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

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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

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:


Project (b)	Scope	Approximate 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	$400	Completed 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	$410	Completed January 2020
	Supported by acreage dedications with long-term primarily fee-based contracts
Bear Creek plant expansion and related infrastructure	200 MMcf/d processing plant expansion and related gathering infrastructure in the Williston Basin	$405	Paused (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	$1,400	Completed 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	$1,360	Completed March 2020
	Supported by long-term contracts
	Expansion capability up to 1 MMBbl/d
MB-4 fractionator and related infrastructure	125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu	$575	Completed March 2020 (d)
	Fully contracted with long-term contracts
ONEOK West Texas NGL pipeline expansion and Arbuckle II connection	Increasing mainline capacity by 80 MBbl/d with additional pump facilities and pipeline looping	$295	Completed 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	$100	Completed August 2020
	Supported by a long-term contract with a minimum volume commitment
Arbuckle II extension project and additional gathering infrastructure	Provide additional takeaway capacity in the STACK area	$240	Completed
Allow increasing volumes on the Elk Creek pipeline access to fractionation capacity at Mont Belvieu, Texas		August 2020
Arbuckle II pipeline expansion	Increasing mainline capacity with additional pump facilities	$60	Paused (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	$750	Paused (c)
	Fully contracted with long-term contracts
ONEOK West Texas NGL pipeline expansion	Increasing mainline capacity by 40 MBbl/d	$145	Paused (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	$150	Paused (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.

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.

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. 2019	2019 vs. 2018
Financial Results	2020		2019		2018		$ 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)
Services	1,287.0		1,248.3		1,197.6		38.7	50.7
Total revenues	8,542.2		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 costs	886.1		982.9		907.0		(96.8)	75.9
Depreciation and amortization	578.7		476.5		428.6		102.2	47.9
Impairment charges	607.2		—		—		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;
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. 2019	2019 vs. 2018
Financial Results	2020		2019		2018		$ Increase (Decrease)
	(Millions of dollars)
NGL sales	$	775.9	$	1,024.3	$	1,567.2	(248.4)	(542.9)
Condensate sales	113.5		200.1		208.8		(86.6)	(8.7)
Residue natural gas sales	771.5		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
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)	2020		2019		2018
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.

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. 2019	2019 vs. 2018
Financial Results	2020		2019		2018		$ 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 other	497.8		424.2		415.7		73.6	8.5
Transportation and storage revenues	182.9		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 investments	39.9		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 Information	2020		2019		2018

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.

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. 2019	2019 vs. 2018
Financial Results	2020		2019		2018		$ Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	401.7	$	393.7	$	343.0	8.0	50.7
Storage revenues	68.4		72.6		72.0		(4.2)	0.6
Residue natural gas sales and other revenues	9.9		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)		(150.8)		(139.2)		(13.6)	11.6
Equity in net earnings from investments	104.4		95.7		90.8		8.7	4.9
Other	(3.0)		(3.5)		(1.0)		0.5	(2.5)
Adjusted EBITDA	$	437.4	$	408.8	$	366.3	28.6	42.5
Capital expenditures	$	71.9	$	99.2	$	119.2	(27.3)	(20.0)

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

2020 vs. 2019 - Adjusted EBITDA increased $28.6 million primarily as a result of the following:

a decrease of $13.6 million in operating costs due primarily to lower employee-related costs and materials and supplies expenses;
an increase of $8.7 million from higher equity in net earnings from investments due primarily to additional firm transportation capacity contracted on Northern Border;
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; and
an increase of $4.0 million from higher net retained fuel and timing of equity gas sales; offset partially by
a decrease of $3.9 million from storage services due primarily to lower park-and-loan activity.

Capital expenditures decreased due primarily to the completion of our expansion projects in 2019.


	Years Ended December 31,
Operating Information (a)	2020		2019		2018
Natural gas transportation capacity contracted (MDth/d)	7,461		7,618		6,846
Transportation capacity contracted	96	%	98	%	96	%

(a) - Includes volumes for consolidated entities only.

2020 vs. 2019 - Natural gas transportation capacity contracted decreased due to a contract settlement and the impact of market conditions.

Roadrunner, in which we have a 50% ownership interest, has contracted all of its westbound capacity through 2041.

Northern Border Pipeline, in which we have a 50% ownership interest, has contracted substantially all of its long-haul transportation capacity through the fourth quarter 2021.

In June 2019, our subsidiary, Viking Gas Transmission Company (Viking), filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with the FERC. In February 2020, Viking filed a Stipulation and Offer of Settlement (Settlement) with the FERC for approval. The FERC accepted the Settlement in July 2020, which did not impact materially our results of operations.

NON-GAAP MEASURES

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


	Years Ended December 31,
(Unaudited)	2020		2019		2018
Reconciliation of net income to adjusted EBITDA, distributable cash flow and dividend coverage	(Thousands of dollars, except per share amounts and coverage ratios)
Net income	$	612,809	$	1,278,577	$	1,155,032
Add:
Interest expense, net of capitalized interest	712,886		491,773		469,620
Depreciation and amortization	578,662		476,535		428,557
Income tax expense	189,507		372,414		362,903
Impairment charges	644,930		—		—
Noncash compensation expense (a)	8,540		26,699		37,954
Equity AFUDC and other noncash items	(23,661)		(65,811)		(6,545)
Adjusted EBITDA (b)	2,723,673		2,580,187		2,447,521
Interest expense, net of capitalized interest	(712,886)		(491,773)		(469,620)
Maintenance capital	(136,920)		(195,631)		(188,420)
Equity in net earnings from investments	(143,241)		(154,541)		(158,383)
Distributions received from unconsolidated affiliates	176,160		257,644		197,285
Other (b)	(25,195)		20,227		(5,994)
Distributable cash flow	1,881,591		2,016,113		1,822,389
Dividends paid to preferred shareholders	(1,100)		(1,100)		(1,100)
Distributable cash flow to shareholders	1,880,491		2,015,013		1,821,289
Dividends paid	(1,604,266)		(1,456,528)		(1,333,958)
Distributable cash flow in excess of dividends paid	$	276,225	$	558,485	$	487,331
Dividends paid per share	$	3.74	$	3.53	$	3.245
Dividend coverage ratio	1.17		1.38		1.37
Number of shares used in computation (thousands)	428,948		412,614		411,081

(a) - Year ended December 31, 2020, includes a benefit of $11.2 million related to the mark-to-market of our share-based deferred compensation plan.

(b) - Year ended December 31, 2020, includes net gains of $22.3 million on extinguishment of debt related to open market repurchases.


	Years Ended December 31,
(Unaudited)	2020		2019		2018
Reconciliation of segment adjusted EBITDA to adjusted EBITDA	(Thousands of dollars)
Segment adjusted EBITDA:
Natural Gas Gathering and Processing	$	650,036	$	702,650	$	631,607
Natural Gas Liquids	1,617,241		1,465,765		1,440,605
Natural Gas Pipelines	437,426		408,816		366,251
Other (a)	18,970		2,956		9,058
Adjusted EBITDA	$	2,723,673	$	2,580,187	$	2,447,521

(a) - Year ended December 31, 2020, includes corporate net gains of $22.3 million on extinguishment of debt related to open market repurchases.

CONTINGENCIES

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for a discussion of regulatory matters.

Other Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

LIQUIDITY AND CAPITAL RESOURCES

General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements. In addition, we expect cash outflows in 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 and quarterly cash dividends. We believe we have sufficient liquidity due to our $2.5 Billion Credit Agreement, which expires in June 2024, cash on hand from our June 2020 equity issuance and access to $1.0 billion available through our “at-the-market” equity program.

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

Guarantees and Cash Management - In March 2020, the SEC amended Rule 3-10 of Regulation S-X and created Rule 13-01 to simplify disclosure requirements related to certain registered securities. 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 F of the Notes to Consolidated Financial Statements in this Annual 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 December 31, 2020, we are in compliance with all covenants of our $2.5 Billion Credit Agreement.

At December 31, 2020, we had no borrowings under our $2.5 Billion Credit Agreement and $524.5 million of cash and cash equivalents.

We had a working capital (defined as current assets less current liabilities) surplus of $525.2 million and a working capital deficit of $550.0 million as of December 31, 2020, and December 31, 2019, respectively. Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures, (c) scheduled debt payments, and (d) accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances; our working capital surplus at December 31, 2020, was driven primarily by cash on hand and our working capital deficit at December 31, 2019, was driven primarily by short-term borrowings and accrued interest. We may have working capital deficits in future periods as we continue to repay long-term debt and finance our capital-growth projects, often initially with short-term borrowings.

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

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes. Other options to obtain financing include, but are not limited

to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.

Debt Issuances - In 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.

Debt Repayments - In May 2020, we repaid the remaining $1.25 billion of our $1.5 Billion Term Loan Agreement with cash on hand from our May 2020 public offering of $1.5 billion senior unsecured notes.

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

Equity Issuances - In July 2020, we established an “at-the-market” equity program for the offer and sale from time to time of our common stock up to an aggregate offering price of $1.0 billion. The program allows us to offer and sell common stock at prices we deem appropriate through a sales agent, in forward sales transactions through a forward seller or directly to one or more of the program’s managers acting as principals. Sales of our common stock may be made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. No shares have been sold through our “at-the-market” program as of the date of this report.

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.

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

The following table sets forth our growth and maintenance capital expenditures, excluding AFUDC and capitalized interest, for the periods indicated:


Capital Expenditures	2020		2019		2018
	(Millions of dollars)
Natural Gas Gathering and Processing	$	446.1	$	926.5	$	694.6
Natural Gas Liquids	1,655.8		2,796.6		1,306.3
Natural Gas Pipelines	71.9		99.2		119.2
Other	21.6		26.0		21.4
Total capital expenditures	$	2,195.4	$	3,848.3	$	2,141.5

Capital expenditures decreased in 2020, compared with 2019, due primarily to our previously completed capital-growth projects, as well as our paused and suspended capital-growth projects. We expect our 2021 capital expenditures to decrease

relative to 2020 due to our previously completed capital-growth projects and paused and suspended capital-growth projects, unless producer activity levels warrant additional infrastructure. See discussion of our announced capital-growth projects in the “Recent Developments” section.

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 February 16, 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 (a)	BBB	F2	Stable
(a) - Fitch assigned first-time ratings to ONEOK in November 2020.

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. Although we are in the midst of a challenging market environment, our credit ratings have remained stable. 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 2020, we paid dividends of $3.74 per share, an increase of 6% compared with the prior year. 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.

Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. In 2020, we paid dividends of $1.1 million for the Series E Preferred Stock. In February 2021, we paid quarterly dividends totaling $0.3 million for the Series E Preferred Stock.

For the year ended December 31, 2020, our cash flows from operations exceeded dividends paid by $293.7 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:


	Years Ended December 31,
	2020		2019		2018
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	1,899.0	$	1,946.8	$	2,186.7
Investing activities	(2,270.5)		(3,768.8)		(2,114.9)
Financing activities	875.0		1,831.0		(97.0)
Change in cash and cash equivalents	503.5		9.0		(25.2)
Cash and cash equivalents at beginning of period	21.0		12.0		37.2
Cash and cash equivalents at end of period	$	524.5	$	21.0	$	12.0

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.

2020 vs. 2019 - Cash flows from operating activities, before changes in operating assets and liabilities, decreased $51.1 million due primarily to higher interest expense, lower realized prices in our Natural Gas Gathering and Processing segment and lower optimization and marketing earnings in our Natural Gas Liquids segment. These decreases were offset partially by an increase in exchange services due to higher volumes and lower rail and pipeline transportation costs in our Natural Gas Liquids segment and lower operating costs across our segments, as discussed in “Financial Results and Operating Information.”

The impact of changes in operating assets and liabilities for 2020 was relatively unchanged compared with 2019, due primarily to net decreases from changes in risk-management assets and liabilities, which include a loss on the settlement of $750 million of our forward-starting interest-rate swaps related to our March 2020 issuance of senior unsecured notes and changes in the fair value of risk-management assets and liabilities, which vary from period to period and with changes in commodity prices and interest rates; and changes in other accruals and deferrals. These decreases were offset partially by the changes in commodity imbalances and NGLs and natural gas in storage, which also vary from period to period and with changes in commodity prices.

Investing Cash Flows

2020 vs. 2019 - Cash used in investing activities decreased $1.5 billion due primarily to reduced capital expenditures related to our completed and paused capital-growth projects.

Financing Cash Flows

2020 vs. 2019 - Cash from financing activities decreased $956.0 million due primarily to the issuance of $3.2 billion in long-term debt in 2020, compared with $4.2 billion in long-term debt issuances in 2019, and the repayment of long-term debt and short-term borrowings, offset partially by the issuance of common stock in June 2020.

Cash Flow Analysis for the Year Ended December 31, 2019 vs. 2018 - The cash flow analysis for the year ended December 31, 2019, compared with the year ended December 31, 2018, is 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.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report.

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.

The following is a summary of our most critical accounting policies and estimates, which are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our estimates and critical accounting policies with the Audit Committee of our Board of Directors. See Note A of the Notes to Consolidated Financial Statements in this Annual Report for the description of our accounting policies and additional information about our critical accounting policies and estimates.

Derivatives and Risk-management Activities - We utilize derivatives to reduce our market-risk exposure to commodity price and interest-rate fluctuations and to achieve more predictable cash flows. Our commodity price risk includes basis risk, which is the difference in price between various locations where commodities are purchased and sold. We record all derivative instruments at fair value, except for normal purchases and normal sales transactions that are expected to result in physical delivery. Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists.

Our fair value measurements classified as Level 3 are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry Hub. These measurements are based on inputs that may include one or more unobservable inputs, including internally developed commodity price curves, that incorporate market data from broker quotes and third-party pricing services. Our commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data. We believe any measurement uncertainty at December 31, 2020, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services.

The accounting for changes in the fair value of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship. When possible, we implement effective hedging strategies using derivative financial instruments that qualify as hedges for accounting purposes. We have not used derivative instruments for trading purposes. For a derivative designated as a cash flow hedge, the gain or loss from a change in fair value of the derivative instrument is deferred in accumulated other comprehensive income (loss) until the forecasted transaction affects earnings, at which time the fair value of the derivative instrument is reclassified into earnings.

We assess hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our derivatives are accounted for as effective cash flow hedges. However, if a derivative instrument is ineligible for cash flow hedge accounting or if we fail to appropriately designate it as a cash flow hedge, changes in fair value of the derivative instrument would be recorded currently in earnings. Additionally, if a cash flow hedge ceases to qualify for hedge accounting treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative instrument would be recognized in earnings. For more information on commodity price sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

See Notes A, B and C of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of fair value measurements and derivatives and risk-management activities.

Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. Due to historic events as a result of COVID-19 impacting supply, demand and commodity prices, we performed a Step 1 analysis in the first quarter 2020 to test our goodwill for impairment and evaluated certain long-lived asset groups and equity investments for impairment.

Goodwill - In the Step 1 analysis, an assessment is made by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying value of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. In January 2020, we adopted ASU 2017-04 in which the requirement to calculate the implied fair value of goodwill under the two-step impairment test was eliminated.

To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply EBITDA multiples to forecasted EBITDA. The multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows for a reporting unit over a period of years.

Based on the results of our impairment test, we concluded that the carrying value of the Natural Gas Gathering and Processing reporting unit exceeded its estimated fair value, resulting in a noncash impairment charge of $153.4 million. The estimated fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units substantially exceeded their respective carrying values.

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, 2020, we assessed qualitative factors subsequent to our first quarter 2020 impairment charges discussed below, to determine whether it was more likely than not that the fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units were less than their carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that it was more likely than not that the fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units were not less than their respective carrying value, no further testing was necessary and goodwill was not considered impaired. At July 1, 2020, there was no remaining goodwill associated with our Natural Gas Gathering and Processing reporting unit.

Long-lived assets - We assess our long-lived assets for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset.

In 2020, we evaluated our Natural Gas Gathering and Processing segment asset groups and determined that the carrying value of certain long-lived asset groups in the Powder River Basin, western Oklahoma and Kansas were not recoverable and exceeded their estimated fair value. We recorded noncash impairment charges of $382.2 million, which includes a natural gas processing plant and infrastructure in the Powder River Basin and its related supply contracts and natural gas processing plants and infrastructure in western Oklahoma and Kansas. In our Natural Gas Liquids segment, we recorded noncash impairment charges of $71.6 million related primarily to certain inactive assets, as our expectation for future use of the assets changed.

Investments in unconsolidated affiliates - The impairment test for equity-method investments considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically evaluate the amount at which we carry our equity-method investments to determine whether current events or circumstances warrant adjustments to our carrying values.

In 2020, we evaluated our investments in unconsolidated affiliates and concluded that the carrying value of our 10.2% investment in Venice Energy Services Company in our Natural Gas Gathering and Processing segment exceeded its estimated fair value, resulting in a noncash impairment charge of $30.5 million, which includes an impairment to our equity-method goodwill of $22.3 million. We also concluded that the carrying value of our 50% investment in Chisholm Pipeline Company in our Natural Gas Liquids segment exceeded its estimated fair value, resulting in a noncash impairment charge of $7.2 million.

Our impairment tests required the use of assumptions and estimates, such as industry economic factors and the profitability of future business strategies. To estimate the fair value of these assets and investments, we used two generally accepted valuation approaches, an income approach and a market approach. Under the income approach, our discounted cash flow analysis included the following inputs that are not readily available: a discount rate reflective of industry cost of capital, our estimated contract rates, volumes, operating margins, operating and maintenance costs and capital expenditures. Under the market approach, our inputs included EBITDA multiples, which were estimated from recent peer acquisition transactions, and forecasted EBITDA, which incorporates inputs similar to those used under the income approach. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.

See Notes A, D, E and M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of goodwill, long-lived assets and investments in unconsolidated affiliates.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment - Our property, plant and equipment are depreciated using the straight-line method that incorporates management assumptions regarding useful economic lives and residual values. As we place additional assets in service, our estimates related to depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material effect on our results of operations. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation expense prospectively. Examples of such circumstances include changes in (i) competition, (ii) laws and regulations that limit the estimated economic life of an asset, (iii) technology that render an asset obsolete, (iv) expected salvage values and (v) forecasts of the remaining economic life for the resource basins where our assets are located, if any. For the fiscal years presented in this Form 10-K, no changes were made to the determinations of useful lives that would have a material effect on the timing of depreciation expense in future periods.

See Note D of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of property, plant and equipment.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table sets forth our contractual obligations related to debt, leases and other long-term obligations as of December 31, 2020. For additional discussion of the debt and lease agreements, see Notes F and O, respectively, of the Notes to Consolidated Financial Statements in this Annual Report.


	Payments Due by Period
Contractual Obligations	Total		2021		2022		2023		2024		2025		Thereafter
	(Millions of dollars)
Senior notes	$	14,347.9	$	—	$	1,437.7	$	925.0	$	500.0	$	887.0	$	10,598.2

Guardian Pipeline senior notes	13.7		7.7		6.0		—		—		—		—
Interest payments on debt	9,710.4		704.2		675.0		631.4		586.8		555.7		6,557.3
Operating leases	116.1		16.5		15.1		13.8		12.5		11.1		47.1
Finance lease	35.1		4.5		4.5		4.5		4.5		4.5		12.6
Firm transportation and storage contracts	516.7		70.9		60.9		55.8		53.4		47.9		227.8
Financial and physical derivatives	393.4		377.9		15.5		—		—		—		—
Employee benefit plans	57.0		11.2		11.8		12.9		10.3		10.8		—
Purchase commitments and other	369.6		83.8		83.4		81.6		41.1		40.7		39.0
Total	$	25,559.9	$	1,276.7	$	2,309.9	$	1,725.0	$	1,208.6	$	1,557.7	$	17,482.0

Senior notes - Represents the amount of principal due in each period.

Interest payments on debt - Interest payments are calculated by multiplying long-term debt principal amount by the respective coupon rates.

Operating leases - Our operating leases primarily include leases for pipeline capacity, certain buildings, warehouses, office space, land and equipment, including pipeline equipment, rail cars and information technology equipment.

Finance lease - We lease certain compression facilities under a finance lease that has a fixed-price purchase option in 2028.

Firm transportation and storage contracts - Our Natural Gas Gathering and Processing and Natural Gas Liquids segments are party to fixed-rate contracts for firm transportation and storage capacity.

Financial and physical derivatives - These are obligations arising from our fixed- and variable-price purchase commitments for physical and financial commodity derivatives. Estimated future variable-price purchase commitments are based on market information at December 31, 2020. Actual future variable-price purchase obligations may vary depending on market prices at the time of delivery. Sales of the related physical volumes and net positive settlements of financial derivatives are not reflected in the table above.

Employee benefit plans - Represents projected minimum required cash contributions. We contributed $11.2 million to our defined benefit pension plan in January 2021 and do not expect to make any contributions to our other postretirement plans in

the remainder of 2021. See Note K of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our employee benefit plans.

Purchase commitments and other - Purchase commitments include payments for NGL fractionation capacity and other contractual commitments. Purchase commitments exclude commodity purchase contracts, which are included in the “Financial and physical derivatives” amounts.

FORWARD-LOOKING STATEMENTS

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

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

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

the length, severity and reemergence of a pandemic or other health crisis, such as the recent outbreak of COVID-19 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, climate change initiatives, 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 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 recent 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 administrative proceedings and litigation, regulatory actions, executive orders, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHMSA, the EPA and the CFTC;
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 this Annual Report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

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