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A.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2019 year-end Consolidated Balance Sheet data was derived from our audited Consolidated Financial Statements but does not include all disclosures required by GAAP. Certain reclassifications have been made in the prior year Consolidated Financial Statements to conform to the current year presentation. These unaudited Consolidated Financial Statements should be read in conjunction with our audited Consolidated Financial Statements in our Annual Report.

In March 2020, the CARES Act was signed into law in response to the COVID-19 pandemic, and we opted into the CARES Act payroll tax deferral program, which will modestly benefit us, and the 401(k) penalty-free hardship withdrawal and loan deferral programs for employees.

For the six months ended June 30, 2020, our effective income tax rate was 60%, driven primarily by excess tax benefits from share-based compensation combined with the tax benefits from year-to-date losses.

Impairment Charges - Late in the first quarter 2020, we experienced a significant decline in our share price and market capitalization as the energy industry experienced historic events that led to a simultaneous demand and supply shock. The World Health Organization declared COVID-19 a global pandemic and recommended containment and mitigation measures worldwide, which contributed to a massive economic slowdown and decreased demand for crude oil. In addition, Saudi Arabia and Russia increased production of crude oil as the two countries competed for market share. As a result, the global supply of crude oil significantly exceeded demand and led to a collapse in crude oil prices. Based on these events, 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 - We assess our goodwill for impairment at least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. 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, which is included within impairment charges in our Consolidated Statement of Income for the six months ended June 30, 2020. The estimated fair value of our Natural Gas Liquids and Natural Gas Pipelines reporting units substantially exceeded their respective carrying values.

The following table sets forth our goodwill, by segment, for the periods indicated:

		June 30, 2020				December 31, 2019
		(Thousands of dollars)
Natural Gas Gathering and Processing		$	—			$	153,404
Natural Gas Liquids		371,217				371,217
Natural Gas Pipelines		156,375				156,375
Total goodwill		$	527,592			$	680,996

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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 the first quarter 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 western Oklahoma, Kansas and the Powder River Basin, where lower pricing impacted drilling and production levels, were not recoverable and exceeded their estimated fair value. We recorded noncash impairment charges of $380.5 million, which includes impairment to intangible assets of $19.9 million related to supply contracts. In our Natural Gas Liquids segment, we recorded noncash impairment charges of $70.2 million related to certain inactive assets, as our expectation for future use of the assets changed. These charges are included within impairment charges in our Consolidated Statement of Income for the six months ended June 30, 2020.

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 the first quarter 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. These impairment charges are included within impairment of equity investments in our Consolidated Statement of Income for the six months ended June 30, 2020.

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Recently Issued Accounting Standards Update - Changes to GAAP are established by the Financial Accounting Standards Board (FASB) in the form of ASUs to the FASB Accounting Standards Codification. We consider the applicability and impact of all ASUs. ASUs not listed below or in our Annual Report were assessed and determined to be either not applicable or clarifications of ASUs previously issued or listed below. Except as discussed below or in our Annual Report, there have been no new accounting pronouncements that have become effective or have been issued that are of significance or potential significance to us. The following table provides a brief description of recently adopted accounting pronouncements and our analysis of the effects on our financial statements:

Standard		Description		Date of Adoption		Effect on the Financial Statements or Other Significant Matters
ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”		The standard requires a financial asset (or a group of financial assets) measured at amortized cost basis to be presented net of the allowance for credit losses to reflect the net carrying value at the amount expected to be collected on the financial asset; and the initial allowance for credit losses for purchased financial assets, including available-for-sale debt securities, to be added to the purchase price rather than being reported as a credit loss expense.		First quarter 2020		The impact of adopting this standard was not material.
ASU 2017-04, “Intangibles- Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment”		The standard simplifies the subsequent measurement of goodwill by eliminating the requirement to calculate the implied fair value of goodwill under step 2. Instead, an entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The standard does not change step zero or step 1 assessments.		First quarter 2020		We adopted and implemented this standard to record noncash impairment charges related to our goodwill, as described above.
ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting”		The standard provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met.		First quarter 2020		The impact of adopting this standard was not material.

B.	FAIR VALUE MEASUREMENTS

Determining Fair Value - For our fair value measurements, we utilize market prices, third-party pricing services, present value methods and standard option valuation models to determine the price we would receive from the sale of an asset or the transfer of a liability in an orderly transaction at the measurement date. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists. Our financial commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing broker account with daily margin requirements. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

We compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from the implied forward LIBOR yield curve. The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using counterparty-specific bond yields. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ materially from our estimates.

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:

•	Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets. These balances are composed predominantly of exchange-traded derivative contracts for natural gas and crude oil.

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•	Level 2 - fair value measurements are based on significant observable pricing inputs, including quoted prices for similar assets and liabilities in active markets and inputs from third-party pricing services supported with corroborative evidence. These balances are composed of over-the-counter interest-rate derivatives.

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Level 3 - fair value 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. These balances 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. 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 June 30, 2020, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as our derivatives are accounted for as hedges.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods indicated:

	June 30, 2020
	Level 1				Level 2				Level 3				Total - Gross				Netting (a)				Total - Net
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	29,175			$	—			$	51,989			$	81,164			$	(52,719	)		$	28,445
Total derivative assets	$	29,175			$	—			$	51,989			$	81,164			$	(52,719	)		$	28,445
Derivative liabilities
Commodity contracts
Financial contracts	$	(10,352	)		$	—			$	(46,406	)		$	(56,758	)		$	52,719			$	(4,039	)
Interest-rate contracts	—				(241,205		)		—				(241,205		)		—				(241,205		)
Total derivative liabilities	$	(10,352	)		$	(241,205	)		$	(46,406	)		$	(297,963	)		$	52,719			$	(245,244	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At June 30, 2020, we held no cash and posted $13.3 million of cash with various counterparties, which is included in other current assets in our Consolidated Balance Sheet.

	December 31, 2019
	Level 1				Level 2				Level 3				Total - Gross				Netting (a)				Total - Net
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	10,892			$	—			$	55,557			$	66,449			$	(28,588	)		$	37,861
Interest-rate contracts	—				581				—				581				—				581
Total derivative assets	$	10,892			$	581			$	55,557			$	67,030			$	(28,588	)		$	38,442
Derivative liabilities
Commodity contracts
Financial contracts	$	(4,811	)		$	—			$	(24,785	)		$	(29,596	)		$	28,588			$	(1,008	)
Interest-rate contracts	—				(201,941		)		—				(201,941		)		—				(201,941		)
Total derivative liabilities	$	(4,811	)		$	(201,941	)		$	(24,785	)		$	(231,537	)		$	28,588			$	(202,949	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2019, we held no cash and posted $8.8 million of cash with various counterparties, which is included in other current assets in our Consolidated Balance Sheet.

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The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:

	Three Months Ended								Six Months Ended
	June 30,								June 30,
Derivative Assets (Liabilities)	2020				2019				2020				2019
	(Thousands of dollars)
Net assets at beginning of period	$	57,401			$	11,529			$	30,772			$	40,484
Total changes in fair value:
Settlements included in net income (loss) (a)	(34,478		)		(8,830		)		(23,383		)		(32,624		)
New Level 3 derivatives included in other comprehensive income (loss) (b)	3,407				4,545				2,002				5,598
Unrealized change included in other comprehensive income (loss) (b)	(20,747		)		12,030				(3,808		)		5,816
Net assets at end of period	$	5,583			$	19,274			$	5,583			$	19,274

(a) - Included in commodity sales revenues/cost of sales and fuel in our Consolidated Statements of Income.

(b) - Included in change in fair value of derivatives in our Consolidated Statements of Comprehensive Income.

During the three and six months ended June 30, 2020 and 2019, there were no transfers in or out of Level 3 of the fair value hierarchy.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and short-term borrowings is equal to book value due to the short-term nature of these items. Our cash and cash equivalents are composed of bank and money market accounts and are classified as Level 1. Our short-term borrowings are classified as Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the commercial paper market.

The estimated fair value of our consolidated long-term debt, including current maturities, was $15.0 billion and $13.8 billion at June 30, 2020, and December 31, 2019, respectively. The book value of our consolidated long-term debt, including current maturities, was $14.3 billion and $12.5 billion at June 30, 2020, and December 31, 2019, respectively. The estimated fair value of the aggregate long-term debt outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our consolidated long-term debt is classified as Level 2.

Nonrecurring Fair Value Measurements - In the first quarter 2020, we incurred noncash impairment charges for certain long-lived assets and equity investments. The valuation of these assets and investments required the use of significant unobservable inputs. To estimate the fair value, 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 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. The estimated fair value of these assets is classified as Level 3. See Note A for additional information about our impairment charges.

C.	RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk-Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We are also subject to the risk of interest-rate fluctuation in the normal course of business. We use physical-forward purchases and sales and financial derivatives to secure a certain price for a portion of our natural gas, condensate and NGL products; to reduce our exposure to commodity price and interest-rate fluctuations; and to achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our risk-management activities. We have not used these instruments for trading purposes.

Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate. We may use the following commodity derivative instruments to reduce the near-term commodity price risk associated with a portion of the forecasted sales of these commodities:

•	Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;

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•	Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, crude oil or NGLs for future physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties;

•	Swaps - Exchange of one or more payments based on the value of one or more commodities. These instruments transfer the financial risk associated with a future change in value between the counterparties of the transaction, without also conveying ownership interest in the asset or liability; and

•	Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity at a fixed price within a specified period of time. Options may either be standardized and exchange-traded or customized and nonexchange-traded.

We may also use other instruments, including collars, to mitigate commodity price risk. A collar is a combination of a purchased put option and a sold call option, which places a floor and a ceiling price for commodity sales being hedged.

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. Under certain POP with fee contracts, our fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. In the current commodity price environment, our contractual fees on these certain POP with fee contracts have decreased, which impacts the average fee rate in our Natural Gas Gathering and Processing segment. We also are exposed to basis risk between the various production and market locations where we buy and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative financial instruments and physical-forward contracts to reduce the impact of price fluctuations related to natural gas, NGLs and condensate.

In our Natural Gas Liquids segment, we are primarily exposed to commodity price risk resulting from the relative values of the various NGL products to each other, the value of NGLs in storage and the relative value of NGLs to natural gas. We are also exposed to location price differential risk as a result of the relative value of NGL purchases at one location and sales at another location, primarily related to our optimization and marketing activities. As part of our hedging strategy, we utilize physical-forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to NGLs.

In our Natural Gas Pipelines segment, we are primarily exposed to commodity price risk on our intrastate pipelines because they consume natural gas in operations and retain natural gas from our customers for operations or as part of our fee for services provided. When the amount consumed in operations differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose this segment to commodity price risk depending on the regulatory treatment for this activity. To the extent that commodity price risk in our Natural Gas Pipelines segment is not mitigated by fuel cost-recovery mechanisms, we may use physical-forward sales or purchases to reduce the impact of natural gas price fluctuations. At June 30, 2020, and December 31, 2019, there were no financial derivative instruments with respect to our natural gas pipeline operations.

Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. In March 2020, we settled $750 million of our forward-starting interest-rate swaps related to our underwritten public offerings of $1.75 billion senior unsecured notes. In May 2020, we settled the remaining $1.3 billion of our interest-rate swaps used to hedge our LIBOR-based interest payments.

At June 30, 2020, and December 31, 2019, we had forward-starting interest-rate swaps with notional amounts totaling $1.1 billion and $1.8 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At December 31, 2019, we had interest-rate swaps with notional amounts totaling $1.3 billion to hedge the variability of our LIBOR-based interest payments, all of which have settled as of June 30, 2020. All of our interest-rate swaps are designated as cash flow hedges.

Accounting Treatment - Our accounting treatment of derivative instruments is consistent with that disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

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Fair Values of Derivative Instruments - See Note B for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of our derivative instruments presented on a gross basis for the periods indicated:

			June 30, 2020								December 31, 2019
	Location in our Consolidated Balance Sheets		Assets				(Liabilities)				Assets				(Liabilities)
Derivatives designated as hedging instruments			(Thousands of dollars)
Commodity contracts (a)
Financial contracts	Other current assets/other current liabilities		$	80,992			$	(56,587	)		$	64,858			$	(26,997	)
	Other deferred credits		—				—				1,591				(2,599		)
Interest-rate contracts	Other current liabilities		—				—				—				(90,161		)
	Other assets/other deferred credits		—				(241,205		)		581				(111,780		)
Total derivatives designated as hedging instruments			$	80,992			$	(297,792	)		$	67,030			$	(231,537	)
Derivatives not designated as hedging instruments
Commodity contracts (a)
Financial contracts	Other current assets		$	172			$	(171	)		$	—			$	—
Total derivatives not designated as hedging instruments			$	172			$	(171	)		$	—			$	—
Total derivatives			$	81,164			$	(297,963	)		$	67,030			$	(231,537	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for the periods indicated:

		June 30, 2020								December 31, 2019
	Contract Type	Purchased/ Payor				Sold/ Receiver				Purchased/ Payor					Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Futures and swaps	5.8				(45.4		)		—					(59.0		)
- Natural gas (Bcf)	Options	—				(31.5		)		—			—		—
- Crude oil and NGLs (MMBbl)	Futures, forwards, swaps and options	13.8				(22.5		)		7.9					(17.4		)
Basis
- Natural gas (Bcf)	Futures and swaps	5.8				(45.4		)		—					(59.0		)
Interest-rate contracts (Billions of dollars)	Swaps	$	1.1			$	—			$	3.1				$	—
Derivatives not designated as hedging instruments:
Fixed price
-Natural gas (Bcf)	Futures and swaps	1.8				(1.8		)		—					—
Basis
- Natural gas (Bcf)	Futures and Swaps	1.8				(1.8		)		—					—

These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to which the positions offset one another and, consequently, do not reflect our actual exposure to market or credit risk.

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Cash Flow Hedges - The following table sets forth the unrealized change in fair value of cash flow hedges in other comprehensive loss for the periods indicated:

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2020				2019				2020				2019
	(Thousands of dollars)
Commodity contracts	$	(39,056	)		$	33,334			$	48,139			$	11,709
Interest-rate contracts	(21,372		)		(107,398		)		(246,413		)		(175,310		)
Total unrealized change in fair value of cash flow hedges in other comprehensive loss	$	(60,428	)		$	(74,064	)		$	(198,274	)		$	(163,601	)

The following table sets forth the effect of cash flow hedges on net income (loss) for the periods indicated:

	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss)	Three Months Ended								Six Months Ended
		June 30,								June 30,
		2020				2019				2020				2019
		(Thousands of dollars)
Commodity contracts	Commodity sales revenues	$	53,138			$	23,319			$	98,137			$	47,141
	Cost of sales and fuel	(14,450		)		(8,075		)		(29,489		)		(13,045		)
Interest-rate contracts (a)	Interest expense	(64,541		)		(4,815		)		(74,819		)		(7,319		)
Total change in fair value of cash flow hedges reclassified from accumulated other comprehensive loss into net income (loss) on derivatives		$	(25,853	)		$	10,429			$	(6,171	)		$	26,777

(a) - The three and six months ended June 30, 2020, include a loss of $48.3 million on the settlement of our remaining $1.3 billion interest-rate swaps used to hedge our LIBOR-based interest payments.

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We use internally developed credit ratings for counterparties that do not have a credit rating.

Our financial commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing broker account with daily margin requirements. However, we may enter into financial derivative instruments that contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on our senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. There were no financial derivative instruments with contingent features related to credit risk at June 30, 2020.

The counterparties to our derivative contracts typically consist of major energy companies, financial institutions and commercial and industrial end users. This concentration of counterparties may affect our overall exposure to credit risk, either positively or negatively, in that the counterparties may be affected similarly by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

At June 30, 2020, the credit exposure from our derivative assets is with investment-grade companies in the financial services sector.

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D.	DEBT

The following table sets forth our consolidated debt for the periods indicated:

		June 30, 2020				December 31, 2019
		(Thousands of dollars)
Commercial paper outstanding, bearing a weighted-average interest rate of 2.16% as of December 31, 2019		$	—			$	220,000
Senior unsecured obligations:
$1,500,000 term loan at 2.70% as of December 31, 2019, due November 2021		—				1,250,000
$700,000 at 4.25% due February 2022		547,397				547,397
$900,000 at 3.375% due October 2022		900,000				900,000
$425,000 at 5.0% due September 2023		425,000				425,000
$500,000 at 7.5% due September 2023		500,000				500,000
$500,000 at 2.75% due September 2024		500,000				500,000
$500,000 at 4.9% due March 2025		500,000				500,000
$400,000 at 2.2% due September 2025		387,000				—
$600,000 at 5.85% due January 2026		600,000				—
$500,000 at 4.0% due July 2027		500,000				500,000
$800,000 at 4.55% due July 2028		800,000				800,000
$100,000 at 6.875% due September 2028		100,000				100,000
$700,000 at 4.35% due March 2029		700,000				700,000
$750,000 at 3.4% due September 2029		714,251				750,000
$850,000 at 3.1% due March 2030		780,093				—
$600,000 at 6.35% due January 2031		600,000				—
$400,000 at 6.0% due June 2035		400,000				400,000
$600,000 at 6.65% due October 2036		600,000				600,000
$600,000 at 6.85% due October 2037		600,000				600,000
$650,000 at 6.125% due February 2041		650,000				650,000
$400,000 at 6.2% due September 2043		400,000				400,000
$700,000 at 4.95% due July 2047		689,006				700,000
$1,000,000 at 5.2% due July 2048		1,000,000				1,000,000
$750,000 at 4.45% due September 2049		737,736				750,000
$500,000 at 4.5% due March 2050		467,625				—
$300,000 at 7.15% due January 2051		300,000				—
Guardian Pipeline
Weighted average 7.85% due December 2022		17,482				21,307
Total debt		14,415,590				12,813,704
Unamortized portion of terminated swaps		14,173				15,032
Unamortized debt issuance costs and discounts		(145,881		)		(121,329		)
Current maturities of long-term debt		(7,650		)		(7,650		)
Short-term borrowings (a)		—				(220,000		)
Long-term debt		$	14,276,232			$	12,479,757

(a) - Individual issuances of commercial paper under our commercial paper program generally mature in 90 days or less.

$2.5 Billion Credit Agreement - Our $2.5 Billion Credit Agreement is a revolving credit facility and contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of net indebtedness to adjusted EBITDA (EBITDA, as defined in our $2.5 Billion Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1 at June 30, 2020. In June 2020, we amended the $2.5 Billion Credit Agreement by, among other things, modifying the leverage ratio so that we may net up to $700 million of cash on hand against our consolidated indebtedness for purposes of calculating the ratio’s numerator for the fiscal quarters ending June 30, 2020, September 30, 2020, and December 31, 2020. At June 30, 2020, we had no outstanding borrowings, our ratio of net indebtedness to adjusted EBITDA was 4.5 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit Agreement.

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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 were 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 were 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.

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.

During the three and six months ended June 30, 2020, we repurchased in the open market outstanding principal of certain of our senior notes in the amounts of $107.3 million and $174.3 million, respectively, for an aggregate repurchase price of $101.8 million and $152.3 million, respectively, with cash on hand. In connection with these open market repurchases, we recognized $4.3 million and $20.0 million of gains on extinguishment of debt, which is included in other income in our Consolidated Statement of Income for the three and six months ended June 30, 2020, respectively.

Debt Guarantees - We, ONEOK Partners and the Intermediate Partnership have cross guarantees in place for our and ONEOK Partners’ indebtedness.

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

E.	EQUITY

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. We expect to use the net proceeds from this offering for general corporate purposes, which could include the repayment of existing indebtedness and the funding of capital expenditures.

Dividends - Holders of our common stock share equally in any dividend declared by our Board of Directors, subject to the rights of the holders of outstanding preferred stock. Dividends paid on our common stock in February 2020 and May 2020 were $0.935 per share. A dividend of $0.935 per share was declared for shareholders of record at the close of business on August 3, 2020, payable August 14, 2020.

The Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. We paid dividends for the Series E Preferred Stock of $0.3 million in February 2020 and May 2020. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable August 14, 2020.

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F.	ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the balance in accumulated other comprehensive loss for the period indicated:

		Risk- Management Assets/Liabilities (a)				Retirement and Other Postretirement Benefit Plan Obligations (a) (b)				Risk- Management Assets/Liabilities of Unconsolidated Affiliates (a)				Accumulated Other Comprehensive Loss (a)
		(Thousands of dollars)
January 1, 2020		$	(233,520	)		$	(131,481	)		$	(8,999	)		$	(374,000	)
Other comprehensive income (loss) before reclassifications		(152,671		)		39				(11,567		)		(164,199		)
Amounts reclassified to net income (loss) (c)		5,849				7,084				363				13,296
Other comprehensive income (loss)		(146,822		)		7,123				(11,204		)		(150,903		)
June 30, 2020		$	(380,342	)		$	(124,358	)		$	(20,203	)		$	(524,903	)

(a) - All amounts are presented net of tax.

(b) - Includes amounts related to supplemental executive retirement plan.

(c) - See Note C for details of amounts reclassified to net income (loss) for risk-management assets/liabilities and Note H for retirement and other postretirement benefit plan obligations.

The following table sets forth information about the balance of accumulated other comprehensive loss at June 30, 2020, representing unrealized gains (losses) related to risk-management assets and liabilities:

		Risk- Management Assets/Liabilities (a)
		(Thousands of dollars)
Commodity derivative instruments expected to be realized within the next 18 months (b)		$	12,317
Settled interest-rate swaps to be recognized over the life of the long-term, fixed-rate debt (c)		(206,931		)
Interest-rate swaps with future settlement dates expected to be amortized over the life of long-term debt		(185,728		)
Accumulated other comprehensive loss at June 30, 2020		$	(380,342	)

(a) - All amounts are presented net of tax.

(b) - Based on June 30, 2020, commodity prices, we expect to realize $12.6 million in net gains, net of tax, over the next 12 months and $0.3 million in net losses, net of tax, thereafter.

(c) - We expect losses of $30.0 million, net of tax, will be reclassified into earnings during the next 12 months as the hedged items affect earnings.

The remaining amounts in accumulated other comprehensive loss relate primarily to our retirement and other postretirement benefit plan obligations, which are expected to be amortized over the average remaining service period of employees participating in these plans.

G.	EARNINGS PER SHARE

The following tables set forth the computation of basic and diluted EPS for the periods indicated:

	Three Months Ended June 30, 2020
	Income				Shares			Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net income available for common stock	$	134,046			419,722			$	0.32
Diluted EPS
Effect of dilutive securities	—				394
Net income available for common stock and common stock equivalents	$	134,046			420,116			$	0.32

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	Three Months Ended June 30, 2019
	Income				Shares			Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net income available for common stock	$	311,688			413,606			$	0.75
Diluted EPS
Effect of dilutive securities	—				1,443
Net income available for common stock and common stock equivalents	$	311,688			415,049			$	0.75

	Six Months Ended June 30, 2020
	Loss				Shares			Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net loss available for common stock	$	(8,086	)		417,002			$	(0.02	)
Diluted EPS
Effect of dilutive securities	—				—
Net loss available for common stock and common stock equivalents (a)	$	(8,086	)		417,002			$	(0.02	)

(a) - For the six months ended June 30, 2020, 729,874 weighted-average shares have been excluded from the calculation of diluted loss per share as their inclusion would have been anti-dilutive due to our net loss available for common stock.

	Six Months Ended June 30, 2019
	Income				Shares			Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net income available for common stock	$	648,621			413,257			$	1.57
Diluted EPS
Effect of dilutive securities	—				1,884
Net income available for common stock and common stock equivalents	$	648,621			415,141			$	1.56

H.	EMPLOYEE BENEFIT PLANS

The following tables set forth the components of net periodic benefit cost for our retirement and other postretirement benefit plans for the periods indicated:

	Retirement Benefits								Other Postretirement Benefits
	Three Months Ended								Three Months Ended
	June 30,								June 30,
	2020				2019				2020				2019
	(Thousands of dollars)
Components of net periodic benefit cost (income)
Service cost	$	2,036			$	1,954			$	115			$	117
Interest cost	4,574				5,126				442				509
Expected return on plan assets	(6,232		)		(5,892		)		(722		)		(570		)
Amortization of prior service cost (credit) (a)	28				—				—				(57		)
Amortization of net loss (a)	4,571				3,158				1				74
Net periodic benefit cost (income)	$	4,977			$	4,346			$	(164	)		$	73

(a) - These components of net periodic benefit cost (income) are recognized in accumulated other comprehensive loss and are reclassified to other income (expense) in our Consolidated Statements of Income, with related income tax benefits of $1.0 million and $0.8 million reclassified to income tax (expense) benefit for the three months ended June 30, 2020 and 2019, respectively.

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	Retirement Benefits								Other Postretirement Benefits
	Six Months Ended								Six Months Ended
	June 30,								June 30,
	2020				2019				2020				2019
	(Thousands of dollars)
Components of net periodic benefit cost (income)
Service cost	$	4,072			$	3,908			$	230			$	234
Interest cost	9,148				10,252				884				1,018
Expected return on plan assets	(12,464		)		(11,784		)		(1,444		)		(1,140		)
Amortization of prior service cost (credit) (a)	56				—				—				(114		)
Amortization of net loss (a)	9,142				6,316				2				148
Net periodic benefit cost (income)	$	9,954			$	8,692			$	(328	)		$	146

(a) - These components of net periodic benefit cost (income) are recognized in accumulated other comprehensive loss and are reclassified to other income (expense) in our Consolidated Statements of Income, with related income tax benefits of $2.1 million and $1.5 million reclassified to income tax (expense) benefit for the six months ended June 30, 2020 and 2019, respectively.

I.	UNCONSOLIDATED AFFILIATES

Equity in Net Earnings from Investments and Impairments - The following table sets forth our equity in net earnings (loss) from investments for the periods indicated:

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2020				2019				2020				2019
	(Thousands of dollars)
Northern Border Pipeline	$	12,871			$	13,689			$	34,991			$	34,491
Overland Pass Pipeline	7,972				15,465				22,083				32,859
Roadrunner	6,809				6,077				13,242				12,415
Other	(2,324		)		(1,113		)		(361		)		(2,166		)
Equity in net earnings from investments	$	25,328			$	34,118			$	69,955			$	77,599
Impairment of equity investments	$	—			$	—			$	(37,730	)		$	—

In the first quarter 2020, we incurred a noncash impairment charge of $30.5 million related to our 10.2% investment in Venice Energy Services Company in our Natural Gas Gathering and Processing segment, which includes $22.3 million related to equity-method goodwill, and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company in our Natural Gas Liquids segment. Our remaining equity-method goodwill was $16.5 million at June 30, 2020. For additional information on our impairment charges, see Note A.

We incurred expenses in transactions with unconsolidated affiliates of $41.8 million and $40.5 million for the three months ended June 30, 2020 and 2019, respectively, and $87.1 million and $82.3 million for the six months ended June 30, 2020 and 2019, respectively, primarily related to Overland Pass Pipeline and Northern Border Pipeline. Accounts payable to our equity-method investees at June 30, 2020, and December 31, 2019, were $9.7 million and $13.5 million, respectively.

J.	COMMITMENTS AND CONTINGENCIES

Environmental Matters and Pipeline Safety - The operation of pipelines, plants and other facilities for the gathering, processing, fractionation, transportation and storage of natural gas, NGLs, condensate and other products is subject to numerous and complex laws and regulations pertaining to health, safety and the environment. As an owner and/or operator of these facilities, we must comply with laws and regulations that relate to air and water quality, hazardous and solid waste management and disposal, cultural resource protection and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with these laws, regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the

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imposition of remedial requirements and the issuance of injunctions or restrictions on operation or construction. Management believes that, based on currently known information, compliance with these laws and regulations will not affect adversely our consolidated results of operations, financial condition or cash flows.

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.

K.	LEASES

In December 2019, we entered into an operating lease for pipeline capacity with a lease term of 10 years that commenced January 1, 2020. In connection with this lease, we recognized an operating lease right-of-use asset and a lease liability with remaining balances of $72.3 million and $72.8 million, respectively, as of June 30, 2020. During the six months ended June 30, 2020, we entered into certain operating leases and recognized operating lease right-of-use assets and lease liabilities with remaining balances of $16.6 million at the end of the period. At June 30, 2020, the weighted-average remaining lease term and the weighted-average discount rate for our operating leases were 8.7 years and 3.18%, respectively.

The following table sets forth supplemental cash flow information related to our leases:

		Six Months Ended
		June 30,
		2020				2019
		(Thousands of dollars)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for operating leases		$	6,150			$	3,300
Financing cash flows for finance lease		$	950			$	860
Right-of-use assets obtained in exchange for operating lease liabilities (noncash)		$	98,134			$	3,041

The following table sets forth the maturity of our lease liabilities as of June 30, 2020:

		Finance Lease				Operating Leases
		(Millions of dollars)
Remainder of 2020		$	2.3			$	8.3
2021		4.5				16.4
2022		4.5				15.0
2023		4.5				13.8
2024		4.5				12.5
2025 and beyond		17.1				57.9
Total lease payments		37.4				123.9
Less: Interest		12.1				16.6
Present value of lease liabilities		$	25.3			$	107.3

L.	REVENUES

Accounting Policies - Our revenue recognition policy is described in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

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Contract Assets and Contract Liabilities - Our contract asset balances at the beginning and end of the period primarily relate to our firm service transportation contracts with tiered rates, which are not material. The following table sets forth the balances in contract liabilities for the periods indicated:

Contract Liabilities		(Millions of dollars)
Balance at December 31, 2019 (a)		$	57.1
Revenue recognized included in beginning balance (b)		(34.1		)
Net additions		27.4
Balance at June 30, 2020 (c)		$	50.4

(a) - Contract liabilities of $22.2 million and $34.9 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheet.

(b) - Includes a contract settlement in the second quarter 2020 of revenue previously deferred.

(c) - Contract liabilities of $31.3 million and $19.1 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheet.

Receivables from Customers and Revenue Disaggregation - Substantially all of the balances in accounts receivable on our Consolidated Balance Sheets at June 30, 2020, and December 31, 2019, relate to customer receivables. Revenues sources are disaggregated in Note M.

Transaction Price Allocated to Unsatisfied Performance Obligations - We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) variable consideration on contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

The following table presents aggregate value allocated to unsatisfied performance obligations as of June 30, 2020, and the amounts we expect to recognize in revenue in future periods, related primarily to firm transportation and storage contracts with remaining contract terms ranging from one month to 24 years:

Expected Period of Recognition in Revenue		(Millions of dollars)
Remainder of 2020		$	172.4
2021		312.4
2022		229.9
2023		183.0
2024 and beyond		846.6
Total estimated transaction price allocated to unsatisfied performance obligations		$	1,744.3

The table above excludes variable consideration allocated entirely to wholly unsatisfied performance obligations, wholly unsatisfied promises to transfer distinct goods or services that are part of a single performance obligation and consideration we determine to be fully constrained. The amounts we determined to be fully constrained relate to future sales obligations under long-term sales contracts where the transaction price is not known and minimum volume agreements, which we consider to be fully constrained until invoiced.

M.	SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments, as follows:

•	our Natural Gas Gathering and Processing segment gathers, treats and processes natural gas;

•	our Natural Gas Liquids segment gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products; and

•	our Natural Gas Pipelines segment operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.

Other and eliminations consist of corporate costs, the operating and leasing activities of our headquarters building and related parking facility and eliminations necessary to reconcile our reportable segments to our Consolidated Financial Statements.

Accounting Policies - The accounting policies of the segments are described in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

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Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:

Three Months Ended June 30, 2020	Natural Gas Gathering and Processing				Natural Gas Liquids (a)				Natural Gas Pipelines (b)				Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	109,581			$	1,174,580			$	—			$	1,284,161
Residue natural gas sales	150,892				—				—				150,892
Gathering, processing and exchange services revenue	35,949				118,174				—				154,123
Transportation and storage revenue	—				40,881				121,777				162,658
Other	3,387				2,079				281				5,747
Total revenues (c)	299,809				1,335,714				122,058				1,757,581
Cost of sales and fuel (exclusive of depreciation and operating costs)	(132,221		)		(905,154		)		(168		)		(1,037,543		)
Operating costs	(78,668		)		(106,977		)		(33,092		)		(218,737		)
Equity in net earnings (loss) from investments	(2,149		)		7,797				19,680				25,328
Noncash compensation expense and other	1,978				6,262				1,355				9,595
Segment adjusted EBITDA	$	88,749			$	337,642			$	109,833			$	536,224
Depreciation and amortization	$	(55,419	)		$	(69,065	)		$	(14,925	)		$	(139,409	)
Capital expenditures	$	118,171			$	459,807			$	10,910			$	588,888

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $477.2 million, of which $432.6 million related to revenues within the segment, and cost of sales and fuel of $117.1 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $79.9 million and cost of sales and fuel of $6.7 million.

(c) - Intersegment revenues for the Natural Gas Gathering and Processing segment totaled $108.2 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.

Three Months Ended June 30, 2020		Total Segments				Other and Eliminations				Total
		(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales		$	1,284,161			$	(88,967	)		$	1,195,194
Residue natural gas sales		150,892				(3,931		)		146,961
Gathering, processing and exchange services revenue		154,123				—				154,123
Transportation and storage revenue		162,658				(3,627		)		159,031
Other		5,747				(327		)		5,420
Total revenues (a)		$	1,757,581			$	(96,852	)		$	1,660,729
Cost of sales and fuel (exclusive of depreciation and operating costs)		$	(1,037,543	)		$	97,085			$	(940,458	)
Operating costs		$	(218,737	)		$	(5,727	)		$	(224,464	)
Depreciation and amortization		$	(139,409	)		$	(1,007	)		$	(140,416	)
Equity in net earnings from investments		$	25,328			$	—			$	25,328
Capital expenditures		$	588,888			$	5,394			$	594,282

(a) - Noncustomer revenue for the three months ended June 30, 2020, totaled $18.8 million related primarily to gains from derivatives on commodity contracts.

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Three Months Ended June 30, 2019	Natural Gas Gathering and Processing				Natural Gas Liquids (a)				Natural Gas Pipelines (b)				Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	312,757			$	1,921,564			$	—			$	2,234,321
Residue natural gas sales	221,333				—				41				221,374
Gathering, processing and exchange services revenue	43,536				105,858				—				149,394
Transportation and storage revenue	—				42,655				117,240				159,895
Other	4,554				2,481				250				7,285
Total revenues (c)	582,180				2,072,558				117,531				2,772,269
Cost of sales and fuel (exclusive of depreciation and operating costs)	(309,745		)		(1,629,573		)		(1,649		)		(1,940,967		)
Operating costs	(85,762		)		(114,933		)		(36,605		)		(237,300		)
Equity in net earnings (loss) from investments	(1,621		)		15,972				19,767				34,118
Noncash compensation expense and other	1,571				2,738				1,500				5,809
Segment adjusted EBITDA	$	186,623			$	346,762			$	100,544			$	633,929
Depreciation and amortization	$	(53,552	)		$	(46,346	)		$	(14,167	)		$	(114,065	)
Capital expenditures	$	213,222			$	591,762			$	21,406			$	826,390

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $303.4 million, of which $267.3 million related to revenues within the segment, and cost of sales and fuel of $116.9 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $72.3 million and cost of sales and fuel of $3.7 million.

(c) - Intersegment revenues for the Natural Gas Gathering and Processing segment totaled $317.9 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.

Three Months Ended June 30, 2019		Total Segments				Other and Eliminations				Total
		(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales		$	2,234,321			$	(310,527	)		$	1,923,794
Residue natural gas sales		221,374				—				221,374
Gathering, processing and exchange services revenue		149,394				—				149,394
Transportation and storage revenue		159,895				(3,880		)		156,015
Other		7,285				(287		)		6,998
Total revenues (a)		$	2,772,269			$	(314,694	)		$	2,457,575
Cost of sales and fuel (exclusive of depreciation and operating costs)		$	(1,940,967	)		$	315,173			$	(1,625,794	)
Operating costs		$	(237,300	)		$	(413	)		$	(237,713	)
Depreciation and amortization		$	(114,065	)		$	(899	)		$	(114,964	)
Equity in net earnings from investments		$	34,118			$	—			$	34,118
Capital expenditures		$	826,390			$	4,069			$	830,459

(a) - Noncustomer revenue for the three months ended June 30, 2019, totaled $18.6 million related primarily to gains from derivatives on commodity contracts.

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Six Months Ended June 30, 2020	Natural Gas Gathering and Processing				Natural Gas Liquids (a)				Natural Gas Pipelines (b)				Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	329,498			$	2,771,291			$	—			$	3,100,789
Residue natural gas sales	339,943				—				2,035				341,978
Gathering, processing and exchange services revenue	73,886				238,710				—				312,596
Transportation and storage revenue	—				91,636				240,141				331,777
Other	6,462				4,669				665				11,796
Total revenues (c)	749,789				3,106,306				242,841				4,098,936
Cost of sales and fuel (exclusive of depreciation and operating costs)	(334,391		)		(2,183,908		)		(1,707		)		(2,520,006		)
Operating costs	(163,138		)		(196,548		)		(66,399		)		(426,085		)
Equity in net earnings (loss) from investments	(1,343		)		23,065				48,233				69,955
Noncash compensation expense and other	(2,520		)		(357		)		(611		)		(3,488		)
Segment adjusted EBITDA	$	248,397			$	748,558			$	222,357			$	1,219,312
Depreciation and amortization	$	(114,175	)		$	(126,906	)		$	(29,694	)		$	(270,775	)
Impairment charges	$	(564,353	)		$	(77,401	)		$	—			$	(641,754	)
Investments in unconsolidated affiliates	$	2,250			$	427,032			$	360,753			$	790,035
Total assets	$	6,426,121			$	13,183,168			$	2,064,197			$	21,673,486
Capital expenditures	$	299,781			$	1,205,990			$	27,500			$	1,533,271

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $912.3 million, of which $810.8 million related to revenues within the segment, and cost of sales and fuel of $237.5 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $153.8 million and cost of sales and fuel of $12.8 million.

(c) - Intersegment revenues for the Natural Gas Gathering and Processing segment totaled $321.5 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.

Six Months Ended June 30, 2020		Total Segments				Other and Eliminations				Total
		(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales		$	3,100,789			$	(288,439	)		$	2,812,350
Residue natural gas sales		341,978				(4,963		)		337,015
Gathering, processing and exchange services revenue		312,596				—				312,596
Transportation and storage revenue		331,777				(7,436		)		324,341
Other		11,796				(697		)		11,099
Total revenues (a)		$	4,098,936			$	(301,535	)		$	3,797,401
Cost of sales and fuel (exclusive of depreciation and operating costs)		$	(2,520,006	)		$	302,620			$	(2,217,386	)
Operating costs		$	(426,085	)		$	(5,419	)		$	(431,504	)
Depreciation and amortization		$	(270,775	)		$	(1,994	)		$	(272,769	)
Impairment charges		$	(641,754	)		$	—			$	(641,754	)
Equity in net earnings from investments		$	69,955			$	—			$	69,955
Investments in unconsolidated affiliates		$	790,035			$	—			$	790,035
Total assets		$	21,673,486			$	1,318,981			$	22,992,467
Capital expenditures		$	1,533,271			$	10,690			$	1,543,961

(a) - Noncustomer revenue for the six months ended June 30, 2020, totaled $99.0 million related primarily to gains from derivatives on commodity contracts.

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Six Months Ended June 30, 2019	Natural Gas Gathering and Processing				Natural Gas Liquids (a)				Natural Gas Pipelines (b)				Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	645,089			$	4,079,667			$	—			$	4,724,756
Residue natural gas sales	540,369				—				1,011				541,380
Gathering, processing and exchange services revenue	83,278				204,392				—				287,670
Transportation and storage revenue	—				94,977				230,105				325,082
Other	8,105				5,022				2,815				15,942
Total revenues (c)	1,276,841				4,384,058				233,931				5,894,830
Cost of sales and fuel (exclusive of depreciation and operating costs)	(760,658		)		(3,476,246		)		(3,404		)		(4,240,308		)
Operating costs	(180,009		)		(225,371		)		(72,873		)		(478,253		)
Equity in net earnings (loss) from investments	(2,823		)		33,516				46,906				77,599
Noncash compensation expense and other	5,516				8,444				2,632				16,592
Segment adjusted EBITDA	$	338,867			$	724,401			$	207,192			$	1,270,460
Depreciation and amortization	$	(106,233	)		$	(92,747	)		$	(28,323	)		$	(227,303	)
Investments in unconsolidated affiliates	$	37,793			$	443,104			$	400,187			$	881,084
Total assets	$	6,343,968			$	10,694,485			$	2,083,940			$	19,122,393
Capital expenditures	$	428,370			$	1,231,100			$	50,094			$	1,709,564

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $626.5 million, of which $537.3 million related to revenues within the segment, and cost of sales and fuel of $235.4 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $142.4 million and cost of sales and fuel of $9.3 million.

(c) - Intersegment revenues for the Natural Gas Gathering and Processing segment totaled $653.7 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.

Six Months Ended June 30, 2019		Total Segments				Other and Eliminations				Total
		(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales		$	4,724,756			$	(648,878	)		$	4,075,878
Residue natural gas sales		541,380				—				541,380
Gathering, processing and exchange services revenue		287,670				—				287,670
Transportation and storage revenue		325,082				(7,817		)		317,265
Other		15,942				(602		)		15,340
Total revenues (a)		$	5,894,830			$	(657,297	)		$	5,237,533
Cost of sales and fuel (exclusive of depreciation and operating costs)		$	(4,240,308	)		$	658,137			$	(3,582,171	)
Operating costs		$	(478,253	)		$	(201	)		$	(478,454	)
Depreciation and amortization		$	(227,303	)		$	(1,819	)		$	(229,122	)
Equity in net earnings from investments		$	77,599			$	—			$	77,599
Investments in unconsolidated affiliates		$	881,084			$	—			$	881,084
Total assets		$	19,122,393			$	629,201			$	19,751,594
Capital expenditures		$	1,709,564			$	10,600			$	1,720,164

(a) - Noncustomer revenue for the six months ended June 30, 2019, totaled $40.9 million related primarily to gains from derivatives on commodity contracts.

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	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2020				2019				2020				2019
	(Thousands of dollars)
Reconciliation of net income (loss) to total segment adjusted EBITDA
Net income (loss)	$	134,321			$	311,963			$	(7,536	)		$	649,171
Add:
Interest expense, net of capitalized interest	218,968				117,493				359,584				232,913
Depreciation and amortization	140,416				114,964				272,769				229,122
Income tax expense (benefit)	43,140				98,935				(12,255		)		176,869
Impairment charges	—				—				641,754				—
Noncash compensation expense (benefit)	957				5,115				(345		)		10,655
Other corporate costs and equity AFUDC (a)	(1,578		)		(14,541		)		(34,659		)		(28,270		)
Total segment adjusted EBITDA	$	536,224			$	633,929			$	1,219,312			$	1,270,460

(a) - The three and six months ended June 30, 2020, include corporate gains of $4.3 million and $20.0 million, respectively, on extinguishment of debt related to open market repurchases.

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

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•	Natural Gas Gathering and Processing - a decrease of $53.1 million due primarily to lower volumes as a result of production curtailments and a decrease of $51.8 million due primarily to lower realized prices;

•

Natural Gas Liquids - a decrease of $32.4 million in optimization and marketing due primarily to lower optimization volumes and narrower location price differentials and $31.3 million in lower exchange services volumes across our system, offset partially by increases in exchange services due to $29.2 million in lower rail transportation and pipeline costs and $15.0 million in higher average fee rates primarily in the Permian Basin; and

•	an increase of $25.4 million in depreciation expense due to capital projects placed in service; offset partially by

•	Natural Gas Pipelines - an increase of $6.4 million from higher transportation services due primarily to higher firm transportation revenue and a $13.5 million contract settlement, offset partially by lower interruptible revenue; and

•	a decrease of $13.3 million in operating costs due primarily to reduced discretionary expenses and lower materials and supplies expenses.

•	a decrease of $604.0 million due to noncash impairment charges in our Natural Gas Gathering and Processing and Natural Gas Liquids segments;

•	an increase of $43.7 million in depreciation expense due to capital projects placed in service; and

•	Natural Gas Gathering and Processing - a decrease of $69.6 million due primarily to lower realized prices and a decrease of $31.1 million due primarily to lower volumes in the Williston Basin and Mid-Continent region as a result of production curtailments; offset partially by

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•	Natural Gas Pipelines - an increase of $11.8 million from higher transportation services due primarily to higher firm transportation revenue and a $13.5 million contract settlement, offset partially by lower interruptible revenue;

•

Natural Gas Liquids - an increase of $105.4 million in exchange services due primarily to lower rail transportation and pipeline costs, higher average fee rates primarily in the Permian Basin and higher volumes primarily in the Rocky Mountain region and Permian Basin, offset partially by a decrease of $93.0 million in optimization and marketing due primarily to narrower location price differentials, lower optimization volumes and lower marketing earnings; and

•	a decrease of $47.0 million in operating costs due primarily to the noncash mark-to-market impact of our share-based deferred compensation plan, reduced discretionary expenses, lower materials and supplies expenses, and lower employee-related costs.

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•	a decrease of $53.1 million due primarily to lower volumes in the Williston Basin and Mid-Continent region as a result of production curtailments; and

•	a decrease of $51.8 million due primarily to lower realized prices impacting our POP with fee contracts; offset partially by

•	a decrease of $7.8 million in operating costs due primarily to lower materials and supplies expenses and reduced discretionary expenses.

•	a decrease of $69.6 million due primarily to lower realized prices impacting our POP with fee contracts; and

•	a decrease of $31.1 million due primarily to lower volumes in the Williston Basin and Mid-Continent region as a result of production curtailments; offset partially by

•	a decrease of $9.4 million in operating costs due primarily to lower materials and supplies expenses, reduced discretionary expenses and lower employee-related costs.

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•	a decrease of $32.4 million in optimization and marketing due primarily to a decrease of $22.2 million due to lower optimization volumes and narrower location price differentials and a decrease of $11.0 million due to narrower product price differentials; and

•	a decrease of $8.2 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline; offset partially by

•

an increase of $16.4 million in exchange services due to $29.2 million in lower rail transportation and pipeline costs, $15.0 million in higher average fee rates primarily in the Permian Basin and $8.2 million in fees charged to customers with minimum volume obligations primarily in the Rocky Mountain region, offset partially by $31.3 million in lower volumes across our system and $5.2 million in narrower product price differentials; and

•	a decrease of $11.1 million in operating costs due primarily to reduced discretionary expenses.

•

an increase of $105.4 million in exchange services due to $47.4 million in higher volumes primarily in the Rocky Mountain region and Permian Basin, $40.1 million in lower rail transportation and pipeline costs, $33.0 million in higher average fee rates primarily in the Permian Basin, $15.8 million in higher fees charged to customers with minimum volume obligations primarily in the Rocky Mountain region and $7.9 million related to lower unfractionated NGLs held in inventory, offset partially by $26.1 million in lower volumes in the Mid-Continent region and $10.6 million in narrower product price differentials; and

•	a decrease of $20.0 million in operating costs due primarily to reduced discretionary expenses and lower employee-related costs; offset partially by

•

a decrease of $93.0 million in optimization and marketing due primarily to a decrease of $51.2 million related to narrower location price differentials and lower optimization volumes, lower marketing earnings of $30.3 million due to the timing of purity NGL inventory sales and changes in the value of NGLs held in inventory, and a decrease of $13.8 million due to narrower product price differentials; and

•	a decrease of $10.4 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline.

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•	an increase of $6.4 million from higher transportation services due primarily to higher firm transportation revenue and a $13.5 million contract settlement, offset partially by lower interruptible revenue; and

•	a decrease of $4.4 million in operating costs due primarily to reduced discretionary expenses and lower supplies.

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•	an increase of $11.8 million from higher transportation services due primarily to higher firm transportation revenue and a $13.5 million contract settlement, offset partially by lower interruptible revenue; and

•	a decrease of $3.9 million in operating costs due primarily to lower supplies and employee-related costs.

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•	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;

•	the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;

•

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;

•	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;

•	economic climate and growth in the geographic areas in which we operate;

•

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;

•	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;

•	demand for our services and products in the proximity of our facilities;

•	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;

•	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 timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;

•	our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;

•	the profitability of assets or businesses acquired or constructed by us;

•	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;

•	risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;

•	the uncertainty of estimates, including accruals and costs of environmental remediation;

•	changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns about climate change;

•	the impact of uncontracted capacity in our assets being greater or less than expected;

•	the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;

•	the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;

•	our ability to control construction costs and completion schedules of our pipelines and other projects;

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•	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;

•	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;

•	difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;

•	the capital-intensive nature of our businesses;

•	the mechanical integrity of facilities operated;

•	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 of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in equity and bond market returns;

•	our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;

•	actions by rating agencies concerning our credit;

•	our ability to access capital at competitive rates or on terms acceptable to us;

•	the impact and outcome of pending and future litigation;

•	performance of contractual obligations by our customers, service providers, contractors and shippers;

•	our ability to control operating costs and make cost-saving changes;

•	the impact of recently issued and future accounting updates and other changes in accounting policies;

•	the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;

•	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;

•	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 disruptions;

•	the impact of potential impairment charges; and

•	the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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•	a $0.01 per-gallon change in the composite price of NGLs, excluding ethane, would change adjusted EBITDA for the six months ending December 31, 2020, and for the year ending December 31, 2021, by approximately $1.1 million and $2.2 million, respectively;

•	a $1.00 per-barrel change in the price of crude oil would change adjusted EBITDA for the six months ending December 31, 2020, and for the year ending December 31, 2021, by approximately $0.6 million and $1.1 million, respectively; and

•	a $0.10 per-MMBtu change in the price of residue natural gas would change adjusted EBITDA for the six months ending December 31, 2020, and for the year ending December 31, 2021, by approximately $2.3 million and $4.6 million, respectively.

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ITEM 4.	CONTROLS AND PROCEDURES

ITEM 1.	LEGAL PROCEEDINGS

ITEM 1A.	RISK FACTORS

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ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

ITEM 4.	MINE SAFETY DISCLOSURES

ITEM 5.	OTHER INFORMATION

ITEM 6.	EXHIBITS

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