false--12-31FY2019000103968401450007240002152000011900000119000002.723.530.010.01120000000012000000004450162344450162344115326064132390500.011250.0110Our senior notes are governed by indentures containing covenants, including among other provisions, limitations on our ability to place liens on our property or assets and to sell and leaseback our property. The indentures governing our 6.875% senior notes due 2028 include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the remainder of our senior notes include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25% in aggregate principal amount of the outstanding senior notes to declare those senior notes immediately due and payable in full. The indenture for the 7.5% notes due 2023 also contains a provision that allows the holders of the notes to require ONEOK to offer to repurchase all or any part of their notes if a change of control and a credit rating downgrade occur at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any.Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our $2.5 Billion Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1 at December 31, 2019. If we consummate one or more acquisitions in which the aggregate purchase is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter in which the acquisition is completed and the following two quarters. Thereafter, the covenant will decrease to 5.0 to 1. Our $2.5 Billion Credit Agreement includes a $100 million sublimit for the issuance of standby letters of credit and a $200 million sublimit for swingline loans. Under the terms of our $2.5 Billion Credit Agreement, we may request an increase in the size of the facility to an aggregate of $3.5 billion by either commitments from new lenders or increased commitments from existing lenders. Our $2.5 Billion Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit ratings. Based on our current credit ratings, borrowings, if any, will accrue at LIBOR plus 110 basis points, and the annual facility fee is 15 basis points. At December 31, 2019, our ratio of indebtedness to adjusted EBITDA was 4.1 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit Agreement.0.0750.02750.0400.0340.04450.04250.04350.04550.068750.05200.0600.04950.033750.061250.0380.0500.0490.0620.086250.06650.0685We determine our overall expected long-term rate of return on plan assets based on our review of historical returns and economic growth models. We determine our discount rates annually utilizing portfolios of high quality bonds matched to the estimated benefit cash flows of our retirement and other postretirement benefit plans. Bonds selected to be included in the portfolios are only those rated by S&P or Moody’s as an AA or Aa2 rating or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.. 000130000000013000000001100000388000000.500.500.500280000002810000011900000119000001190000011900000119000005510000280620001072750000.001500.03630.02700.0785878000142500029100002689900011013000605800019006000169400044149000038.3555.0055.000.010.01200002000020000200000P54YP40YP60YP54YP40YP3YP3YP2YP5YP5YP25YP88YP77YP50YP5YP5YP5YP2YFor the year ended December 31, 2017, we had no single customer from which we received 10% or more of our consolidated revenues. 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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019.
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.

Commission file number  001-13643
okelogo.jpg
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1520922
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer Identification No.)
 
100 West Fifth Street,
Tulsa,
OK
 
74103
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code   (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common stock, par value of $0.01
OKE
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No .

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  No .

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes   No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.  (Check one)
Large accelerated filer     Accelerated filer     Non-accelerated filer     Smaller reporting company
Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No .

Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on June 28, 2019, was $28.1 billion.

On February 18, 2020, the Company had 413,319,000 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 20, 2020, are incorporated by reference in Part III.


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ONEOK, Inc.
2019 ANNUAL REPORT

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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.


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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 dated November 19, 2018
$2.5 Billion Credit Agreement
ONEOK’s $2.5 billion revolving credit agreement, as amended
AFUDC
Allowance for funds used during construction
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2019
ASU
Accounting Standards Update
Bbl
Barrels, 1 barrel is equivalent to 42 United States gallons
BBtu/d
Billion British thermal units per day
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
Btu
British thermal unit
CFTC
U.S. Commodity Futures Trading Commission
Clean Air Act
Federal Clean Air Act, as amended
Clean Water Act
Federal Water Pollution Control Act Amendments of 1972, as amended
DJ
Denver-Julesburg
DOT
United States Department of Transportation
EBITDA
Earnings before interest expense, income taxes, depreciation and amortization
EPA
United States Environmental Protection Agency
Exchange Act
Securities Exchange Act of 1934, as amended
FERC
Federal Energy Regulatory Commission
Foundation
ONEOK Foundation, Inc.
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
KCC
Kansas Corporation Commission
LIBOR
London Interbank Offered Rate
MBbl/d
Thousand barrels per day
MDth/d
Thousand dekatherms per day
Merger Transaction
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
MMBbl
Million barrels
MMBbl/d
Million barrels per day
MMBtu
Million British thermal units
MMcf/d
Million cubic feet per day
Moody’s
Moody’s Investors Service, Inc.
Natural Gas Act
Natural Gas Act of 1938, as amended
Natural Gas Policy Act
Natural Gas Policy Act of 1978, as amended
NGL(s)
Natural gas liquid(s)
NGL products
Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
Northern Border Pipeline
Northern Border Pipeline Company, a 50% owned joint venture
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OCC
Oklahoma Corporation Commission
ONEOK
ONEOK, Inc.
ONEOK Partners
ONEOK Partners, L.P.
ONEOK Partners Term Loan Agreement
The senior unsecured three-year $1.0 billion term loan agreement dated January 8, 2016, as amended

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OPIS
Oil Price Information Service
Overland Pass Pipeline
Overland Pass Pipeline Company, LLC, a 50% owned joint venture
PHMSA
United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
POP
Percent of Proceeds
Quarterly Report(s)
Quarterly Report(s) on Form 10-Q
Roadrunner
Roadrunner Gas Transmission, LLC, a 50% owned joint venture
RRC
Railroad Commission of Texas
S&P
S&P Global Ratings
SCOOP
South Central Oklahoma Oil Province, an area in the Anadarko Basin in Oklahoma
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
Series E Preferred Stock
Series E Non-Voting, Perpetual Preferred Stock, par value $0.01 per share
STACK
Sooner Trend Anadarko Canadian Kingfisher, an area in the Anadarko Basin in Oklahoma
Tax Cuts and Jobs Act
H.R. 1, the tax reform bill, signed into law on December 22, 2017
Topic 606
Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”
West Texas LPG
West Texas LPG pipeline and Mesquite pipeline
WTI
West Texas Intermediate
WTLPG
West Texas LPG Pipeline Limited Partnership
XBRL
eXtensible Business Reporting Language

The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A, Risk Factors, and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and “Forward-Looking Statements,” in this Annual Report.


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PART I

ITEM 1.    BUSINESS

GENERAL

We are incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.” We are a leading midstream service provider and own one of the nation’s premier NGL systems, connecting NGL supply in the Rocky Mountain, Permian and Mid-Continent regions with key market centers and an extensive network of natural gas gathering, processing, storage and transportation assets. We apply our core capabilities of gathering, processing, fractionating, transporting, storing and marketing natural gas and NGLs through vertical integration across the midstream value chain to provide our customers with premium services while generating consistent and sustainable earnings growth.

Midstream Value Chain
 
Legend
 
valuechaingraphic6a01.gif
 
 
 
 
 
We are connected to supply in natural gas and NGL producing basins and have significant basin diversification, including the Williston, Permian, Powder River and DJ Basins and the STACK and SCOOP areas. In our Natural Gas Gathering and Processing segment, we have more than 3 million dedicated acres in the Williston Basin and approximately 300,000 dedicated acres in the STACK and SCOOP areas. In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the Williston Basin; Oklahoma, including the STACK and SCOOP areas; Kansas; and the Texas Panhandle. We also have a significant presence in the Permian Basin.

 
 
Natural Gas Gathering & Processing
 
 
 
 
 
 
 
Natural Gas Liquids
 
 
 
 
 
 
 
Natural Gas Pipelines
 
 
 
 
 
 
 
 
 
Raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. Most raw natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline, which remain in a mixed unfractionated form.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Once processed, residue natural gas is recompressed and delivered to intrastate and interstate natural gas pipelines.
Gathered wellhead natural gas is directed to our processing plants to remove NGLs, resulting in residue natural gas (primarily methane).
 
 
 
 
 
 
 
 
valuechain2graphic3.gif
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NGLs extracted at processing plants, both third-party and our own, are then gathered by our NGL gathering pipelines.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gathered NGLs are directed to our downstream fractionators in the Mid-Continent region and Mont Belvieu, Texas, to be separated into purity products.
 
 
 
 
 
 
 
 
 
Residue natural gas is transported to storage facilities and end-users, such as large industrial customers, natural gas and electric utilities serving commercial and residential consumers, and international markets through liquefied natural gas exports.

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purity products are stored or distributed to our customers, such as petrochemical companies, propane distributors, heating fuel users, ethanol producers, refineries and exporters.
 
 
 
 
 
 
 
 
 
 
 
 
 

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EXECUTIVE SUMMARY

Business Update and Market Conditions - We operate primarily fee-based businesses in each of our three reportable segments, and our consolidated earnings were approximately 90% fee-based in 2019. Volumes increased across our system in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in 2019, compared with 2018, as a result of our completed capital-growth projects, continued drilling and producer improvements in production due to enhanced completion techniques, offset partially by natural production declines. Since the beginning of 2018, we have completed several capital-growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas and NGL infrastructure, and expect capital expenditures to decrease in 2020 and 2021, compared with 2019. Our NGL projects in the Gulf Coast allow flexibility to add NGL fractionators, NGL storage and, potentially, new export facilities in the future. We expect these projects to meet the needs of producers, natural gas processors and the petrochemical industry that require additional midstream infrastructure to accommodate increasing supply and demand.

We experienced fluctuating NGL location price differentials due to increased supply, increased demand in the Mid-Continent region, infrastructure constraints and slower demand growth in the Gulf Coast due primarily to delays in the startup of petrochemical facilities and constrained NGL export facilities. The Conway-to-Mont Belvieu OPIS price differential for ethane in ethane/propane mix averaged $0.07 per gallon in 2019, compared with $0.15 per gallon in 2018, which resulted in lower earnings from our optimization and marketing activities in our Natural Gas Liquids segment. We expect narrower NGL location price differentials in 2020.

Rocky Mountain Region - We expect to benefit from increased production in this region, which includes the Williston, Powder River and DJ Basins. In our Natural Gas Gathering and Processing segment, gathered and processed volumes increased in 2019, compared with 2018, due primarily to our capital-growth projects, new well connections and increased producer productivity. Our Demicks Lake I natural gas processing plant was placed in service in October 2019, and we expect it to reach its 200 MMcf/d capacity in the first quarter 2020 due to natural gas flaring by producers on our more than 3 million dedicated acres in the Williston Basin. In addition, we completed construction of our Demicks Lake II natural gas processing plant in January 2020. With continued volume growth expected, we are in the process of expanding our Bear Creek plant by 200 MMcf/d, which is expected to be completed in first quarter 2021, and recently announced plans to construct our Demicks Lake III natural gas processing plant, with capacity of 200 MMcf/d and expected completion in the third quarter 2021. Upon completion of these projects, our total processing capacity will be approximately 1.9 Bcf/d in the Williston Basin and is expected to help producers meet North Dakota’s natural gas capture targets and add incremental NGLs to our NGL gathering system.

In our Natural Gas Liquids segment, we announced the completion of our Elk Creek pipeline in December 2019. We are the largest NGL takeaway provider and expect our NGL pipelines to transport more than 240 MBbl/d of NGLs out of this region by the end of the first quarter 2020 due to a combination of growth in volumes from our new and existing processing plants, third-party processing plants and volumes previously transported by rail. In addition, we recently announced an expansion of our Elk Creek pipeline to 400 MBbl/d by adding additional pump stations. The project is expected to be fully completed in the third quarter 2021, with a portion of this incremental capacity available as early as first quarter 2021. In April 2019, we announced a project to extend our Bakken NGL pipeline into an area of the Williston Basin with limited access to NGL pipeline takeaway capacity. This project will provide connectivity for third-party processing plants to key NGL market centers as well as provide additional volumes to our Elk Creek pipeline. To accommodate expected volumes, we are also expanding our Mid-Continent NGL fractionation facilities by 65 MBbl/d and constructing an extension of our Arbuckle II pipeline farther north.

Mid-Continent Region - In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the STACK and SCOOP areas where volumes continued to increase in 2019, compared with 2018. We expect continued demand for our services from producers that need takeaway capacity for natural gas and NGLs out of this region. In our Natural Gas Gathering and Processing segment, natural gas gathered and processed volumes increased in this region in 2019, compared with 2018, due primarily to new well connections. We expect volumes in this region to decline modestly in 2020, compared with 2019.

Our Natural Gas Pipelines segment transports natural gas from more than 35 natural gas processing plants in Oklahoma. We completed pipeline expansions to provide increased westbound transportation services from the STACK area to multiple interstate pipeline delivery points in western Oklahoma and a 150 MMcf/d eastbound expansion from the STACK and SCOOP areas to an eastern Oklahoma interstate pipeline delivery point.

Permian Basin - We expect our Natural Gas Liquids and Natural Gas Pipelines business segments to continue to benefit from increased production in the Permian Basin from the highly productive Delaware and Midland Basins. In our Natural Gas Liquids segment, we are well-positioned in the Permian Basin through our West Texas LPG pipeline system. Due to our

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expansion of the system in the third quarter 2018 and new plant connections, volumes increased in 2019, compared with 2018. We expect volumes to continue to increase on our West Texas LPG pipeline system as our previously announced second and third expansions are completed, which will increase the mainline capacity out of the Permian Basin by 80 MBbl/d in the first quarter 2020 and 40 MBbl/d in the first quarter 2021, respectively, as well as connect our West Texas LPG pipeline with our Arbuckle II pipeline in north Texas. In addition, we recently announced the fourth expansion of our West Texas LPG pipeline system by 100 MBbl/d, which is expected to be completed in the second quarter 2021. These projects are expected to position our West Texas LPG pipeline system for significant NGL volume growth and are backed by long-term acreage and/or plant dedications.

In our Natural Gas Pipelines segment, our Roadrunner joint venture and our WesTex pipeline are well-positioned to serve growth in the Permian Basin. The Roadrunner pipeline connects with our existing natural gas pipeline and storage infrastructure in Texas and, together with our completed WesTex intrastate natural gas pipeline expansion project, creates future opportunities for us to deliver natural gas to Mexico and transport natural gas to other markets in the region.

Gulf Coast - Demand for NGLs is expected to increase at the Mont Belvieu, Texas, NGL market center as new world-scale ethylene production projects, petrochemical plant expansions and NGL export facilities continue to be completed. We are constructing our Arbuckle II pipeline to support expected supply growth and transport NGLs to the Gulf Coast market center and have announced an expansion of our Arbuckle II pipeline to a total capacity of 500 MBbl/d. NGL supply growth and other new NGL pipelines recently completed or being constructed, including our Elk Creek and West Texas LPG pipeline projects, are increasing NGL deliveries to Mont Belvieu, Texas. While we have significant NGL fractionation and storage assets in this area, additional capacity is needed to accommodate expected volume growth. To respond to this need, we are constructing two additional 125 MBbl/d fractionators with related infrastructure in Mont Belvieu, Texas, MB-4 and MB-5, which are both fully contracted. In December 2019, we completed construction of 75 MBbl/d of the MB-4 capacity, with the remaining 50 MBbl/d to be completed in the first quarter 2020, and MB-5 is expected to be completed in the first quarter 2021. Following the completion of MB-4 and MB-5, we expect our NGL fractionation capacity to be approximately 600 MBbl/d in the Gulf Coast and more than 1 MMBbl/d across our entire system. Our MB-5 project also includes system expansions that provide infrastructure capacity to support additional assets as we continue to evaluate opportunities for fractionation, storage and, potentially, export facilities to meet the supply and demand for NGLs.

See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report for more information on our growth projects, results of operations, liquidity and capital resources.

BUSINESS STRATEGY

Our primary business strategy is to maintain prudent financial strength and flexibility while growing our fee-based earnings and dividends per share with a focus on safe, reliable, environmentally responsible, legally compliant and sustainable operations for our customers, employees, contractors and the public through the following:
Operate in a safe, reliable, environmentally responsible and sustainable manner - environmental, safety and health continues to be a primary focus for us, and our emphasis on personal and process safety has produced improvements in the key indicators we track. We also continue to look for ways to reduce our environmental impact by conserving resources and utilizing more efficient technologies. In 2019, we were added to the Dow Jones Sustainability North America Index, which recognizes companies for industry-leading environmental, social and governance performance;
Pursue organic investments in our existing operating regions to support earnings growth - we expect our investment in capital projects to create stable earnings growth that positions us to grow our dividend. In 2019, we paid dividends of $3.53 per share, an increase of 9% compared with the prior year. Our dividend increase and expected future dividend growth is due primarily to earnings growth from capital projects;
Manage our balance sheet and maintain investment-grade credit ratings - we seek to maintain investment-grade credit ratings, fund capital-growth projects and begin to pay down debt. We expect to benefit from increasing cash flows from operations in 2020, which we expect to reduce leverage and fund capital-growth projects. At December 31, 2019, we had no borrowings outstanding under our $2.5 Billion Credit Agreement, $220 million of commercial paper outstanding and $21 million of cash and cash equivalents; and
Attract, select, develop, motivate, challenge and retain a diverse group of employees to support strategy execution - we continue to execute on our recruiting strategy that targets professional and field personnel in our operating areas. We also continue to focus on employee development efforts with our current employees and monitor our benefits and compensation package to remain competitive.


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NARRATIVE DESCRIPTION OF BUSINESS

We report operations in the following business segments:
Natural Gas Gathering and Processing;
Natural Gas Liquids; and
Natural Gas Pipelines.

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma.

Rocky Mountain region - The Williston Basin is located in portions of North Dakota and Montana and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations, and is an active drilling region. Our completed capital-growth projects in the Williston Basin have increased our gathering and processing capacity and allow us to capture increased natural gas production from new wells and previously flared natural gas production.

The Powder River Basin is primarily located in Wyoming, which includes the NGL-rich Niobrara Shale and Frontier, Turner and Sussex formations where we provide gathering and processing services to customers in the eastern portion of Wyoming.

Mid-Continent region - The Mid-Continent region is an active drilling region and includes the oil-producing, NGL-rich STACK and SCOOP areas and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations of Oklahoma and Kansas, and the Hugoton and Central Kansas Uplift Basins of Kansas.

 
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Property - Our Natural Gas Gathering and Processing segment owns the following assets:
18,900 miles of natural gas gathering pipelines;
ten natural gas processing plants with 1.0 Bcf/d of processing capacity in the Mid-Continent region, and 12 natural gas processing plants with 1.5 Bcf/d of processing capacity in the Rocky Mountain region; and
14 MBbl/d of NGL fractionation capacity at various natural gas processing plants.


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In addition, we have access to up to 200 MMcf/d of processing capacity in the Mid-Continent region through a long-term processing services agreement with an unaffiliated third party.

We are in the process of expanding our Bear Creek plant by 200 MMcf/d and recently announced plans to construct our Demicks Lake III natural gas processing plant, with capacity of 200 MMcf/d, in the core of the Williston Basin. The additional capacity from these projects is excluded from the assets listed above.

See “Recent Developments” in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report for more information on our growth projects.

Sources of Earnings - Earnings for this segment are derived primarily from the following types of service contracts:
POP with fee contracts with no producer take-in-kind rights - We purchase raw natural gas and charge contractual fees for providing midstream services, which include gathering, treating, compressing and processing the producer’s natural gas. After performing these services, we sell the commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees. This type of contract represented 63% and 60% of supply volumes in this segment for 2019 and 2018, respectively.
POP with fee contracts with producer take-in-kind rights - We purchase a portion of the raw natural gas stream, charge fees for providing the midstream services listed above, return primarily the residue natural gas to the producer, sell the remaining commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees. This type of contract represented 33% and 36% of supply volumes in this segment for 2019 and 2018, respectively.
Fee-only - Under this type of contract, we charge a fee for the midstream services we provide, based on volumes gathered, processed, treated and/or compressed. Our fee-only contracts represented 4% of supply volumes in this segment in 2019 and 2018.

For commodity sales, we contract to deliver residue natural gas, condensate and/or unfractionated NGLs to downstream customers at a specified delivery point. Our sales of NGLs are primarily to our affiliate in the Natural Gas Liquids segment.

Utilization - The utilization rates for our natural gas processing plants were 84% and 83% for 2019 and 2018, respectively. We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service.

Unconsolidated Affiliates - Our Natural Gas Gathering and Processing segment includes the following unconsolidated affiliates:
49% ownership interest in Bighorn Gas Gathering, which gathers dry natural gas produced in the Powder River Basin;
42.6% ownership interest in Fort Union Gas Gathering, which gathers dry natural gas produced in the Powder River Basin and delivers it to the interstate pipeline system;
35% ownership interest in Lost Creek Gathering Company, which gathers natural gas produced from conventional dry natural gas wells in the Wind River Basin of central Wyoming and delivers it to the interstate pipeline system; and
10.2% ownership interest in Venice Energy Services Co., a natural gas processing facility near Venice, Louisiana.

See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our unconsolidated affiliates.

Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the transportation or sale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. Although the FERC has made no specific declaration as to the jurisdictional status of our natural gas processing operations or facilities, our natural gas processing plants are primarily involved in extracting NGLs and, therefore, are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe our natural gas gathering facilities and operations meet the criteria used by the FERC for nonjurisdictional natural gas gathering facility status. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. We transport residue natural gas from certain of our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act. Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, to varying degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.



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Natural Gas Liquids

Overview - Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL products, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston, Powder River and DJ Basins. We provide midstream services to producers of NGLs and deliver those products to the two primary market centers: one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated NGL gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas Panhandle are connected to our NGL gathering systems. We own and operate truck- and rail-loading and -unloading facilities connected to our NGL fractionation and pipeline assets. We also own FERC-regulated NGL distribution pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. A portion of our ONEOK North System transports refined petroleum products, including unleaded gasoline and diesel, from Kansas to Iowa.

 
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Property - Our Natural Gas Liquids segment owns the following assets:
8,380 miles of gathering pipelines with peak capacity of 1,820 MBbl/d, including 5,550 miles of FERC-regulated pipelines with peak capacity of 920 MBbl/d;
4,490 miles of distribution pipelines with peak capacity of 1,400 MBbl/d, including 4,460 miles of FERC-regulated pipelines with peak capacity of 1,360 MBbl/d;
eight NGL fractionators with combined operating capacity of 870 MBbl/d (includes interests in our proportional share of operating capacity), including 520 MBbl/d in the Mid-Continent region and 350 MBbl/d in the Gulf Coast region;
one isomerization unit with operating capacity of 10 MBbl/d;
one ethane/propane splitter with operating capacity of 40 MBbl/d;
six NGL storage facilities with operating storage capacity of 20 MMBbl; and
eight NGL product terminals.


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In addition, we lease 10 MMBbl of annual pipeline capacity near our ONEOK North System and have access to 5 MMBbl of combined NGL storage capacity at facilities in Kansas and Texas and 60 MBbl/d of NGL fractionation capacity in the Gulf Coast through service agreements.

Our uncompleted growth projects are excluded from the assets listed above and include:
gathering pipelines, including expansions, with combined operating capacity of 880 MBbl/d;
the MB-5 fractionator in the Gulf Coast with operating capacity of 125 MBbl/d;
remaining fractionation capacity on the MB-4 fractionator in the Gulf Coast of 50 MBbl/d; and
additional fractionation capacity in the Mid-Continent of 65 MBbl/d.

See “Recent Developments” in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report for more information on our growth projects.

Sources of Earnings - Earnings for our Natural Gas Liquids segment are derived primarily from commodity sales and fee-based services. We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment. Our business activities are categorized as follows:
Exchange services - We utilize our assets to gather, transport, treat and fractionate unfractionated NGLs, thereby converting them into marketable NGL products delivered to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments that provide a minimum level of revenues regardless of volumetric throughput. Our exchange services activities are primarily fee-based and include some rate-regulated tariffs; however, we also capture certain product price differentials through the fractionation process.
Transportation and storage services - We transport NGL products and refined petroleum products, primarily under FERC-regulated tariffs. Tariffs specify the maximum rates we may charge our customers and the general terms and conditions for transportation service on our pipelines. Our storage activities consist primarily of fee-based NGL storage services at our Mid-Continent and Gulf Coast storage facilities.
Optimization and marketing - We utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials through the purchase and sale of NGLs and NGL products. We primarily transport NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers. Our marketing activities also include utilizing our NGL storage facilities to capture seasonal price differentials. A growing portion of our marketing activities serves truck and rail markets. Our isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas.

In many of our exchange services contracts, we purchase the unfractionated NGLs at the tailgate of the processing plant and deduct contractual fees related to the transportation and fractionation services we must perform before we can sell them as NGL products. To the extent we hold unfractionated NGLs in inventory, the related contractual fees will not be recognized until the unfractionated inventory is fractionated and sold.

Utilization - The utilization rates for our various assets, including leased assets, have been impacted by ethane rejection. The utilization rates for 2019 and 2018, respectively, were as follows:
our NGL gathering pipelines were 78% in both years;
our NGL distribution pipelines were 63% and 59%; and
our NGL fractionators were 84% and 85%.

We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service. Our fractionation utilization rate reflects approximate proportional capacity associated with our ownership interests.

Unconsolidated Affiliates - Our Natural Gas Liquids segment includes the following unconsolidated affiliates:
50% ownership interest in Overland Pass Pipeline Company, which operates an interstate NGL pipeline system extending 760 miles, originating in Wyoming and Colorado and terminating in Kansas;
50% ownership interest in Chisholm Pipeline Company, which operates an interstate NGL pipeline system extending 185 miles from origin points in Oklahoma and terminating in Kansas; and
50% ownership interest in Heartland Pipeline Company, which operates a terminal and pipeline system that transports refined petroleum products in Kansas, Nebraska and Iowa.


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See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Government Regulation - The operations and revenues of our NGL pipelines are regulated by various state and federal government agencies. Our interstate NGL pipelines are regulated by the FERC, which has authority over the terms and conditions of service; rates, including depreciation and amortization policies; and initiation of service. In Oklahoma, Kansas and Texas, certain aspects of our intrastate NGL pipelines that provide common carrier service are subject to the jurisdiction of the OCC, KCC and RRC, respectively.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment provides transportation and storage services to end users through its wholly owned assets and its 50% ownership interests in Northern Border Pipeline and Roadrunner.

Interstate Pipelines - Our interstate pipelines are regulated by the FERC and are located in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include:
Midwestern Gas Transmission, which is a bidirectional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines that have access to both the Utica Shale and the Marcellus Shale at the Chicago Hub near Joliet, Illinois;
Viking Gas Transmission, which is a bidirectional system that interconnects with a TransCanada Corporation pipeline at the United States border near Emerson, Canada, and ANR Pipeline Company near Marshfield, Wisconsin;
Guardian Pipeline, which interconnects with several pipelines at the Chicago Hub near Joliet, Illinois, and with local natural gas distribution companies in Wisconsin; and
OkTex Pipeline, which has interconnections with several pipelines in Oklahoma, Texas and New Mexico.

Intrastate Pipelines - Our intrastate natural gas pipeline assets in Oklahoma transport natural gas through the state and have access to the major natural gas production areas in the Mid-Continent region, which include the STACK and SCOOP areas and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing formations in the Texas Panhandle, including the Granite Wash formation and Delaware and Midland Basins in the Permian Basin. These pipelines are capable of transporting natural gas throughout the western portion of Texas, including the Waha area where other pipelines may be accessed for transportation to western markets, exports to Mexico, the Houston Ship Channel market to the east and the Mid-Continent market to the north. Our intrastate natural gas pipeline assets also have access to the Hugoton and Central Kansas Uplift Basins in Kansas.


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Property - Our Natural Gas Pipelines segment owns the following assets:
1,500 miles of FERC-regulated interstate natural gas pipelines with 3.5 Bcf/d of peak transportation capacity;
5,100 miles of state-regulated intrastate transmission pipelines with peak transportation capacity of 4.3 Bcf/d; and
six underground natural gas storage facilities with 52.2 Bcf of total active working natural gas storage capacity.

Our storage includes two underground natural gas storage facilities in Oklahoma, two underground natural gas storage facilities in Kansas and two underground natural gas storage facilities in Texas.

Sources of Earnings - Earnings in this segment are derived primarily from transportation and storage services.

Our transportation earnings are primarily fee-based from the following types of services:
Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates the customer to pay regardless of usage. Under this type of contract, the customer pays a monthly fixed fee and incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or store. Under the firm service contract, the customer generally is guaranteed access to the capacity they reserve.
Interruptible service - Under interruptible service transportation agreements, the customer may utilize available capacity after firm service requests are satisfied. The customer is not guaranteed use of our pipelines unless excess capacity is available.

Our regulated natural gas transportation services contracts are based upon rates stated in the respective tariffs, which have generally been established through shipper specific negotiation, discounts and negotiated settlements. The rates are filed with FERC or the appropriate state jurisdictional agencies. In addition, customers typically are assessed fees, such as a commodity charge, and we may retain a percentage or specified volume of natural gas in-kind based on the natural gas volumes transported.

Our storage earnings are primarily fee-based from the following types of services:
Firm service - Customers reserve a specific quantity of storage capacity, including injection and withdrawal rights, and generally pay fixed fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically have terms longer than one year.
Park-and-loan service - An interruptible storage service offered to customers providing the ability to park (inject) or loan (withdraw) natural gas into or out of our storage, typically for monthly or seasonal terms. Customers reserve the

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right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity is available.

Utilization - Our natural gas pipelines were 98% and 96% subscribed in 2019 and 2018, respectively, and our natural gas storage facilities were 64% subscribed in both 2019 and 2018.

Unconsolidated Affiliates - Our Natural Gas Pipelines segment includes the following unconsolidated affiliates:
50% ownership interest in Northern Border Pipeline, which owns a FERC-regulated interstate pipeline that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, and the Williston Basin in North Dakota to a terminus near North Hayden, Indiana.
50% ownership interest in Roadrunner, a bidirectional pipeline, which has the capacity to transport 570 MMcf/d of natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas, and has capacity to transport approximately 1.0 Bcf/d of natural gas from the Delaware Basin to the Waha area. We are the operator of Roadrunner.

See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Government Regulation - Interstate - Our interstate natural gas pipelines are regulated under the Natural Gas Act, which gives the FERC jurisdiction to regulate virtually all aspects of this business, such as transportation of natural gas, rates and charges for services, construction of new facilities, depreciation and amortization policies, acquisition and disposition of facilities, and the initiation and discontinuation of services.

Intrastate - Our intrastate natural gas pipelines in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively, and by the FERC under the Natural Gas Policy Act for certain services where we deliver natural gas into FERC regulated natural gas pipelines. While we have flexibility in establishing natural gas transportation rates with customers, there is a maximum rate that we can charge our customers in Oklahoma and Kansas and for the services regulated by the FERC. In Texas and Kansas, natural gas storage may be regulated by the state and by the FERC for certain types of services. In Oklahoma, natural gas storage operations are not subject to rate regulation by the state, and we have market-based rate authority from the FERC for certain types of services.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Market Conditions and Seasonality

We operate primarily fee-based businesses in each of our three reportable segments, and our consolidated earnings were approximately 90% fee-based in 2019. While our Natural Gas Gathering and Processing and Natural Gas Liquids segments generate primarily fee-based earnings, those segments’ results of operations are exposed to volumetric risk. We are exposed to volumetric risk from declining well productivity, reduced drilling activity, severe weather disruptions, operational outages and ethane rejection.

Supply and Demand - Supply for each of our segments depends on crude oil and natural gas drilling and production activities, which are driven by the strength of the economy; the decline rate of existing production; producer access to capital; producer firm commitments to transportation pipelines; natural gas, crude oil and NGL prices; or the demand for each of these products from end users.

Demand for gathering and processing services is dependent on natural gas production by producers in the regions in which we operate. State requirements in North Dakota for producers to reduce natural gas flaring have increased the need for our services to capture, gather and process natural gas. Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations affect the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, transportation and fractionation services. Natural gas and NGL products are affected by economic conditions and the demand associated with the various industries that utilize the commodities, such as butanes and natural gasoline used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil. Ethane, propane, normal butane and natural gasoline are also used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fibers. Propane is also used to heat homes and businesses. Demand for NGLs is expected to increase at the Mont Belvieu, Texas, NGL market center as new world-scale ethylene production projects, petrochemical plant expansions and NGL export facilities continue to be completed.


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Commodity Prices - Our earnings are primarily fee-based in all three of our segments, with limited commodity price risk. In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. In our Natural Gas Liquids segment, we are exposed to commodity price risk associated with changes in the price of NGLs; the location differential between the Mid-Continent, Chicago, Illinois, and Gulf Coast regions; and the relative price differential between natural gas, NGLs and individual NGL products, which affect our NGL purchases and sales, our exchange services, transportation and storage services, and optimization and marketing financial results. NGL storage revenue may be affected by price volatility and forward pricing of NGL physical contracts versus the price of NGLs on the spot market. In our Natural Gas Pipelines segment, we are exposed to commodity price risk associated with (i) changes in the price of natural gas, which impact our fuel costs and retained fuel in-kind received for our services; and (ii) the differential between forward pricing of natural gas physical contracts and the price of natural gas on the spot market, which affects our natural gas storage revenue.

See additional discussion regarding our commodity price risk and related hedging activities under “Commodity Price Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report.

Seasonality - Cold temperatures usually increase demand for natural gas and certain NGL products, such as propane, the main heating fuels for homes and businesses. Warm temperatures usually increase demand for natural gas used in gas-fired electric generation for residential and commercial cooling, as well as agriculture-related equipment like irrigation pumps and crop dryers. Demand for butanes and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, are also subject to some variability during seasonal periods when certain government restrictions on motor fuel blending products change. During periods of peak demand for a certain commodity, prices for that product typically increase.

Extreme weather conditions, seasonal temperature changes and the impact of temperature and humidity on the mechanical abilities of the processing equipment impact the volumes of natural gas gathered and processed and NGL volumes gathered, transported and fractionated. Power interruptions and inaccessible well sites as a result of severe storms or freeze-offs, a phenomenon where water produced from natural gas freezes at the wellhead or within the gathering system, may cause a temporary interruption in the flow of natural gas and NGLs.

In our Natural Gas Pipelines segment, natural gas storage is necessary to balance the relatively steady natural gas supply with the seasonal demand of residential, commercial and electric-generation users.

Competition - We compete for natural gas and NGL supply with other midstream companies and major integrated oil companies and independent exploration and production companies that have gathering and processing assets, fractionators, intrastate and interstate pipelines and storage facilities. The factors that typically affect our ability to compete for natural gas and NGL supply are:
quality of services provided;
producer drilling activity;
proceeds remitted and/or fees charged under our contracts;
proximity of our assets to natural gas and NGL supply areas and markets;
location of our assets relative to those of our competitors;
efficiency and reliability of our operations;
receipt and delivery capabilities for natural gas and NGLs that exist in each pipeline system, plant, fractionator and storage location;
the petrochemical industry’s level of capacity utilization and feedstock requirements;
current and forward natural gas and NGL prices; and
cost of and access to capital.

We have responded by making capital investments to access and connect new supplies with end-user demand; increasing gathering, processing, fractionation and pipeline capacity; increasing storage, withdrawal and injection capabilities; and reducing operating costs so that we compete effectively. Our competitors also continue to invest in midstream infrastructure to address the growing natural gas and NGL supply and market demand. Our and our competitors’ infrastructure projects may affect commodity prices and compete with and could displace supply volumes from the Mid-Continent and Rocky Mountain regions and the Permian Basin where our assets are located. We believe our assets are located strategically, connecting diverse supply areas to market centers.

Customers - Our Natural Gas Gathering and Processing and Natural Gas Liquids segments derive services revenue from major and independent crude oil and natural gas producers. Our Natural Gas Liquids segment’s customers also include NGL and

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natural gas gathering and processing companies. Our downstream commodity sales customers are primarily utilities, large industrial companies, natural gasoline distributors, propane distributors, municipalities and petrochemical, refining and marketing companies. Our Natural Gas Pipeline segment’s assets primarily serve local natural gas distribution companies, electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies. Our utility customers generally require our services regardless of commodity prices. See discussion regarding our customer credit risk under “Counterparty Credit Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report.

Other

Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own a 17-story office building (ONEOK Plaza) with 517,000 square feet of net rentable space and a parking garage in downtown Tulsa, Oklahoma, where our headquarters are located. ONEOK Leasing Company, L.L.C. leases excess office space to others and operates our headquarters office building. ONEOK Parking Company, L.L.C. owns and operates a parking garage adjacent to our headquarters.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

Environmental Matters - We are subject to a variety of historical preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands and waterways preservation, cultural resources protection, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect adversely our results of operations and cash flows. In addition, emissions controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us.

Some scientists have determined that GHG emissions endanger public health and the environment because emissions of such gases may contribute to warming of the earth’s atmosphere and other climatic changes. GHG emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at issues associated with climate change. Various federal and state legislative proposals have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally binding reductions in emissions of GHGs.

Our environmental actions focus on minimizing the impact of our operations on the environment. These actions include: (i) developing and maintaining an accurate GHG emissions inventory according to current rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and NGL fractionation facilities; (iii) following developing technologies for emissions control and the capture of carbon dioxide to keep it from reaching the atmosphere; and (iv) utilizing practices to reduce the loss of methane from our facilities. In addition, many of our compressor station facilities are designed and operated with electric-driven compression units, which reduce the potential emission from these facilities, including GHG emissions.

We participate in the EPA’s Natural Gas STAR Program to reduce voluntarily methane emissions. We continue to focus on maintaining low methane gas release rates through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.

We believe it is likely that future governmental legislation and/or regulation may require us either to limit GHG emissions from our operations, to purchase allowances for such emissions or to be subject to a carbon emissions tax. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations, when they will become effective or the impact on our results of operations. In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted.


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For additional information regarding the potential impact of laws and regulations on our operations see Item 1A “Risk Factors.”

Pipeline Safety - We are subject to PHMSA safety regulations, including pipeline asset integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) increased maximum penalties for violating federal pipeline safety regulations, directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us and may result in the imposition of more stringent regulations.

In 2015, PHMSA issued notices of proposed rule-making for hazardous liquid pipeline safety regulations, natural gas transmission and gathering lines and underground natural gas storage facilities, known as “the Mega Rule.” Due to the large number of rules being considered, PHMSA partitioned the new rulemaking into three sections. To date, the first section of rules was finalized and published in 2019 in the federal register. These final rules mostly address congressional mandates due to former pipeline safety reauthorizations. Coupled together, these new rules provide increased requirements for operating and maintenance, integrity management, public awareness and civil/criminal penalties. The potential capital and operating expenditures related to the new regulations are not fully known, but we do not anticipate a material impact to our planned capital or operations and maintenance costs resulting from compliance with the new or pending regulations. In 2019, legislation was introduced to reauthorize PHMSA through 2024. If passed, requirements for operations and maintenance, integrity management, public awareness, civil and criminal penalties could be increased. The potential capital and operating expenditures related to the proposed regulations are unknown, but we do not anticipate a material impact to our planned capital or operations and maintenance costs resulting from compliance with the current or pending regulations.

Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at issues associated with climate change. We monitor all relevant legislation and regulatory initiatives to assess the potential impact on our operations and otherwise take efforts to limit GHG emissions from our facilities, including methane. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual GHG emissions reporting from affected facilities and the carbon dioxide emission equivalents for the natural gas delivered by us and the emission equivalents for all NGLs produced by us as if all of these products were combusted, even if they are used otherwise.

Our 2018 total emissions reported pursuant to EPA requirements were approximately 60 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers and produced as if all such fuel and NGL products were combusted. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce GHG emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rule-making associated with GHG emissions from the oil and natural gas industry. At this time, no rule or legislation has been enacted that assesses any material costs, fees or expenses on any of these emissions.

We monitor proposed and final rule-makings. At this time, we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations and EPA actions. However, the EPA may issue additional regulations, responses, amendments and/or policy guidance, which could alter our present expectations. Generally, EPA rule-makings require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities.

Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released the Chemical Facility Anti-Terrorism Standards in 2007, and the new final rule associated with these regulations was issued in December 2014. We provided information regarding our chemicals via Top-Screens submitted to Homeland Security, and our facilities subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, one of our facilities has been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to

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complete Site Security Plans, including possible physical security enhancements. We do not expect the cost of the Site Security Plans to have a material impact on our results of operations, financial position or cash flows.

Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration and the DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.

EMPLOYEES

At January 31, 2020, we employed 2,882 people.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

All executive officers are elected annually by our Board of Directors. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.
Name and Position
 
Age
 
Business Experience in Past Five Years
John W. Gibson
 
67

 
2011 to present
 
Chairman of the Board, ONEOK
Chairman of the Board
 
 
 
2007 to 2017
 
Chairman of the Board, ONEOK Partners
Terry K. Spencer
 
60

 
2014 to present
 
President and Chief Executive Officer, ONEOK
President and Chief Executive Officer
 
 
 
2014 to 2017
 
President and Chief Executive Officer, ONEOK Partners
 
 
 
 
2014 to present
 
Member of the Board of Directors, ONEOK
 
 
 
 
2014 to 2017
 
Member of the Board of Directors, ONEOK Partners
Robert F. Martinovich
 
62

 
2015 to present
 
Executive Vice President and Chief Administrative Officer, ONEOK
Executive Vice President and Chief Administrative Officer
 
 
 
2015 to 2017
 
Executive Vice President and Chief Administrative Officer, ONEOK Partners
 
 
 
 
2014 to 2015
 
Executive Vice President, Commercial, ONEOK and ONEOK Partners
Walter S. Hulse III
 
56

 
2019 to present
 
Chief Financial Officer, Treasurer and Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK
Chief Financial Officer, Treasurer and Executive Vice President, Strategic Planning and Corporate Affairs
 
 
 
2017 to 2019
 
Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK
 
 
 
 
2015 to 2017
 
Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK and ONEOK Partners
 
 
 
 
2012 to 2015
 
Managing Member, Spinnaker Strategic Advisory Services, LLC
Kevin L. Burdick
 
55

 
2017 to present
 
Executive Vice President and Chief Operating Officer, ONEOK
Executive Vice President and Chief Operating Officer
 
 
 
2017
 
Executive Vice President and Chief Commercial Officer, ONEOK and ONEOK Partners
 
 
 
 
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
Charles M. Kelley
 
61

 
2018 to present
 
Senior Vice President, Natural Gas, ONEOK
Senior Vice President, Natural Gas
 
 
 
2017 to 2018
 
Senior Vice President, Natural Gas Gathering & Processing, ONEOK
 
 
 
 
2015 to 2017
 
Senior Vice President, Corporate Planning and Development, ONEOK and ONEOK Partners
 
 
 
 
2014 to 2015
 
Vice President, Corporate Development, ONEOK and ONEOK Partners
Sheridan C. Swords
 
50

 
2017 to present
 
Senior Vice President, Natural Gas Liquids, ONEOK
Senior Vice President, Natural Gas Liquids
 
 
 
2013 to 2017
 
Senior Vice President, Natural Gas Liquids, ONEOK Partners
Stephen B. Allen
 
46

 
2017 to present
 
Senior Vice President, General Counsel and Assistant Secretary, ONEOK
Senior Vice President, General Counsel
and Assistant Secretary
 
 
 
2008 to 2017
 
Vice President and Associate General Counsel, ONEOK and ONEOK Partners
Mary M. Spears
 
40

 
2019 to present
 
Vice President and Chief Accounting Officer, ONEOK
Vice President and Chief Accounting Officer
 
 
 
2015 to 2019
 
Director, SEC Reporting, ONEOK
 
 
 
 
2015 to 2017
 
Director, SEC Reporting, ONEOK Partners
 
 
 
 
2009 to 2015
 
Director, Natural Gas Liquids Accounting, ONEOK Partners

No family relationships exist between any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act

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as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Director Independence Guidelines, Corporate Sustainability Report, Bylaws and the written charter of our Audit Committee also are available on our website, and we will provide copies of these documents upon request.

In addition to our filings with the SEC and materials posted on our website, we also use social media platforms as additional channels of distribution to reach public investors. Information contained on our website, posted on our social media accounts, and any corresponding applications, are not incorporated by reference into this report.

ITEM 1A.    RISK FACTORS

Our investors should consider the following risks that could affect us and our business. Although we have tried to identify key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should consider carefully the following discussion of risks and the other information included or incorporated by reference in this Annual Report, including “Forward-Looking Statements,” which are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

If the level of drilling in the regions in which we operate declines substantially near our assets, our volumes and revenues could decline.

Our gathering and transportation pipeline systems are dependent upon production from natural gas and crude oil wells, which naturally declines over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and the asset utilization rates at our processing and fractionation facilities, we must continually obtain new supplies. Our ability to maintain or expand our businesses depends largely on the level of drilling and production by third parties in the regions in which we operate. Our natural gas and NGL supply volumes may be impacted if producers curtail or redirect drilling and production activities. Drilling and production are impacted by factors beyond our control, including:
demand and prices for natural gas, NGLs and crude oil;
producers’ access to capital;
producers’ finding and development costs of reserves;
producers’ ability to obtain necessary permits, drilling rights and surface access in a timely manner and on reasonable terms;
natural gas field characteristics and production performance; and
capacity constraints on natural gas, crude oil and NGL infrastructure from the producing areas and our facilities.

Commodity prices have experienced significant volatility. Drilling and production activity levels may vary across our geographic areas; however, a prolonged period of low commodity prices may reduce drilling and production activities across all areas. If we are not able to obtain new supplies to replace the natural decline in volumes from existing wells or because of competition, throughput on our gathering and transportation pipeline systems and the utilization rates of our processing and fractionation facilities would decline, which could affect adversely our business, results of operations, financial position and cash flows, and our ability to pay cash dividends.

Continued development of supply sources outside of our operating regions could impact demand for our services.

Natural gas production areas outside of our operating regions may compete with natural gas originating in production areas connected to our systems. For example, increased production in the Marcellus Shale may cause natural gas and NGLs in supply areas connected to our systems to be diverted to markets other than our traditional market areas and may affect capacity utilization adversely on our pipeline systems and our ability to renew or replace existing contracts. In our Natural Gas Gathering and Processing segment, the development of reserves could move drilling rigs from our current service areas to other areas, which may reduce demand for our services. In our Natural Gas Pipelines segment, the displacement of natural gas originating in supply areas connected to our pipeline systems by supply sources that are closer to the end-use markets could reduce demand for our services. Either of these possibilities could result in lower revenues, which could affect adversely our business, results of operations, financial position and cash flows.


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Our operations are subject to operational hazards and unforeseen interruptions, which could affect adversely our business and for which we may not be adequately insured.

Our operations are subject to all of the risks and hazards typically associated with the operation of natural gas and NGL gathering, transportation and distribution pipelines, storage facilities and processing and fractionation facilities, which include, but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes and the performance of facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, explosions, fires, the collision of equipment with our pipeline facilities (for example, this may occur if a third party were to perform excavation or construction work near our facilities) and catastrophic events such as tornados, hurricanes, earthquakes, floods, and other similar events beyond our control. Also, the United States government warned that energy assets, specifically the nation’s pipeline infrastructure, may be targets of terrorist attacks. An act of terrorism could target our facilities, those of our suppliers or customers or those of other pipelines. A casualty occurrence may result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred and interruptions to the operations of our pipeline or other facilities caused by such an event could reduce our revenues and increase expenses, thereby impairing our ability to meet our obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost, and we are not fully insured against all risks inherent to our business.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could affect adversely our business, results of operations, financial position and cash flows. Further, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Our operating results may be affected adversely by unfavorable economic and market conditions.

An adverse change in economic conditions worldwide or in the economic regions in which we operate could negatively affect the crude oil and natural gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our services and products. Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices may have an impact on many of our suppliers and customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. Periods of severe volatility in equity and credit markets may disrupt our access to such markets, make it difficult to obtain financing necessary to expand facilities or acquire assets, increase financing costs and result in the imposition of restrictive financial covenants. If adverse global or regional economic and market conditions remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, results of operations, financial position, cash flows and liquidity.

Increased regulation of exploration and production activities, including hydraulic fracturing, well setbacks and disposal of waste water, could result in reductions or delays in drilling and completing new crude oil and natural gas wells.

The crude oil and natural gas industry is relying increasingly on supplies from nonconventional sources, such as shale and tight sands. Natural gas extracted from these sources frequently requires hydraulic fracturing, which involves the pressurized injection of water, sand and chemicals into a geologic formation to stimulate crude oil and natural gas production. Legislation or regulations placing restrictions on exploration and production activities, including hydraulic fracturing and disposal of waste water, could result in operational delays, increase operating costs and additional regulatory burdens on exploration and production operators. Any of these factors could reduce their production of unprocessed natural gas and, in turn, affect adversely our revenues and results of operations by decreasing the volumes of natural gas and NGLs gathered, treated, processed, fractionated and transported on our or our joint ventures’ assets.

In the competition for supply, we may have significant levels of excess capacity on our natural gas and NGL pipelines, processing, fractionation and storage assets.

Our natural gas and NGL pipelines, processing, fractionation and storage assets compete with other pipelines, processing, fractionation and storage assets for natural gas and NGL supply delivered to the markets we serve. As a result of competition, we may have significant levels of uncontracted or discounted capacity on our assets, which could affect adversely our business, results of operations, financial position and cash flows.


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Growing our business by constructing new pipelines and facilities or making modifications to our existing facilities subjects us to construction risk and supply risks, should adequate natural gas or NGL supply be unavailable upon completion of the facilities.

To expand our business, we regularly construct new and modify or expand existing pipelines and gathering, processing, storage and fractionation facilities. The construction and modification of these facilities may involve the following risks:
projects may require significant capital expenditures, which may exceed our estimates, and involve 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;
opposition from environmental groups, landowners, tribal groups, local groups and other advocates could result in organized protests, attempts to block or sabotage our construction activities or operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the construction or operation of our assets; and
we may be required to rely on third parties downstream of our facilities to have available capacity for our delivered natural gas or NGLs, which may not yet be operational.
As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve our expected investment return, which could affect adversely our business, results of operations, financial position and cash flows.

Estimates of hydrocarbon reserves may be inaccurate which could result in lower than anticipated volumes.

We may not be able to accurately estimate hydrocarbon reserves and production volumes expected to be delivered to us for a variety of reasons, including the unavailability of sufficiently detailed information and unanticipated changes in producers’ expected drilling schedules. Accordingly, we may not have accurate estimates of total reserves serviced by our assets, the anticipated life of such reserves or the expected volumes to be produced from those reserves. In such event, if we are unable to secure additional sources, then the volumes that we gather or process in the future could be less than anticipated. A decline in such volumes could affect adversely our business, results of operations, financial position and cash flows.

The volatility of natural gas, crude oil and NGL prices could affect adversely our earnings and cash flows.

A significant portion of our revenues are derived from the sale of commodities that are received in conjunction with natural gas gathering and processing services, the transportation and storage of natural gas, and from the purchase and sale of NGLs and NGL products. Commodity prices have been volatile and are likely to continue to be so in the future. The prices we receive for our commodities are subject to wide fluctuations in response to a variety of factors beyond our control, including, but not limited to, the following:
overall domestic and global economic conditions;
relatively minor changes in the supply of, and demand for, domestic and foreign energy;
market uncertainty;
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;
weather conditions;
domestic and foreign governmental regulations and taxes;
the price and availability of alternative fuels;
speculation in the commodity futures markets;
the effects of imports and exports on the price of natural gas, crude oil, NGL and liquefied natural gas;
the effect of worldwide energy-conservation measures;
the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials; and
technology and improved efficiency impacting supply and demand for natural gas, NGLs and crude oil.

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These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services, which could affect adversely our business, results of operations, financial position and cash flows. As commodity prices decline, we could be paid less for our commodities, thereby reducing our cash flows. In addition, crude oil, natural gas and NGL production could also decline due to lower prices.

We do not hedge fully against commodity price risk or interest rate risk, including commodity price changes, seasonal price differentials, product price differentials or location price differentials. This could result in decreased revenues, increased costs and lower margins, affecting adversely our results of operations.

Certain of our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs and crude oil prices. Market risk refers to the risk of loss of future cash flows and earnings arising from adverse changes in commodity prices. Our primary commodity price exposures arise from:
the value of the commodities sold under POP with fee contracts of which we retain a portion of the sales proceeds;
the price differentials between the individual NGL products with respect to our NGL transportation and fractionation agreements;
the location price differentials in the price of natural gas and NGLs;
the seasonal price differentials in natural gas and NGLs related to our storage operations;
the price risk related to electric costs to operate our facilities, primarily in Texas; and
the fuel costs and the value of the retained fuel in-kind in our natural gas pipelines and storage operations.

To manage the risk from market price fluctuations in natural gas, NGLs and crude oil prices, we may use derivative instruments such as swaps, futures, forwards and options. However, we do not hedge fully against commodity price changes, and we therefore retain some exposure to market risk. Further, hedging instruments that are used to reduce our exposure to interest-rate fluctuations could expose us to risk of financial loss where we may contract for fixed-rate swap instruments to hedge variable-rate instruments and the fixed rate exceeds the variable rate. Finally, hedging arrangements for forecasted sales and purchases are used to reduce our exposure to commodity price fluctuations and may limit the benefit we would otherwise receive if market prices for natural gas, crude oil and NGLs differ from the stated price in the hedge instrument for these commodities.

A breach of information security, including a cybersecurity attack, or failure of one or more key information technology or operational systems, or those of third parties, may affect adversely our operations, financial results or reputation.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. The various uses of these information technology systems, networks and services include, but are not limited to:
controlling our plants and pipelines with industrial control systems including Supervisory Control and Data Acquisition (SCADA);
collecting and storing customer, employee, investor and other stakeholder information and data;
processing transactions;
summarizing and reporting results of operations;
hosting, processing and sharing confidential and proprietary research, business plans and financial information;
complying with regulatory, legal, financial or tax requirements;
providing data security; and
other processes necessary to manage our business.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to perform critical functions, which could affect adversely our business and results of operations. Our financial results could also be affected adversely if an individual causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our businesses. We use software to help manage and operate our businesses, and this may subject us to increased risks. In recent years, there has been a rise in the number and sophistication of cyberattacks on companies’ network and information systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, physical

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damages, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. If any such failure, interruption or similar event results in the improper disclosure of information maintained in our information systems and networks or those of our vendors, including personnel, customer and vendor information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Efforts by us and our vendors to develop, implement and maintain security measures may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. Cybersecurity, physical security and the continued development and enhancement of our controls, processes and practices designed to protect our enterprise, information systems and data from attack, damage or unauthorized access and to identify and appropriately report cyberattacks, remain a priority for us. Although we believe that we have robust information security procedures and other safeguards in place, as cyberthreats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

Cyberattacks against us or others in our industry could result in additional regulations. Current efforts by the federal government, such as the Improving Critical Infrastructure Cybersecurity executive order, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Our operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.

The risk of incurring substantial environmental costs and liabilities is inherent in our business. Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the protection of, the environment. Examples of these laws include:
the Clean Air Act and analogous state laws that impose obligations related to air emissions;
the Clean Water Act and analogous state laws that regulate discharge of wastewater from our facilities to state and federal waters;
the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal; and
the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

Various federal and state governmental authorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the CERCLA, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.

There is an inherent risk of incurring environmental costs and liabilities in our business due to our handling of the products we gather, transport, process and store, air emissions related to our operations, past industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which our pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could increase significantly our compliance costs and the cost of any remediation that may become necessary, some of which may be material. Additional information is included under Item 1, Business, under “Regulatory, Environmental and Safety Matters” and in Note N of the Notes to Consolidated Financial Statements in this Annual Report.

Our insurance may not cover all environmental risks and has limits on coverage in the event an environmental claim is made against us. Our business may be affected adversely by increased costs due to stricter pollution-control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. New or revised environmental regulations might also affect adversely our products and activities, and federal and state agencies could impose additional safety requirements, all of which could affect adversely our profitability.


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We may face significant costs to comply with the regulation of GHG emissions.

GHG emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at issues associated with climate change. Various federal and state legislative proposals have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally binding reductions in emissions of GHGs.

We believe it is likely that future governmental legislation and/or regulation on the federal, state and regional levels, may require us either to limit GHG emissions associated with our operations, pay additional taxes or to purchase allowances for such emissions. These legislative and/or regulatory initiatives could make some of our activities uneconomic to maintain or operate. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with GHG regulatory requirements. Our future results of operations, financial position or cash flows could be affected adversely if such costs are not recovered or otherwise passed on to our customers. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations or when they may become effective.

We may be subject to physical and financial risks associated with climate change and changes in investor sentiment towards climate change may affect the demand for our securities.

The threat of global climate change may create physical and financial risks to our business. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornados and snow or ice storms. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks.

Due to climate change concerns, some investors may choose to either not invest, or reduce their investment, in companies that explore for, produce, process, transport or sell products derived from hydrocarbons. If this investor sentiment increases, we may see reduced demand for our securities, which could impact our liquidity or the value of our securities. In addition, to the extent financial markets view climate change and emissions of GHGs as a financial risk, this could affect negatively our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings.

Changes in regulatory policies, public sentiment or technology due to the threat of climate change that result in a reduction in the demand for hydrocarbon products, restrictions on their use, or increased use of renewable energy could reduce future demand for hydrocarbons and reduce volumes available to us for gathering, processing, fractionation, transportation, storage and marketing. Finally, increasing attention to climate change and the impacts of GHG emissions has resulted in an increased likelihood of governmental investigations, regulation and private litigation, which could increase our costs or otherwise affect adversely our business.

Our business is subject to regulatory oversight and potential penalties.

The energy industry historically has been subject to heavy state and federal regulation that extends to many aspects of our businesses and operations, including:
regulatory approval and review of certain of our rates, operating terms and conditions of service;
the types of services we may offer our counterparties;
construction of new facilities;
the integrity, safety and security of facilities and operations;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
maintenance of accounts and records; and
relationships with affiliate companies involved in all aspects of the natural gas and energy businesses.


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Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair our ability to compete for business or to recover costs and may increase the cost and burden of our operations. We cannot guarantee that state or federal regulators will not challenge our safety practices or will authorize any projects or acquisitions that we may propose in the future. Moreover, there can be no guarantee that, if granted, any such authorizations will be made in a timely manner or will be free from potentially burdensome conditions.

Under the Natural Gas Act, which is applicable to our interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to our NGL pipelines, our interstate transportation rates are regulated by the FERC and many changes to our pipeline tariffs must be approved in a regulatory proceeding. Additionally, either shippers, the FERC and/or state regulatory agencies may investigate our tariff rates which could result in, among other things, being ordered to reduce rates or make refunds to shippers.

Failure to comply with all applicable state or federal statutes, rules and regulations and orders could bring substantial penalties and fines.

Our regulated pipeline companies have recorded certain assets that may not be recoverable from our customers.

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated rate-making process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.

A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs.

Our operations require skilled and experienced workers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has, at times, caused us to conduct certain operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs. This shortage of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain areas, combined with the challenges of attracting new, qualified workers to the midstream energy industry. This shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could affect adversely our labor productivity and costs and our ability to expand operations in the event there is an increase in the demand for our services and products, which could affect adversely our business, results of operations, financial position and cash flows.

Measurement adjustments on our pipeline system may be impacted materially by changes in estimation, type of commodity and other factors.

Natural gas and NGL measurement adjustments occur as part of the normal operating conditions associated with our assets. The quantification and resolution of measurement adjustments are complicated by several factors including: (i) the significant quantities (i.e., thousands) of measurement equipment that we use across our natural gas and NGL systems, primarily around our gathering and processing assets; (ii) varying qualities of natural gas in the streams gathered and processed through our systems and the mixed nature of NGLs gathered and fractionated; and (iii) variances in measurement that are inherent in metering technologies. Each of these factors may contribute to measurement adjustments that may occur on our systems, which could affect adversely our business, results of operations, financial position and cash flows.

Many of our assets have been in service for several decades.

Many of our pipeline and storage assets are designed as long-lived assets. Over time the age of these assets could result in increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and liabilities. Any significant increase in these expenditures, costs or liabilities could affect adversely our business, results of operations, financial position and cash flows, as well as our ability to pay cash dividends.

We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint-venture participants agree.

We participate in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets that may be substantially dependent on or

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otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint-venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint-venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

Moreover, subject to contractual restrictions, any joint-venture owner generally may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint-venture owners. Any such transaction could result in us being required to partner with different or additional parties who may have business interests different from ours.

We do not operate all of our joint-venture assets nor do we employ directly all of the persons responsible for providing administrative, operating and management services. This reliance on others to operate joint-venture assets and to provide other services could affect adversely our business and results of operations.

We rely on others to provide administrative, operating and management services for certain of our joint-venture assets. We have a limited ability to control the operations and the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the operator or an outsourced service provider. We may have to contract elsewhere for outsourced services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our contracts and affect adversely our business and results of operations.

We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which could disrupt our operations.

We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could affect adversely our business, results of operations, financial position and cash flows.

Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per-share basis.

Any acquisition involves potential risks that may include, among other things:
inaccurate assumptions about volumes, revenues and costs, including potential synergies;
an inability to integrate successfully the businesses we acquire;
decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;
a significant increase in our interest expense and/or financial leverage if we incur additional debt to finance the acquisition;
the assumption of unknown liabilities for which we are not indemnified, our indemnity is inadequate or our insurance policies may exclude from coverage;
an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets;
limitations on rights to indemnity from the seller;
inaccurate assumptions about the overall costs of equity or debt;
the diversion of management’s and employees’ attention from other business concerns;
unforeseen difficulties operating in new product areas or new geographic areas;
increased regulatory burdens;
customer or key employee losses at an acquired business; and
increased regulatory requirements.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.

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If we fail to maintain an effective system of internal controls, we may not be able to report accurately our financial results or prevent fraud. As a result, current and potential holders of our equity and debt securities could lose confidence in our financial reporting.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our equity, our access to capital markets and the cost of capital.

Our employees or directors may engage in misconduct or other improper activities, including noncompliance with regulatory standards and requirements.

As with all companies, we are exposed to the risk of employee fraud or other misconduct. Our Board of Directors has adopted a code of business conduct and ethics that applies to our directors, officers (including our principal executive and financial officers, principal accounting officer, controllers and other persons performing similar functions) and all other employees. We require all directors, officers and employees to adhere to our code of business conduct and ethics in addressing the legal and ethical issues encountered in conducting their work for our company. Our code of business conduct and ethics requires, among other things, that our directors, officers and employees avoid conflicts of interest, comply with all applicable laws and other legal requirements, conduct business in an honest and ethical manner and otherwise act with integrity and in our company’s best interest. All directors, officers and employees are required to report any conduct that they believe to be an actual or apparent violation of our code of business conduct and ethics. However, it is not always possible to identify and deter misconduct, and the precautions we take to detect and prevent this activity may not be effective in controlling unknown or unmanaged risks or losses or in protecting us from governmental investigations or other actions or lawsuits stemming from a failure to comply with such laws or regulations. If any such actions are instituted against us, and we are not successful in defending ourselves or asserting our rights, those actions could affect adversely our reputation, business, results of operations, financial position and cash flows.

An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings.

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if a low commodity price environment persisted for a prolonged period, it could result in lower volumes delivered to our systems and impairments of our assets or equity-method investments. If we determine that an impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by consolidated debt to total capitalization.

Any reduction in our credit ratings could affect adversely our business, results of operations, financial position and cash flows.

Our long-term debt and our commercial paper program have been assigned an investment-grade credit rating of “Baa3” and Prime-3, respectively, by Moody’s and “BBB” and A-2, respectively, by S&P. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. If Moody’s or S&P were to downgrade our long-term debt or our commercial paper rating, particularly below investment grade, our borrowing costs would increase, which would affect adversely our financial results, and our potential pool of investors and funding sources could decrease. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.


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Holders of our common stock may not receive dividends in the amount identified in guidance, or any dividends at all.

We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we pay in the form of dividends may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including our working capital needs, our ability to borrow, the restrictions contained in our indentures and credit facility, our debt service requirements and the cost of acquisitions, if any. A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our stock price.

Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates.

Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates, as discussed in Note M of the Notes to Consolidated Financial Statements in this Annual Report. The amount of cash that our unconsolidated affiliates can distribute principally depends upon the amount of cash flows these affiliates generate from their respective operations, which may fluctuate from quarter to quarter. We do not have any direct control over the cash distribution policies of our unconsolidated affiliates. This lack of control may contribute to us not having sufficient available cash each quarter to continue paying dividends at the current levels.

Additionally, the amount of cash that we have available for cash dividends depends primarily upon our cash flows, including working capital borrowings, and is not solely a function of profitability, which will be affected by noncash items such as depreciation, amortization and provisions for asset impairments. As a result, we may be able to pay cash dividends during periods when we record losses and may not be able to pay cash dividends during periods when we record net income.

We are exposed to the credit risk of our customers or counterparties, and our credit-risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties. Our customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions, commodity prices or financial difficulties that could impact their creditworthiness or ability to pay us for our services. We assess the creditworthiness of our customers and counterparties and obtain collateral or contractual terms as we deem appropriate. We cannot, however, predict to what extent our business may be impacted by deteriorating market or financial conditions, including possible declines in our customers’ and counterparties’ creditworthiness. Our customers and counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent our customers and counterparties are in financial distress or commence bankruptcy proceedings, contracts with them may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If our risk-management policies and procedures fail to assess adequately the creditworthiness of existing or future customers and counterparties, any material nonpayment or nonperformance by our customers and counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could affect adversely our business, results of operations, financial position, cash flows and ability to pay cash dividends to our shareholders.

Our primary market areas are located in the Mid-Continent, Rocky Mountain, Permian Basin and Gulf Coast regions of the U.S. Our counterparties are primarily major integrated and independent exploration and production, pipeline, marketing and petrochemical companies. Therefore our counterparties may be similarly affected by changes in economic, regulatory or other factors that may affect our overall credit risk.

Changes in interest rates could affect adversely our business.

We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our short-term borrowings. Our results of operations, cash flows and financial position could be affected adversely by significant fluctuations in interest rates from current levels.

In July 2017, the head of the United Kingdom Financial Conduct Authority announced the desire to phase out the use of LIBOR by the end of 2021. In addition, the U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee composed of large US financial institutions, is considering replacing U.S. dollar LIBOR with the Secured Overnight Financing Rate (SOFR), a new index supported by short-term Treasury repurchase agreements. Although there have been some issuances utilizing SOFR, it is unknown whether this alternative reference rate will attain market acceptance as a replacement for LIBOR.


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Our $2.5 Billion Credit Agreement and our $1.5 Billion Term Loan Agreement include provisions that grant the agreement’s administrative agents with broad discretion to establish a replacement rate for LIBOR, if necessary.

Our indebtedness and guarantee obligations could impair our financial condition and our ability to fulfill our obligations.

As of December 31, 2019, we had total indebtedness of $12.8 billion. Our indebtedness and guarantee obligations could have significant consequences. For example, they could:
make it more difficult for us to satisfy our obligations with respect to senior notes and other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or the senior notes;
impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;
diminish our ability to withstand a downturn in our business or the economy;
require us to dedicate a substantial portion of our cash flows from operations to debt-service payments, reducing the availability of cash for working capital, capital expenditures, acquisitions, dividends or general corporate purposes;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
place us at a competitive disadvantage compared with our competitors that have proportionately less debt and fewer guarantee obligations.

We are not prohibited under the indentures governing the senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations summarized in the next paragraph. If we incur significant additional indebtedness, it could worsen the negative consequences mentioned above and could affect adversely our ability to repay our other indebtedness.

Our $2.5 Billion Credit Agreement and $1.5 Billion Term Loan Agreement contain provisions that restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, certain of these agreements contain provisions that, among other things, limit our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, grant liens or make negative pledges. Certain agreements also require us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur, as described in the “Liquidity and Capital Resources” section of Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive covenants.

If we are unable to meet our debt-service obligations or comply with financial covenants, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be effectively subordinated to any future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the senior notes.

Although many of our operating subsidiaries have guaranteed our debt securities, the guarantees are subject to release under certain circumstances, and we may have subsidiaries that are not guarantors. In that case, the debt securities effectively would be subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the debt securities.

An event of default may require us to offer to repurchase certain of our and ONEOK Partners’ senior notes or may impair our ability to access capital.

The indentures governing certain of our and ONEOK Partners’ senior notes include an event of default upon the acceleration of other indebtedness of $15 million or more for certain of our senior notes or $100 million or more for certain of our and ONEOK Partners’ senior notes. Such events of default would entitle the trustee or the holders of 25% in aggregate principal amount of our and ONEOK Partners’ outstanding senior notes to declare those senior notes immediately due and payable in full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to

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borrow money under our credit facility or seek alternative financing sources to finance the repurchases and repayment. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.

A court may use fraudulent conveyance considerations to avoid or subordinate the cross guarantees of our and ONEOK Partners’ indebtedness.

ONEOK, ONEOK Partners and the Intermediate Partnership have cross guarantees in place for our and ONEOK Partners’ indebtedness. A court may use fraudulent conveyance laws to subordinate or avoid the cross guarantees of certain of our and ONEOK Partners’ indebtedness. It is also possible that under certain circumstances, a court could avoid or subordinate the guarantor’s guarantee of our and ONEOK Partners’ indebtedness in favor of the guarantor’s other debts or liabilities to the extent that the court determined either of the following were true at the time the guarantor issued the guarantee:
the guarantor incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the guarantor contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or
the guarantor did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, the guarantor:
–     was insolvent or rendered insolvent by reason of the issuance of the guarantee;
was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or
–     intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if:
the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation;
the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or
it could not pay its debts as they become due.

Among other things, a legal challenge of the cross guarantees of our and ONEOK Partners’ indebtedness on fraudulent conveyance grounds may focus on the benefits, if any, realized by the guarantor as a result of our and ONEOK Partners’ issuance of such debt. To the extent the guarantor’s guarantee of our and ONEOK Partners’ indebtedness is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of such debt would cease to have any claim in respect of the guarantee.

The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may increase.

We have a defined benefit pension plan for certain employees and former employees hired before January 1, 2005, and postretirement welfare plans that provide postretirement medical and life insurance benefits to certain employees hired prior to 2017 who retire with at least five years of full-time service. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and postretirement benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries and changes in health care costs. For further discussion of our defined benefit pension plan and postretirement welfare plans, see Note K of the Notes to Consolidated Financial Statements in this Annual Report.

Any sustained declines in equity markets and reductions in bond yields may affect adversely the value of our pension and postretirement benefit plan assets. In these circumstances, additional cash contributions to our pension plans may be required, which could affect adversely our business, financial condition and liquidity.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.    PROPERTIES

A description of our properties is included in Item 1, Business.

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ITEM 3.    LEGAL PROCEEDINGS

Information about our legal proceedings is included in Note N of the Notes to Consolidated Financial Statements in this Annual Report.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the NYSE under the trading symbol “OKE.” The corporate name ONEOK is used in newspaper stock listings.

At February 18, 2020, there were 14,001 holders of record of our 413,319,000 outstanding shares of common stock.

For information regarding our Employee Stock Award Program and other equity compensation plans see Note J of the Notes to Consolidated Financial Statements and “Equity Compensation Plan Information” included in Part III, Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, in this Annual Report.


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PERFORMANCE GRAPH

The following performance graph compares the performance of our common stock with the S&P 500 Index, the Alerian Midstream Energy Select Index and a ONEOK Peer Group during the period beginning on December 31, 2014, and ending on December 31, 2019.

The graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.

Value of $100 Investment, Assuming Reinvestment of Distributions/Dividends,
at December 31, 2014, and at the End of Every Year Through December 31, 2019.

chart-cde29d5ed2ea3a058d2a01.jpg

 
 
Cumulative Total Return
 
 
Years Ended December 31,
 
 
2015
 
2016
 
2017
 
2018
 
2019
 
 
 
 
 
 
 
 
 
 
 
ONEOK, Inc.
 
$
52.64

 
$
131.26

 
$
128.53

 
$
136.60

 
$
201.86