts
Interest-rate contracts
Total derivatives designated as hedging
instruments
Derivatives not designated as hedging
instruments
Commodity contracts
Financial contracts
Total derivatives not designated as hedging
instruments
Total derivatives
Location in our
Consolidated Balance
Sheets
December 31, 2018
December 31, 2017
Assets
(Liabilities)
Assets
(Thousands of dollars)
(Liabilities)
Other current assets/other
current liabilities
Other assets/other deferred
credits
Other current assets/other
current liabilities
Other current assets/other
current liabilities
Other assets/other deferred
credits
$
78,891
$
(31,793) $
16,978
$
(42,819)
1,086
1,142
(946)
—
—
—
19,005
(15,012)
1,330
—
(84,248)
48,630
(3,838)
(4,781)
—
—
100,124
(131,999)
66,938
(51,438)
Other current assets/other
current liabilities
—
—
100,124
$
—
—
$ (131,999) $
7,477
(7,311)
7,477
74,415
$
(7,311)
(58,749)
Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative
instruments held for the periods indicated:
December 31, 2018
Contract
Type
Purchased/
Payor
Sold/
Receiver
December 31, 2017
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 (Millions of dollars)
Derivatives not designated as hedging instruments:
Fixed price
-NGLs (MMBbl)
Futures and swaps
Futures, forwards
and swaps
—
6.5
(29.9)
(13.8)
—
3.5
Futures and swaps
Swaps
$
—
4,250.0
$
(29.9)
— $
—
1,750.0
$
(24.5)
(11.1)
(24.5)
—
Futures, forwards
and swaps
—
—
0.8
(0.8)
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.
84
The following table sets forth the unrealized effect of cash flow hedges recognized in other comprehensive income (loss) for
the periods indicated:
Derivatives in Cash Flow Hedging Relationships
2018
Commodity contracts
Interest-rate contracts
Total unrealized gain (loss) recognized in other comprehensive income (loss) on
derivatives
$
$
Years Ended December 31,
2017
(Thousands of dollars)
(40,577) $
163
$
53,217
(60,584)
2016
(78,513)
42,761
(7,367) $
(40,414) $
(35,752)
The following table sets forth the effect of cash flow hedges in our Consolidated Statements of Income for the periods
indicated:
Derivatives in Cash Flow
Hedging Relationships
Location of Gain (Loss) Reclassified from
Accumulated Other Comprehensive Loss into
Net Income
2018
Commodity contracts
Interest-rate contracts
Commodity sales revenues
Interest expense
Total gain (loss) reclassified from accumulated other comprehensive loss into
net income on derivatives
$
$
Years Ended December 31,
2017
(Thousands of dollars)
(69,561) $
(21,025)
(29,596) $
(18,287)
2016
26,422
(19,215)
(47,883) $
(90,586) $
7,207
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
account 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, 2018.
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
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, 2018, the net credit exposure from our derivative assets is with investment-grade companies in the financial
services sector.
85
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
Natural gas liquids 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,
2018
December 31,
2017
(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
—
$
$
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
$
$
3,613,344
3,873,709
604,656
700,455
504,610
362,253
12,486
1,406,780
4,340,428
57,902
83,044
15,559,667
(1,888,010)
(973,531)
12,698,126
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,
2017
1.9%
2.1%
2018
1.9%
2.1%
2016
1.9%
2.1%
We incurred costs for construction work in process that had not been paid at December 31, 2018, 2017 and 2016, of $388.3
million, $92.4 million and $83.0 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
December 31,
December 31,
2018
2017
(Thousands of dollars)
$
$
153,404
371,217
156,479
681,100
$
$
153,404
371,217
156,479
681,100
86
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 20 to 40 years.
Amortization expense for intangible assets was $11.9 million in 2018, 2017 and 2016, 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:
December 31,
December 31,
2017
2018
(Thousands of dollars)
$
$
411,650
(125,608)
286,042
$
$
426,068
(113,708)
312,360
December 31,
December 31,
2018
2017
(Thousands of dollars)
Commercial paper outstanding, bearing a weighted-average interest rate of 2.23% as of December 31,
2017
$
— $
614,673
Senior unsecured obligations:
$425,000 at 3.2% due September 2018
$1,000,000 term loan, rate of 2.87% as of December 31, 2017, due January 2019
$500,000 at 8.625% due March 2019
$300,000 at 3.8% due March 2020
$1,500,000 term loan, rate of 3.63% as of December 31, 2018, 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 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
$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
$450,000 at 5.2% due July 2048
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
—
—
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
425,000
500,000
500,000
300,000
—
547,397
900,000
425,000
500,000
500,000
500,000
—
100,000
400,000
600,000
600,000
650,000
400,000
700,000
—
28,957
9,451,354
16,750
(87,120)
(507,650)
—
8,873,334
$
36,607
9,198,677
18,468
(78,193)
(432,650)
(614,673)
8,091,629
$
(a) - Individual issuances of commercial paper under our commercial paper program generally mature in 90 days or less.
$2.5 Billion Credit Agreement - In June 2018, we extended the term of our $2.5 Billion Credit Agreement by one year to June
2023. 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
87
certain lender-approved capital expansion projects). At December 31, 2018, due to our acquisition of the remaining 20 percent
interest in WTLPG for $195 million, the covenant increased to 5.5 to 1 for the second half of 2018 and first quarter 2019, and
5.0 to 1 thereafter.
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. We have the option to request an additional one-
year extension, subject to lender approval, which may be used for working capital, capital expenditures, acquisitions and
mergers, the issuance of letters of credit and for other general corporate purposes. At December 31, 2018, our ratio of
indebtedness to adjusted EBITDA was 3.5 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit
Agreement.
At December 31, 2018 and 2017, we had letters of credit issued totaling $1.4 million and $15.8 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 November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which is
available to be drawn until May 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. As of December 31, 2018,
we had borrowings totaling $550 million outstanding under our $1.5 Billion Term Loan Agreement, which were used for
general corporate purposes, including repayment of existing indebtedness.
In July 2018, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $800 million,
4.55 percent senior notes due 2028 and $450 million, 5.2 percent 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 percent senior notes due 2027, and $700 million, 4.95 percent 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 capital expenditures.
In 2016, ONEOK Partners entered into the $1.0 billion senior unsecured ONEOK Partners Term Loan Agreement with a
syndicate of banks that was due to mature in 2019 with interest at LIBOR plus 130 basis points based on our current credit
ratings and contained substantially the same covenants as our $2.5 Billion Credit Agreement. As of January 2018, all amounts
outstanding under the ONEOK Partners Term Loan Agreement had been repaid. See “Repayments” section below.
Repayments - In August 2018, we repaid the $425 million, 3.2 percent senior notes due September 2018 with cash on hand.
We repaid the ONEOK Partners Term Loan Agreement due 2019 with two payments of $500 million each in January 2018 and
July 2017 with a combination of cash on hand and short-term borrowings.
In September 2017, we repaid ONEOK Partners’ $400 million, 2.0 percent senior notes due in October 2017 with a
combination of cash on hand and short-term borrowings.
In July 2017, we redeemed our 6.5 percent senior notes due 2028 at a redemption price of $87.0 million, including the
outstanding principal amount, plus accrued and unpaid interest, with cash on hand.
In October 2016, ONEOK Partners repaid its $450 million, 6.15 percent senior notes at maturity with a combination of cash on
hand and short-term borrowings.
88
The aggregate maturities of long-term debt outstanding as of December 31, 2018, for the years 2019 through 2023 are shown
below:
2019
2020
2021
2022
2023
Senior
Notes
Guardian
Pipeline
Total
$
$
$
$
$
500.0
300.0
550.0
1,447.4
925.0
$
$
$
$
$
$
7.7
$
7.7
$
7.7
$
5.9
— $
507.7
307.7
557.7
1,453.3
925.0
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 percent 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 percent 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 percent 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 percent 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 2020, 2022, 2023, 2025, 2027, 2028 (4.55%), 2041, 2043, 2047 and 2048 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, 2018, 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.
G.
EQUITY
Noncontrolling Interests - As a result of the Merger Transaction in 2017, we and our subsidiaries own 100 percent of ONEOK
Partners. At December 31, 2017, the caption “Noncontrolling interests” on our Consolidated Balance Sheet reflects only the 20
percent of WTLPG that we did not own. On July 31, 2018, we acquired the remaining 20 percent 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.
89
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 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.
Prior to the close of the Merger Transaction, ONEOK Partners had an “at-the-market” equity program for the offer and sale
from time to time of its common units, up to an aggregate amount of $650 million. During the six months ended June 30,
2017, and the year ended December 31, 2016, no common units were sold through ONEOK Partners’ “at-the-market” equity
program. Upon the close of the Merger Transaction on June 30, 2017, the ONEOK Partners “at-the-market” equity program
terminated.
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 $1.3 billion, $829.4 million and $517.6 million for
2018, 2017 and 2016, 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,
2017
2016
2018
$
$
0.770
0.795
0.825
0.855
3.245
$
$
0.615
0.615
0.745
0.745
2.72
$
$
0.615
0.615
0.615
0.615
2.46
Additionally, in February 2019, we paid a quarterly dividend of $0.86 per share ($3.44 per share on an annualized basis), which
was paid to shareholders of record as of January 28, 2019.
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 percent per year. We paid dividends for the Series E Preferred Stock of $1.1 million and
$0.6 million in 2018 and 2017, respectively. We paid dividends totaling $0.3 million for the Series E Preferred Stock in
February 2019.
Cash Distributions - Prior to the consummation of the Merger Transaction, we received distributions from ONEOK Partners
on our common and Class B units and our 2 percent general partner interest, which included our incentive distribution rights.
As a result of the Merger Transaction, we are entitled to receive all available ONEOK Partners cash. Our incentive distribution
rights effectively terminated at the close of the Merger Transaction.
90
The following table sets forth ONEOK Partners’ distributions paid during the periods prior to the closing of the Merger
Transaction on June 30, 2017:
Years Ended December 31,
2017
2016
Distribution per unit
General partner distributions
Incentive distributions
Distributions to general partner
Limited partner distributions to ONEOK
Limited partner distributions to other unitholders
Total distributions paid
$
$
$
(Thousands, except per unit
amounts)
1.58
$
3.16
13,320
201,076
214,396
180,646
270,959
666,001
$
$
26,640
402,152
428,792
361,292
541,919
1,332,003
H.
ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the balance in accumulated other comprehensive loss for the periods indicated:
Unrealized Gains
(Losses) on Risk-
Management
Assets/Liabilities (a)
Pension and
Postretirement
Benefit Plan
Obligations (a) (b)
Unrealized Gains
(Losses) on Risk-
Management
Assets/Liabilities of
Unconsolidated
Affiliates (a)
Accumulated
Other
Comprehensive
Loss (a)
$
(52,155) $
(101,236) $
(959) $
(154,350)
(Thousands of dollars)
(35,013)
45,541
(40,288)
(29,760)
(81,915)
3,078
(5,673)
36,870
(12,337)
8,162
—
(4,175)
(105,411)
(805)
(8,116)
12,887
(409)
164
—
(245)
(1,204)
(2,273)
2,396
28
31,197
(17,020)
(64,660) $
4,771
(20,340)
(121,785) $
$
2,424
(741)
(1,794) $
(47,759)
53,867
(40,288)
(34,180)
(188,530)
—
(11,393)
49,785
38,392
(38,101)
(188,239)
January 1, 2017
Other comprehensive income (loss) before
reclassifications
Amounts reclassified from accumulated other
comprehensive loss
Impact of Merger Transaction (c)
Other comprehensive income (loss)
attributable to ONEOK
December 31, 2017
Beginning balance adjustments (d)
Other comprehensive income (loss) before
reclassifications
Amounts reclassified from accumulated other
comprehensive loss
Other comprehensive income (loss)
attributable to ONEOK
Impact of adoption of ASU 2018-02 (e)
December 31, 2018
(a) All amounts are presented net of tax.
(b) Includes amounts related to supplemental executive retirement plan.
(c) Includes the remaining portion of ONEOK Partners’ accumulated other comprehensive loss at June 30, 2017, that we acquired in the
Merger Transaction, related to commodity and interest-rate contracts.
(d) Reclassifications were made between categories to conform to current presentation.
(e) 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.
91
The following table sets forth information about the balance of accumulated other comprehensive loss at December 31, 2018,
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)
37,589
$
(40,037)
Forward-starting interest-rate swaps with future settlement dates expected to be amortized over the life of long-
term fixed-rate debt upon issuance of the debt
Accumulated other comprehensive loss at December 31, 2018
$
(62,212)
(64,660)
(a) - All amounts are presented net of tax.
(b) - Based on December 31, 2018, commodity prices, we will realize $37.5 million in net gains, net of tax, over the next 12 months and $0.1
million in net gains, net of tax, thereafter.
(c) - Losses of $13.5 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 pension and postretirement benefit
plan obligations, which are expected to be amortized over the average remaining service period of employees participating in
these plans.
92
The following table sets forth the effect of reclassifications from accumulated other comprehensive loss in our Consolidated
Statements of Income for the periods indicated:
Details about Accumulated Other
Comprehensive Loss Components
Risk-management assets/liabilities
Commodity contracts
Interest-rate contracts
2018
Years Ended December 31,
2017
(Thousands of dollars)
2016
Affected Line Item in the
Consolidated Statements of Income
$
(29,596) $
(18,287)
(47,883)
11,013
(36,870)
(69,561) $
(21,025)
(90,586)
26,899
(63,687)
26,422 Commodity sales revenues
Interest expense
(19,215)
Income before income taxes
7,207
Income taxes
(230)
6,977 Net income
Noncontrolling interests
—
(18,146)
6,301
Less: Net income attributable
noncontrolling interests
$
(36,870) $
(45,541) $
676 Net income attributable to ONEOK
Pension and postretirement benefit plan
obligations (a)
Amortization of net loss
$
(18,398) $
(15,265) $
(12,012) Other income (expense)
Amortization of unrecognized prior service cost
Risk-management assets/liabilities of
unconsolidated affiliates
Interest-rate contracts
Noncontrolling interests
Total reclassifications for the period attributable
to ONEOK
$
$
$
$
1,662
(16,736)
3,849
(12,887) $
1,662
(13,603)
5,441
(8,162) $
1,662 Other income (expense)
Income before income taxes
Income taxes
(10,350)
4,140
(6,210) Net income attributable to ONEOK
(36) $
(367) $
8
(28)
97
(270)
—
(28) $
(106)
(164) $
Equity in net earnings from
investments
(63)
Income taxes
10
(53) Net income
Less: Net income attributable to
noncontrolling interests
(37)
(16) Net income attributable to ONEOK
(49,785) $
(53,867) $
(5,550) 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, 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
93
Year Ended December 31, 2017
Income
Shares
(Thousands, except per share amounts)
Per Share
Amount
Basic EPS
Net income attributable to ONEOK available for common stock
Diluted EPS
Effect of dilutive securities
Net income attributable to ONEOK available for common stock and common stock
equivalents
$
$
387,074
297,477
$
1.30
—
2,303
387,074
299,780
$
1.29
Year Ended December 31, 2016
Income
Shares
Per Share
Amount
(Thousands, except per share amounts)
Basic EPS
Net income attributable to ONEOK available for common stock
$
352,039
211,128
$
1.67
Diluted EPS
Effect of dilutive securities
Net income attributable to ONEOK available for common stock and common stock
equivalents
—
1,255
$
352,039
212,383
$
1.66
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 a new 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, 2018, we had 8.5
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 percent to 200 percent) 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) 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 number of shares of
94
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 or DSCP. There are no options outstanding under the EIP or DSCP.
General
For all awards outstanding, we used a 3 percent 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 $25.6 million, $16.6 million and $30.7 million during 2018,
2017 and 2016, respectively, which is net of tax benefits of $7.6 million, $11.1 million and $9.8 million, respectively.
Restricted Stock Unit Activity
As of December 31, 2018, we had $13.9 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 1.9 years. The following tables set
forth activity and various statistics for our restricted stock unit awards:
Nonvested December 31, 2017
Granted
Released to participants
Forfeited
Nonvested December 31, 2018
Weighted-average grant date fair value (per share)
Fair value of units granted (thousands of dollars)
Fair value of units vested (thousands of dollars)
Performance Unit Activity
Number of
Units
Weighted
Average Price
$
1,001,805
296,277
$
(243,289) $
(29,600) $
$
1,025,193
32.30
46.94
39.26
39.34
34.68
2018
2017
2016
$
$
$
46.94
13,907
9,552
$
$
$
45.11
12,685
7,258
$
$
$
20.04
11,081
4,429
As of December 31, 2018, we had $21.1 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 1.9 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, 2017
Granted
Released to participants
Forfeited
Nonvested December 31, 2018
Volatility (a)
Dividend yield
Risk-free interest rate
Number of
Units
Weighted
Average Price
$
1,136,133
370,677
$
(257,807) $
(5,360) $
$
1,243,643
40.08
59.57
48.66
46.97
44.08
2018
39.20%
5.49%
2.44%
2017
40.59%
4.68%
1.49%
2016
39.94%
11.32%
0.93%
(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)
Fair value of units vested (thousands of dollars)
2018
2017
2016
$
$
$
59.57
22,081
12,545
$
$
$
56.65
17,621
8,704
$
$
$
25.54
15,229
—
95
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 percent of their annual base pay withheld to purchase our common stock, subject to terms and
limitations of the plan. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price.
Approximately 60 percent, 58 percent and 57 percent of employees participated in the plan in 2018, 2017 and 2016,
respectively. Under the plan, we sold 165,877 shares at $45.53 per share in 2018, 151,803 shares at $44.20 per share in 2017
and 232,553 shares at $27.21 per share in 2016.
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 2018 totaled 2,553 and compensation
expense related to the Employee Stock Award Program was $0.2 million. No shares were issued to employees under this
program during 2017 or 2016. The next award will be issued when our common stock closes at or above $72.
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 before
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
effective January 1, 2019. 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 service. The postretirement medical
plan is contributory with retiree contributions adjusted periodically and contains other cost-sharing features such as deductibles
and coinsurance.
96
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,
2018
2017
2018
(Thousands of dollars)
2017
$
$
$
$
$
481,615
7,339
17,659
—
(24,345)
(15,274)
466,994
$
428,386
6,896
18,645
—
41,678
(13,990)
481,615
306,008
(12,350)
12,300
—
(15,274)
290,684
(176,310) $
261,671
50,827
7,500
—
(13,990)
306,008
(175,607) $
(4,514) $
(4,544) $
(171,796)
(176,310) $
(171,063)
(175,607) $
$
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) $
54,823
662
2,261
901
3,456
(4,165)
57,938
29,550
5,385
2,000
901
(3,703)
34,133
(23,805)
—
(23,805)
(23,805)
The table above includes the supplemental executive retirement plan obligation. ONEOK has investments included in other
assets on the Consolidated Balance Sheets, which totaled $87.7 million and $93.2 million at December 31, 2018 and 2017,
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 $434.4 million and $456.6 million at December 31, 2018 and
2017, 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,
2017
2016
2018
Other Postretirement Benefits
Years Ended December 31,
2017
2016
2018
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)
$
$
7,339
17,659
(23,917)
—
17,060
18,141
$
$
6,896
18,645
(21,376)
—
13,586
17,751
$
$
6,501
19,820
(20,348)
—
10,966
16,939
$
$
845
2,108
(2,690)
(1,662)
1,338
$
(61) $
662
2,261
(2,257)
(1,662)
1,679
683
$
$
596
2,404
(2,124)
(1,662)
1,046
260
97
Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income
(loss) related to our retirement benefits and other postretirement benefits for the periods indicated:
Retirement Benefits
Years Ended December 31,
2017
2016
2018
Other Postretirement Benefits
Years Ended December 31,
2017
2016
2018
Net gain (loss) arising during the period
Amortization of prior service credit
Amortization of net loss
Deferred income taxes (a)
Total recognized in other comprehensive income (loss)
$ (16,351) $ (16,572) $ (33,043) $
(Thousands of dollars)
6,545
(1,662)
1,338
(2,831)
3,390
—
10,966
8,831
$
(328) $
(1,662)
1,679
82
(229) $
$
(5,128)
(1,662)
1,046
2,297
(3,447)
(3,946) $ (13,246) $
—
17,060
(18,928)
$ (18,219) $
—
13,586
(960)
(a) - Year ended December 31, 2018, includes the impact of adopting ASU 2018-02.
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:
Retirement Benefits
December 31,
Other Postretirement Benefits
December 31,
Prior service credit
Accumulated loss
Accumulated other comprehensive loss
Deferred income taxes
Accumulated other comprehensive loss, net of tax
2018
$
$
— $
(160,212)
(160,212)
43,286
(116,926) $
2017
2018
(Thousands of dollars)
— $
(160,921)
(160,921)
62,214
(98,707) $
$
227
(5,108)
(4,881)
1,567
(3,314) $
2017
1,889
(12,991)
(11,102)
4,398
(6,704)
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,
2018
4.50%
3.65%
2017
3.75%
3.00%
2018
4.50%
N/A
2017
3.75%
N/A
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,
2017
4.50%
4.25%
7.75%
3.10%
2018
3.75%
3.75%
8.00%
3.00%
2016
5.25%
5.00%
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. We estimate our discount rate based upon a comparison of the expected cash flows
associated with our future payments under our retirement and other postretirement obligations to a hypothetical bond portfolio
created using high-quality bonds that closely match expected cash flows. Bond portfolios are developed by selecting a bond
for each of the next 60 years based on the maturity dates of the bonds. Bonds selected to be included in the portfolios are only
those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers
and other filtering criteria to remove unsuitable bonds.
98
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
2018
6.50%
5.00%
2022
2017
7.00%
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 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, 2018, 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. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the
exception of indexing purposes, are prohibited from owning our stock.
The following tables set forth 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, 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.
99
Pension Benefits
December 31, 2017
Asset Category
Level 1
Level 2
Level 3
Subtotal
Measured at
NAV (d)
Total
(Thousands of dollars)
Investments:
Equity securities (a)
Government obligations
Corporate obligations (b)
Common/collective trusts
Cash
Other investments (c)
Fair value of plan assets
$
$
176,347
—
—
—
298
—
176,645
$
$
19,199
19,481
62,981
6,621
—
—
108,282
$
$
— $
—
—
—
—
—
— $
195,546
19,481
62,981
6,621
298
—
284,927
$
$
— $
—
—
—
—
21,081
21,081
$
195,546
19,481
62,981
6,621
298
21,081
306,008
(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, 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.
Other Postretirement Benefits
December 31, 2017
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)
$
$
1,951
—
—
1,951
$
$
— $
1,515
30,667
32,182
$
— $
—
—
— $
1,951
1,515
30,667
34,133
(a) - This category represents securities of the respective market sector from diverse industries.
Contributions - During 2018, we made $12.3 million in contributions to our defined benefit pension plan and $1.1 million in
contributions to our other postretirement benefit plans. We contributed $14.5 million to our defined benefit pension plan in
January 2019 and expect to make $2.0 million in contributions to our other postretirement plans in 2019.
100
Pension and Other Postretirement Benefit Payments - Benefit payments for our defined benefit pension and other
postretirement benefit plans for the period ending December 31, 2018, were $15.3 million and $4.9 million, respectively. The
following table sets forth the defined benefit pension and other postretirement benefits payments expected to be paid in 2019
through 2028:
Benefits to be paid in:
2019
2020
2021
2022
2023
2024 through 2028
Pension
Benefits
Other
Postretirement
Benefits
(Thousands of dollars)
$
$
$
$
$
$
17,014
18,164
19,215
20,279
21,362
122,012
$
$
$
$
$
$
3,114
3,237
3,230
3,346
3,315
16,178
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31,
2018, 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 match 100
percent of employee contributions up to 6 percent of each participant’s eligible compensation, subject to certain limits. Our
contributions made to the plan were $15.1 million, $13.7 million and $11.9 million in 2018, 2017 and 2016, respectively.
Profit Sharing Plan - We historically maintained a profit-sharing plan (Profit Sharing Plan) for all employees hired after
December 31, 2004. Employees who were employed prior to January 1, 2005, were given a one-time opportunity to make an
irrevocable election to participate in the Profit Sharing Plan and not accrue any additional benefits under our defined benefit
pension plan after December 31, 2004. The Profit Sharing Plan was merged into our 401(k) Plan as of January 1, 2019, and
ceased to exist as a separate plan. We plan to make a contribution to the 401(k) Plan each quarter equal to 1 percent of each
profit-sharing participant’s eligible compensation during the quarter. Additional discretionary employer profit-sharing
contributions may be made at the end of each year. Our contributions made to our former Profit Sharing Plan were $12.9
million, $7.4 million and $8.2 million in 2018, 2017 and 2016, respectively.
Nonqualified Deferred Compensation Plan - The Nonqualified Deferred Compensation Plan provides select employees, as
approved by our Chief Executive Officer, with the option to defer portions of their compensation and provides nonqualified
deferred compensation benefits that are not available due to limitations on employer and employee contributions to qualified
defined contribution plans under the federal tax laws. The 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 2018, 2017 and 2016.
101
L.
INCOME TAXES
The following table sets forth our provision for income taxes from continuing operations and excludes discontinued operations
for the periods indicated:
Current income tax provision
Federal
State
Total current income taxes
Deferred income tax provision
Federal
State
Total deferred income taxes
Total provision for income taxes
2018
Years Ended December 31,
2017
(Thousands of dollars)
2016
$
$
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
$
$
6,086
2,449
8,535
193,974
9,897
203,871
212,406
The following table is a reconciliation of our income tax provision from continuing operations and excludes discontinued
operations 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
Other, net
Income tax provision
2018
Years Ended December 31,
2017
(Thousands of dollars)
$
$
$ 1,517,935
3,329
1,514,606
1,040,801
205,678
835,123
2016
957,956
391,460
566,496
21.0%
35.0%
35.0%
318,067
38,668
5,552
616
362,903
$
292,293
16,197
141,283
(2,491)
447,282
$
198,274
12,303
43
1,786
212,406
$
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)
Regulatory assets
Total deferred tax liabilities
Net deferred tax assets (liabilities)
(a) Due primarily to excess of tax over book depreciation.
102
December 31,
December 31,
2018
2017
(Thousands of dollars)
$
$
$
91,587
420,318
108,004
22,108
13,378
655,395
85,355
159,162
73,277
30,060
13,546
361,400
(73,820)
581,575
(66,632)
294,768
73,113
728,193
—
801,306
(219,731) $
64,508
77,035
15
141,558
153,210
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 percent from 35
percent, 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 $5.6 million and $54.1 million related to these tax benefits in 2018 and 2017,
respectively.
As a result of adopting ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” in first quarter 2017,
we recorded an adjustment increasing beginning retained earnings and deferred tax assets of $73.4 million to recognize the
cumulative tax benefits included in net operating loss carryforwards on the tax return but not reflected in deferred tax assets as
of December 31, 2016. Beginning in January 2017, all share-based payment tax effects have been recorded in earnings.
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 Company
Roadrunner Gas Transmission
Other
Investments in unconsolidated affiliates (a)
Net
Ownership
Interest
50%
50%
50%
Various
December 31,
December 31,
2018
2017
(Thousands of dollars)
$
$
381,623
429,295
93,857
64,375
969,150
$
$
396,800
436,111
93,048
77,197
1,003,156
(a) - Equity-method goodwill (Note A) was $38.8 million at December 31, 2018 and 2017.
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 Company
Roadrunner Gas Transmission
Other
Equity in net earnings from investments
Impairment of equity investments
$
$
$
67,854
65,887
22,993
1,649
158,383
68,153
60,067
19,150
11,908
159,278
$
— $
$
(4,270) $
2018
Years Ended December 31,
2017
(Thousands of dollars)
$
$
2016
69,990
53,984
4,445
11,271
139,690
—
Impairment Charges - In the third quarter 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.
103
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 loss
Owners’ equity
Income Statement
Operating revenues
Operating expenses
Net income
Distributions paid to us
December 31,
December 31,
2018
2017
(Thousands of dollars)
$
$
$
$
$
$
$
$
158,723
2,413,662
16,273
83,057
480,731
47,826
2,053
1,974,991
$
$
$
$
$
$
$
$
151,907
2,490,692
14,793
70,434
479,050
53,830
(9,946)
2,064,024
2018
Years Ended December 31,
2017
(Thousands of dollars)
2016
$
$
$
$
637,762
276,373
337,694
197,285
$
$
$
$
639,102
277,121
347,692
196,114
$
$
$
$
578,542
260,753
293,921
196,717
We incurred expenses in transactions with unconsolidated affiliates of $153.9 million, $156.1 million and $140.3 million for
2018, 2017 and 2016, respectively, primarily related to Overland Pass Pipeline Company and Northern Border Pipeline.
Accounts payable to our equity-method investees at December 31, 2018 and 2017, was $14.7 million and $13.6 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 percent 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 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 will reduce tariff rates 12.5 percent 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.
In compliance with the FERC final rule, Northern Border Pipeline completed the required filing related to the Tax Cuts and
Jobs Act, and we do not expect the impact on tariff rates to be material to us.
Overland Pass Pipeline Company - The Overland Pass Pipeline Company limited liability company agreement provides that
distributions to Overland Pass Pipeline Company’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 Company requires the
unanimous approval of the Overland Pass Pipeline Company Management Committee. Cash distributions are equal to
100 percent of available cash as defined in the limited liability company agreement.
104
Roadrunner Gas Transmission - The Roadrunner limited liability company 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 limited liability
company agreement. Cash distributions are equal to 100 percent of available cash, as defined in the limited liability company
agreement. We made contributions of $65 million to Roadrunner in 2016. In 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, 2018, 2017 and 2016, were not material.
N.
COMMITMENTS AND CONTINGENCIES
Commitments - Operating leases represent future minimum lease payments under noncancelable leases, which primarily
includes office space, pipeline equipment, rail cars and information technology equipment. Rental expense in 2018, 2017 and
2016 was not material. We have no material operating leases. We lease certain compression facilities under a capital lease that
has a fixed-price purchase option in 2028. Firm transportation and storage contracts are fixed-price contracts that provide us
with firm transportation and storage capacity. The following table sets forth our capital lease future minimum payments and
our firm transportation and storage contract payments for the periods indicated:
2019
2020
2021
2022
2023
Thereafter
Total
(a) - At December 31, 2018, $28 million in principal represents noncash financing activities.
$
$
Firm
Transportation
and Storage
Contracts
Capital
Lease
(a)
(Millions of dollars)
4.5
4.5
4.5
4.5
4.5
21.6
44.1
$
$
63.7
51.6
35.7
22.4
17.3
11.7
202.4
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 have a material adverse effect on 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. (OESC), 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 March 2017, the United States District Court for the District of Nevada (the Nevada District Court) granted summary
judgment to OESC in Sinclair Oil Corporation v. ONEOK Energy Services Company, L.P. (filed in the United States District
Court for the District of Wyoming (the Wyoming District Court) in September 2005, transferred to MDL-1566 in the Nevada
District Court). In September 2017, the Nevada District Court entered a final judgment in favor of OESC in Sinclair, which
was appealed by Sinclair Oil Corporation to the Ninth Circuit Court of Appeals. On August 1, 2018, the Ninth Circuit Court of
Appeals reversed the Nevada District Court’s granting of summary judgment and remanded the case back to the Nevada
District Court. On February 11, 2019, Sinclair was further remanded back to the Wyoming District Court. We expect that
105
future charges, if any, from the ultimate resolution of the Sinclair case will not be material to our results of operations, financial
position or cash flows.
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 have a material adverse effect on our consolidated results of operations,
financial position or cash flows.
O.
REVENUES
Adoption of ASC Topic 606: Revenue from Contracts with Customers - We adopted Topic 606 on January 1, 2018, using
the modified retrospective method applied to contracts that were active as of January 1, 2018. Results for reporting periods
beginning after January 1, 2018, are presented under Topic 606, while prior periods are not adjusted and continue to be reported
under the accounting standards in effect for those periods. We recorded a net increase to the beginning balance of retained
earnings of $1.7 million as of January 1, 2018, due to the cumulative impact of adopting the standard, primarily related to the
timing of revenue on transportation contracts with tiered rates that resulted in contract assets in our Natural Gas Pipelines
segment, contributions in aid of construction from customers that resulted in contract liabilities and an adjustment to NGL
inventory related to contractual fees in our Natural Gas Liquids Segment, as described below.
Based on the new guidance, 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.
Therefore, contractual fees in these identified contracts are now recorded as a reduction of the commodity purchase price in
cost of sales and fuel pursuant to ASC 705 rather than as services revenue. To the extent we hold inventory related to these
purchases, the related fees previously recorded in services revenue will not be recognized until the inventory is sold. We
continue to be principal on the downstream sales of those commodities, which is unchanged from our assessment under
previous guidance.
The impact on our Consolidated Income Statement and Balance Sheet is as follows (in thousands):
Income Statement
Commodity sales
Services revenue
Cost of sales and fuel (exclusive of depreciation and operating costs)
Depreciation and amortization
Income taxes
Net income
Net income attributable to noncontrolling interests
Net income attributable to ONEOK
Year Ended December 31, 2018
As Reported
Balance Without
Adoption of
Topic 606
Effect of Change
Increase/
(Decrease)
$
$
$
$
$
$
$
$
11,395,642
1,197,554
9,422,708
428,557
362,903
1,155,032
3,329
1,151,703
$
$
$
$
$
$
$
$
11,460,913
2,712,256
11,006,278
427,976
362,210
1,152,709
3,322
1,149,387
$
$
$
$
$
$
$
$
(65,271)
(1,514,702)
(1,583,570)
581
693
2,323
7
2,316
106
Balance Sheet
Accounts receivable, net
Natural gas and natural gas liquids in storage
Other current assets
Property, plant and equipment
Accumulated depreciation and amortization
Other assets
Accounts payable
Other current liabilities
Deferred income taxes
Other deferred credits
Retained earnings/paid-in capital
December 31, 2018
As Reported
Balance Without
Adoption of
Topic 606
Effect of Change
Increase/
(Decrease)
$
$
$
$
$
$
$
$
$
$
$
818,958
296,667
100,808
18,030,963
3,264,312
130,096
1,118,102
211,110
219,731
450,627
7,615,138
$
$
$
$
$
$
$
$
$
$
$
956,523
301,555
99,579
18,006,653
3,262,359
125,606
1,255,667
209,258
218,536
434,508
7,611,116
$
$
$
$
$
$
$
$
$
$
$
(137,565)
(4,888)
1,229
24,310
1,953
4,490
(137,565)
1,852
1,195
16,119
4,022
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.
Receivables from Customers - The balances in accounts receivable on our Consolidated Balance Sheet at December 31, 2018,
and December 31, 2017, include customer receivables of $0.8 billion and $1.2 billion, respectively.
Accounting Policies - See Note A for revenue recognition accounting policies.
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 NGL storage contracts for which revenue is
recognized over a one-year term and deferred revenue on contributions in aid of construction received from customers for
which revenue is recognized over the contract period, which averages 10 years. The following tables set forth the changes in
our contract asset and contract liability balances for the year ended December 31, 2018:
Contract Assets
Balance at January 1, 2018 (a)
Amounts invoiced in excess of revenue recognized
Net additions
Balance at December 31, 2018 (b)
(Millions of dollars)
6.4
$
(0.9)
0.7
6.2
$
(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.
Contract Liabilities
Balance at January 1, 2018 (a)
Revenue recognized included in beginning balance
Net additions
Balance at December 31, 2018 (b)
(Millions of dollars)
33.3
$
(19.5)
17.9
31.7
$
(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.
107
Transaction Price Allocated to Unsatisfied Performance Obligations - The following table presents aggregate value
allocated to unsatisfied performance obligations as of December 31, 2018, 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 25 years:
Expected Period of Recognition in Revenue
2019
2020
2021
2022
2023 and beyond
Total estimated transaction price allocated to unsatisfied performance obligations
(Millions of dollars)
308.6
$
256.1
242.4
192.7
892.0
1,891.8
$
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
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.
P.
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, 2018, 2017 and 2016, we had no single customer from which we received 10 percent
or more of our consolidated revenues.
108
Operating Segment Information - The following tables set forth certain selected financial information for our operating
segments for the periods indicated:
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
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
$
$
$
(196,090) $
$
6,078,473
$
694,611
(174,007) $
$
9,663,640
$
1,306,341
— $ 12,095,838
1,093,934
568,091
593,032
49,995
14,400,890
(11,234,245)
(907,313)
158,383
20,748
2,438,463
9,772
—
394,014
27,949
431,735
(15,984)
(144,259)
90,847
3,912
366,251
$
(55,118) $
2,131,669
119,185
(425,215)
$ 17,873,782
2,120,137
$
(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, Natural Gas Liquids and Natural Gas Pipelines segments totaled
$1,768.8 million, $28.7 million and $12.6 million, respectively.
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
Total assets
Capital expenditures
Total
Segments
Other and
Eliminations
(Thousands of dollars)
Total
$ 12,095,838
1,093,934
568,091
593,032
49,995
$ 14,400,890
$ (1,794,342) $ 10,301,496
1,091,102
568,070
583,426
49,102
$ (1,807,694) $ 12,593,196
(2,832)
(21)
(9,606)
(893)
$ (11,234,245) $
(907,313) $
$
(425,215) $
$
$
$
158,383
$
$ 17,873,782
$
2,120,137
$
$ (9,422,708)
1,811,537
(907,068)
245
$
(428,557)
(3,342) $
158,383
— $
$ 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 reclassified from
accumulated other comprehensive income from derivatives on commodity contracts.
109
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
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) $
$
$
5,495,163
284,205
(167,277) $
— $
$
$
8,782,700
114,267
(51,025) $
— $
2,055,020
95,564
(403,225)
(20,240)
$ 16,332,883
494,036
$
(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.
Year Ended December 31, 2017
Reconciliations of total segments to consolidated
Sales to unaffiliated customers
Intersegment revenues
Total revenues
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
1,898,228
(31,748) $
(3,110) $
— $
— $
513,054
18,357
$ (9,538,045)
(822,710)
(406,335)
(20,240)
159,278
$ 16,845,937
512,393
$
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
Total assets
Capital expenditures
$ (11,436,273) $
(790,962) $
$
(403,225) $
$
(20,240) $
$
$
$
159,278
$
$ 16,332,883
$
494,036
$
110
Year Ended December 31, 2016
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
Total assets
Capital expenditures
Natural Gas
Gathering and
Processing
Natural Gas
Liquids (a)
Natural Gas
Pipelines (b)
Total
Segments
1,375,738
675,839
2,051,577
(1,331,542)
(283,395)
10,742
(604)
446,778
$
$
$
(Thousands of dollars)
7,168,983
506,671
7,675,654
(6,321,377)
(326,056)
54,513
(3,115)
1,079,619
373,738
5,623
379,361
(30,561)
(114,658)
74,435
4,560
313,137
$
$
$
8,918,459
1,188,133
10,106,592
(7,683,480)
(724,109)
139,690
841
1,839,534
(178,548) $
$
5,320,666
$
410,485
(163,303) $
$
8,347,961
$
105,861
(46,718) $
1,946,318
96,274
(388,569)
$ 15,614,945
612,620
$
$
$
$
$
$
(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 $992.8 million related to sales within the segment, and cost of sales and fuel of $458.7 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated
operations had revenues of $238.7 million and cost of sales and fuel of $30.0 million.
Year Ended December 31, 2016
Reconciliations of total segments to consolidated
Sales to unaffiliated customers
Intersegment revenues
Total revenues
Total
Segments
Other and
Eliminations
(Thousands of dollars)
Total
$
8,918,459
1,188,133
$ 10,106,592
$
$
2,475
(1,188,133)
$ (1,185,658) $
8,920,934
—
8,920,934
Cost of sales and fuel (exclusive of depreciation and operating costs)
Operating costs
Depreciation and amortization
Equity in net earnings from investments
Total assets
Capital expenditures
$ (7,683,480) $
(724,109) $
$
(388,569) $
$
$
$
139,690
$
$ 15,614,945
$
612,620
$
1,187,356
(22,973) $
(3,016) $
— $
523,806
12,014
$ (6,496,124)
(747,082)
(391,585)
139,690
$ 16,138,751
624,634
$
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
2018
Years Ended December 31,
2017
(Thousands of dollars)
$
593,519
$
2016
743,499
$ 1,155,032
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
469,651
391,585
212,406
—
31,981
(9,588)
$ 1,839,534
(a) - 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.
111
Q.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Year Ended December 31, 2018
Total revenues
Net income
Net income attributable to ONEOK
Net income attributable 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
266,049
264,508
264,233
0.65
0.64
$
$
$
$
$
$
2,960,529
282,179
281,048
280,773
0.68
0.68
$
$
$
$
$
$
3,393,890
313,916
313,259
312,984
0.76
0.75
$
$
$
$
$
$
3,136,700
292,888
292,888
292,613
0.71
0.70
In the third quarter 2018, we acquired the remaining 20 percent interest in WTLPG for $195 million with cash on hand. We are
now the sole owner of the West Texas LPG pipeline system.
Year Ended December 31, 2017
Total revenues
Net income
Net income attributable to ONEOK
Net income attributable to common shareholders
Earnings per share total
Basic
Diluted
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Thousands of dollars except per share amounts)
$
$
$
$
$
$
2,749,611
186,185
87,361
87,361
0.41
0.41
$
$
$
$
$
$
2,725,772
175,991
71,693
71,476
0.34
0.33
$
$
$
$
$
$
2,906,366
166,531
165,742
165,466
0.43
0.43
$
$
$
$
$
$
3,792,158
64,812
63,045
62,771
0.16
0.16
The fourth quarter 2017 includes a one-time noncash charge of $141.3 million related to 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, as described in Note L.
The third quarter 2017 includes noncash impairment charges of $20.2 million related to Natural Gas Gathering and Processing
assets and equity investments.
The second quarter 2017 includes 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.
R.
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 percent 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.
112
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.
113
Condensed Consolidating Statements of Income
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
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
Year Ended December 31, 2018
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
$
— $
—
—
— $
—
—
— $
—
—
$
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
—
—
—
—
1,660.5
315.1
(315.1)
1,660.5
—
1,660.5
—
1,660.5
—
—
—
—
—
1,660.5
315.1
(315.1)
1,660.5
—
1,660.5
—
1,660.5
—
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
—
—
(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
$
1,150.6
$
1,660.5
$
1,660.5
$
1,613.5
$
(4,934.5) $
1,150.6
Year Ending December 31, 2017
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
$
— $
—
—
— $
—
—
— $
—
—
9,862.7
2,313.2
12,175.9
—
17.8
—
—
(17.8)
1,236.6
—
(12.3)
(137.1)
1,069.4
(480.2)
589.2
201.4
387.8
0.8
—
—
—
—
—
1,215.7
—
353.1
(353.1)
1,215.7
—
1,215.7
—
1,215.7
—
—
9.2
—
—
(9.2)
1,224.9
—
353.1
(353.1)
1,215.7
—
1,215.7
—
1,215.7
—
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
—
$
— $
(2.0)
(2.0)
—
(2.0)
—
—
—
(3,618.6)
—
(706.2)
706.2
(3,618.6)
—
(3,618.6)
—
(3,618.6)
—
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
$
387.0
$
1,215.7
$
1,215.7
$
1,187.2
$
(3,618.6) $
387.0
114
Year Ending December 31, 2016
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(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
Income from continuing operations
Income (loss) from discontinued
operations, net of tax
Net income
Less: Net income attributable to
noncontrolling interests
Net income attributable to ONEOK
$
—
18.7
0.3
(19.0)
1,063.9
(5.0)
(102.9)
937.0
(199.0)
738.0
—
738.0
386.0
352.0
—
—
—
—
1,066.8
373.5
(373.5)
1,066.8
—
1,066.8
—
1,066.8
—
—
—
—
1,066.8
373.5
(373.5)
1,066.8
—
1,066.8
—
1,066.8
6,858.5
2,064.3
8,922.8
6,496.1
1,121.8
(9.9)
1,314.8
69.7
(2.8)
(366.8)
1,014.9
(13.4)
1,001.5
(2.1)
999.4
$
— $
(1.8)
(1.8)
—
(1.8)
—
—
(3,127.5)
(747.0)
747.0
(3,127.5)
—
(3,127.5)
—
(3,127.5)
6,858.5
2,062.5
8,921.0
6,496.1
1,138.7
(9.6)
1,295.8
139.7
(7.8)
(469.7)
958.0
(212.4)
745.6
(2.1)
743.5
391.5
352.0
—
1,066.8
$
—
1,066.8
$
$
5.5
993.9
$
—
(3,127.5) $
115
Condensed Consolidating Statements of Comprehensive Income
Year Ended December 31, 2018
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
Net income
$
1,151.7
$
1,660.5
$
1,660.5
$
1,616.8
$
(4,934.5) $
1,155.0
Other comprehensive income (loss), net of
tax
Unrealized gains (losses) on derivatives,
net of tax
(46.7)
Realized (gains) losses on derivatives
recognized in net income, net of tax
Change in pension and postretirement
benefit plan liability, net of tax
Other comprehensive income (loss) on
investments in unconsolidated affiliates,
net of tax
Total other comprehensive income
(loss), net of tax
Comprehensive income
Less: Comprehensive income attributable
to noncontrolling interests
Comprehensive income attributable to
ONEOK
53.2
45.5
(0.7)
3.1
53.2
29.6
—
3.1
41.0
19.1
0.2
2.3
(106.4)
(59.2)
—
(6.1)
(5.7)
36.9
4.8
2.4
1.9
5.3
—
(39.5)
1,112.2
101.1
1,761.6
85.9
1,746.4
62.6
1,679.4
(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
Year Ending December 31, 2017
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
Net income
$
589.2
$
1,215.7
$
1,215.7
$
1,191.5
$
(3,618.6) $
593.5
Other comprehensive income (loss), net of
tax
Unrealized gains (losses) on derivatives,
net of tax
Realized (gains) losses on derivatives
recognized in net income, net of tax
Change in pension and postretirement
benefit plan liability, net of tax
Other comprehensive income (loss) on
investments in unconsolidated affiliates,
net of tax
Total other comprehensive income
(loss), net of tax
Comprehensive income
Less: Comprehensive income attributable
to noncontrolling interests
Comprehensive income attributable to
ONEOK
19.1
2.5
(4.2)
(72.2)
(40.6)
86.5
—
69.6
—
—
(1.1)
(1.1)
(8.8)
44.3
—
(1.0)
(139.2)
—
2.2
81.1
(21.4)
17.4
606.6
232.4
13.2
1,228.9
27.9
1,243.6
34.5
1,226.0
(55.9)
(3,674.5)
—
—
4.3
—
63.7
(4.2)
(1.0)
37.1
630.6
236.7
$
374.2
$
1,228.9
$
1,243.6
$
1,221.7
$
(3,674.5) $
393.9
116
Year Ending December 31, 2016
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
Net income
$
738.0
$
1,066.8
$
1,066.8
$
999.4
$
(3,127.5) $
743.5
Other comprehensive income (loss), net of
tax
Unrealized gains (losses) on derivatives,
net of tax
Realized (gains) losses on derivatives
recognized in net income, net of tax
Change in pension and postretirement
benefit plan liability, net of tax
Other comprehensive income (loss) on
investments in unconsolidated affiliates,
net of tax
Total other comprehensive income
(loss), net of tax
Comprehensive income
Less: Comprehensive income attributable
to noncontrolling interests
Comprehensive income attributable to
ONEOK
(35.8)
(78.5)
(108.8)
192.8
(30.3)
—
2.1
(14.6)
723.4
357.6
(10.7)
(26.4)
(16.7)
—
—
—
(1.8)
(1.8)
(48.3)
1,018.5
(106.7)
960.1
(33.4)
—
(3.3)
(145.5)
853.9
61.4
—
5.4
259.6
(2,867.9)
(7.0)
(16.7)
(1.5)
(55.5)
688.0
—
—
5.5
—
363.1
$
365.8
$
1,018.5
$
960.1
$
848.4
$
(2,867.9) $
324.9
117
Condensed Consolidating Balance Sheets
December 31, 2018
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Natural gas and natural gas liquids 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
1,086.8
278.4
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
1,118.1
482.6
2,108.4
Intercompany debt
—
—
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
$
6,579.5
(19,245.1)
(33,784.2) $ 18,231.7
118
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Materials and supplies
Natural gas and natural gas liquids 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
December 31, 2017
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
$
37.2
—
—
—
9.8
47.0
128.3
86.4
41.9
$
— $
—
—
— $
—
—
—
1.3
1.3
—
—
—
—
—
—
—
—
—
5,752.1
2,926.9
416.9
9,095.9
3,133.7
8,627.8
0.2
11,761.7
8,058.4
3,703.1
—
11,761.5
— $
1,203.0
90.3
342.3
80.6
1,716.2
15,431.3
2,775.1
12,656.2
803.0
—
1,007.4
1,810.4
— $
—
—
—
—
—
—
—
—
(16,744.0)
(15,257.8)
(44.4)
(32,046.2)
37.2
1,203.0
90.3
342.3
91.7
1,764.5
15,559.6
2,861.5
12,698.1
1,003.2
—
1,380.1
2,383.3
Total assets
$
9,184.8
$ 11,763.0
$ 11,761.5
$
16,182.8
$
(32,046.2) $ 16,845.9
Liabilities and equity
Current liabilities
Current maturities of long-term debt
Short-term borrowings
Accounts payable
Other current liabilities
Total current liabilities
$
— $
614.7
12.0
65.9
692.6
$
425.0
—
—
85.0
510.0
— $
—
—
—
—
$
7.7
—
1,128.6
328.4
1,464.7
— $
—
—
—
—
432.7
614.7
1,140.6
479.3
2,667.3
Intercompany debt
—
—
8,627.8
6,630.0
(15,257.8)
—
Long-term debt, excluding current
maturities
2,726.4
5,336.4
—
237.9
237.9
—
—
—
—
—
—
—
28.8
—
8,091.6
97.1
111.0
208.1
(44.4)
—
52.7
348.9
(44.4)
401.6
Deferred credits and other liabilities
Deferred income taxes
Other deferred credits
Total deferred credits and other
liabilities
Commitments and contingencies
Equity
Equity excluding noncontrolling interests
in consolidated subsidiaries
Noncontrolling interests in consolidated
subsidiaries
Total equity
Total liabilities and equity
5,527.9
5,916.6
3,133.7
7,693.7
(16,744.0)
5,527.9
—
5,527.9
9,184.8
—
5,916.6
$ 11,763.0
—
3,133.7
$ 11,761.5
$
$
157.5
7,851.2
16,182.8
$
—
157.5
5,685.4
(16,744.0)
(32,046.2) $ 16,845.9
119
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2018
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
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 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)
—
—
—
—
15.3
15.3
(2,122.7)
11.3
(2,111.4)
(1,332.0)
—
912.3
—
—
(925.0)
—
—
—
(1,344.7)
—
(1,332.0)
—
1,248.8
—
—
—
—
—
—
(83.2)
—
—
—
—
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
—
(3.5)
(6.7)
—
—
(7.7)
—
—
16.3
(1.6)
—
—
37.2
—
—
$
12.0
$
— $
— $
— $
— $
12.0
120
Year Ending December 31, 2017
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
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
121
Year Ending December 31, 2016
Parent
Issuer &
Guarantor
Subsidiary
Issuer &
Guarantor
Guarantor
Subsidiary
Combined
Non-Guarantor
Subsidiaries
Consolidating
Entries
Total
(Millions of dollars)
Operating activities
Cash provided by operating activities
$
717.0
$
1,334.5
$
70.0
$
1,353.9
$
(2,122.1) $
1,353.3
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
Borrowing 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
Other, net
Cash used in financing activities
Change in cash and cash equivalents
Change in cash and cash equivalents
included in discontinued operations
Change in cash and cash equivalents
included in continuing operations
Cash and cash equivalents at
beginning of period
Cash and cash equivalents at end of
period
(0.2)
—
(0.2)
(517.6)
—
(63.1)
—
—
—
(0.3)
22.0
(1.7)
(560.7)
156.1
(0.1)
156.0
92.5
—
—
—
(1,332.0)
—
(470.8)
563.9
1,000.0
(2.8)
(1,100.0)
—
7.2
(1,334.5)
—
—
—
—
—
34.9
34.9
(1,332.0)
—
1,222.4
—
—
—
—
—
—
(109.6)
(4.7)
—
(4.7)
5.1
(624.4)
(25.7)
(650.1)
—
(7.5)
(688.5)
—
—
—
(7.7)
—
(0.1)
(703.8)
—
—
—
—
—
—
—
2,664.0
(541.9)
—
—
—
—
—
—
—
2,122.1
—
—
—
—
(624.6)
9.2
(615.4)
(517.6)
(549.4)
—
563.9
1,000.0
(2.8)
(1,108.0)
22.0
5.4
(586.5)
151.4
(0.1)
151.3
97.6
$
248.5
$
— $
0.4
$
— $
— $
248.9
122
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 and applicable SEC rules, our management
concluded that our internal control over financial reporting was effective as of December 31, 2018.
The effectiveness of our internal control over financial reporting as of December 31, 2018, 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, 2018, 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 2019 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 2019 definitive Proxy Statement and is
incorporated herein by this reference.
123
Code of Ethics
Information concerning the code of ethics, or code of business conduct, is set forth in our 2019 definitive Proxy Statement and
is incorporated herein by this reference.
Nominating Committee Procedures
Information concerning the Nominating Committee procedures is set forth in our 2019 definitive Proxy Statement and is
incorporated herein by this reference.
Audit Committee
Information concerning the Audit Committee is set forth in our 2019 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 2019 definitive Proxy Statement and is
incorporated herein by this reference.
ITEM 11.
EXECUTIVE COMPENSATION
Information on executive compensation is set forth in our 2019 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 2019 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 2019 definitive Proxy Statement and is
incorporated herein by this reference.
124
Equity Compensation Plan Information
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2018:
Number of Securities
to be Issued
Upon Exercise of
Outstanding Options,
Warrants and Rights
(a)
2,893,150
323,520
3,216,670
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(b) (3)
$
$
$
42.88
53.95
43.99
Number of Securities
Remaining Available For
Future Issuance Under
Equity Compensation
Plans (Excluding
Securities in Column (a))
(c)
10,077,540
—
10,077,540
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
units 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 percent of the performance units vesting at the end of the
three-year performance period. Column (c) includes 1,469,175; 147,097; and 8,461,268 shares available for future issuance under our
Employee Stock Purchase Plan, Employee Stock Award Program, and Equity Incentive Plan, respectively.
(2) - Includes our Employee Non-Qualified Deferred Compensation 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 $53.95, which represents the 2018 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 2019 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 2019 definitive Proxy Statement and is
incorporated herein by this reference.
125
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, 2018, 2017 and 2016
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2018, 2017 and 2016
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Cash Flows for the years ended
December 31, 2018, 2017 and 2016
Consolidated Statements of Changes in Equity for the years ended
December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
Page No.
60-61
62
63
64-65
67
68-69
70-122
(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)).
126
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 percent 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 percent 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 percent
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 percent
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 percent 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 percent 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)).
127
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 percent 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 percent
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
percent 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
percent 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
percent 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)).
Second 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 6.15
percent Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to ONEOK Partners, L.P.’s Current
Report on Form 8-K filed September 26, 2006 (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 percent
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 percent
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 percent
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)).
128
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
10
10.1
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 percent
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)).
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)).
Sixth 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 3.250 percent
Senior Notes due 2016 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s Current
Report on Form 8-K filed January 26, 2011 (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 percent
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 percent 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 percent 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
(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 percent 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 percent 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)).
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)).
129
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
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)).
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)).
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)).
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)).
130
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
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)).
Third Amended and Restated Limited Liability Company Agreement of ONEOK Partners GP, L.L.C.
effective July 14, 2009 (incorporated by reference to Exhibit 99.1 to ONEOK Partners, L.P.’s Current Report
on Form 8-K filed on July 17, 2009 (File No. 1-12202)).
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)).
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)).
Underwriting Agreement, dated July 10, 2017, between ONEOK, Inc., ONEOK Partners, L.P., ONEOK
Partners Intermediate Limited Partnership and Citigroup Global Markets Inc., Barclays Capital Inc., Merrill
Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC, as representatives of the
several underwriters named therein (incorporated by reference to Exhibit 1.1 from ONEOK, Inc.’s Current
Report on Form 8-K filed July 13, 2017 (File No. 1-13643)).
Equity Distribution Agreement, dated July 19, 2017, by and among ONEOK, Inc. and Merrill Lynch, Pierce,
Fenner & Smith Incorporated, BB&T Capital Markets, a division of BB&T Securities, LLC, Credit Suisse
Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman Sachs & Co. LLC, Jefferies LLC, J.P.
Morgan Securities LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, TD Securities (USA)
LLC, UBS Securities LLC and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 1.1 from
ONEOK, Inc.’s Current Report on Form 8-K filed July 19, 2017 (File No. 1-13643)).
131
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
Letter Agreement between ONEOK, Inc. and John W. Gibson, dated as of December 9, 2013 (incorporated
by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed December 10, 2013 (File
No. 1-13643)).
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)).
Underwriting Agreement, dated January 4, 2018, between ONEOK, Inc. and Credit Suisse Securities (USA)
LLC, as representative of the several underwriters named therein (incorporated by reference to Exhibit 1.1
from ONEOK, Inc.’s Current Report on Form 8-K filed January 9, 2018 (File No. 1-13643)).
Extension Agreement, dated as of January 29, 2016, among ONEOK Partners, L.P., Citibank, N.A., as
administrative agent, swingline lender, a letter of credit issuer and a lender, and the other lenders and letter
of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s
Current Report on Form 8-K filed on February 3, 2016 (File No. 1-12202)).
Underwriting Agreement, dated June 19, 2018, between ONEOK, Inc., ONEOK Partners, L.P., ONEOK
Partners Intermediate Limited Partnership and Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner
& Smith Incorporated, Mizuho Securities USA LLC and Wells Fargo Securities, LLC, as representatives of
the several underwriters named therein (incorporated by reference from Exhibit 1.1 to ONEOK Inc.’s
Current Report on Form 8-K filed June 20, 2018 (File No. 1-13643)).
Extension Agreement, dated as of January 29, 2016, among ONEOK, Inc., Bank of America, N.A., as
administrative agent, swingline lender, a letter of credit issuer and a lender, and the other lenders and letter
of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONEOK. Inc.’s Current Report
on Form 8-K filed on February 3, 2016 (File No. 1-13643)).
Services Agreement among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services,
LLC, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership executed
April 6, 2006, but effective as of April 1, 2006 (incorporated by reference from Exhibit 10.1 to ONEOK,
Inc.’s Current Report on Form 8-K filed April 12, 2006 (File No. 1-13643)).
Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P., dated as of
September 15, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on
Form 8-K filed September 19, 2006 (File No. 1-12202)).
Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners,
L.P. (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed
February 17, 2012 (File No. 1-12202)).
The 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)).
10.36
Not used.
10.37
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)).
132
10.38
Increase and Joinder Agreement, dated as of March 10, 2015, among ONEOK Partners, L.P., Citibank, N.A.,
as administrative agent, 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 March 10, 2015 (File No. 1-2202)).
10.39
Not used.
10.40
Not used.
10.41
Not used.
10.42
10.43
10.44
10.45
10.46
10.47
10.48
10.49
10.50
Amended and Restated Credit Agreement, effective as of January 31, 2014, among ONEOK, Inc., Bank of
America, N.A., as administrative agent, swing-line lender, a letter of credit issuer and a lender, and the other
lenders and letter of credit issuers parties thereto, attached as an annex to that certain Amendment
Agreement, dated as of December 20, 2013 (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s
Current Report on Form 8-K filed December 23, 2013 (File No. 1-13643)).
Amended and Restated Credit Agreement, effective as of January 31, 2014, among ONEOK Partners, L.P.,
Citibank, N.A., as administrative agent, swing-line lender, a letter of credit issuer and a lender, and the other
lenders and letter of credit issuers parties thereto, attached as an annex to that certain Amendment
Agreement, dated as of December 20, 2013 (incorporated by reference to Exhibit 10.1 to ONEOK Partners,
L.P.’s Current Report on Form 8-K filed December 23, 2013 (File No. 1-12202)).
Guaranty Agreement, dated as of January 31, 2014, by ONEOK Partners Intermediate Limited Partnership
in favor of Citibank, N.A., as administrative agent, under the above-referenced Amended and Restated
Credit Agreement (incorporated by reference to Exhibit 10.2 to ONEOK Partners, L.P.’s Quarterly Report on
Form 10-Q for the period ended March 31, 2014, filed May 7, 2014 (File No. 1-12202)).
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)).
Northern Border Partners, L.P. Certificate of Limited Partnership dated July 12, 1993, Certificate of
Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by
reference to Exhibit 3.1 to Northern Border Partners, L.P.’s Annual Report on Form 10-K for the year ended
December 31, 2004, filed on March 14, 2005 (File No. 1-12202)).
Certificate of Amendment to Certificate of Limited Partnership of Northern Border Partners, L.P. dated
May 17, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form
8-K filed on May 23, 2006 (File No. 1-12202)).
133
10.51
10.52
10.53
Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners,
L.P., dated July 20, 2007 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Quarterly
Report on Form 10-Q for the quarter ended June 30, 2007, filed August 3, 2007 (File No. 1-12202)).
Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners,
L.P., dated July 12, 2011 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current
Report on Form 8-K filed July 13, 2011 (File No. 1-12202)).
Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of ONEOK
Partners GP, L.L.C. effective July 14, 2009 (incorporated by reference to Exhibit 10.1 to ONEOK Partners,
L.P.’s Current Report on Form 8-K filed February 17, 2012 (File No. 1-12202)).
10.54
Form of 2019 Restricted Unit Award Agreement, dated February 20, 2019.
10.55
Form of 2019 Performance Unit Award Agreement, dated February 20, 2019.
10.56
10.57
10.58
10.59
10.60
First Amended and Restated Limited Liability Company Agreement of ONEOK ILP GP, L.L.C. effective
July 14, 2009 (incorporated by reference to Exhibit 99.2 to ONEOK Partners, L.P.’s Current Report on Form
8-K filed July 17, 2009 (File No. 1-12202)).
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)).
Form of 2015 Restricted Unit Award Agreement, dated February 18, 2015 (incorporated by reference to
Exhibit 10.59 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015,
filed February 25, 2015 (File No. 1-13643)).
Form of 2015 Performance Unit Award Agreement, dated February 18, 2015 (incorporated by reference to
Exhibit 10.60 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015,
filed February 25, 2015 (File No. 1-13643)).
10.61
Not used.
10.62
21
23
31.1
31.2
32.1
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)).
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 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)).
134
32.2
Certification of Walter S. Hulse pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definitions Document
101.LAB
XBRL Taxonomy Label Linkbase Document
101.PRE
XBRL Taxonomy Presentation Linkbase Document
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, 2018, 2017 and 2016; (iii) Consolidated
Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016; (iv) Consolidated Balance
Sheets at December 31, 2018 and 2017; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2018,
2017 and 2016; (vi) Consolidated Statements of Changes in Equity for the years ended December 31, 2018, 2017 and 2016;
and (vii) Notes to Consolidated Financial Statements.
ITEM 16.
FORM 10-K SUMMARY
None.
135
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 26, 2019
By:
/s/ Walter S. Hulse III
Walter S. Hulse III
Chief Financial Officer 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 26th day of February 2019.
/s/ John W. Gibson
John W. Gibson
Chairman of the Board
/s/ Walter S. Hulse III
Walter S. Hulse III
Chief Financial Officer 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
/s/ Terry K. Spencer
Terry K. Spencer
President, Chief Executive Officer and
Director
/s/ Sheppard F. Miers III
Sheppard F. Miers III
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
136
OUR ASSETS
MIDSTREAM INDUSTRY
Local Distribution Companies
Electric Generation
Large Industrials
Liquefied Natural Gas Exports
W I S C O N S I N
NGL Distribution Pipeline
N G L F R A C T I O N A T O R
N A T U R A L G A S S T O R A G E &
E N D - U S E M A R K E T S
Natural Gas
Pipeline
NGL Gathering
Pipeline
Ethane
Propane
Isobutane
Normal Butane
Natural Gasoline
FEE-BASED
EARNINGS
IN 2018
Natural Gas
Gathering
Residue Gas
Raw Feed NGLs
W E L L H E A D
N A T U R A L G A S
P R O C E S S I N G
P L A N T
Petrochemical
Refining
Heating
Exports
N G L S T O R A G E &
M A R K E T C E N T E R
NEARLY
90%
OPERATIONS
NGL RAW FEED THROUGHPUT
in thousand barrels per day (MBbl/d)
M O N T A N A
M I N N E S O T A
A
N O R T H
D A K O T A
WILLISTON BASIN
S O U T H D A K O T A
W Y O M I N G
B
POWDER RIVER
BASIN
I O W A
N E B R A S K A
I N D I A N A
I L L I N O I S
C O L O R A D O
K A N S A S
M I S S O U R I
K E N T U C K Y
O K L A H O M A
T E N N E S S E E
A R K A N S A S
LEGEND
N E W M E X I C O
G
H
STACK &
SCOOP PLAYS
C
D
F
PERMIAN BASIN
T E X A S
L O U I S I A N A
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
E
I
F
G
H
I
GROWTH PROJECTS
A
B
C
D
E
BOARD OF DIRECTORS
Brian L. Derksen
Retired Global Deputy Chief Executive Officer, Deloitte Touche Tohmatsu Limited
Dallas, Texas
Jim W. Mogg
Retired Chairman, DCP Midstream GP, L.L.C.
Hydro, Oklahoma
Julie H. Edwards
Former Chief Financial Officer, Southern Union Company;
Former Chief Financial Officer, Frontier Oil Corporation
Houston, Texas
Pattye L. Moore
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, 2019
Terry K. Spencer, 59
President and Chief Executive Officer
Derek S. Reiners, 47
Senior Vice President, Finance, and Treasurer
Robert F. Martinovich, 61
Executive Vice President and Chief Administrative Officer
Sheridan C. Swords, 49
Senior Vice President, Natural Gas Liquids
Walter S. Hulse III, 55
Chief Financial Officer and Executive Vice President, Strategic Planning
Charles M. Kelley, 60
Senior Vice President, Natural Gas
and Corporate Affairs
Kevin L. Burdick, 54
Executive Vice President and Chief Operating Officer
Stephen B. Allen, 45
Senior Vice President, General Counsel and Assistant Secretary
Sheppard F. Miers III, 50
Vice President and Chief Accounting Officer
Eric Grimshaw, 66
Vice President, Associate General Counsel and Corporate Secretary
2019 Guidance
2018
2017
2016
895
836
1,080 -
1,165
1,010
NATURAL GAS PROCESSED
in million cubic feet per day (MMcf/d)
ONEOK ANNUAL MEETING
The 2019 annual meeting of shareholders will be held Wednesday, May 22, 2019,
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 (stable)
CORPORATE INFORMATION
2019 Guidance
2018
2017
2016
1,552
1,409
1,800 -
2,000
1,808
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
Demicks Lake Plants I & II (IN PROGRESS) Elk Creek Pipeline (IN PROGRESS)Canadian Valley Plant Expansion (COMPLETED)ONEOK Gas Transportation Expansions (COMPLETED)Sterling III Pipeline Expansion (COMPLETED)Arbuckle II Pipeline & Expansion (IN PROGRESS)West Texas LPG System Expansion I(COMPLETED) & II (IN PROGRESS)Roadrunner and ONEOK WesTex Expansion (COMPLETED)MB-4 & MB-5 NGL Fractionators and Storage (IN PROGRESS) Dear Reader:
We strive to make our annual report informative, relevant
Dear Reader:
and interesting. Please take a few minutes to provide us
with your feedback.
We strive to make our annual report informative, relevant
and interesting. Please take a few minutes to provide us
You may detach the card below and return it by mail, or
with your feedback.
if you prefer to complete the survey online, please visit
www.oneok.com/annualreportsurvey.
You may detach the card below and return it by mail, or
if you prefer to complete the survey online, please visit
www.oneok.com/annualreportsurvey.
2018 ANNUAL REPORT SURVEY
2018 ANNUAL REPORT SURVEY
Please consider the following questions as they pertain to
the annual report wrap (color portion before the Form 10-K).
Which best describes you?
Please consider the following questions as they pertain to
V Retail (individual) investor
the annual report wrap (color portion before the Form 10-K).
V Sell-side analyst
V Other:
Which best describes you?
V Retail (individual) investor
How long have you been a ONEOK shareholder?
V Sell-side analyst
V Less than 2 years V 2-5 years V 6-15 years V 15+ years
V Other:
V Institutional (broker or fund manager) investor
V ONEOK employee or retiree
V Institutional (broker or fund manager) investor
V ONEOK employee or retiree
The report provided adequate insight into ONEOK’s businesses and
How long have you been a ONEOK shareholder?
strategies, including announced growth projects.
V Less than 2 years V 2-5 years V 6-15 years V 15+ years
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
The report provided adequate insight into ONEOK’s businesses and
The foldout cover gave me an adequate overview of ONEOK.
strategies, including announced growth projects.
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
After reading this report, I better understand ONEOK’s role
The foldout cover gave me an adequate overview of ONEOK.
in the midstream industry.
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
After reading this report, I better understand ONEOK’s role
I like the ratio of charts and graphics to text in this report.
in the midstream industry.
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
This report was well-written and easy to understand.
I like the ratio of charts and graphics to text in this report.
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
I found this report helpful when considering my
This report was well-written and easy to understand.
investment strategy.
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
I found this report helpful when considering my
The information in this report most valuable to me is:
investment strategy.
(Select all that apply.)
V Strongly Agree V Agree V Neutral V Disagree V Strongly Disagree
V Written operational summary
V Financial charts
V Asset map
V Growth projects summary tables
The information in this report most valuable to me is:
V Midstream graphic
V Financial tables
(Select all that apply.)
V Operational charts
V Form 10-K
V Written operational summary
V Financial charts
V Asset map
V Growth projects summary tables
I access my annual report online in addition to receiving
V Midstream graphic
V Financial tables
a printed copy.
V Operational charts
V Form 10-K
V Yes V No
I access my annual report online in addition to receiving
Which report type do you prefer?
a printed copy.
V Print V Digital (online) V Neutral
V Yes V No
Comments:
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V Print V Digital (online) V Neutral
Comments:
Thank you for taking the time to complete and return
this survey.
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this survey.
Please remove before mailing.
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.
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Paper from
responsible sources
FSC® C103375
W I L L I S T O N B A S I N
D E M I C K S L A K E
P O W D E R R I V E R B A S I N
E L K C R E E K
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.
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
Mid-Continent, Permian and Rocky Mountain regions with key market centers and an extensive network of natural gas gathering, processing, storage and transportation assets.
O
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C O N W AY,
K A N S A S
S TA C K A N D S C O O P P L AY S
W E S T T E X A S L P G
A R B U C K L E I I
DIVIDEND GROWTH
TOTAL SHAREHOLDER RETURN*
P E R M I A N B A S I N
R O A D R U N N E R
M O N T B E LV I E U ,
T E X A S
100 West Fifth Street
Tulsa, Oklahoma 74103-4298
Post Office Box 871
Tulsa, Oklahoma 74102-0871
www.oneok.com
CONNECTIONS.
Basins. Assets. Markets. Relationships.
2 0 1 8 A N N U A L R E P O R T
2018 FINANCIAL PERFORMANCE
OPERATING INCOME
(MILLIONS OF DOLLARS)
ADJUSTED EBITDA
(MILLIONS OF DOLLARS )
2018
2017
2016
2015
$1,835.5
$996.2
$1,295.8
$1,391.8
2018
2017
2016
2015
$2.43
$2.46
$2.72
$3.245
2018
2017
2016
2015
$1,579.5
$1,849.9
$1,986.9
$2,447.5
MARKET CAP
27
BILLION
YIELD
5∙2%
Market cap and yield as of March 5, 2019
29%
50%
13%
30%
6%
5-YEAR
-25%
3-YEAR
1-YEAR
-15%
-4%
160%
ONEOK
ONEOK
ONEOK Peer Group
S&P 500 Index
ONEOK Peer Group
S&P 500 Index
ONEOK
ONEOK Peer Group
S&P 500 Index
%
0
5
-
%
5
2
-
%
0
%
5
2
%
0
5
%
5
7
%
0
0
1
%
5
2
1
%
0
5
1
%
5
7
1
%
0
0
2
As of Dec. 31, 2018
*Total return represents share-price appreciation and the reinvestment of dividends.