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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, 2020.
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.

Commission file number  001-13643
oke-20201231_g1.jpg
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma73-1520922
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer Identification No.)
 
100 West Fifth Street,
Tulsa,OK74103
(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 classTrading Symbol(s)Name of each exchange on which registered
Common stock, par value of $0.01OKENew 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.
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

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 30, 2020, was $14.5 billion.

On February 16, 2021, the Company had 444,983,595 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 26, 2021, are incorporated by reference in Part III.



ONEOK, Inc.
2020 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.

2



GLOSSARY

The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
$1.5 Billion Term Loan Agreement
The senior unsecured delayed-draw three-year $1.5 billion term loan agreement dated November 19, 2018
$2.5 Billion Credit Agreement
ONEOK’s $2.5 billion revolving credit agreement, as amended
AFUDCAllowance for funds used during construction
Annual ReportAnnual Report on Form 10-K for the year ended December 31, 2020
ASUAccounting Standards Update
BblBarrels, 1 barrel is equivalent to 42 United States gallons
BBtu/dBillion British thermal units per day
BcfBillion cubic feet
Bcf/dBillion cubic feet per day
CARES ActCoronavirus Aid, Relief, and Economic Security Act
CFTCU.S. Commodity Futures Trading Commission
Clean Air ActFederal Clean Air Act, as amended
Clean Water ActFederal Water Pollution Control Act Amendments of 1972, as amended
COVID-19Coronavirus disease 2019
DJDenver-Julesburg
DOTUnited States Department of Transportation
EBITDAEarnings before interest expense, income taxes, depreciation and amortization
EPAUnited States Environmental Protection Agency
EPSEarnings per share of common stock
Exchange ActSecurities Exchange Act of 1934, as amended
FERCFederal Energy Regulatory Commission
FitchFitch Ratings, Inc.
GAAPAccounting principles generally accepted in the United States of America
GHGGreenhouse gas
ICEIntercontinental Exchange
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
KCCKansas Corporation Commission
LIBORLondon Interbank Offered Rate
MBbl/dThousand barrels per day
MDth/dThousand dekatherms per day
MMBblMillion barrels
MMBbl/dMillion barrels per day
MMBtuMillion British thermal units
MMcf/dMillion cubic feet per day
Moody’sMoody’s Investors Service, Inc.
Natural Gas ActNatural Gas Act of 1938, as amended
Natural Gas Policy ActNatural 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 PipelineNorthern Border Pipeline Company, a 50% owned joint venture
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
OCCOklahoma Corporation Commission
ONEOKONEOK, Inc.
ONEOK PartnersONEOK Partners, L.P., a wholly owned subsidiary of ONEOK, Inc.
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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ONEOK West Texas NGLONEOK West Texas NGL pipeline and Mesquite pipeline (formerly known as West Texas LPG pipeline and Mesquite pipeline)
OPISOil 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
POPPercent of Proceeds
Quarterly Report(s)Quarterly Report(s) on Form 10-Q
RoadrunnerRoadrunner Gas Transmission, LLC, a 50% owned joint venture
RRCRailroad Commission of Texas
S&PS&P Global Ratings
SCOOP
South Central Oklahoma Oil Province, an area in the Anadarko Basin in Oklahoma
SECSecurities and Exchange Commission
Securities ActSecurities Act of 1933, as amended
Series E Preferred StockSeries 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 606Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”
WTIWest Texas Intermediate
XBRLeXtensible 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
oke-20201231_g2.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 and Powder River Basins; 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, including ethane, propane, iso-butane, normal butane and natural gasoline.
Gathered wellhead natural gas is directed to our processing plants to remove NGLs, resulting in residue natural gas (primarily methane). Once processed, residue natural gas is recompressed and delivered to intrastate and interstate natural gas pipelines primarily in our Natural Gas Pipelines segment.
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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 and cross-border pipelines.
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, Market Conditions and COVID-19 - Late in the first quarter 2020, the energy industry experienced historic events that led to a simultaneous demand and supply disruption. The World Health Organization declared COVID-19 a global pandemic and recommended containment and mitigation measures worldwide, which contributed to a massive economic slowdown and decreased demand for crude oil. In addition, Saudi Arabia and Russia increased production of crude oil as the two countries competed for market share. As a result, the global supply of crude oil significantly exceeded demand and led to a collapse in crude oil prices. Crude oil prices and the related impact on crude oil drilling impacts our business due to associated natural gas, which is natural gas produced by oil wells. Associated natural gas contains NGLs. The decline of crude oil prices resulted in crude oil and associated natural gas and NGL production being curtailed in the second quarter 2020. We are still experiencing global and regional economic disruptions due primarily to COVID-19; however, in the third quarter 2020, many of our producers reversed curtailments, bringing volumes back to pre-COVID-19 levels as prices and demand significantly improved from second quarter 2020 lows. The full impact of the continued global and regional economic disruption will depend on the unknown duration and severity of COVID-19 and, among other things, the impact of governmental actions imposed in response to COVID-19, the pace and scale of economic recovery and corresponding demand for crude oil and the impacts to commodity prices. We continue to monitor producers’ drilling, completion and production plans, which are increasingly positive as commodity prices have stabilized and improved, and our expectations for 2021 include the potential for an improving pace of drilling and completion activity.

The energy industry has experienced many up and down cycles, and as a result, we have positioned ourselves to minimize exposure to direct commodity price volatility. Each of our three segments’ earnings are primarily fee-based, and our consolidated earnings were more than 90% fee-based in 2020. While our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based, we have direct commodity price exposure related primarily to fee with POP contracts. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. In addition, although 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 as a result of production curtailments, reduced drilling and completion activity, declining well productivity, severe weather disruption, operational outages and crude oil, NGL and natural gas demand. Our Natural Gas Pipelines segment is not exposed to significant volumetric risk due to nearly all of our capacity being subscribed under long-term firm fee-based contracts.

In continued response to COVID-19, we remain committed to managing the impact of the pandemic on our employees. We continue to take actions for safe operations, to protect our workforce and to implement appropriate cost reduction measures. We reduced our 2020 capital-growth expenditures by approximately $1.7 billion, compared with 2019, driven primarily by our previously completed, paused and suspended capital-growth projects. We also significantly reduced our operating expenses in 2020, compared with 2019, primarily as a result of reduced outside services from contractors, asset optimizations and lower employee-related costs. As always, we remain focused on operating our assets safely, reliably and in an environmentally responsible manner. We continue to monitor the COVID-19 outbreak and have implemented our business continuity plans. ONEOK is a critical infrastructure business as defined by the United States Department of Homeland Security, and, therefore, our workforce has remained fully engaged in the midst of federal, state and local government issued guidelines and safety-related ordinances. We continue to practice remote work procedures when possible to protect the safety of our employees and their families and have taken extra precautions for our employees who work in the field or need to report to a ONEOK facility, such as increased facility access restrictions, workspace modifications, social distancing, face covering protocols and sanitation procedures. We continue to apply risk-management and cybersecurity measures designed so that our systems remain functional in order to both serve our operational needs and to provide service to our customers. In the first quarter 2020, the CARES Act was signed into law in response to the COVID-19 pandemic, and we opted into the CARES Act payroll tax deferral program, which will modestly benefit us, and the 401(k) penalty-free hardship withdrawal and loan deferral programs for our employees.

In 2020, due to the commodity price and market environment, we experienced a significant decline in our share price and market capitalization, and performed a Step 1 analysis to test our goodwill for impairment and evaluated certain long-lived asset groups and equity investments for impairment. As a result, we incurred $644.9 million in noncash impairment charges, which had an adverse impact on our financial results for the year ended December 31, 2020. We expect to maintain sufficient liquidity and financial stability into 2021 due to cash on hand from our June 2020 equity issuance, cash flows from operations and access to our undrawn $2.5 Billion Credit Agreement.

See Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in this Annual Report for more information on our exposure to market risk.

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Natural Gas - In our Natural Gas Gathering and Processing segment, gathered and processed volumes decreased in 2020, compared with 2019, due primarily to natural production declines in the Mid-Continent region. Production curtailments from many of our crude oil and natural gas producers impacted volumes in the second quarter 2020, however in the third quarter 2020, many of our producers returned production and our captured natural gas returned to pre-COVID-19 levels as commodity prices strengthened. We expect to maintain pre-COVID-19 volume levels in the Rocky Mountain region through 2021, assuming no increase in producer activity, due to the completion of previously drilled but uncompleted wells, the capture of natural gas previously flared and rising gas-to-oil ratios. In addition, as prices and volumes continue to strengthen, we have the processing capacity to benefit from production growth without significant capital investment due to the completion of our Demicks Lake I and II natural gas processing plants, which were placed in service in the fourth quarter 2019 and the first quarter 2020, respectively. These plants increased our total processing capacity to approximately 1.5 Bcf/d in the Williston Basin.

Production growth may be impacted by the current litigation challenging the validity of an easement for the Dakota Access Pipeline (DAPL), which is used to transport crude oil from the Williston Basin to markets in the Mid-Continent region and Gulf Coast. If DAPL operations are suspended, production growth could be limited due to increased crude oil transportation costs and pipeline capacity constraints in the region, which could impact us due to the associated natural gas and NGLs. However, we expect limited impact to our producers due to alternative available crude pipeline capacity and existing rail infrastructure out of the Rocky Mountain region.

In our Natural Gas Pipelines segment, our assets are connected to key supply areas and demand centers, including export markets in Mexico via our Roadrunner joint venture and supply areas in Canada and the United States via our interstate and intrastate natural gas pipelines and our Northern Border Pipeline joint venture, which enables us to provide essential natural gas transportation and storage services to end users. Continued demand from local distribution companies, electric-generation facilities and large industrial companies resulted in low-cost expansions in 2019 and 2020 that position us well to provide additional expansions for our customers in 2021. Our natural gas transportation capacity contracted was not significantly impacted by market conditions and COVID-19 in 2020, as our end users rely on natural gas to support their business regardless of commodity price fluctuations. We continued to experience stable fee-based earnings throughout 2020 with transportation capacity more than 95% contracted with firm commitments, and we expect these stable fee-based earnings to continue into 2021 at similarly contracted levels.

NGLs - In our Natural Gas Liquids segment, NGL volumes increased for the year ended December 31, 2020, compared with the same period in 2019, due primarily to increased volumes in the Rocky Mountain region, where we are the largest NGL takeaway provider. While we saw significant declines in volumes in the second quarter 2020, due to reduced demand as a result of COVID-19, by the third quarter 2020 average volumes exceeded pre-COVID-19 levels. NGL volumes were also favorably impacted by ethane production driven by improved ethane recovery economics due to increased demand from petrochemical manufacturers. We expect the improved NGL volumes to continue into 2021, and to benefit without significant capital investment, from our integrated assets, which were strengthened through our recently completed capital-growth projects. Our Elk Creek pipeline was completed in two phases during the second half of 2019. In 2020, we completed an extension of our Bakken NGL pipeline, the construction and extension of our Arbuckle II pipeline and the construction of our 125 MBbl/d MB-4 fractionator.

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 sustaining our dividends per share with a focus on safe, reliable, environmentally responsible, legally compliant and reliable operations for our customers, employees, contractors and the public through the following:
Operate in a safe, reliable and environmentally responsible manner - environmental, safety and health continues to be a primary focus for us, and our emphasis on personal and process safety has produced improving trends in the key indicators we track. We also continue to seek ways to reduce our environmental impact by conserving resources and utilizing more efficient technologies. We are preparing for the future energy transition and our role in meeting the world’s energy needs in an environmentally responsible way. In 2020, we were included in the Dow Jones Sustainability North America Index for the second consecutive year and added to the Dow Jones Sustainability World Index, which recognize companies for industry-leading environmental, social and governance performance;
Pursue organic investments in our existing operating regions to support earnings growth - we expect earnings growth and dividend stability provided by significant earnings power and available operating capacity from our recently
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completed capital-growth projects. As producer activity warrants additional infrastructure, we have the option for low-cost expansions of existing infrastructure to accommodate increasing volumes;
Manage our balance sheet and maintain investment-grade credit ratings - we seek to maintain investment-grade credit ratings, pay down debt and internally fund capital-growth projects, when producer activity levels warrant additional infrastructure. At December 31, 2020, we had no borrowings outstanding under our $2.5 Billion Credit Agreement and $524.5 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.

NARRATIVE DESCRIPTION OF BUSINESS

We report operations in the following business segments:
Natural Gas Gathering and Processing;
Natural Gas Liquids; and
Natural Gas Pipelines.
oke-20201231_g4.jpg

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. Our completed capital-growth projects in the Williston Basin increased our gathering and processing capacity and enable us to capture increased natural gas production from new wells and previously flared natural gas production.

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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 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.
oke-20201231_g5.jpg
Property - Our Natural Gas Gathering and Processing segment includes 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.

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.

Our paused and suspended growth projects are 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:
Fee with POP 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 65% and 63% of supply volumes in this segment for 2020 and 2019, respectively.
Fee with POP 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 29% and 33% of supply volumes in this segment for 2020 and 2019, 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 6% and 4% of supply volumes in this segment in 2020 and 2019, respectively.

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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 66% and 84% for 2020 and 2019, respectively. Our utilization rates decreased in 2020 due primarily to reduced demand as a result of COVID-19. We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service.

Unconsolidated Affiliates - Our unconsolidated affiliates in this segment are not material.

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.

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 Kansas, Missouri, Nebraska, Iowa and Illinois. We have a 50% ownership interest in Overland Pass Pipeline Company, which operates an interstate NGL pipeline originating in Wyoming and Colorado and terminating in Kansas. 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 lease rail cars and own and operate truck- and rail-loading and -unloading facilities connected to our NGL fractionation, storage 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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oke-20201231_g6.jpg
Property - Our Natural Gas Liquids segment includes the following assets:
9,130 miles of gathering pipelines with operating capacity of 1,760 MBbl/d, including 6,330 miles of FERC-regulated pipelines with operating capacity of 1,460 MBbl/d;
4,350 miles of distribution pipelines with operating capacity of 1,150 MBbl/d, including 4,180 miles of FERC-regulated pipelines with operating capacity of 1,080 MBbl/d;
eight NGL fractionators with combined operating capacity of 920 MBbl/d (includes interests in our proportional share of operating capacity), including 520 MBbl/d in the Mid-Continent region and 400 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 30 MMBbl; and
eight NGL product terminals.

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 paused and suspended growth projects are 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 our Natural Gas Liquids segment are derived primarily from commodity sales and purchases and fee-based services. We 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
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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 and serving 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, decreased in 2020, due primarily to reduced demand as a result of COVID-19, which was partially offset by ethane economics, including the impact of ethane rejection in 2019 and ethane recovery in 2020. The utilization rates for 2020 and 2019, respectively, were as follows:
our NGL gathering pipelines were 61% and 78%;
our NGL distribution pipelines were 51% and 63%; and
our NGL fractionators were 77% and 84%.

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 - We have a 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. Our other unconsolidated affiliates in this segment are not material.

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 under the Interstate Commerce Act, which gives the FERC jurisdiction to regulate 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, through its wholly owned assets, provides transportation and storage services to end users. We have 50% ownership interests in Northern Border Pipeline and Roadrunner, which provide transportation services to various end users.

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;
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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 throughout 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.
oke-20201231_g7.jpg
Property - Our Natural Gas Pipelines segment includes 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.
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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 of natural gas in-kind based on the natural gas volumes transported.

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

Utilization - Our natural gas pipelines were 96% and 98% subscribed in 2020 and 2019, respectively, and our natural gas storage facilities were 71% and 64% subscribed in 2020 and 2019, respectively.

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

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
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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 components, used for a range of products that improve our daily lives and promote economic growth, including health care products, recyclable food packaging, clothing, technology, building materials, industrial, manufacturing and energy infrastructure, lightweight vehicle components and batteries. Propane is also used to heat homes and businesses.

See additional discussion regarding the impacts of COVID-19 on supply and demand under “Business Update, Market Conditions and COVID-19” in our Executive Summary at the beginning of this Item 1. Business.

Commodity Prices - In March 2020, the increase in crude oil supply combined with a decrease in crude oil demand stemming from the global response and uncertainties related to COVID-19 resulted in a sharp decline in crude oil prices. However, in the third quarter 2020, prices significantly improved from second quarter lows. Our earnings are primarily fee-based in all three of our segments, however 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 fee with POP contracts. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. 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 minimal 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 may affect our customer demand for our natural gas storage services.

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, 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;
proximity of our assets to alternative energy production;
location of our assets relative to those of our competitors;
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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 and our competitors’ infrastructure projects may affect commodity prices 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 natural gas gathering and processing companies. Our downstream commodity sales customers are primarily petrochemical, refining and marketing companies, utilities, large industrial companies, natural gasoline distributors, propane distributors and municipalities. 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) 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, wildlife conservation, 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, reputational harm and/or interruptions in our operations that could be material to our results of operations or financial condition. 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. We also cannot assure that existing permits will not be revised or cancelled, potentially impacting facility construction activities or ongoing operations.

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 GHG emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. 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;
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(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 Scope 1 GHG emissions, which are emissions directly sourced from our facilities.

We participate in the EPA’s Natural Gas STAR Program and the Our Nation’s Energy (ONE) Future Coalition 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.

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 rulemaking 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. We do not anticipate the potential capital and operating expenditures related to the first section of rules to create a material impact to our planned capital or operations and maintenance costs. At this point, we do not fully know the impact of the regulations that remain to be finalized. Coupled together, these new rules may provide increased requirements for operating and maintenance, integrity management, public awareness and civil/criminal penalties; however, 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 2020, legislation was passed to reauthorize PHMSA through 2024. Certain requirements for operations and maintenance, integrity management, leak detection and public awareness will be subject to new rulemaking as a result. 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 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 2019 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
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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 rulemaking 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 rulemakings. 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 rulemakings 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 final rule associated with these regulations was issued in December 2014. We provided information regarding our chemicals via Top-Screens submitted to Homeland Security, and our facilities subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, one of our facilities has been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to complete Site Security Plans, including possible physical security enhancements. The cost of the Site Security Plans and security enhancements did not 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.

HUMAN CAPITAL

The long-term sustainability of our business is dependent on our continued ability to attract, select, develop, motivate, challenge and retain a diverse group of employees to execute our business strategies. We manage our human capital by offering compensation and benefits that are designed to position us as an employer of choice. We also invest significant time and resources developing our employees, training them on health, safety and compliance matters and building inclusive, high-performing teams.

As of December 31, 2020, we had 2,886 employees. Listed below is a summary of our human capital resources, measures and objectives that are collectively important to our success as an organization.

Culture - Our success is due in large part to the skills, experience and dedication of our employees. We are committed to cultivating an inclusive and dynamic work environment where talented people can find opportunities to succeed, grow and contribute to the success of the company. Our employees work each day to provide safe and reliable services to a wide range of customers in the states where we operate. Our core values - Ethics, Quality, Diversity, Value and Service - guide the way in which our employees conduct our business and operations. Our core value of Ethics means our actions are founded on trust, honesty and integrity through open communications and adherence to the highest standards of personal, professional and business ethics. Our core value of Quality drives us to make continuous improvements in our quest for excellence. Our core value of Diversity means we value the diversity, dignity and worth of each employee, and believe that a diverse and inclusive workforce is critical to our continued success. Our core value of Value means we are committed to creating value for all stakeholders - employees, customers, investors and our communities - through the optimum development and utilization of our resources. Finally, our core value of Service means we provide responsive, flexible service to customers, and commit to preserving the environment, providing a safe work environment and improving the quality of life for employees where they live and work.

Diversity and Inclusion - Our diversity and inclusion (D&I) strategy is a cross-functional effort that draws upon contributions from employees at all levels of the organization and is focused on enhancing the workplace to retain and attract talent. The strategy is guided by a D&I Council composed of a diverse group of employees who represent different demographics, work locations, points of view, roles and levels of seniority. Our Chief Executive Officer serves as chair of the D&I Council and attends all meetings of the D&I Council, along with the rest of our senior leadership team. We also have a team within our organizational development group that is wholly dedicated to supporting our D&I efforts.

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In 2020, we provided funding and support for five employee-led business resource groups (BRGs): a Black/African American Resource Group; an Indigenous/Native American Resource Group; a Latinx/Hispanic American Resource Group; a Veterans Resource Group; and a Women’s Resource Group. Each BRG’s purpose is to promote the attraction, development, motivation and retention of members of traditionally underrepresented groups in our industry and workplace in an effort to drive positive business outcomes. A key factor in the success of our BRGs is the active participation by officer-level executive sponsors and allies from outside the BRG’s underrepresented populations. All employees are invited to become a supporter of one or more of our BRGs.

We embed D&I concepts into our core leadership development curriculum and sponsor a number of internal programs intended to promote D&I. In addition, we seek to give back to the communities where we operate by partnering on initiatives to support underrepresented community members and local charitable organizations.

Employee Safety - The safety of our employees is critical to our operations and success. By monitoring the integrity of our assets and promoting the safety of our employees, we are investing in the long-term sustainability of our businesses. We continuously assess the risks our employees face in their jobs, and we work to mitigate those risks through training, appropriate engineering controls, work procedures and other preventive safety programs. Reducing incidents and improving our personal safety incident rates are important, but we are not focused only on statistics. Low personal safety incident rates alone cannot prevent a large-scale incident, which is why we continue to focus on enhancing our Environmental, Safety and Health management systems and process safety programs, such as key risk/key control identification and knowledge sharing. We endeavor to operate our assets safely, reliably and in an environmentally responsible manner. We maintain mature and robust programs that guide trained staff in the completion of these activities, and we continue to enhance and improve these programs and our internal capabilities. In response to COVID-19, we have taken steps to manage the potential impacts of the COVID-19 outbreak on our employees. We continue to practice remote work procedures when possible to protect the safety of our employees and their families, and have taken extra precautions for our employees who work in the field or need to report to a ONEOK facility, such as increased facility access restrictions, workspace modifications, social distancing, face covering protocols and sanitation procedures. During 2020, ONEOK employees completed more than 50,000 hours of virtual and classroom training focused on employee safety.

Health and Welfare - We provide a variety of benefits to help promote the health and welfare of our employees and their families. These benefits include medical, dental and vision plans, virtual health visits and engagement of third-party service providers to offer company on-site and near-site clinics in several of our operating areas, which have access to both rapid antigen and polymerase chain reaction COVID-19 testing. In response to COVID-19, we provided temporary benefit adjustments, including waiving charges for virtual health visits, COVID-19 diagnostic tests and COVID-19 vaccines. Current resources include a dedicated employee information site that houses regular updates regarding COVID-19 and provides resources for prevention best practices, physical health, mental health and caregiver services. Eligible employees also have access, at no charge, to an employee assistance program, a medical second opinion service and a health care concierge service to assist with finding in-network providers and resolving claims. We offer full pay for maternity, paternity or adoption leave of up to 240 hours per qualifying event. We also provide up to $10,000 for reasonable and necessary expenses of a qualifying adoption. Additional benefits provided for the welfare of our employees include, among others, life insurance and long-term disability plans, health and dependent care flexible spending accounts, and full pay while on bereavement and personal and family care leave.

We also provide the opportunity for our employees to help fellow employees through the ONE Trust Fund by contributing donated vacation hours or monetary donations. The ONE Trust Fund is a nonprofit, charitable organization, that serves our employees in times of personal crises due to natural disasters, medical emergencies or other hardships.

Personal and Professional Development - We provide various options to assist with career growth and development. For employees just entering the workforce who desire to advance their career and continue to learn or for the professional who is interested in developing their skills, we provide education and training in a variety of areas, including leadership, functional and industry-specific topics, professional development and skill-building opportunities. Our organizational development and D&I teams provide live virtual classroom training, computer-based self-study and one-on-one coaching that is available to all employees.

We value education and assist eligible employees with the expense of furthering their education in job-related fields, including up to $5,000 per year in qualifying tuition expenses. We also may reimburse employees for certain job-related professional certification examination fees.

Recruiting - We make it a priority to attract, select, develop, motivate, challenge and retain the talent necessary to support our key business strategies. We use targeted recruitment events, maintain strong relationships with area technical schools, colleges
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and universities, and we offer compensation benefits and career opportunities that are designed to position us as an employer of choice. In response to COVID-19, we continue to recruit and hire new employees for critical positions through virtual interviews. D&I continue to be a priority in recruiting, and we deploy sourcing strategies designed to access talent from groups that are historically underrepresented in our industry and workplace.

Retirement - We maintain a 401(k) Plan for our employees and match 100% of employee contributions up to 6% of eligible compensation, subject to applicable tax limits. We also have a defined benefit pension plan covering certain employees and former employees hired prior to January 1, 2005. Employees that do not participate in our defined benefit pension plan are eligible to receive quarterly and annual profit-sharing contributions under our 401(k) Plan. As of December 31, 2020, approximately 96% of eligible employees were contributing to our 401(k) Plan. In first quarter 2020, we opted into the CARES Act 401(k) penalty-free hardship withdrawal and loan deferral programs for employees. For additional information about our retirement benefits, see Note K of the Notes to Consolidated Financial Statements in this Annual Report.

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 PositionAgeBusiness Experience in Past Five Years
John W. Gibson68 2011 to presentChairman of the Board, ONEOK
Chairman of the Board2007 to 2017Chairman of the Board, ONEOK Partners
Terry K. Spencer61 2014 to presentPresident and Chief Executive Officer, ONEOK
President and Chief Executive Officer2014 to 2017President and Chief Executive Officer, ONEOK Partners
2014 to presentMember of the Board of Directors, ONEOK
2014 to 2017Member of the Board of Directors, ONEOK Partners
Robert F. Martinovich63 2015 to presentExecutive Vice President and Chief Administrative Officer, ONEOK
Executive Vice President and Chief Administrative Officer2015 to 2017Executive Vice President and Chief Administrative Officer, ONEOK Partners
Walter S. Hulse III572019 to presentChief Financial Officer, Treasurer and Executive Vice President, Strategy and Corporate Affairs, ONEOK
Chief Financial Officer, Treasurer and Executive Vice President, Strategy and Corporate Affairs2017 to 2019Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK
2015 to 2017Executive Vice President, Strategic Planning and Corporate Affairs, ONEOK and ONEOK Partners
Kevin L. Burdick562017 to presentExecutive Vice President and Chief Operating Officer, ONEOK
Executive Vice President and Chief Operating Officer2017Executive Vice President and Chief Commercial Officer, ONEOK and ONEOK Partners
2016 to 2017Senior Vice President, Natural Gas Gathering and Processing, ONEOK Partners
2013 to 2016Vice President, Natural Gas Gathering and Processing, ONEOK Partners
Charles M. Kelley622018 to presentSenior Vice President, Natural Gas, ONEOK
Senior Vice President, Natural Gas2017 to 2018Senior Vice President, Natural Gas Gathering & Processing, ONEOK
2015 to 2017Senior Vice President, Corporate Planning and Development, ONEOK and ONEOK Partners
Sheridan C. Swords512017 to presentSenior Vice President, Natural Gas Liquids, ONEOK
Senior Vice President, Natural Gas Liquids2013 to 2017Senior Vice President, Natural Gas Liquids, ONEOK Partners
Stephen B. Allen472017 to presentSenior Vice President, General Counsel and Assistant Secretary, ONEOK
Senior Vice President, General Counsel
and Assistant Secretary
2008 to 2017Vice President and Associate General Counsel, ONEOK and ONEOK Partners
Mary M. Spears412019 to presentVice President and Chief Accounting Officer, ONEOK
Vice President and Chief Accounting Officer2015 to 2019Director, SEC Reporting, ONEOK
2015 to 2017Director, SEC Reporting, ONEOK Partners

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

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Director Independence Guidelines, Corporate Sustainability Report, Response to COVID-19 and the written charter of our Audit Committee also are available on our website, and we will provide copies of these documents upon request.
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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.

RISK FACTORS RELATED TO OUR BUSINESS AND INDUSTRY

The COVID-19 pandemic has affected adversely, and could further affect adversely, our results of operations.

The COVID-19 pandemic led to global and regional economic disruption, volatility in the financial markets and a weakened commodity price environment. The outbreak and government measures taken in response, including extended quarantines, closures and reduced operations of businesses had a significant adverse impact, both direct and indirect, on our business and the economy. Due to reductions in economic activity, the world experienced reduced demand for crude oil, refined products, NGLs and natural gas, and weakened commodity prices, which affected adversely our operations.

Uncertainty remains regarding the duration of global impacts due to COVID-19 and the possible resurgence or mutation of the virus. This uncertainty, and the occurrence of these events and measures taken in response, could further affect adversely our results of operations by, among other things, reducing demand for the services we provide, impacting our supply chains and the availability and efficiency of our workforce, creating operational challenges and impacting our ability to access capital markets. The degree to which the pandemic further impacts our business and results of operations will depend on future developments beyond our control, including the success of actions to contain the virus, the length of time needed to vaccinate a significant segment of the global population, how quickly and to what extent normal economic and operating conditions can resume, and the severity and duration of the global and regional economic downturn that results from the pandemic.

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’ desire and ability to obtain necessary permits, drilling rights and surface access in a timely manner and on reasonable terms;
crude oil and associated natural gas field characteristics and production performance; and
capacity constraints and/or shut downs on the pipelines that transport crude oil, natural gas and NGLs from 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.
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Our operating results may be affected adversely by unfavorable economic and market conditions.

In addition to impacts from the COVID-19 pandemic, 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 markets, as well as in the specific segments 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.

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

Lower commodity prices could reduce crude oil, natural gas and NGL production which could decrease the demand for our services. Additionally, 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. As commodity prices decline, we could be paid less for our commodities thereby reducing our cash flows. Historically, commodity prices have been volatile and can change quickly. For example, in March 2020, unsuccessful negotiations between the Organization of the Petroleum Exporting Countries (OPEC) and Russia regarding crude oil production cuts resulted in a price war between Saudi Arabia and Russia. As a result, the global supply of crude oil significantly exceeded demand and led to a collapse in crude oil prices. It is likely that commodity prices will continue to be volatile 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;
geopolitical conditions impacting supply and demand for natural gas, NGLs and crude oil;
production decisions by other countries, such as the failure of countries to abide by recent agreements to reduce production volumes;
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;
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.

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.

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.

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.
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Due to climate change concerns, some investors may choose to either not invest, or to 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.

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.

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 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, infectious disease including a pandemic, geopolitical reactions, 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.

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. 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. 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.

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

Production areas outside of our operating regions may compete with natural gas and NGL supply originating in production areas connected to our systems, which 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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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 fee with POP 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; 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 and an increase in remote work arrangements due to the COVID-19 pandemic, 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. According to experts, since the beginning of the COVID-19 pandemic 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 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
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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.

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 and social 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.

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.

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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.

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.

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.

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

We participate in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets that may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100%) 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
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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.

RISK FACTORS RELATED TO REGULATION

Increased regulation of exploration and production activities, including hydraulic fracturing, well setbacks and disposal of wastewater, 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 wastewater, could result in operational delays, increased 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.

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 and operation 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.

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, 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.

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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.

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. Increased litigation challenging oil and gas development and changes to laws, regulations and policies could impact adversely our business.

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.

Increased litigation challenging oil and gas development, as well as changes to laws, regulations and policies could impact our business. These actions could, among other things, impact our customers’ activities, our existing permits and our ability to obtain permits for new development projects, which could affect adversely our business, financial position, or results of operations.

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
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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.

RISK FACTORS RELATED TO FINANCING OUR BUSINESS

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. However, in November 2020, the administrator of LIBOR, the ICE Benchmark Administration, announced its intention to continue publications of all U.S. dollar LIBOR tenors through June 2023, with the exception of one-week and two-month tenors which will cease at the end of 2021. 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.

Our $2.5 Billion Credit Agreement includes provisions that grant the administrative agent broad discretion to establish a replacement rate for LIBOR, if necessary, which could increase our short-term borrowing costs for amounts issued under this facility.

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

Our long-term debt has been assigned an investment-grade credit rating of “Baa3” by Moody’s and “BBB” by both S&P and Fitch. Our commercial paper program has been assigned an investment-grade credit rating of Prime-3, A-2 and F-2 by Moody’s, S&P and Fitch, respectively. 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 these credit rating agencies. If these agencies were to downgrade our long-term debt or our commercial paper rating, particularly below investment grade, our borrowing costs could increase, which would affect adversely our financial results, and our potential pool of investors and funding sources could decrease. Ratings from these agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.

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

As of December 31, 2020, we had total indebtedness of $14.4 billion. Our indebtedness and guarantee obligations could have significant consequences. For example, they could:
make it more difficult for us to satisfy our obligations with respect to senior notes and other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or the senior notes;
impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;
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.

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Our $2.5 Billion Credit Agreement contains provisions that restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our $2.5 Billion Credit Agreement contains 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. It also requires 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.

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 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.

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 ONEOK Partners and the Intermediate Partnership have guaranteed our debt securities, the guarantees are subject to release under certain circumstances, and we have subsidiaries that are not guarantors. In those cases, the debt securities effectively are 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.

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;
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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.

GENERAL RISK FACTORS

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.

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.

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

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.

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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.

For further discussion of impairments of goodwill, long-lived assets and equity-method investments, see Notes A, E, D and M, respectively, of the Notes to Consolidated Financial Statements in this Annual Report.

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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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.

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.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.    PROPERTIES

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

ITEM 3.    LEGAL PROCEEDINGS

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

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

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

At February 16, 2021, there were 13,844 holders of record of our 444,983,595 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, 2015, and ending on December 31, 2020.

Value of a $100 Investment, Assuming Reinvestment of Distributions/Dividends,
at December 31, 2015, and at the End of Every Year Through December 31, 2020.

oke-20201231_g8.jpg

 Cumulative Total Return
 Years Ended December 31,
 20162017201820192020
ONEOK, Inc.$249.37 $244.18 $259.53 $383.51 $217.21 
S&P 500 Index$111.96 $136.40 $130.42 $171.49 $203.04 
ONEOK Peer Group (a)$148.02 $138.01 $117.37 $127.36 $90.69 
Alerian Midstream Energy Select Index (b)$143.55 $144.65 $119.08 $145.69 $111.56 
(a) - The ONEOK Peer Group is composed of the following companies: DCP Midstream, LP; Enable Midstream Partners, LP; Energy Transfer LP; EnLink Midstream, LLC; Enterprise Products Partners L.P.; Kinder Morgan, Inc.; Magellan Midstream Partners, L.P.; MPLX LP; NuStar Energy L.P.; Plains All American Pipeline, L.P.; Targa Resources Corp.; and The Williams Companies, Inc.
(b) - The Alerian Midstream Energy Select Index measures the composite performance of approximately 36 North American energy infrastructure companies who are engaged in midstream activities involving energy commodities.

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ITEM 6.    SELECTED FINANCIAL DATA

The following table sets forth our selected financial data for the periods indicated:
 Years Ended December 31,
 20202019201820172016
 
(Millions of dollars, except per share data)
Revenues$8,542.2 $10,164.4 $12,593.2 $12,173.9 $8,920.9 
Net income$612.8 $1,278.6 $1,155.0 $593.5 $743.5 
Total assets$23,078.8 $21,812.1 $18,231.7 $16,845.9 $16,138.8 
Long-term debt, including current maturities$14,236.1 $12,487.4 $9,381.0 $8,524.3 $8,330.6 
EPS - total
Basic$1.42 $3.09 $2.80 $1.30 $1.67 
Diluted$1.42 $3.07 $2.78 $1.29 $1.66 
Dividends declared per share of common stock$3.74 $3.53 $3.245 $2.72 $2.46 

Changes in commodity prices and sales volumes affect both revenue and cost of sales and fuel, and, therefore, the changes in revenue in the above table are largely offset in cost of sales and fuel.

In 2020, we incurred $644.9 million in noncash impairment charges, which had an adverse impact on our financial results for the year ended December 31, 2020. In 2017, we recorded noncash impairment charges of $20.2 million.

Upon adoption of Topic 606 in January 2018, we determined that certain Natural Gas Gathering and Processing segment fee with POP contracts and Natural Gas Liquids segment exchange services contracts that include the purchase of commodities are supplier contracts. Contractual fees in these identified contracts are recorded as a reduction of the commodity purchase price in cost of sales and fuel. In 2017 and prior periods, these fees were recorded as services revenue.

In 2017, we recorded a one-time noncash charge to net income through income tax expense of $141.3 million, related to the revaluation of our deferred tax balances and a valuation allowance on certain state net operating loss and tax credit carryforwards resulting from the enactment of the Tax Cuts and Jobs Act.

ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with Part I, Item 1, Business, our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.

RECENT DEVELOPMENTS

Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for additional information.

COVID-19 - While we are still experiencing global and regional economic disruption due primarily to COVID-19, our producers have reversed curtailments that were put in place during the second quarter 2020, bringing volumes back to pre-COVID-19 levels as prices significantly improved from second quarter 2020 lows. The full impact of the continued global and regional economic disruption will depend on the unknown duration and severity of COVID-19, and, among other things, the impact of governmental actions imposed in response to COVID-19, the pace and scale of economic recovery and corresponding demand for crude oil, and the impacts to commodity prices. We continue to monitor producers’ drilling, completion and production plans, which are increasingly positive as commodity prices have stabilized and improved, and our expectations for 2021 include the potential for an improving pace of drilling and completion activity.

In this challenging market environment, we expect to maintain sufficient liquidity and financial stability into 2021 due to cash on hand from our June 2020 equity issuance, cash flows from operations and access to our undrawn $2.5 Billion Credit Agreement. We have no debt maturities prior to 2022, and our investment-grade credit ratings have remained stable.

Sustainability - In 2020, we were included in the Dow Jones Sustainability North America Index for the second consecutive year and added to the Dow Jones Sustainability World Index (DJSI World), which recognize companies for industry-leading
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environmental, social and governance performance. We are currently the only North American energy company included in the DJSI World group of global sustainability leaders. We continue to look for ways to reduce our environmental impact and utilize more efficient technologies. We are preparing for the future energy transition and our role in meeting the world’s energy needs in an environmentally responsible way.

Growth Projects - We operate an integrated, reliable and diversified network of NGL and natural gas gathering, processing, fractionation, storage and transportation assets connecting supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers. We have completed significant capital-growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas and NGL infrastructure. These projects provide us the capacity to benefit from future supply growth without significant capital investment. In the first quarter 2020, due to the decline in commodity prices and economic demand disruption caused by COVID-19, we suspended our announced plans to construct the Demicks Lake III natural gas processing plant, the fourth expansion of the ONEOK West Texas NGL pipeline system, and reduced the scope of the expansion of our Elk Creek pipeline and various other paused projects. These projects can be restarted quickly when producer activity warrants additional infrastructure. Our announced capital-growth projects are outlined in the table below:

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Project (b)ScopeApproximate
Costs (a)

Completion
Natural Gas Gathering and Processing
(In millions)
Demicks Lake I plant and related infrastructure
200 MMcf/d processing plant and related gathering infrastructure in the core of the Williston Basin$400Completed
October 2019
Supported by acreage dedications with long-term primarily fee-based contracts
Demicks Lake II plant and related infrastructure
200 MMcf/d processing plant and related gathering infrastructure in the core of the Williston Basin$410Completed
January 2020
Supported by acreage dedications with long-term primarily fee-based contracts
Bear Creek plant expansion and related infrastructure200 MMcf/d processing plant expansion and related gathering infrastructure in the Williston Basin$405Paused (c)
Supported by acreage dedications with long-term primarily fee-based contracts
Natural Gas Liquids
Elk Creek pipeline and related infrastructure
900-mile NGL pipeline from the Williston Basin to the Mid-Continent region, with capacity of up to 240 MBbl/d, and related infrastructure$1,400Completed
December 2019
Anchored by long-term contracts
Expansion capability up to 400 MBbl/d with additional pump facilities
Arbuckle II pipeline and related infrastructure
530-mile NGL pipeline from the STACK area to Mont Belvieu, Texas, and related infrastructure$1,360Completed
March 2020
Supported by long-term contracts
Expansion capability up to 1 MMBbl/d
MB-4 fractionator and related infrastructure125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu$575Completed
March 2020 (d)
Fully contracted with long-term contracts
ONEOK West Texas NGL pipeline expansion and Arbuckle II connectionIncreasing mainline capacity by 80 MBbl/d with additional pump facilities and pipeline looping$295Completed
June 2020 (e)
Connecting ONEOK West Texas NGL pipeline system to the Arbuckle II pipeline
Supported by long-term dedicated production from six third-party processing plants expected to produce up to 60 MBbl/d
Bakken NGL pipeline extension
75-mile NGL pipeline in the Williston Basin connecting to a third-party processing plant$100Completed
August 2020
Supported by a long-term contract with a minimum volume commitment
Arbuckle II extension project and additional gathering infrastructureProvide additional takeaway capacity in the STACK area$240Completed
Allow increasing volumes on the Elk Creek pipeline access to fractionation capacity at Mont Belvieu, TexasAugust 2020
Arbuckle II pipeline expansionIncreasing mainline capacity with additional pump facilities$60Paused (c)
Increases capacity to 500 MBbl/d
MB-5 fractionator and related infrastructure
125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu$750Paused (c)
Fully contracted with long-term contracts
ONEOK West Texas NGL pipeline expansionIncreasing mainline capacity by 40 MBbl/d$145Paused (c)
Supported by long-term dedicated production from third-party processing plants expected to produce up to 45 MBbl/d
Mid-Continent fractionation facility expansions
65 MBbl/d of expansions at our Mid-Continent NGL facilities$150Paused (c)
(a) - Excludes capitalized interest/AFUDC.
(b) - Projects listed exclude our suspended capital-growth projects, which include the Demicks Lake III natural gas processing plant, the fourth expansion of the ONEOK West Texas NGL pipeline system and a reduction in the scope of the expansion of the Elk Creek pipeline.
(c) - Given the current environment, we paused the majority of construction activities on these projects and do not expect to complete construction by the original target completion date.
(d) - We completed 75 MBbl/d in December 2019 and completed the remaining 50 MBbl/d in March 2020.
(e) - We completed expansions to increase mainline capacity by approximately 45 MBbl/d in the first quarter 2020 and completed the remaining portion of this project in the second quarter 2020, which was delayed due to weather.

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Ethane Production - Ethane production fluctuates over short-term periods driven by ethane economics, and as a result, volumes can also fluctuate period to period. Ethane volumes under long-term contracts delivered to our NGL system averaged 375 MBbl/d in 2020, compared with 385 MBbl/d in 2019, but increased by approximately 30 MBbl/d in the second half of 2020, compared with the second quarter 2020, due primarily to improved ethane economics. We expect ethane production to continue to fluctuate throughout 2021.

Debt Issuances and Repayments - In May 2020, we completed an underwritten public offering of $1.5 billion senior unsecured notes consisting of $600 million, 5.85% senior notes due 2026; $600 million, 6.35% senior notes due 2031; and $300 million, 7.15% senior notes due 2051. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.48 billion. A portion of the proceeds was used to repay the outstanding borrowings under our $1.5 Billion Term Loan Agreement. The remainder was used for general corporate purposes.

In March 2020, we completed an underwritten public offering of $1.75 billion senior unsecured notes consisting of $400 million, 2.2% senior notes due 2025; $850 million, 3.1% senior notes due 2030; and $500 million, 4.5% senior notes due 2050. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.73 billion. A portion of the proceeds was used to pay all outstanding amounts under our commercial paper program. The remainder was used for general corporate purposes, which included repayment of other existing indebtedness and funding capital expenditures.

In 2020, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $224.4 million for an aggregate repurchase price of $199.6 million with cash on hand. In connection with these open market repurchases, we recognized $22.3 million of net gains on extinguishment of debt.

Equity Issuances - In June 2020, we completed an underwritten public offering of 29.9 million shares of our common stock at a public offering price of $32.00 per share, generating net proceeds, after deducting underwriting discounts, commissions and offering expenses, of $937.0 million. A portion of the proceeds was, and we anticipate the remainder will be, used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures.

Dividends - During 2020, we paid dividends totaling $3.74 per share, an increase of 6% from the $3.53 per share paid in 2019. In February 2021, we maintained and paid a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis), which is consistent with the same quarter in the prior year.

Impairments - Due to historic events as a result of COVID-19 impacting supply, demand and commodity prices, in 2020 we evaluated our goodwill, certain long-lived asset groups and equity investments for impairment. Based on the results, we recorded the following impairment charges:

Natural Gas Gathering and Processing - In 2020, we recorded $382.2 million of noncash impairment charges related primarily to certain long-lived asset groups that were not recoverable, $153.4 million of noncash impairment charges related to goodwill and $30.5 million of noncash impairment charges related to our 10.2% investment in Venice Energy Services Company.

Natural Gas Liquids - In 2020, we recorded $71.6 million of noncash impairment charges related primarily to certain inactive assets as our expectation for future use of the assets changed and $7.2 million of noncash impairment charges related to our 50% investment in Chisholm Pipeline Company.

For additional information on our impairment charges, see Notes A, D, E and M of the Notes to Consolidated Financial Statements in this Annual Report.

FINANCIAL RESULTS AND OPERATING INFORMATION

How We Evaluate Our Operations

Management uses a variety of financial and operating metrics to analyze our performance. Our consolidated financial metrics include: (1) operating income; (2) net income; (3) diluted EPS; and (4) the following non-GAAP financial measures: adjusted EBITDA and distributable cash flow. We evaluate segment operating results using adjusted EBITDA and our operating metrics, which include various volume and rate statistics that are relevant for the respective segment. These operating metrics allow investors to analyze the various components of segment financial results in terms of volumes and rate/price. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. For additional information on our operating metrics, see the respective segment subsections of this “Financial Results and Operating Information” section.

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Non-GAAP Financial Measures - Adjusted EBITDA, distributable cash flow and dividend coverage ratio are non-GAAP measures of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation expense and certain other noncash items. Distributable cash flow is defined as adjusted EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, excluding noncash impairment charges, adjusted for net cash distributions received from unconsolidated affiliates and certain other items. Dividend coverage ratio is defined as distributable cash flow to common shareholders divided by the dividends paid in the period. We believe these non-GAAP financial measures are useful to investors because they and similar measures are used by many companies in our industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA, distributable cash flow and dividend coverage ratio should not be considered alternatives to net income, EPS or any other measure of financial performance presented in accordance with GAAP. Additionally, these calculations may not be comparable with similarly titled measures of other companies.

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods indicated:
 Years Ended December 31,2020 vs. 20192019 vs. 2018
Financial Results202020192018$ Increase (Decrease)
 
(Millions of dollars, except per share amounts)
Revenues
Commodity sales$7,255.2 $8,916.1 $11,395.6 (1,660.9)(2,479.5)
Services1,287.0 1,248.3 1,197.6 38.7 50.7 
Total revenues8,542.2 10,164.4 12,593.2 (1,622.2)(2,428.8)
Cost of sales and fuel (exclusive of items shown separately below)
5,110.1 6,788.0 9,422.7 (1,677.9)(2,634.7)
Operating costs886.1 982.9 907.0 (96.8)75.9 
Depreciation and amortization578.7 476.5 428.6 102.2 47.9 
Impairment charges607.2 — — 607.2 — 
(Gain) loss on sale of assets(1.3)2.6 (0.6)3.9 (3.2)
Operating income$1,361.4 $1,914.4 $1,835.5 (553.0)78.9 
Equity in net earnings from investments$143.2 $154.5 $158.4 (11.3)(3.9)
Impairment of equity investments$(37.7)$— $— 37.7 — 
Interest expense, net of capitalized interest$(712.9)$(491.8)$(469.6)221.1 22.2 
Net income$612.8 $1,278.6 $1,155.0 (665.8)123.6 
Diluted EPS$1.42 $3.07 $2.78 (1.65)0.29 
Adjusted EBITDA$2,723.7 $2,580.2 $2,447.5 143.5 132.7 
Distributable cash flow$1,881.6 $2,016.1 $1,822.4 (134.5)193.7 
Capital expenditures$2,195.4 $3,848.3 $2,141.5 (1,652.9)1,706.8 
See reconciliation of net income to adjusted EBITDA and distributable cash flow in the “Non-GAAP Measures” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel in our Consolidated Statements of Income, and, therefore, the impact is largely offset between these line items.

2020 vs. 2019 - Operating income decreased $553.0 million primarily as a result of the following:
a decrease of $607.2 million due to noncash impairment charges in our Natural Gas Gathering and Processing and Natural Gas Liquids segments;
an increase of $102.2 million in depreciation expense due to capital projects placed in service;
Natural Gas Gathering and Processing - a decrease of $47.6 million due primarily to lower realized prices and a decrease of $42.6 million due primarily to natural production declines in the Mid-Continent region; offset partially by
Natural Gas Liquids - an increase of $270.6 million in exchange services due primarily to higher volumes in the Rocky Mountain region and Permian Basin and lower rail and pipeline transportation costs, offset partially by a decrease of $123.5 million in optimization and marketing due primarily to narrower location price differentials, lower optimization volumes and lower marketing earnings;
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a decrease of $96.8 million in operating costs due primarily to reduced outside services, lower materials and supplies expenses, lower employee-related costs and the noncash mark-to-market impact of our share-based deferred compensation plan; and
Natural Gas Pipelines - an increase of $6.7 million in transportation services due primarily to higher firm transportation revenue and a $13.5 million contract settlement, offset partially by lower interruptible revenue.

Net income and diluted EPS decreased due primarily to the items discussed above and higher interest expense related to an increase in our debt balance and lower capitalized interest and noncash impairment charges related to equity investments in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, offset partially by net gains on extinguishment of debt related to open market repurchases. Diluted EPS was also impacted by our equity issuance in June 2020.

Capital expenditures decreased due primarily to our previously completed capital-growth projects as well as our paused and suspended capital-growth projects related to weakened commodity prices and economic disruption caused by COVID-19.

Additional information regarding our financial results and operating information is provided in the discussions for each of our segments and in Non-GAAP Measures.

Selected Financial Results and Operating Information for the Year Ended December 31, 2019 vs. 2018 - The consolidated and segment financial results and operating information for the year ended December 31, 2019, compared with the year ended December 31, 2018, are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2019 Annual Report on Form 10-K, which is available via the SEC’s website at www.sec.gov and our website at www.oneok.com.

Natural Gas Gathering and Processing

Growth Projects - Our Natural Gas Gathering and Processing segment has invested in growth projects in NGL-rich areas in the Williston Basin. See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth projects.

See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
 Years Ended December 31,2020 vs. 20192019 vs. 2018
Financial Results202020192018$ Increase (Decrease)
 
(Millions of dollars)
NGL sales$775.9 $1,024.3 $1,567.2 (248.4)(542.9)
Condensate sales113.5 200.1 208.8 (86.6)(8.7)
Residue natural gas sales771.5 966.1 1,084.2 (194.6)(118.1)
Gathering, compression, dehydration and processing fees and other revenue
159.2 178.1 174.4 (18.9)3.7 
Cost of sales and fuel (exclusive of depreciation and operating costs)
(844.0)(1,302.3)(2,041.4)(458.3)(739.1)
Operating costs, excluding noncash compensation adjustments
(320.0)(352.8)(357.7)(32.8)(4.9)
Equity in net earnings (loss) from investments(1.1)(6.3)0.4 5.2 (6.7)
Other(5.0)(4.5)(4.3)(0.5)(0.2)
Adjusted EBITDA$650.0 $702.7 $631.6 (52.7)71.1 
Impairment charges$566.1 $— $— 566.1 — 
Capital expenditures$446.1 $926.5 $694.6 (480.4)231.9 
See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Measures” section.

Changes in commodity prices and sales volumes affect both revenue and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.

2020 vs. 2019 - Adjusted EBITDA decreased $52.7 million, primarily as a result of the following:
a decrease of $47.6 million due primarily to lower realized prices impacting our fee with POP contracts; and
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a decrease of $42.6 million due primarily to natural production declines in the Mid-Continent region; offset partially by
a decrease of $32.8 million in operating costs due primarily to lower materials and supplies expenses due to reduced asset utilization, lower employee-related costs and outside services.

The year ended December 31, 2020, includes $382.2 million of noncash impairment charges related primarily to certain long-lived asset groups in the Powder River Basin, western Oklahoma and Kansas that were not recoverable, a $153.4 million noncash impairment charge related to goodwill and a $30.5 million noncash impairment charge related to our 10.2% investment in Venice Energy Services Company. For additional information on our impairment charges, see Notes A, D, E and M of the Notes to Consolidated Financial Statements in this Annual Report.

Capital expenditures decreased due primarily to capital-growth projects completed in 2019 and early 2020, as well as several paused capital-growth projects in 2020.

 Years Ended December 31,
Operating Information (a)202020192018
Natural gas gathered (BBtu/d)
2,553 2,753 2,546 
Natural gas processed (BBtu/d) (b)
2,364 2,555 2,382 
Average fee rate ($/MMBtu)
$0.89 $0.92 $0.90 
(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes at company-owned and third-party facilities.

2020 vs. 2019 - Our natural gas gathered and natural gas processed volumes decreased due primarily to natural production declines in the Mid-Continent region. In the Williston Basin, we saw significant declines in volumes in the second quarter 2020 due to production curtailments from some of our crude oil and natural gas producers. By the end of the third quarter 2020, curtailed volumes returned.

Our average fee rate decreased due primarily to production curtailments in the second quarter 2020 on producer contracts with higher fees and lower POP components in the Williston Basin. As these curtailed volumes returned to our system, the Williston Basin’s contribution to our average fee rate increased in the second half of 2020.

Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Natural Gas Liquids

Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market centers NGL supply from shale and other resource development areas. Our growth strategy is focused around connecting diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with NGL product demand from the petrochemical and refining industries and NGL export demand in the Gulf Coast. See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth projects.

In 2020, we connected two third-party natural gas processing plants in the Permian Basin and two third-party natural gas processing plants in the Rocky Mountain region to our NGL system. In addition, one affiliate and two third-party natural gas processing plants in the Rocky Mountain region and one third-party natural gas processing plant in the Mid-Continent region connected to our system were expanded.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

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Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:
 Years Ended December 31,2020 vs. 20192019 vs. 2018
Financial Results202020192018$ Increase (Decrease)
 
(Millions of dollars)
NGL and condensate sales$6,409.3 $7,910.8 $10,319.9 (1,501.5)(2,409.1)
Exchange service revenues and other497.8 424.2 415.7 73.6 8.5 
Transportation and storage revenues182.9 197.5 199.0 (14.6)(1.5)
Cost of sales and fuel (exclusive of depreciation and operating costs)
(5,108.6)(6,690.9)(9,176.8)(1,582.3)(2,485.9)
Operating costs, excluding noncash compensation adjustments
(396.4)(434.4)(378.3)(38.0)56.1 
Equity in net earnings from investments39.9 65.1 67.1 (25.2)(2.0)
Other(7.7)(6.5)(6.0)(1.2)(0.5)
Adjusted EBITDA$1,617.2 $1,465.8 $1,440.6 151.4 25.2 
Impairment charges$78.8 $— $— 78.8 — 
Capital expenditures$1,655.8 $2,796.6 $1,306.3 (1,140.8)1,490.3 
See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Measures” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.

2020 vs. 2019 - Adjusted EBITDA increased $151.4 million, primarily as a result of the following:
an increase of $270.6 million in exchange services due primarily to $137.8 million in higher volumes in the Rocky Mountain region and Permian Basin, $128.4 million in lower costs due primarily to lower rail and pipeline transportation costs, $18.8 million in higher fees charged to customers with minimum volume obligations primarily in the Rocky Mountain region, $17.2 million in higher average fee rates primarily in the Permian Basin and $13.7 million related to lower unfractionated NGLs held in inventory, offset partially by $34.2 million in lower volumes in the Mid-Continent region; and
a decrease of $38.0 million in operating costs due primarily to lower outside services and employee-related costs; offset partially by
a decrease of $123.5 million in optimization and marketing due primarily to a decrease of $78.2 million related to narrower location price differentials and lower optimization volumes, lower marketing earnings of $53.0 million due to lower earnings from purity NGL inventory sales and changes in the value of NGLs held in inventory; and
a decrease of $25.2 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline.

The year ended December 31, 2020, includes $71.6 million of noncash impairment charges related primarily to certain inactive assets and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company. For additional information on our impairment charges, see Notes A, D and M of the Notes to Consolidated Financial Statements in this Annual Report.

Capital expenditures decreased due primarily to completed and paused capital-growth projects.

 Years Ended December 31,
Operating Information202020192018
Raw feed throughput (MBbl/d) (a)
1,084 1,079 1,010 
Average Conway-to-Mont Belvieu OPIS price differential -
ethane in ethane/propane mix ($/gallon)
$0.01 $0.07 $0.15 
(a) - Represents physical raw feed volumes on which we charge a fee for transportation and/or fractionation services.

2020 vs. 2019 - Volumes increased due primarily to increased production at new and existing processing plants in the Rocky Mountain region and Permian Basin, offset partially by lower volumes in the Mid-Continent region and the unfavorable impact from producer curtailments primarily in the second quarter 2020.

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Natural Gas Pipelines

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:
 Years Ended December 31,2020 vs. 20192019 vs. 2018
Financial Results202020192018$ Increase (Decrease)
 
(Millions of dollars)
Transportation revenues$401.7 $393.7 $343.0 8.0 50.7 
Storage revenues68.4 72.6 72.0 (4.2)0.6 
Residue natural gas sales and other revenues9.9 5.7 16.7 4.2 (11.0)
Cost of sales and fuel (exclusive of depreciation and operating costs)
(6.8)(4.6)(16.0)2.2 (11.4)
Operating costs, excluding noncash compensation adjustments
(137.2)