Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our 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 Quarterly Report for additional information.

Market Conditions, COVID-19 and Business Update - We experienced earnings growth from increased volumes in the third quarter 2021, compared with the third quarter 2020, due primarily to increased producer activity and rising gas-to-oil ratios in the Rocky Mountain region, increased ethane production across our system and higher commodity prices, highlighting both the resiliency of our integrated assets and the economic recovery from the pandemic. Although the energy industry has experienced many up and down cycles, we have positioned ourselves to reduce exposure to direct commodity price volatility. Each of our three reportable segments are primarily fee-based, and we expect our consolidated earnings to be approximately 90% fee-based in 2021. 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. In addition, our Natural Gas Gathering and Processing and Natural Gas Liquids segments are exposed to volumetric risk as a result of drilling and completion activity, normal volumetric well decline, 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 protect our workforce and, as always, we remain focused on operating our assets safely, reliably and in an environmentally responsible manner. We continue to monitor the COVID-19 pandemic and have previously 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 within 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 continue to take precautions for our employees who work in the field or need to report to a ONEOK facility. We anticipate implementing a return to office plan in early 2022. 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.

Due to higher commodity prices, increased producer activity in the regions we operate and increased ethane production across our system, volumes in the third quarter 2021 increased, compared with the second quarter 2021, in both our Natural Gas Gathering and Processing and Natural Gas Liquids segments. We expect volumes to remain strong for the remainder of 2021 and into 2022 due to continued increases in producer activity, rising gas-to-oil ratios in the Rocky Mountain region and increased ethane demand from the petrochemical industry.

In February 2021, Winter Storm Uri brought significant challenges to the energy industry and our operating areas. Our employees were proactive in preparing for the severe winter weather, made the necessary operational adjustments to keep our assets operational and provided exceptional service to meet the needs of our customers during the difficult weather conditions as demand for natural gas, propane and electricity soared. This increased demand, coupled with supply reductions from producer wellhead freeze-offs and power outages impacting processing plants in the Mid-Continent and Rocky Mountain regions and the Permian Basin and fractionators in the Mid-Continent region, resulted in record high commodity prices at certain market hubs, particularly in the Mid-Continent region and in Texas. Commodity prices quickly returned to previous levels as the weather improved and natural gas supply returned.

Winter Storm Uri impacted all three of our operating segments, resulting in a net positive impact to our financial results, primarily in the first quarter 2021, as our ability to meet increased demand for natural gas and to provide services during the period offset the unfavorable volume impacts. Our well-positioned natural gas storage assets and market connected pipelines in our Natural Gas Pipelines segment were able to meet critical needs during this period of severe winter weather. The reliability of our interstate and intrastate assets enabled us to continue to provide our customers access to transportation services, park-and-loan services and additional natural gas supply if available, which improved our financial results. However, producer wellhead freeze-offs reduced February volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, which negatively impacted our financial results in the first quarter 2021.

See Part I, Item 3, Quantitative and Qualitative Disclosures About Market Risk, in this Quarterly Report for more information on our exposure to market risk.

Sustainability and Social Responsibility - We continue to look for ways to reduce our environmental impact and utilize more efficient technologies. In 2021, we qualified for inclusion in the S&P Global Sustainability Yearbook and received Industry Mover status, which is awarded to a company that recorded the strongest year-over-year improvement in its industry. In addition, we received a perfect score of 100 in the Human Rights Campaign 2021 Corporate Equality Index. We have a stand-alone environmental sustainability team, formed in 2017, that accelerated our ongoing environmental stewardship efforts and is exploring ways to lower our greenhouse gas emissions. Additionally, in 2020, we created a group dedicated to the commercial development of renewable energy and low-carbon projects. Together with our sustainability team, we are actively researching opportunities that will complement our extensive midstream assets and expertise, strengthening the vital role we expect to play in the transformation to a lower-carbon economy.

In September 2021, we announced a 30% absolute greenhouse gas emissions reduction target, or 2.2 million metric tons, of our combined Scope 1 and Scope 2 emissions by 2030, compared with 2019 base-year levels. Scope 1 and 2 emissions represent our total operational emissions, including direct emissions from sources we operate and indirect emissions from the generation of purchased power. We anticipate several potential pathways toward achieving our emissions reduction target, which could include the electrification of certain natural gas compression assets across our operations, methane mitigation through best management practices and system optimizations. Additionally, we are identifying potential opportunities to collaborate with utilities and power generators to accelerate the availability of lower-carbon power options across our operations. We will maintain a disciplined capital approach and continue to discuss our total capital expenditures and provide our expected total capital spend annually in the “Liquidity and Capital Resources” section. We also expect to provide periodic updates regarding our progress towards our emissions reduction target at least annually.

Natural Gas - In our Natural Gas Gathering and Processing segment, gathered and processed volumes in the Rocky Mountain region increased in the third quarter 2021, compared with the second quarter 2021, due primarily to increased production. Volumes in the Rocky Mountain region also increased, compared with the third quarter 2020, due primarily to increased producer activity, rising gas-to-oil ratios and the impact of curtailed production in 2020. We expect to benefit from increased producer activity in the Rocky Mountain region, which includes the completion of previously drilled but uncompleted wells, and from our Bear Creek plant expansion that is complete and in-service. Our Bear Creek plant expansion increased our total processing capacity to approximately 1.7 Bcf/d in the Williston Basin.

In our Natural Gas Pipelines segment, our assets are connected to key supply areas and demand centers, including export markets in Mexico via Roadrunner and supply areas in Canada and the United States via our interstate and intrastate natural gas pipelines and Northern Border Pipeline, which enable us to provide essential natural gas transportation and storage services. Continued demand from local distribution companies, electric-generation facilities and large industrial companies resulted in low-cost expansions in 2019, 2020, 2021 and expansions expected to be completed in 2022 that position us well to provide additional services to our customers when needed. The contracted portion of our natural gas transportation capacity is not significantly impacted by commodity prices, as our end users rely on natural gas to support their business regardless of commodity price fluctuations. We continue to experience stable fee-based earnings with transportation capacity approximately

95% contracted with firm commitments, which we expect to continue for the remainder of 2021 at similarly contracted levels. Our ability to provide reliable service throughout the extreme weather conditions of Winter Storm Uri highlighted the importance of market-connected pipelines and storage assets and the value of these services. Since the storm, we have received increased interest from customers seeking additional long-term transportation and storage capacity on our system. As a result, we have recontracted storage services at higher rates and longer terms. Additionally, we are expanding the capacity of our storage facilities in Texas and exploring additional storage capacity expansion opportunities. In addition, during the first quarter 2021, we sold natural gas that we owned and held in storage, which benefited our segment’s financial results. During the extreme winter weather periods, we maximized natural gas storage withdrawals for firm service customers serving critical needs.

NGLs - In our Natural Gas Liquids segment, NGL volumes were higher in the third quarter 2021, compared with the second quarter 2021, due primarily to increased producer activity in the Rocky Mountain region and Permian Basin and increased ethane production across our system. Volumes were also higher, compared with the third quarter 2020, due primarily to increased producer activity in the Rocky Mountain region and Permian Basin, increased ethane production across our system in 2021 and the impact of curtailed production in 2020, offset partially by lower volumes in the Barnett Shale. We expect to benefit from increased producer activity and increased demand for ethane as the economic recovery continues and two new petrochemical plants are expected to come online in the next six to twelve months.

Ethane Production - Price differentials between ethane and natural gas can cause natural gas processors to extract ethane or leave it in the natural gas stream. As a result of these ethane economics, ethane volumes on our system can fluctuate period to period. Ethane volumes under long-term contracts delivered to our NGL system increased approximately 20 MBbl/d to an average of 455 MBbl/d in the third quarter 2021, compared with 435 MBbl/d in the second quarter 2021, due primarily to changes in ethane extraction economics. We estimate that there are more than 225 MBbl/d of discretionary ethane, consisting of more than 125 MBbl/d in the Rocky Mountain region and approximately 100 MBbl/d in the Mid-Continent region, that can be recovered and transported on our system. Ethane recovery opportunities will fluctuate based on regional natural gas pricing, ethane economics and potential incentivized recovery.

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. Our announced capital-growth projects are outlined in the table below:


Project	Scope	Approximate Costs (a)	Expected Completion
Natural Gas Gathering and Processing		(In millions)




Bear Creek plant expansion and related infrastructure	200 MMcf/d processing plant expansion and related gathering infrastructure in the Williston Basin	$405	Completed
	Supported by acreage dedications with long-term primarily fee-based contracts
Natural Gas Liquids















Arbuckle II pipeline expansion	Increasing mainline capacity with additional pump facilities	$60	Completed
	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	$750	Paused (b)

West Texas LPG pipeline expansion	Increasing mainline capacity by 40 MBbl/d	$145	Paused (b)

Mid-Continent fractionation facility expansions	65 MBbl/d of expansions at our Mid-Continent NGL facilities	$150	Paused (b)

(a) - Excludes capitalized interest/AFUDC.

(b) - We do not expect to complete construction by the original target completion date. While many of the construction activities on these projects were paused in 2020, some activity continued in order to complete the infrastructure necessary to support volumes until market conditions warrant full project completion.

Debt Repayments - On November 1, 2021, we redeemed the remaining $536.1 million of our $700 million, 4.25% senior notes due February 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings. As of October 31, 2021, we had $150 million of short-term borrowings outstanding.

In June 2021, we repaid the remaining $11.7 million of Guardian Pipeline’s senior notes due December 2022 with cash on hand.

In the first quarter 2021, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $55.2 million for an aggregate repurchase price of $54.6 million with cash on hand.

Dividends - In February 2021, May 2021 and August 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 respective quarters in the prior year. We declared a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis) in October 2021. The quarterly dividend will be paid November 15, 2021, to shareholders of record at the close of business on November 1, 2021.

Goodwill Impairment Review - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. At July 1, 2021, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than their carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, costs and overall financial performance), we determined that it was more likely than not that the fair value of each reporting unit was not less than their respective carrying value, that no further testing was necessary and that goodwill was not considered impaired.

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) adjusted EBITDA. 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.

Non-GAAP Financial Measures - Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation expense and certain other noncash items. We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, EPS or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies.

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected financial results for the periods indicated:


	Three Months Ended				Nine Months Ended				Three Months	Nine Months
	September 30,				September 30,				2021 vs. 2020	2021 vs. 2020
Financial Results	2021		2020		2021		2020		$ Increase (Decrease)	$ Increase (Decrease)
	(Millions of dollars, except per share amounts)
Revenues
Commodity sales	$	4,204.8	$	1,852.2	$	10,115.7	$	5,004.4	2,352.6	5,111.3
Services	331.4		322.1		1,004.1		967.3		9.3	36.8
Total revenues	4,536.2		2,174.3		11,119.8		5,971.7		2,361.9	5,148.1
Cost of sales and fuel (exclusive of items shown separately below)	3,449.1		1,265.7		7,937.6		3,483.1		2,183.4	4,454.5
Operating costs	265.2		205.0		770.9		636.5		60.2	134.4
Depreciation and amortization	154.5		153.2		468.6		426.0		1.3	42.6
Impairment charges	—		—		—		604.0		—	(604.0)
Gain on sale of assets	(0.5)		—		(1.4)		(0.6)		0.5	0.8
Operating income	$	667.9	$	550.4	$	1,944.1	$	822.7	117.5	1,121.4
Equity in net earnings from investments	$	28.6	$	38.0	$	87.6	$	108.0	(9.4)	(20.4)
Impairment of equity investments	$	—	$	—	$	—	$	(37.7)	—	(37.7)
Interest expense, net of capitalized interest	$	(184.0)	$	(176.4)	$	(554.5)	$	(536.0)	7.6	18.5
Net income	$	392.0	$	312.3	$	1,120.3	$	304.8	79.7	815.5
Diluted EPS	$	0.88	$	0.70	$	2.50	$	0.71	0.18	1.79
Adjusted EBITDA	$	865.2	$	747.0	$	2,533.1	$	1,981.7	118.2	551.4
Capital expenditures	$	166.2	$	380.0	$	490.3	$	1,924.0	(213.8)	(1,433.7)

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial 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, except where noted.

Operating income increased $117.5 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

*•*Natural Gas Liquids - increases of $97.8 million in exchange services related primarily to higher volumes in the Rocky Mountain region and wider commodity price differentials and $10.3 million in optimization and marketing;

*•*Natural Gas Gathering and Processing - increases of $36.4 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020 and $26.3 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts; and

*•*Natural Gas Pipelines - an increase of $4.9 million in transportation and storage services due primarily to higher storage and firm transportation rates; offset by

an increase of $60.2 million in consolidated operating costs due primarily to higher employee-related costs, materials and supplies, outside services and property taxes.

Operating income increased $1.1 billion for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

an increase of $604.0 million due to noncash impairment charges in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the nine months ended September 30, 2020;

*•*Natural Gas Liquids - increases of $299.0 million in exchange services related primarily to higher volumes in the Rocky Mountain region and $85.1 million in optimization and marketing, offset by a $46.2 million decrease from the impact of Winter Storm Uri in exchange services;

*•*Natural Gas Gathering and Processing - increases of $150.5 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts and $94.2 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020; and

*•*Natural Gas Pipelines - an increase of $106.8 million due primarily to increased natural gas sales; offset by

an increase of $134.4 million in consolidated operating costs due primarily to higher employee-related costs, property taxes, materials and supplies, and the impact of a loss on the mark-to-market of our share-based deferred compensation plan in 2021 compared with a benefit in 2020; and
an increase of $42.6 million in depreciation expense due to capital projects placed in service.

Net income and diluted EPS increased for the three months ended September 30, 2021, compared with the same period in 2020, due primarily to the items discussed above. These increases were offset partially by higher income taxes, lower equity in net earnings from investments and higher interest expense related to lower capitalized interest.

Net income and diluted EPS increased for the nine months ended September 30, 2021, compared with the same period in 2020, due primarily to the items discussed above and noncash impairment charges related to equity investments in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the prior year. These increases were offset partially by higher income taxes, higher interest expense related to lower capitalized interest, lower equity AFUDC due to completed projects, lower equity in net earnings from investments and a $20.0 million gain in 2020 on extinguishment of debt related to open market repurchases.

Capital expenditures decreased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to our previously completed capital-growth projects, with the nine months ended September 30, 2021, also impacted by paused capital-growth projects.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. Raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines, storage facilities and end users. The NGLs separated from the raw natural gas are sold and delivered through NGL pipelines to fractionation facilities for further processing.

Our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based, but we have some 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. To mitigate the impact of this commodity price exposure, we have hedged a portion of our Natural Gas Gathering and Processing segment’s commodity price risk for the remainder of 2021 and into 2022. This segment has substantial long-term acreage dedications in some of the most productive areas of the Williston Basin, which helps to mitigate long-term volumetric risk.

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 project.

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

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Gathering and Processing segment for the periods indicated:


	Three Months Ended				Nine Months Ended				Three Months	Nine Months
	September 30,				September 30,				2021 vs. 2020	2021 vs. 2020
Financial Results	2021		2020		2021		2020		$ Increase (Decrease)	$ Increase (Decrease)
	(Millions of dollars)
NGL sales	$	788.8	$	216.3	$	1,782.3	$	488.7	572.5	1,293.6
Condensate sales	27.2		23.5		91.9		80.6		3.7	11.3
Residue natural gas sales	370.8		178.5		940.9		518.4		192.3	422.5
Gathering, compression, dehydration and processing fees and other revenue	41.7		41.1		116.6		121.5		0.6	(4.9)
Cost of sales and fuel (exclusive of depreciation and operating costs)	(913.9)		(207.5)		(2,019.7)		(541.9)		706.4	1,477.8
Operating costs, excluding noncash compensation adjustments	(91.3)		(67.4)		(254.0)		(229.8)		23.9	24.2
Equity in net earnings (loss) from investments	0.5		—		2.7		(1.4)		0.5	4.1
Other	5.9		(1.4)		2.9		(4.6)		7.3	7.5
Adjusted EBITDA	$	229.7	$	183.1	$	663.6	$	431.5	46.6	232.1
Impairment charges	$	—	$	—	$	—	$	564.4	—	(564.4)
Capital expenditures	$	80.8	$	63.0	$	177.4	$	362.8	17.8	(185.4)

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial 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.

Adjusted EBITDA increased $46.6 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

an increase of $36.4 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020, offset partially by natural production declines in the Mid-Continent region;
an increase of $26.3 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts; and
an increase of $7.3 million from a gain on the partial sale of an equity investment; offset by
an increase of $23.9 million in operating costs due primarily to higher materials and supplies, employee-related costs and outside services due primarily to the growth of our operations.

Adjusted EBITDA increased $232.1 million for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

an increase of $150.5 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts; and
an increase of $94.2 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020, offset partially by natural production declines in the Mid-Continent region; offset by
an increase of $24.2 million in operating costs due primarily to higher materials and supplies, employee-related costs and outside services due primarily to the growth of our operations.

The nine months ended September 30, 2020, includes $380.5 million of noncash impairment charges related primarily to certain long-lived asset groups in western Oklahoma, Kansas and the Powder River Basin 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.

Capital expenditures increased for the three months ended September 30, 2021, compared with the same period in 2020, due primarily to our Bear Creek plant expansion and decreased for the nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to our previously completed capital-growth projects.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2021		2020		2021		2020
Natural gas gathered (BBtu/d)	2,757		2,514		2,693		2,503
Natural gas processed (BBtu/d) (b)	2,549		2,345		2,471		2,327





Average fee rate ($/MMBtu)	$	1.02	$	0.94	$	1.04	$	0.84

(a) - Includes volumes for consolidated entities only.

(b) - Includes volumes we processed at company-owned and third-party facilities.

Our natural gas gathered and natural gas processed volumes increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to increased producer activity and rising gas-to-oil ratios in the Rocky Mountain region and the impact of curtailed production in 2020, offset partially by natural production declines in the Mid-Continent region.

Our average fee rate increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to an increase in the Rocky Mountain region’s contribution to our average fee rate.

Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk in this Quarterly Report.

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.

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 the nine months ended September 30, 2021, we connected one third-party natural gas processing plant in the Permian Basin and one third-party natural gas processing plant in the Rocky Mountain region to our NGL system.

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

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:


	Three Months Ended				Nine Months Ended				Three Months	Nine Months
	September 30,				September 30,				2021 vs. 2020	2021 vs. 2020
Financial Results	2021		2020		2021		2020		$ Increase (Decrease)	$ Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	3,853.1	$	1,658.1	$	9,097.5	$	4,429.4	2,195.0	4,668.1
Exchange service revenues and other	136.0		134.3		414.6		377.7		1.7	36.9
Transportation and storage revenues	40.5		39.8		127.1		131.4		0.7	(4.3)
Cost of sales and fuel (exclusive of depreciation and operating costs)	(3,377.9)		(1,289.7)		(7,838.1)		(3,473.6)		2,088.2	4,364.5
Operating costs, excluding noncash compensation adjustments	(122.4)		(97.0)		(359.5)		(290.6)		25.4	68.9
Equity in net earnings from investments	5.4		8.0		14.1		31.1		(2.6)	(17.0)
Other	(2.5)		(2.3)		(7.6)		(5.6)		(0.2)	(2.0)
Adjusted EBITDA	$	532.2	$	451.2	$	1,448.1	$	1,199.8	81.0	248.3
Impairment charges	$	—	$	—	$	—	$	77.4	—	(77.4)
Capital expenditures	$	53.8	$	298.9	$	225.8	$	1,504.9	(245.1)	(1,279.1)

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial 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.

Adjusted EBITDA increased $81.0 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

an increase of $97.8 million in exchange services due primarily to $59.6 million in higher volumes primarily in the Rocky Mountain region and Permian Basin, offset partially by lower volumes in the Barnett Shale, and $29.5 million related to wider commodity price differentials; and
an increase of $10.3 million in optimization and marketing due primarily to wider locations and commodity price differentials; offset by
an increase of $25.4 million in operating costs due primarily to higher employee-related costs, increased property taxes associated with our completed capital-growth projects and higher outside services.

Adjusted EBITDA increased $248.3 million for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

an increase of $299.0 million in exchange services (excluding the impact of Winter Storm Uri discussed below) due primarily to:

◦$249.6 million in higher volumes in the Rocky Mountain region and lower transportation costs, offset by $11.3 million in lower volumes primarily in the Barnett Shale,

◦$65.9 million related to wider commodity price differentials, and

◦$12.9 million related to the recognition of proceeds previously considered a gain contingency, offset by

◦$15.6 million related to lower earnings on unfractionated NGLs held in inventory due primarily to decreasing inventory levels throughout 2020; and

*•*an increase of $85.1 million in optimization and marketing due primarily to wider location and commodity price differentials, increased activities during Winter Storm Uri and higher earnings on purity NGL sales; offset by

the negative impact of Winter Storm Uri of $46.2 million in exchange services due primarily to decreased volumes across our operations and higher electricity costs;
an increase of $68.9 million in operating costs due primarily to higher employee-related costs, increased property taxes associated with our completed capital-growth projects and higher outside services; and
a decrease of $17.0 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline.

The nine months ended September 30, 2020, includes $70.2 million of noncash impairment charges related to certain inactive assets and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company.

Capital expenditures decreased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to previously completed capital-growth projects, with the nine months ended also impacted by paused capital-growth projects.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information	2021		2020		2021		2020
Raw feed throughput (MBbl/d) (a)	1,275		1,162		1,174		1,088


Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.00	$	0.03	$	(0.01)	$	0.01

(a) - Represents physical raw feed volumes on which we charge a fee for transportation and/or fractionation services.

Volumes increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to increased production primarily in the Rocky Mountain region and increased ethane production across our system.

Volumes for the nine months ended September 30, 2021, also increased due to the impact of curtailed production across our system in 2020 and were offset partially by the impact of Winter Storm Uri in 2021. Volumes for the three months ended September 30, 2021, have also benefited from increased production in the Permian Basin, offset partially by lower volumes in the Barnett Shale.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment, through its wholly owned assets primarily in Oklahoma, Texas and the upper Midwest, provides transportation and storage services to end users, such as natural gas distribution and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. We have 50% ownership interests in Northern Border Pipeline and Roadrunner, which provide transportation services to various end users.

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:


	Three Months Ended				Nine Months Ended				Three Months	Nine Months
	September 30,				September 30,				2021 vs. 2020	2021 vs. 2020
Financial Results	2021		2020		2021		2020		$ Increase (Decrease)	$ Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	101.2	$	96.4	$	313.0	$	303.1	4.8	9.9
Storage revenues	19.1		16.6		52.6		50.1		2.5	2.5
Residue natural gas sales and other revenues	0.2		4.3		116.1		6.9		(4.1)	109.2
Cost of sales and fuel (exclusive of depreciation and operating costs)	(0.3)		(3.4)		(10.9)		(5.1)		(3.1)	5.8
Operating costs, excluding noncash compensation adjustments	(39.2)		(33.4)		(115.4)		(99.0)		5.8	16.4
Equity in net earnings from investments	22.7		30.1		70.9		78.3		(7.4)	(7.4)
Other	(1.0)		(0.8)		(2.7)		(2.1)		(0.2)	(0.6)
Adjusted EBITDA	$	102.7	$	109.8	$	423.6	$	332.2	(7.1)	91.4

Capital expenditures	$	24.6	$	13.0	$	73.5	$	40.5	11.6	33.0

See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.

Adjusted EBITDA decreased $7.1 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

a decrease of $7.4 million from lower equity in net earnings from investments due primarily to decreased firm transportation revenues on Northern Border Pipeline; and
an increase of $5.8 million in operating costs due primarily to higher employee-related costs and higher supplies expenses; offset by
an increase of $4.9 million in transportation and storage services due primarily to higher storage and firm transportation rates.

Adjusted EBITDA increased $91.4 million for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:

an increase of $106.8 million due primarily to higher average natural gas prices on 5.2 Bcf of natural gas sales in the first quarter 2021 of volumes previously held in inventory, compared with 1.2 Bcf in the first quarter 2020; and
an increase of $7.0 million in transportation services due primarily to higher park-and-loan revenue and higher interruptible transportation revenue in the first quarter 2021, offset partially by a favorable $13.5 million contract settlement in April 2020; offset by
an increase of $16.4 million in operating costs due primarily to higher employee-related costs and higher supplies expenses; and
a decrease of $7.4 million from lower equity in net earnings from investments due primarily to decreased firm transportation revenues on Northern Border Pipeline.

Capital expenditures increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to capital-growth and maintenance capital projects.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2021		2020		2021		2020
Natural gas transportation capacity contracted (MDth/d)	7,335		7,349		7,353		7,485
Transportation capacity contracted	94	%	94	%	94	%	96	%

(a) - Includes volumes for consolidated entities only.

Roadrunner has contracted all of its westbound capacity through 2041.

Northern Border Pipeline has contracted substantially all of its long-haul transportation capacity through the fourth quarter 2021.

In February 2021, our subsidiary, Midwestern Gas Transmission Company, filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with the FERC. The FERC is currently reviewing the filing. While the ultimate outcome of the filing cannot be predicted, we do not expect the ultimate outcome to impact materially our results of operations.

Non-GAAP Financial Measures

The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the periods indicated:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
Reconciliation of net income to adjusted EBITDA	(Thousands of dollars)
Net income	$	392,018	$	312,316	$	1,120,333	$	304,780
Add:
Interest expense, net of capitalized interest	184,049		176,371		554,529		535,955
Depreciation and amortization	154,542		153,245		468,583		426,014
Income tax expense	121,899		106,555		354,100		94,300
Impairment charges	—		—		—		641,754
Noncash compensation expense (a)	12,978		1,606		37,086		1,261
Equity AFUDC and other noncash items	(246)		(3,084)		(1,485)		(22,346)
Adjusted EBITDA (b)	865,240		747,009		2,533,146		1,981,718
Reconciliation of segment adjusted EBITDA to adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing	$	229,657	$	183,148	$	663,639	$	431,545
Natural Gas Liquids	532,159		451,243		1,448,078		1,199,801
Natural Gas Pipelines	102,726		109,837		423,597		332,194
Other (b)	698		2,781		(2,168)		18,178
Adjusted EBITDA	$	865,240	$	747,009	$	2,533,146	$	1,981,718

(a) - Includes a loss of $6.9 million and a benefit of $16.9 million for the nine months ended September 30, 2021 and 2020, respectively, related to the mark-to-market of our share-based deferred compensation plan.

(b) - The three and nine months ended September 30, 2020, includes corporate gains of $2.2 million and $22.2 million, respectively, on extinguishment of debt related to open market repurchases.

CONTINGENCIES

See Note J of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of our legal proceedings.

LIQUIDITY AND CAPITAL RESOURCES

General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements. In addition, we expect cash outflows for the remainder of 2021 to be primarily related to dividends paid to shareholders and capital expenditures.

We expect our sources of cash inflows to provide sufficient resources to finance our operations, capital expenditures and quarterly cash dividends. We believe we have sufficient liquidity due to our $2.5 Billion Credit Agreement, which expires in June 2024 and access to $1.0 billion available through our “at-the-market” equity program. As of the date of this report, no shares have been sold through our “at-the-market” equity program.

We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. For additional information on our interest-rate swaps, see Note C of the Notes to Consolidated Financial Statements in this Quarterly Report.

Guarantees and Cash Management - We and ONEOK Partners are issuers of certain public debt securities. We guarantee certain indebtedness of ONEOK Partners, and ONEOK Partners and the Intermediate Partnership guarantee certain of our indebtedness. The guarantees in place for our and ONEOK Partners’ indebtedness are full, irrevocable, unconditional and absolute joint and several guarantees to the holders of each series of outstanding securities. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness. As ONEOK Partners and the Intermediate Partnership are consolidated subsidiaries of ONEOK, separate financial statements for the guarantors are not required as long as the alternative disclosure required by Rule 13-01 is provided, which includes narrative disclosure and summarized financial information. The Intermediate Partnership holds all of ONEOK Partners’ interests and equity in its subsidiaries, which are non-guarantors, and substantially all the assets and operations reside with non-guarantor operating

subsidiaries. Therefore, as allowed under Rule 13-01, we have excluded the summarized financial information for each issuer and guarantor as the combined financial information of the subsidiary issuer and parent guarantor, excluding our ownership of all the interests in ONEOK Partners, reflect no material assets, liabilities or results of operations, apart from the guaranteed indebtedness. For additional information on our and ONEOK Partners’ indebtedness, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

We use a centralized cash management program that concentrates the cash assets of our non-guarantor operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity-method investments, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement. As of September 30, 2021, we are in compliance with all covenants of the $2.5 Billion Credit Agreement.

At September 30, 2021, we had no borrowings under our $2.5 Billion Credit Agreement and $224.3 million of cash and cash equivalents.

As of September 30, 2021, we had a working capital deficit of $136.0 million (defined as current assets less current liabilities). Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures, (c) scheduled debt payments, and (d) accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficit at September 30, 2021, was driven primarily by current maturities of long-term debt. We may have working capital deficits in future periods as we continue to repay long-term debt. We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.

For additional information on our $2.5 Billion Credit Agreement, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes, as needed. Other options to obtain financing include, but are not limited to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.

In June 2021, we repaid the remaining $11.7 million of Guardian Pipeline’s senior notes due December 2022 with cash on hand.

For additional information on our long-term debt, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

Capital Expenditures - We classify expenditures that are expected to generate additional revenue, return on investment or significant operating efficiencies as capital-growth expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our existing assets and operations and do not generate additional revenues. Maintenance capital expenditures are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. Our capital expenditures are financed typically through operating cash flows and short- and long-term debt.

Capital expenditures, excluding AFUDC and capitalized interest, were $490.3 million and $1.9 billion for the nine months ended September 30, 2021 and 2020, respectively.

We expect total capital expenditures, excluding AFUDC and capitalized interest, of $525-$675 million in 2021.

Credit Ratings - Our long-term debt credit ratings as of October 25, 2021, are shown in the table below:


Rating Agency	Long-Term Rating	Short-Term Rating	Outlook
Moody’s	Baa3	Prime-3	Stable
S&P	BBB	A-2	Stable
Fitch	BBB	F2	Stable

Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under our $2.5 Billion Credit Agreement could increase and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our $2.5 Billion Credit Agreement, which expires in 2024. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement.

In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments.

Dividends - Holders of our common stock share equally in any common stock dividends declared by our Board of Directors, subject to the rights of the holders of outstanding preferred stock. In February 2021, May 2021 and August 2021 we paid a dividend of $0.935 per share ($3.74 per share on an annualized basis). A dividend of $0.935 per share was declared for the shareholders of record at the close of business on November 1, 2021, payable November 15, 2021.

Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. We paid dividends for the Series E Preferred Stock of $0.3 million in February 2021, May 2021 and August 2021. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable November 15, 2021.

For the nine months ended September 30, 2021, our cash flows from operations exceeded dividends paid by $241.0 million. We expect our cash flows from operations to continue to sufficiently fund our cash dividends. To the extent operating cash flows are not sufficient to fund our dividends, we may utilize cash on hand from other sources of short- and long-term liquidity to fund a portion of our dividends.

CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These reconciling items can include depreciation and amortization, impairment charges, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:


					Variances
	Nine Months Ended				2021 vs. 2020
	September 30,				Favorable (Unfavorable)
	2021		2020
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	1,491.1	$	1,103.1	$	388.0
Investing activities	(475.4)		(1,981.9)		1,506.5
Financing activities	(1,315.9)		1,304.9		(2,620.8)
Change in cash and cash equivalents	(300.2)		426.1		(726.3)
Cash and cash equivalents at beginning of period	524.5		21.0		503.5
Cash and cash equivalents at end of period	$	224.3	$	447.1	$	(222.8)

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash flows can also be impacted by changes in our NGLs and natural gas inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.

Cash flows from operating activities, before changes in operating assets and liabilities for the nine months ended September 30, 2021, increased $542.3 million compared with the same period in 2020. This increase is due primarily to higher net income resulting from higher exchange services in our Natural Gas Liquids segment, higher realized prices and increased volumes in our Natural Gas Gathering and Processing segment and natural gas sales in our Natural Gas Pipelines segment, as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $500.8 million for the nine months ended September 30, 2021, compared with a decrease of $346.6 million for the same period in 2020. This change is due primarily to changes in accounts receivable resulting from the timing of receipt of cash from customers and NGLs and natural gas in storage, both of which vary from period to period and with changes in commodity prices; offset partially by changes in accounts payable resulting from the timing of payments to vendors, suppliers and other third parties; and changes in other assets and liabilities.

Investing Cash Flows - Cash used in investing activities for the nine months ended September 30, 2021, decreased $1.5 billion, compared with the same period in 2020, due primarily to reduced capital expenditures related to our completed and paused capital-growth projects.

Financing Cash Flows - Cash from financing activities for the nine months ended September 30, 2021, decreased $2.6 billion, compared with the same period in 2020, due primarily to the issuances of $3.25 billion in long-term debt and the issuance of common stock in 2020, offset partially by the repayment of long-term debt in 2020.

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, costs, liabilities (including joint and several liability for the obligations of others), reputational harm and/or interruptions in our operations that could be material to our results of operations or financial condition. 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.

Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration (TSA) issued two Security Directives in 2021 in response to ongoing cybersecurity threats to the pipeline industry. The first Security Directive was issued in May 2021 and requires critical pipeline owners and operators to (1) report confirmed and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (CISA); (2) designate a cybersecurity coordinator to be available 24 hours a day, seven days a week; (3) review current practices; and, (4) identify any gaps and related remediation measures to address cyber-related risks and report the results to TSA and CISA within 30 days. The second Security Directive was issued in July 2021 and requires owners and operators of TSA-designated critical pipelines to implement specific mitigation measures to protect against ransomware and other known threats to information technology and operational technology systems, develop and implement a cybersecurity contingency and recovery plan, and conduct a cybersecurity architecture design review. While compliance with the Security Directives is utilizing significant internal resources, we do not expect it to have a material impact on our results of operations, financial position or cash flows.

Additional information about our regulatory, environmental and safety matters can be found in “Regulatory, Environmental and Safety Matters” under Part I, Item 1, Business, in our Annual Report.

IMPACT OF NEW ACCOUNTING STANDARDS

See Note A of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of new accounting standards.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

Information about our critical accounting policies and estimates is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and Estimates,” in our Annual Report.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements as defined under federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s plans and objectives for our future capital-growth projects and other future operations (including plans to construct additional natural gas and NGL pipelines, processing and fractionation facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under federal securities legislation and other applicable laws. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report identified by words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “target,” “guidance,” “intend,” “may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would,” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

the length, severity and reemergence of a pandemic or other health crisis, such as the COVID-19 pandemic and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address it, which may (as with COVID-19) precipitate or exacerbate one or more of the factors herein, reduce the demand for natural gas, NGLs and crude oil and significantly disrupt or prevent us and our customers and counterparties from operating in the ordinary course for an extended period and increase the cost of operating our business;
operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruption;
the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to drill and obtain necessary permits; regulatory compliance; reserve performance; and capacity constraints and/or shut downs on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling, the shutting-in of production by producers, actions taken by federal, state or local governments to require producers to prorate or to cut their production levels as a way to address any excess market supply situations or extended periods of ethane rejection;
demand for our services and products in the proximity of our facilities;
economic climate and growth in the geographic areas in which we operate;
the risk of a slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
performance of contractual obligations by our customers, service providers, contractors and shippers;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, cybersecurity, climate change initiatives, emissions credits, carbon offsets, carbon pricing, production limits and authorized rates of recovery of natural gas and natural gas transportation costs;
changes in demand for the use of natural gas, NGLs and crude oil because of the development of new technologies or other market conditions caused by concerns about climate change;
the transition to a lower-carbon economy, including the timing and extent of the transition, as well as the expected role of different energy sources in such a transition;
the pace of technological advancements and industry innovation, including those focused on reducing greenhouse gas emissions and advancing other climate-related initiatives, and our ability to take advantage of those innovations and developments;
the effectiveness of our risk management strategies, including mitigating climate-related risks;
our ability to identify and execute opportunities, and the economic viability of those opportunities, including those relating to renewable natural gas, carbon capture, use and storage, other renewable energy sources such as solar and wind and alternative low carbon fuel sources such as hydrogen;
the ability of our existing assets and our ability to apply and continue to develop our expertise to support the growth of, and transition to, various renewable and alternative energy opportunities, including through the positioning and optimization of our assets;
our ability to efficiently reduce the carbon intensity of our operations (both Scope 1 and 2 emissions), including through the use of lower carbon power alternatives, management practices and system optimizations;
the necessity to direct our focus on maintaining and enhancing our existing assets instead of efforts to reduce our greenhouse gas emissions;
the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;
acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’, customers’ or shippers’ facilities;
the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions throughout the world;
the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
the timing and extent of changes in energy commodity prices, including changes due to production decisions by other countries, such as the failure of countries to abide by agreements to reduce production volumes;
competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;
the ability to market pipeline capacity on favorable terms, including the effects of:

– future demand for and prices of natural gas, NGLs and crude oil;

– competitive conditions in the overall energy market;

– availability of supplies of United States natural gas and crude oil; and

– availability of additional storage capacity;

the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
our ability to control operating costs and make cost-saving changes;
the risk inherent in the use of information systems in our respective businesses and those of our counterparties and service providers, including cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the COVID-19 pandemic; implementation of new software and hardware; and the impact on the timeliness of information for financial reporting;
the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
the results of governmental actions, administrative proceedings and litigation, regulatory actions, executive orders, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the Department of Homeland Security, the PHMSA, the EPA and the CFTC;
the mechanical integrity of facilities and pipelines operated;
the capital-intensive nature of our businesses;
the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in equity and bond market returns;
actions by rating agencies concerning our credit;
our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;
our ability to access capital at competitive rates or on terms acceptable to us;
our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;
our ability to control construction costs and completion schedules of our pipelines and other projects;
difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;
the uncertainty of estimates, including accruals and costs of environmental remediation;
the impact of uncontracted capacity in our assets being greater or less than expected;
the impact of potential impairment charges;
the profitability of assets or businesses acquired or constructed by us;
risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
the impact and outcome of pending and future litigation;
the impact of recently issued and future accounting updates and other changes in accounting policies; and
the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also affect adversely our future results. These and

other risks are described in greater detail in Part I, Item 1A, Risk Factors, in our Annual Report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

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