Item 1. Financial Statements.

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Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts, unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Revenues
Services	$	2,011	$	1,889	$	4,061	$	3,806
Commodity sales	3,100		1,246		5,308		4,475
Other	40		15		75		80
Total Revenues	5,151		3,150		9,444		8,361

Operating Costs, Expenses and Other
Costs of sales	2,683		936		4,577		2,945
Operations and maintenance	663		582		1,248		1,096
Depreciation, depletion and amortization	543		528		1,081		1,069
General and administrative	152		160		308		316
Taxes, other than income taxes	116		108		227		218

(Gain) loss on divestitures and impairments, net	(11)		1,602		(21)		1,598
Other income, net	(1)		(2)		(6)		(3)
Total Operating Costs, Expenses and Other	4,145		3,914		7,414		7,239

Operating Income (Loss)	1,006		(764)		2,030		1,122

Other Income (Expense)
Earnings from equity investments	182		157		369		223

Amortization of excess cost of equity investments	(19)		(13)		(38)		(35)
Interest, net	(355)		(377)		(688)		(754)
Other, net (Note 2)	23		20		42		243
Total Other Expense	(169)		(213)		(315)		(323)

Income (Loss) Before Income Taxes	837		(977)		1,715		799

Income Tax (Expense) Benefit	(184)		237		(378)		(114)

Net Income (Loss)	653		(740)		1,337		685






Net Income Attributable to Noncontrolling Interests	(18)		(17)		(35)		(33)

Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	635	$	(757)	$	1,302	$	652





Class P Common Stock
Basic and Diluted Earnings (Loss) Per Share	$	0.28	$	(0.34)	$	0.57	$	0.29

Basic and Diluted Weighted Average Shares Outstanding	2,265		2,265		2,266		2,264

The accompanying notes are an integral part of these consolidated financial statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In millions, unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Net income (loss)	$	653	$	(740)	$	1,337	$	685
Other comprehensive income (loss), net of tax
Net unrealized loss from derivative instruments (net of taxes of $24, $47, $149 and $94, respectively)	(78)		(157)		(489)		(313)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $(48), $(9), $(89), and $(27), respectively)	157		30		292		89

Benefit plan adjustments (net of taxes of $(1), $(1), $(5) and $(5), respectively)	3		5		16		22
Total other comprehensive income (loss)	82		(122)		(181)		(202)

Comprehensive income (loss)	735		(862)		1,156		483
Comprehensive income attributable to noncontrolling interests	(18)		(17)		(35)		(33)
Comprehensive income (loss) attributable to KMI	$	717	$	(879)	$	1,121	$	450

The accompanying notes are an integral part of these consolidated financial statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share and per share amounts, unaudited)


	June 30, 2022		December 31, 2021
ASSETS
Current Assets
Cash and cash equivalents	$	100	$	1,140
Restricted deposits	317		7
Accounts receivable	2,063		1,611
Fair value of derivative contracts	141		220
Inventories	690		562


Other current assets	297		289
Total current assets	3,608		3,829

Property, plant and equipment, net	35,530		35,653
Investments	7,470		7,578
Goodwill	19,914		19,914
Other intangibles, net	1,557		1,678
Deferred income taxes	—		115

Deferred charges and other assets	1,311		1,649
Total Assets	$	69,390	$	70,416

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,970	$	2,646
Accounts payable	1,691		1,259

Accrued interest	442		504
Accrued taxes	217		270
Fair value of derivative contracts	521		178

Other current liabilities	1,051		964
Total current liabilities	6,892		5,821

Long-term liabilities and deferred credits
Long-term debt
Outstanding	28,140		29,772

Debt fair value adjustments	412		902
Total long-term debt	28,552		30,674
Deferred income taxes	196		—

Other long-term liabilities and deferred credits	2,125		2,000

Total long-term liabilities and deferred credits	30,873		32,674
Total Liabilities	37,765		38,495
Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity

Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,257,464,962 and 2,267,391,527 shares, respectively, issued and outstanding	23		23
Additional paid-in capital	41,654		41,806
Accumulated deficit	(10,540)		(10,595)
Accumulated other comprehensive loss	(592)		(411)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,545		30,823
Noncontrolling interests	1,080		1,098
Total Stockholders’ Equity	31,625		31,921
Total Liabilities and Stockholders’ Equity	$	69,390	$	70,416

The accompanying notes are an integral part of these consolidated financial statements.


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)

	Six Months Ended June 30,
	2022		2021
Cash Flows From Operating Activities
Net income	$	1,337	$	685
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,081		1,069
Deferred income taxes	369		105
Amortization of excess cost of equity investments	38		35

Change in fair market value of derivative contracts	51		40
(Gain) loss on divestitures and impairments, net	(21)		1,598
Gain on sale of interest in equity investment (Note 2)	—		(206)
Earnings from equity investments	(369)		(223)
Distributions from equity investment earnings	348		346
Changes in components of working capital
Accounts receivable	(414)		(130)
Inventories	(108)		(51)
Other current assets	(39)		(31)
Accounts payable	499		145
Accrued interest, net of interest rate swaps	(53)		(42)
Accrued taxes	(53)		(51)
Other current liabilities	86		195
Rate reparations, refunds and other litigation reserve adjustments	(53)		(102)
Other, net	(51)		(71)
Net Cash Provided by Operating Activities	2,648		3,311
Cash Flows From Investing Activities


Capital expenditures	(779)		(545)
Proceeds from sales of investments	4		413
Contributions to investments	(20)		(26)
Distributions from equity investments in excess of cumulative earnings	104		48

Other, net	19		(1)
Net Cash Used in Investing Activities	(672)		(111)
Cash Flows From Financing Activities
Issuances of debt	4,622		3,110
Payments of debt	(5,848)		(4,273)
Debt issue costs	(7)		(12)
Dividends	(1,247)		(1,212)

Repurchases of shares	(173)		—

Contributions from noncontrolling interests	—		3
Distributions to investment partner	—		(45)

Distributions to noncontrolling interests	(53)		(8)
Other, net	—		(3)
Net Cash Used in Financing Activities	(2,706)		(2,440)

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(730)		760
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,147		1,209
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	417	$	1,969


KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)

	Six Months Ended June 30,
	2022		2021
Cash and Cash Equivalents, beginning of period	$	1,140	$	1,184
Restricted Deposits, beginning of period	7		25
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,147		1,209
Cash and Cash Equivalents, end of period	100		1,365
Restricted Deposits, end of period	317		604
Cash, Cash Equivalents, and Restricted Deposits, end of period	417		1,969
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(730)	$	760

Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments	$	(8)	$	28

Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	792		807
Cash paid during the period for income taxes, net	10		8

The accompanying notes are an integral part of these consolidated financial statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions, unaudited)


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI		Non-controlling interests
	Issued shares	Par value								Total
Balance at March 31, 2022	2,267	$	23	$	41,813	$	(10,544)	$	(674)		$	30,618	$	1,089	$	31,707



Repurchases of shares	(10)			(172)							(172)				(172)
Restricted shares				13							13				13
Net income						635					635		18		653
Distributions											—		(27)		(27)

Dividends						(631)					(631)				(631)

Other comprehensive income								82			82				82
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)		$	30,545	$	1,080	$	31,625


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI		Non-controlling interests
	Issued shares	Par value								Total
Balance at March 31, 2021	2,264	$	23	$	41,775	$	(9,124)	$	(487)		$	32,187	$	416	$	32,603





Restricted shares	1			18							18				18
Net (loss) income						(757)					(757)		17		(740)


Distributions											—		(5)		(5)
Contributions											—		1		1
Dividends						(615)					(615)				(615)



Other comprehensive loss								(122)			(122)				(122)
Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)		$	30,711	$	429	$	31,140


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI		Non-controlling interests
	Issued shares	Par value								Total
Balance at December 31, 2021	2,267	$	23	$	41,806	$	(10,595)	$	(411)		$	30,823	$	1,098	$	31,921
Impact of adoption of ASU 2020-06 (Note 4)				(11)							(11)				(11)
Balance at January 1, 2022	2,267	23		41,795		(10,595)		(411)			30,812		1,098		31,910

Repurchases of shares	(10)			(173)							(173)				(173)
EP Trust I Preferred security conversions				1							1				1
Restricted shares				31							31				31
Net income						1,302					1,302		35		1,337
Distributions											—		(53)		(53)

Dividends						(1,247)					(1,247)				(1,247)

Other comprehensive loss								(181)			(181)				(181)
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)		$	30,545	$	1,080	$	31,625


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI		Non-controlling interests
	Issued shares	Par value								Total
Balance at December 31, 2020	2,264	$	23	$	41,756	$	(9,936)	$	(407)		$	31,436	$	402	$	31,838





Restricted shares	1			37							37				37
Net income						652					652		33		685


Distributions											—		(8)		(8)
Contributions											—		3		3
Dividends						(1,212)					(1,212)				(1,212)


Other											—		(1)		(1)
Other comprehensive loss								(202)			(202)				(202)
Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)		$	30,711	$	429	$	31,140

The accompanying notes are an integral part of these consolidated financial statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines, 141 terminals, and 700 billion cubic feet of working natural gas storage capacity. Our pipelines transport natural gas, refined petroleum products, renewable fuels, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, renewable fuel feedstocks, chemicals, ethanol, metals and petroleum coke.

Basis of Presentation

General

Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation.

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2021 Form 10-K.

The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.

Mas CanAm, LLC Acquisition

On July 19, 2022, we completed an acquisition of three landfill assets from Mas CanAm, LLC, comprising a renewable natural gas facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for approximately $358 million including a preliminary purchase price adjustment for working capital.

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For our May 31, 2022 evaluation, we grouped our businesses into seven reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals and (vii) Energy Transition Ventures.

The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions, general economic conditions and the related demand for products handled or transported by our assets. Changes to any one or a combination of these factors would result in a change to the reporting unit fair values, which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.

The results of our May 31, 2022 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

The following table sets forth the allocation of net income (loss) available to shareholders of Class P common stock and participating securities:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders	$	635	$	(757)	$	1,302	$	652
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)	(2)		(3)		(6)		(6)
Net Income (Loss) Allocated to Class P Stockholders	$	633	$	(760)	$	1,296	$	646

Basic Weighted Average Shares Outstanding	2,265		2,265		2,266		2,264
Basic Earnings (Loss) Per Share	$	0.28	$	(0.34)	$	0.57	$	0.29

(a)As of June 30, 2022, there were 12 million restricted stock awards outstanding.

The following table presents the maximum number of potential common stock equivalents which are antidilutive and accordingly are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.


	Three Months Ended June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
	(In millions on a weighted average basis)
Unvested restricted stock awards	12	12	13	12
Convertible trust preferred securities	3	3	3	3

2. Losses and Gains on Impairments, Divestitures and Other Write-downs

Long-lived Asset Impairment

During the second quarter of 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. We utilized an income approach to estimate fair value and compared it to the carrying value. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates, a Level 3 input. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the six months ended June 30, 2021.

Investment in Ruby

During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, which is included within “Earnings from equity investments” on our accompanying consolidated statement of operations for the six months ended June 30, 2021. The write-down was driven by the impairment recognized by Ruby of its assets.

Ruby Chapter 11 Bankruptcy Filing

The balance of Ruby Pipeline, L.L.C.’s 2022 unsecured notes matured on April 1, 2022 in the principal amount of $475 million. Although Ruby has sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its

obligations under the 2022 unsecured notes on the maturity date of April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Ruby, as the debtor, will continue to operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. We had no amounts included in our “Investments” on our accompanying consolidated balance sheets associated with Ruby as of June 30, 2022 or December 31, 2021.

Sale of an Interest in NGPL Holdings

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $413 million for our proportionate share of the interests sold. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” on our accompanying consolidated statement of operations for the six months ended June 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

3. Debt

The following table provides information on the principal amount of our outstanding debt balances:


	June 30, 2022		December 31, 2021
	(In millions, unless otherwise stated)
Current portion of debt

$3.5 billion credit facility due August 20, 2026	$	—	$	—
$500 million credit facility due November 16, 2023	—		—
Commercial paper notes(a)	936		—
Current portion of senior notes
8.625%, due January 2022(b)	—		260
4.15%, due March 2022(b)	—		375
1.50%, due March 2022(b)(c)	—		853
3.95% due September 2022(d)	—		1,000
3.15% due January 2023	1,000		—
Floating rate, due January 2023(e)	250		—
3.45% due February 2023	625		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	48		47
Total current portion of debt	2,970		2,646

Long-term debt (excluding current portion)
Senior notes	27,477		29,097
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	339		348

Trust I preferred securities, 4.75%, due March 2028	109		110
Other	215		217
Total long-term debt	28,140		29,772
Total debt(f)	$	31,110	$	32,418

(a)Weighted average interest rate on borrowings outstanding as of June 30, 2022 was 1.90%.

(b)We repaid the principal amount of these senior notes during the first quarter of 2022.

(c)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The December 31, 2021 balance is reported above at the exchange rate of 1.1370 U.S. dollars per Euro. As of December 31, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $38 million related to these notes, which was offset by a corresponding change in the value of cross-currency swaps reflected in “Current Assets*—Fair value of derivative contracts” and “Current Liabilities—Fair value of derivative contracts” on our accompanying consolidated balance sheet. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 5 “Risk Management—Foreign Currency Risk Management*”).

(d)We repaid the principal amount of these senior notes on June 1, 2022.

(e)These senior notes have an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge (see Note 5 “Risk Management*—Interest Rate Risk Management*”).

(f)Excludes our “Debt fair value adjustments” which, as of June 30, 2022 and December 31, 2021, increased our total debt balances by $412 million and $902 million, respectively.

We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.

On February 23, 2022, EPNG issued in a private offering $300 million aggregate principal amount of 3.50% senior notes due 2032 and received net proceeds of $298 million after discount and issuance costs. These notes are guaranteed through the cross guarantee agreement discussed above.

Credit Facilities and Restrictive Covenants

As of June 30, 2022, we had no borrowings outstanding under our credit facilities, $936 million in borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of June 30, 2022 was $3.0 billion. As of June 30, 2022, we were in compliance with all required covenants.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below:


	June 30, 2022				December 31, 2021
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	31,522	$	30,376	$	33,320	$	37,775

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $203 million and $218 million as of June 30, 2022 and December 31, 2021, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both June 30, 2022 and December 31, 2021.

4. Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. During the six months ended June 30, 2022, we repurchased approximately 10 million of our shares for $173 million at an average price of $17.37 per share. Subsequent to June 30, 2022 and through July 21, 2022, we repurchased 6 million of our shares for $102 million at an average price of $16.63 per share, and since December 2017, in total, we have repurchased 49 million of our shares under the program at an average price of $17.50 per share for $850 million.

Dividends

The following table provides information about our per share dividends:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Per share cash dividend declared for the period	$	0.2775	$	0.27	$	0.555	$	0.54
Per share cash dividend paid in the period	0.2775		0.27		0.5475		0.5325

On July 20, 2022, our board of directors declared a cash dividend of $0.2775 per share for the quarterly period ended June 30, 2022, which is payable on August 15, 2022 to shareholders of record as of the close of business on August 1, 2022.

Adoption of Accounting Pronouncement

On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the six months ended June 30, 2022.

Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” on our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:


	Net unrealized gains/(losses) on cash flow hedge derivatives		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2021	$	(172)	$	(239)	$	(411)
Other comprehensive (loss) gain before reclassifications	(489)		16		(473)
Loss reclassified from accumulated other comprehensive loss	292		—		292
Net current-period change in accumulated other comprehensive (loss) income	(197)		16		(181)
Balance as of June 30, 2022	$	(369)	$	(223)	$	(592)


	Net unrealized gains/(losses) on cash flow hedge derivatives		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2020	$	(13)	$	(394)	$	(407)
Other comprehensive (loss) gain before reclassifications	(313)		22		(291)
Loss reclassified from accumulated other comprehensive loss	89		—		89
Net current-period change in accumulated other comprehensive (loss) income	(224)		22		(202)
Balance as of June 30, 2021	$	(237)	$	(372)	$	(609)

5. Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

Energy Commodity Price Risk Management

As of June 30, 2022, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:


	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price	(19.0)	MMBbl
Crude oil basis	(5.2)	MMBbl
Natural gas fixed price	(55.9)	Bcf
Natural gas basis	(45.0)	Bcf
NGL fixed price	(0.8)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.1)	MMBbl
Crude oil basis	(6.6)	MMBbl
Natural gas fixed price	(9.3)	Bcf
Natural gas basis	(22.5)	Bcf
Natural gas options	(0.4)	Bcf
NGL fixed price	(1.1)	MMBbl

As of June 30, 2022, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2026.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of June 30, 2022:


	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)	$	6,750	Fair value hedge	March 2035
Variable-to-fixed interest rate contracts	250		Cash flow hedge	January 2023
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts	5,100		Mark-to-Market	December 2022

(a)The principal amount of hedged senior notes consisted of $100 million included in “Current portion of debt” and $6,650 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the three and six months ended June 30, 2022, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 10 “Recent Accounting Pronouncements” for further information on Topic 848.

During the six months ended June 30, 2022, we entered into fixed-to-variable interest rate swap agreements with a combined notional principal amount of $400 million. These agreements were designated as accounting hedges and convert a portion of our fixed rate debt to variable rates through February 2032.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of June 30, 2022:


	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$	543	Cash flow hedge	March 2027

(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.

Impact of Derivative Contracts on Our Consolidated Financial Statements

The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets:


Fair Value of Derivative Contracts
		Derivatives Asset				Derivatives Liability
		June 30, 2022		December 31, 2021		June 30, 2022		December 31, 2021
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	$	58	$	61	$	(357)	$	(141)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		3		(193)		(94)
Subtotal		62		64		(550)		(235)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	6		101		(38)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	59		284		(132)		(15)
Subtotal		65		385		(170)		(18)
Foreign currency contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		35		(9)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		6		(27)		—
Subtotal		—		41		(36)		(3)
Total		127		490		(756)		(256)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	18		11		(117)		(31)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	11		1		(42)		(6)
Subtotal		29		12		(159)		(37)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	59		12		—		—





Total		88		24		(159)		(37)
Total derivatives		$	215	$	514	$	(915)	$	(293)

The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.


	Balance sheet asset fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
	(In millions)
As of June 30, 2022
Energy commodity derivative contracts(a)	$	52	$	39	$	—	$	91	$	(90)	$	—	$	1
Interest rate contracts	—		124		—		124		—		—		124

As of December 31, 2021
Energy commodity derivative contracts(a)	$	56	$	20	$	—	$	76	$	(53)	$	(20)	$	3
Interest rate contracts	—		397		—		397		(9)		—		388
Foreign currency contracts	—		41		—		41		(3)		—		38


	Balance sheet liability fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral posted(b)		Net amount
	(In millions)
As of June 30, 2022
Energy commodity derivative contracts(a)	$	(96)	$	(613)	$	—	$	(709)	$	90	$	125	$	(494)
Interest rate contracts	—		(170)		—		(170)		—		—		(170)
Foreign currency contracts	—		(36)		—		(36)		—		—		(36)
As of December 31, 2021
Energy commodity derivative contracts(a)	$	(15)	$	(257)	$	—	$	(272)	$	53	$	—	$	(219)
Interest rate contracts	—		(18)		—		(18)		9		—		(9)
Foreign currency contracts	—		(3)		—		(3)		3		—		—

(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.

(b)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

The following tables summarize the pre-tax impact of our derivative contracts on our accompanying consolidated statements of operations and comprehensive income (loss):


Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item
		Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021
		(In millions)
Interest rate contracts	Interest, net	$	(160)	$	28	$	(476)	$	(189)

Hedged fixed rate debt(a)	Interest, net	$	162	$	(28)	$	482	$	190

(a)As of June 30, 2022, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $106 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended June 30,					Three Months Ended June 30,
	2022		2021			2022		2021
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(70)	$	(215)	Revenues—Commodity sales	$	(185)	$	(53)

					Costs of sales	7		(2)
Interest rate contracts	3		1		Earnings from equity investments(c)	—		—
Foreign currency contracts	(35)		10		Other, net	(27)		16
Total	$	(102)	$	(204)	Total	$	(205)	$	(39)


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,					Six Months Ended June 30,
	2022		2021			2022		2021
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(569)	$	(374)	Revenues—Commodity sales	$	(317)	$	(73)

					Costs of sales	17		2
Interest rate contracts	6		2		Earnings from equity investments(c)	—		—
Foreign currency contracts	(75)		(35)		Other, net	(81)		(45)
Total	$	(638)	$	(407)	Total	$	(381)	$	(116)

(a)We expect to reclassify approximately $267 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 2022 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

(b)During the six months ended June 30, 2022 and 2021, we recognized approximate gains of $5 million and $6 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).

(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).


Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(17)	$	(33)	$	(26)	$	(663)
	Costs of sales	(8)		(2)		(99)		160
	Earnings from equity investments	—		(2)		(5)		(2)
Interest rate contracts	Interest, net	12		—		48		—
Total(a)		$	(13)	$	(37)	$	(82)	$	(505)

(a)The three and six months ended June 30, 2022 amounts include approximate losses of $38 million and $20 million, respectively, and the three and six months ended June 30, 2021 amounts include approximate losses of $7 million and $455 million, respectively. These losses were associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of June 30, 2022 and December 31, 2021, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2022, we had cash margins of $309 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2021, we had cash margins of $14 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at June 30, 2022 represents our initial margin requirements of $184 million and variation margin requirements of $125 million posted by us with our counterparties. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of June 30, 2022, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $358 million of additional collateral.

6. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:


	Three Months Ended June 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	849	$	60	$	198	$	1	$	(1)	$	1,107
Fee-based services	234		242		96		11		—		583
Total services	1,083		302		294		12		(1)		1,690
Commodity sales
Natural gas sales	1,810		—		—		24		(6)		1,828
Product sales	410		640		7		404		13		1,474

Total commodity sales	2,220		640		7		428		7		3,302
Total revenues from customers	3,303		942		301		440		6		4,992
Other revenues(c)
Leasing services(d)	118		49		149		15		—		331
Derivatives adjustments on commodity sales	(81)		—		—		(121)		—		(202)
Other	16		5		—		9		—		30
Total other revenues	53		54		149		(97)		—		159
Total revenues	$	3,356	$	996	$	450	$	343	$	6	$	5,151


	Three Months Ended June 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	799	$	66	$	198	$	—	$	—	$	1,063
Fee-based services	176		244		84		10		—		514
Total services	975		310		282		10		—		1,577
Commodity sales
Natural gas sales	674		—		—		1		(3)		672
Product sales	248		157		7		258		(13)		657

Total commodity sales	922		157		7		259		(16)		1,329
Total revenues from customers	1,897		467		289		269		(16)		2,906
Other revenues(c)
Leasing services(d)	118		43		144		15		1		321
Derivatives adjustments on commodity sales	(37)		(1)		—		(47)		—		(85)
Other	(2)		5		—		6		(1)		8
Total other revenues	79		47		144		(26)		—		244
Total revenues	$	1,976	$	514	$	433	$	243	$	(16)	$	3,150


	Six Months Ended June 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	1,788	$	119	$	386	$	1	$	(2)	$	2,292
Fee-based services	447		476		194		24		—		1,141
Total services	2,235		595		580		25		(2)		3,433
Commodity sales
Natural gas sales	3,036		—		—		44		(10)		3,070
Product sales	752		1,066		11		752		(3)		2,578

Total commodity sales	3,788		1,066		11		796		(13)		5,648
Total revenues from customers	6,023		1,661		591		821		(15)		9,081
Other revenues(c)
Leasing services(d)	235		93		289		28		—		645
Derivatives adjustments on commodity sales	(120)		(3)		—		(220)		—		(343)
Other	31		11		—		19		—		61
Total other revenues	146		101		289		(173)		—		363
Total revenues	$	6,169	$	1,762	$	880	$	648	$	(15)	$	9,444


	Six Months Ended June 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	1,665	$	125	$	389	$	—	$	—	$	2,179
Fee-based services	354		465		165		25		—		1,009
Total services	2,019		590		554		25		—		3,188
Commodity sales
Natural gas sales	3,993		—		—		2		(8)		3,987
Product sales	468		282		12		487		(23)		1,226

Total commodity sales	4,461		282		12		489		(31)		5,213
Total revenues from customers	6,480		872		566		514		(31)		8,401
Other revenues(c)
Leasing services(d)	237		86		287		27		—		637
Derivatives adjustments on commodity sales	(655)		(1)		—		(80)		—		(736)
Other	39		10		—		11		(1)		59
Total other revenues	(379)		95		287		(42)		(1)		(40)
Total revenues	$	6,101	$	967	$	853	$	472	$	(32)	$	8,361

(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)).

(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as “Fee-based services.”

(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 “Risk Management” for additional information related to our derivative contracts.

(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

As of June 30, 2022 and December 31, 2021, our contract asset balances were $42 million and $39 million, respectively. Of the contract asset balance at December 31, 2021, $22 million was transferred to accounts receivable during the six months ended June 30, 2022. As of June 30, 2022 and December 31, 2021, our contract liability balances were $215 million and $212 million, respectively. Of the contract liability balance at December 31, 2021, $59 million was recognized as revenue during the six months ended June 30, 2022.

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of June 30, 2022 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Estimated Revenue
	(In millions)
Six months ended December 31, 2022	$	2,279
2023	3,895
2024	3,173
2025	2,635
2026	2,319
Thereafter	13,421
Total	$	27,722

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedient that we elected to apply, remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

7. Reportable Segments

Financial information by segment follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	3,363	$	1,960	$	6,156	$	6,070
Intersegment revenues	(7)		16		13		31

Products Pipelines	996		514		1,762		967

Terminals
Revenues from external customers	449		433		878		852
Intersegment revenues	1		—		2		1
CO2	343		243		648		472

Corporate and intersegment eliminations	6		(16)		(15)		(32)
Total consolidated revenues	$	5,151	$	3,150	$	9,444	$	8,361


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,134	$	(570)	$	2,318	$	1,533
Products Pipelines	299		265		598		513
Terminals	253		246		491		473
CO2	212		150		404		436


Total Segment EBDA	1,898		91		3,811		2,955
DD&A	(543)		(528)		(1,081)		(1,069)
Amortization of excess cost of equity investments	(19)		(13)		(38)		(35)

General and administrative and corporate charges	(144)		(150)		(289)		(298)
Interest, net	(355)		(377)		(688)		(754)

Income tax (expense) benefit	(184)		237		(378)		(114)

Total consolidated net income (loss)	$	653	$	(740)	$	1,337	$	685


	June 30, 2022		December 31, 2021
	(In millions)
Assets
Natural Gas Pipelines	$	47,780	$	47,746
Products Pipelines	9,221		9,088
Terminals	8,428		8,513
CO2	2,921		2,843



Corporate assets(b)	1,040		2,226

Total consolidated assets	$	69,390	$	70,416

(a)Includes revenues, earnings from equity investments, operating expenses,(gain) loss on divestitures and impairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

8. Income Taxes

Income tax expense (benefit) included on our accompanying consolidated statements of operations is as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
	(In millions, except percentages)
Income tax expense (benefit)	$	184		$	(237)		$	378		$	114
Effective tax rate	22.0		%	24.3		%	22.0		%	14.3		%

The effective tax rate for the three and six months ended June 30, 2022 is higher than the statutory federal rate of 21% primarily due to state income taxes, partially offset by dividend-received deductions from our investments in Florida Gas Pipeline (Citrus), NGPL Holdings, and Products (SE) Pipe Line Company (PPL).

The effective tax rate for the three months ended June 30, 2021 is higher than the statutory federal rate of 21% primarily due to state income taxes.

The effective tax rate for the six months ended June 30, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL

Holdings, and dividend-received deductions from our investments in Citrus, NGPL Holdings and PPL, partially offset by state income taxes.

9. Litigation and Environmental

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

EPNG FERC Proceeding

On April 21, 2022, EPNG was notified by the FERC of the commencement of a rate proceeding against it pursuant to section 5 of the Natural Gas Act. This proceeding sets the matter for hearing to determine whether EPNG’s current rates remain just and reasonable. A proceeding under section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would only occur after the FERC has issued an order. Unless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in late June 2023, with a final FERC decision anticipated in late 2023. We do not believe that the ultimate resolution of this proceeding will have a material adverse impact to our business.

Gulf LNG Facility Disputes

On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. The Notice of Arbitration sought declaratory and monetary relief based upon Eni USA’s assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. On June 29, 2018, the arbitration tribunal delivered an Award that called for the termination of the agreement and Eni USA’s payment of compensation to GLNG. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. In response to the foregoing lawsuit, Eni S.p.A. filed counterclaims under the terminal use agreement and claims under a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing claims asserted by Eni S.p.A seek unspecified damages and involve the same allegations as the claims which were resolved conclusively in the arbitrations with Eni USA described above and with GLNG’s remaining customer as described below. On January 4, 2022, the trial court entered a decision granting Eni S.p.A’s motion for summary judgment on the claims asserted by GLNG to enforce the Guarantee Agreement. GLNG filed an interlocutory appeal of the decision. Pending resolution of GLNG’s appeal and further proceedings in the trial court, the foregoing counterclaims and other claims asserted by Eni S.p.A under the terminal use agreement and parent direct agreement remain pending in the trial court.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A., filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. On July 15, 2021, the arbitration tribunal delivered an Award on the merits of all claims submitted to the tribunal and denied all of ALSS’s claims with prejudice. On November 23, 2021, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award.

Continental Resources, Inc. v. Hiland Partners Holdings, LLC

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition asserts additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $276 million. We deny and are vigorously defending against these claims.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed suit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. We believe that our declaration of force majeure was valid and we are vigorously defending against these claims.

Pipeline Integrity and Releases

From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

Arizona Line 2000 Rupture

On August 15, 2021, the 30” EPNG Line 2000 natural gas transmission pipeline ruptured in a rural area in Coolidge, Arizona. The failure resulted in a fire which destroyed a home, resulting in two fatalities and one injury. The National Transportation Safety Board is investigating the incident. The impacted pipeline segment is currently out of service.

General

As of June 30, 2022 and December 31, 2021, our total reserve for legal matters was $178 million and $231 million, respectively.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.

We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts.

In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, crude oil, NGL, natural gas or CO2.

PHMSA Enforcement Matter for KMLT Midwest Terminals

On July 11, 2022, Kinder Morgan Liquid Terminals (KMLT) received a Notice of Probable Violation (NOPV) from PHMSA relating to inspections conducted during 2021 at KMLT’s Cincinnati, Indianapolis, Dayton, Argo, O’Hare, and Wood River Terminals. The NOPV alleges 16 violations of Department of Transportation regulations. The NOPV proposes a penalty of approximately $455,000 and seeks a compliance agreement relating to three of the alleged violations. The alleged violations are predominately procedural in nature. We are reviewing the NOPV and have not yet determined which of the allegations we will contest or whether we will pursue an alternative resolution with PHMSA. We do not anticipate the costs to resolve this matter, including any costs to implement a compliance agreement, will have a material adverse impact to our business.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated to be more than $2.8 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around October 2023. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a PRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if

necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey

EPEC Polymers, Inc. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River in New Jersey. EPEC entered into two Administrative Orders on Consent (AOCs) with the EPA which obligates EPEC to investigate and characterize contamination at the Site. EPEC is part of a joint defense group of approximately 44 cooperating parties which is directing and funding the AOC work required by the EPA. We have established a reserve for the anticipated cost of compliance with these two AOCs. On March 4, 2016, the EPA issued a Record of Decision (ROD) for the lower eight miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020 and certain PRPs, including EPEC, are engaged in discussions with the EPA as a result thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the upper nine mile ROD. Until the ongoing discussions with the EPA conclude, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the Site, will have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In December 2013, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In April 2015, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. In May 2018, the case was removed for a second time to the U.S. District Court. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court. The case is effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal court and ordered to be remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. The defendants to those consolidated cases are pursuing an appeal of the remand decisions to the United States Court of Appeals for the Fifth Circuit to determine whether there is federal officer jurisdiction. The case remains effectively stayed pending a ruling by the Fifth Circuit in the consolidated case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to

which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

Products Pipeline Incident, Walnut Creek, California

On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in California from Concord to San Jose. We shut down the pipeline and notified the appropriate regulatory agencies of a “threatened release” of gasoline. We investigated the issue over the next several days and on November 24, 2020, identified a crack in the pipeline and notified the regulatory agencies of a “confirmed release.” The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on November 26, 2020. We reported the estimated volume of gasoline released to be 8.1 Bbl. On December 2, 2020, complaints of gasoline odors were reported along the LS-16 pipeline corridor in Walnut Creek. A unified response was implemented by us along with the EPA, the California Office of Spill Prevention and Response, the California Fire Marshall, and the San Francisco Regional Water Quality Control Board. On December 8, 2020, we reported an updated estimated spill volume of up to 1,000 Bbl.

On October 28, 2021, we were informed by the California Attorney General it was contemplating criminal charges against us asserting the November 2020 discharge of gasoline affected waters of the State of California, and there was a failure to make timely notices of this discharge to appropriate state agencies. On December 16, 2021, we entered into a plea agreement with the State of California to resolve misdemeanor charges of the unintentional, non-negligent discharge of gasoline resulting from the release and the claimed failure to provide timely notices of the discharge to appropriate state agencies. Under the plea agreement, SFPP plead no-contest to two misdemeanors and paid approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and was placed on informal, unsupervised probation for a term of 18 months.

Since the November 2020 release, we have cooperated fully with federal and state agencies and have worked diligently to remediate the affected areas. We anticipate civil enforcement actions by federal and state agencies arising from the November 2020 release as well as ongoing monitoring and, where necessary, remediation under the oversight of the San Francisco Regional Water Quality Control Board until site conditions demonstrate no further actions are required. We do not anticipate the costs to resolve those enforcement matters, including the costs to monitor and further remediate the site, will have a material adverse impact to our business.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of June 30, 2022 and December 31, 2021, we have accrued a total reserve for environmental liabilities in the amount of $235 million and $243 million, respectively. In addition, as of both June 30, 2022 and December 31, 2021, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.

10. Recent Accounting Pronouncements

Accounting Standards Updates

Reference Rate Reform (Topic 848)

On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform – Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate (SOFR). Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.

On January 7, 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional

expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.

The guidance was effective upon issuance and generally can be applied through December 31, 2022.

During the six months ended June 30, 2022 we amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. These agreements contain a combined notional principal amount of $725 million and convert a portion of our fixed rate debt to variable rates through March 2035. Concurrent with these amendments, we elected certain of the optional expedients provided in Topic 848 which allow us to maintain our prior designation of fair value hedge accounting to these agreements. As we continue to amend our interest rate swap agreements to transition from LIBOR to SOFR, we will assess whether such amendments qualify for any of the optional expedients in Topic 848 and, should they qualify, whether we wish to elect any such optional expedients. See Note 5*“*Risk Management—Interest Rate Risk Management” for more information on our interest rate risk management activities.

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