10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

F O R M  10-Q  

☑  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2022

or

☐  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-35081

KINDER MORGAN, INC.

(Exact name of registrant as specified in its charter)

Delaware	80-0682103
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

Registrant’s telephone number, including area code: 713-369-9000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class P Common Stock	KMI	New York Stock Exchange
2.250% Senior Notes due 2027	KMI 27 A	New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes þ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐ No þ

As of July 21, 2022, the registrant had 2,253,000,833 shares of Class P common stock outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

			Page Number
	Glossary		2
	Information Regarding Forward-Looking Statements		3
	PART I.  FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Operations - Three and Six Months Ended June 30, 2022 and 2021		4
	Consolidated Statements of Comprehensive Income (Loss) - Three and Six Months Ended June 30, 2022 and 2021		5
	Consolidated Balance Sheets - as of June 30, 2022 and December 31, 2021		6
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2022 and 2021		7
	Consolidated Statements of Stockholders’ Equity - Three and Six Months Ended June 30, 2022 and 2021		9
	Notes to Consolidated Financial Statements		10
	Note 1.	General	10
	Note 2.	Losses and Gains on Impairments, Divestitures and Other Write-downs	11
	Note 3.	Debt	12
	Note 4.	Stockholders’ Equity	13
	Note 5.	Risk Management	15
	Note 6.	Revenue Recognition	21
	Note 7.	Reportable Segments	24
	Note 8.	Income Taxes	25
	Note 9.	Litigation and Environmental	26
	Note 10.	Recent Accounting Pronouncements	30
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		32
	Results of Operations		32
	Overview		32
	Consolidated Earnings Results (GAAP)		35
	Non-GAAP Financial Measures		38
	Segment Earnings Results		41
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		49
	Income Taxes		50
	Liquidity and Capital Resources		51
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		54
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		55
Item 4.	Controls and Procedures		55
	PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings		55
Item 1A.	Risk Factors		55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		55
Item 3.	Defaults Upon Senior Securities		55
Item 4.	Mine Safety Disclosures		56
Item 5.	Other Information		56
Item 6.	Exhibits		57
	Signature		58

1

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

EPNG	=	El Paso Natural Gas Company, L.L.C.	Ruby	=	Ruby Pipeline Holding Company, L.L.C.
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	SFPP	=	SFPP, L.P.
KMI	=	Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries	SNG	=	Southern Natural Gas Company, L.L.C.
			TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KMLT	=	Kinder Morgan Liquid Terminals, LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d	=	per day	FERC	=	Federal Energy Regulatory Commission
Bbl	=	barrels	GAAP	=	U.S. Generally Accepted Accounting Principles
BBtu	=	billion British Thermal Units	LLC	=	limited liability company
Bcf	=	billion cubic feet	LIBOR	=	London Interbank Offered Rate
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	MBbl	=	thousand barrels
			MMBbl	=	million barrels
CO2	=	carbon dioxide or our CO2 business segment	MMtons	=	million tons
DCF	=	distributable cash flow	NGL	=	natural gas liquids
DD&A	=	depreciation, depletion and amortization	NYMEX	=	New York Mercantile Exchange
EBDA	=	earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments	OTC	=	over-the-counter
			PHMSA	=	Pipeline and Hazardous Materials Safety Administration
EBITDA	=	earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investments	ROU	=	Right-of-Use
			U.S.	=	United States of America
EPA	=	U.S. Environmental Protection Agency	WTI	=	West Texas Intermediate
FASB	=	Financial Accounting Standards Board

2

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, our anticipated dividends and capital projects, including expected completion timing and benefits of those projects.

Important factors that could cause actual results to differ materially from those expressed in or implied by the forward-looking statements in this report include: the timing and extent of changes in the supply of and demand for the products we transport and handle; commodity prices; and the other risks and uncertainties described in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” in this report, as well as “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021 (except to the extent such information is modified or superseded by information in subsequent reports).

You should keep these risk factors in mind when considering forward-looking statements. These risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.

3

PART I.  FINANCIAL INFORMATION

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.

4

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.

5

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.

6

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

7

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.

8

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.

9

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.

10

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

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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.

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(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.

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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)

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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.

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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.

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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)

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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.

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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).

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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.

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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

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	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

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	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.

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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

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	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

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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.

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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.

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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

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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

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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

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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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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

General and Basis of Presentation

The following discussion and analysis should be read in conjunction with our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes in our 2021 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2021 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2021 Form 10-K; and (iv) “Risk Factors” in Part I, Item 1A of our 2021 Form 10-K.

2022 Dividends and Discretionary Capital

We expect to declare dividends of $1.11 per share for 2022, a 3% increase from the 2021 declared dividends of $1.08 per share. We now expect to invest $1.9 billion in expansion projects, acquisitions, and contributions to joint ventures or discretionary capital expenditures during 2022.

The expectations for 2022 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 7 “Reportable Segments”) and Net income (loss) attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA and Net Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the three and six months ended June 30, 2022 and 2021 present Segment EBDA and Net income (loss) attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income (loss) attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income (loss) attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan,

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Inc. (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below). In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

Adjusted Earnings

Adjusted Earnings is calculated by adjusting Net income (loss) attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us and certain external users of our financial statements to assess the earnings of our business excluding Certain Items as another reflection of our ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net income (loss) attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting Net income (loss) attributable to Kinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income (loss) attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” and “—Non-GAAP Financial Measures—Adjusted Segment EBDA to Adjusted EBITDA to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income (loss) attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries. (See “—Non-GAAP Financial Measures—Supplemental Information” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of

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DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of June 30, 2022, by subtracting the following amounts from our debt balance of $31,522 million: (i) cash and cash equivalents of $100 million; and (ii) debt fair value adjustments of $412 million; and excluding the foreign exchange impact on Euro-denominated bonds of $(19) million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt is a non-GAAP financial measure that management believes is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents.

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Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.

	Three Months Ended June 30,
	2022		2021		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,134	$	(570)	$	1,704	299%
Products Pipelines	299		265		34		13%
Terminals	253		246		7		3%
CO2	212		150		62		41%
Total Segment EBDA	1,898		91		1,807		1,986%
DD&A	(543)		(528)		(15)		(3)%
Amortization of excess cost of equity investments	(19)		(13)		(6)		(46)%
General and administrative and corporate charges	(144)		(150)		6		4%
Interest, net	(355)		(377)		22		6%
Income (loss) before income taxes	837		(977)		1,814		186%
Income tax (expense) benefit	(184)		237		(421)		(178)%
Net income (loss)	653		(740)		1,393		188%
Net income attributable to noncontrolling interests	(18)		(17)		(1)		(6)%
Net income (loss) attributable to Kinder Morgan, Inc.	$	635	$	(757)	$	1,392	184%

	Six Months Ended June 30,
	2022		2021		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	2,318	$	1,533	$	785	51	%
Products Pipelines	598		513		85		17	%
Terminals	491		473		18		4	%
CO2	404		436		(32)		(7)	%
Total Segment EBDA	3,811		2,955		856		29	%
DD&A	(1,081)		(1,069)		(12)		(1)	%
Amortization of excess cost of equity investments	(38)		(35)		(3)		(9)	%
General and administrative and corporate charges	(289)		(298)		9		3	%
Interest, net	(688)		(754)		66		9	%
Income before income taxes	1,715		799		916		115	%
Income tax expense	(378)		(114)		(264)		(232)	%
Net income	1,337		685		652		95	%
Net income attributable to noncontrolling interests	(35)		(33)		(2)		(6)	%
Net income attributable to Kinder Morgan, Inc.	$	1,302	$	652	$	650	100	%

(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.

Net income (loss) attributable to Kinder Morgan, Inc. increased $1,392 million and $650 million for the three and six months ended June 30, 2022, respectively, as compared to the respective prior year periods. The second quarter and year-to-

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date increases were primarily due to the $1,600 million pre-tax non-cash impairment loss in 2021 related to South Texas gathering and processing assets within our Natural Gas Pipeline segment and higher earnings from our Products Pipelines business segment with our West Coast Refined Products and Southeast Refined Products assets. The year-to-date increase was partially offset by the benefit in the 2021 period of $1,102 million for largely nonrecurring earnings related to the February 2021 winter storm, mostly impacting the earnings from our Natural Gas Pipelines and CO2 business segments.

Certain Items Affecting Consolidated Earnings Results

	Three Months Ended June 30,
	2022						2021
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,134	$	(1)	$	1,133	$	(570)	$	1,634	$	1,064	$	69
Products Pipelines	299		—		299		265		28		293		6
Terminals	253		—		253		246		—		246		7
CO2	212		(1)		211		150		1		151		60
Total Segment EBDA(a)	1,898		(2)		1,896		91		1,663		1,754		142
DD&A and amortization of excess cost of equity investments	(562)		—		(562)		(541)		—		(541)		(21)
General and administrative and corporate charges(a)	(144)		—		(144)		(150)		—		(150)		6
Interest, net(a)	(355)		(17)		(372)		(377)		(3)		(380)		8
Income (loss) before income taxes	837		(19)		818		(977)		1,660		683		135
Income tax (expense) benefit(b)	(184)		5		(179)		237		(387)		(150)		(29)
Net income (loss)	653		(14)		639		(740)		1,273		533		106
Net income attributable to noncontrolling interests(a)	(18)		—		(18)		(17)		—		(17)		(1)
Net income (loss) attributable to Kinder Morgan, Inc.	$	635	$	(14)	$	621	$	(757)	$	1,273	$	516	$	105

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	Six Months Ended June 30,
	2022						2021
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	2,318	$	112	$	2,430	$	1,533	$	1,625	$	3,158	$	(728)
Products Pipelines	598		—		598		513		43		556		42
Terminals	491		—		491		473		—		473		18
CO2	404		15		419		436		6		442		(23)
Total Segment EBDA(a)	3,811		127		3,938		2,955		1,674		4,629		(691)
DD&A and amortization of excess cost of equity investments	(1,119)		—		(1,119)		(1,104)		—		(1,104)		(15)
General and administrative and corporate charges(a)	(289)		—		(289)		(298)		—		(298)		9
Interest, net(a)	(688)		(61)		(749)		(754)		(9)		(763)		14
Income before income taxes	1,715		66		1,781		799		1,665		2,464		(683)
Income tax expense(b)	(378)		(15)		(393)		(114)		(427)		(541)		148
Net income	1,337		51		1,388		685		1,238		1,923		(535)
Net income attributable to noncontrolling interests(a)	(35)		—		(35)		(33)		—		(33)		(2)
Net income attributable to Kinder Morgan, Inc.	$	1,302	$	51	$	1,353	$	652	$	1,238	$	1,890	$	(537)

(a)For a more detailed discussion of Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.

(b)The combined net effect of the income tax Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

Net income (loss) attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) increased by $105 million for the three months ended June 30, 2022 and decreased by $537 million for the six months ended June 30, 2022 as compared to the respective prior year periods. The second quarter increase was primarily due to higher earnings from our Natural Gas Pipeline and CO2 business segments. The year-to-date decrease was impacted by lower earnings of $806 million from our Natural Gas Pipelines business segment’s Midstream region and $56 million from our CO2 business segment’s oil and gas producing activities (both primarily related to the February 2021 winter storm, and therefore largely nonrecurring) partially offset by lower income tax expense and higher earnings from our Products Pipelines business segment.

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Non-GAAP Financial Measures

Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	635	$	(757)	$	1,302	$	652
Total Certain Items	(14)		1,273		51		1,238
Adjusted Earnings(a)	621		516		1,353		1,890
DD&A and amortization of excess cost of equity investments for DCF(b)	627		604		1,250		1,242
Income tax expense for DCF(a)(b)	199		170		434		589
Cash taxes(b)	(47)		(45)		(48)		(44)
Sustaining capital expenditures(b)	(213)		(210)		(338)		(317)
Other items(c)	(11)		(10)		(20)		(6)
DCF	$	1,176	$	1,025	$	2,631	$	3,354

Adjusted Segment EBDA to Adjusted EBITDA to DCF

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions, except per share amounts)
Natural Gas Pipelines	$	1,133	$	1,064	$	2,430	$	3,158
Products Pipelines	299		293		598		556
Terminals	253		246		491		473
CO2	211		151		419		442
Adjusted Segment EBDA(a)	1,896		1,754		3,938		4,629
General and administrative and corporate charges(a)	(144)		(150)		(289)		(298)
Joint venture DD&A and income tax expense(a)(b)	85		83		172		186
Net income attributable to noncontrolling interests(a)	(18)		(17)		(35)		(33)
Adjusted EBITDA	1,819		1,670		3,786		4,484
Interest, net(a)	(372)		(380)		(749)		(763)
Cash taxes(b)	(47)		(45)		(48)		(44)
Sustaining capital expenditures(b)	(213)		(210)		(338)		(317)
Other items(c)	(11)		(10)		(20)		(6)
DCF	$	1,176	$	1,025	$	2,631	$	3,354
Adjusted Earnings per share	$	0.27	$	0.23	$	0.59	$	0.83
Weighted average shares outstanding for dividends(d)	2,277		2,277		2,279		2,277
DCF per share	$	0.52	$	0.45	$	1.15	$	1.47
Declared dividends per share	$	0.2775	$	0.27	$	0.555	$	0.54

(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.

(b)Includes or represents DD&A, income tax expense, cash taxes and/or sustaining capital expenditures (as applicable for each item) from joint ventures. See tables included in “—Supplemental Information” below.

(c)Includes pension contributions, non-cash pension expense and non-cash compensation associated with our restricted stock program.

(d)Includes restricted stock awards that participate in dividends.

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Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	635	$	(757)	$	1,302	$	652
Certain Items:
Fair value amortization	(3)		(4)		(7)		(8)
Legal, environmental and taxes other than income tax reserves	—		28		—		112
Change in fair value of derivative contracts(a)	(27)		28		55		42
Loss on impairments, divestitures and other write-downs, net(b)	—		1,600		—		1,511
Income tax Certain Items	5		(387)		(15)		(427)
Other	11		8		18		8
Total Certain Items(c)	(14)		1,273		51		1,238
DD&A and amortization of excess cost of equity investments	562		541		1,119		1,104
Income tax expense(d)	179		150		393		541
Joint venture DD&A and income tax expense(d)(e)	85		83		172		186
Interest, net(d)	372		380		749		763
Adjusted EBITDA	$	1,819	$	1,670	$	3,786	$	4,484

(a)Gains or losses are reflected in our DCF when realized.

(b)Three and six months ended June 30, 2021 amounts include a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from anticipated lower volumes and rates on contract renewals. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings LLC, offset partially by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, reported within “Other, net” and “Earnings from equity investments,” respectively, on the accompanying consolidated statement of operations.

(c)Three and six months ended June 30, 2022 amounts include no amount and $5 million, respectively, and three and six months ended June 30, 2021 amounts include $10 million and $127 million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.

(d)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

(e)Represents joint venture DD&A and income tax expense. See tables included in “—Supplemental Information” below.

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Supplemental Information

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions)
DD&A (GAAP)	$	543	$	528	$	1,081	$	1,069
Amortization of excess cost of equity investments (GAAP)	19		13		38		35
DD&A and amortization of excess cost of equity investments	562		541		1,119		1,104
Joint venture DD&A	65		63		131		138
DD&A and amortization of excess cost of equity investments for DCF	$	627	$	604	$	1,250	$	1,242
Income tax expense (benefit) (GAAP)	$	184	$	(237)	$	378	$	114
Certain Items	(5)		387		15		427
Income tax expense(a)	179		150		393		541
Unconsolidated joint venture income tax expense(a)(b)	20		20		41		48
Income tax expense for DCF(a)	$	199	$	170	$	434	$	589
Additional joint venture information
Unconsolidated joint venture DD&A	$	76	$	74	$	153	$	160
Less: Consolidated joint venture partners’ DD&A	11		11		22		22
Joint venture DD&A	65		63		131		138
Unconsolidated joint venture income tax expense(a)(b)	20		20		41		48
Joint venture DD&A and income tax expense(a)	$	85	$	83	$	172	$	186
Unconsolidated joint venture cash taxes(b)	$	(39)	$	(34)	$	(39)	$	(34)
Unconsolidated joint venture sustaining capital expenditures	$	(39)	$	(32)	$	(51)	$	(52)
Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(2)		(4)		(3)
Joint venture sustaining capital expenditures	$	(37)	$	(30)	$	(47)	$	(49)

(a)Amounts are adjusted for Certain Items.

(b)Amounts are associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments.

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Segment Earnings Results

Natural Gas Pipelines

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions, except operating statistics)
Revenues	$	3,356	$	1,976	$	6,169	$	6,101
Operating expenses	(2,374)		(1,077)		(4,158)		(3,347)
Loss on impairments and divestitures, net	—		(1,599)		—		(1,599)
Other income	1		1		2		2
Earnings from equity investments	149		126		303		167
Other, net	2		3		2		209
Segment EBDA	1,134		(570)		2,318		1,533
Certain Items(a)	(1)		1,634		112		1,625
Adjusted Segment EBDA	$	1,133	$	1,064	$	2,430	$	3,158
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	69			$	(728)
Volumetric data(b)
Transport volumes (BBtu/d)	37,822		38,408		38,771		38,627
Sales volumes (BBtu/d)	2,579		2,561		2,547		2,411
Gathering volumes (BBtu/d)	2,997		2,667		2,908		2,588
NGLs (MBbl/d)	30		30		31		30

Certain Items affecting Segment EBDA

(a)Three months ended June 30, 2022 amount includes an increase in revenues of $11 million and a decrease in costs of sales of $1 million, and six months ended June 30, 2022 amount includes a decrease in revenues of $3 million and an increase in costs of sales of $86 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales and purchases. Three and six months ended June 30, 2022 amounts also include an increase in other operating expenses of $11 million and $18 million, respectively, related to costs associated with a pipeline rupture. Three and six months ended June 30, 2021 amounts include a pre-tax non-cash asset impairment loss of $1,600 million resulting from anticipated lower volumes and rates on contract renewals related to our South Texas gathering and processing assets and decreases in revenues of $16 million and $22 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings partially offset by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a litigation reserve.

Other

(b)Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included and volumes for assets sold are excluded for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

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Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2022 and 2021:

Three Months Ended June 30, 2022 versus Three Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
East	$	599	$	539	$	60
Midstream	328		300		28
West	206		225		(19)
Total Natural Gas Pipelines	$	1,133	$	1,064	$	69

Six Months Ended June 30, 2022 versus Six Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
East	$	1,251	$	1,129	$	122
Midstream	712		1,518		(806)
West	467		511		(44)
Total Natural Gas Pipelines	$	2,430	$	3,158	$	(728)

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2022 and 2021:

•$60 million (11%) and $122 million (11%) increases, respectively, in the East Region was primarily due to our July 2021 acquisition of the Stagecoach assets and increased earnings from Kinder Morgan Louisiana Pipeline, LLC from a new customer contract. The year-to-date increase was also impacted by higher earnings from TGP primarily due to increases in transportation revenues as a result of new customer contracts partially offset by lower revenues as a result of the February 2021 winter storm; and

•$28 million (9%) increase and $806 million (53%) decrease, respectively, in Midstream. The second quarter increase was primarily due to higher NGL sales margins driven by higher prices on our South Texas and Altamont assets and higher volumes on Kinderhawk assets partially offset by lower gas sales margin on our Texas intrastate natural gas pipeline operations due to lower prices. The year-to-date decrease was primarily due to lower sales margins resulting in decreases of $846 million on our Texas intrastate natural gas pipeline operations and $71 million on our South Texas assets largely driven by higher 2021 commodity prices related to the February 2021 winter storm. These decreases were partially offset by higher earnings on our Oklahoma assets from higher 2021 commodity prices on certain purchase contracts as a result of the February 2021 winter storm, higher volumes on Kinderhawk assets, and higher NGL sales margins driven by higher prices on our Altamont asset. Overall, Midstream’s revenues are partially offset by corresponding changes in costs of sales; partially offset by

•$19 million (8%) and $44 million (9%) decreases, respectively, in the West Region was primarily due to lower earnings from EPNG driven by lower commodity and park and loan revenues resulting from a partial pipeline outage, and lower earnings from Colorado Interstate Gas Company, L.L.C. driven by lower revenues due to a rate case settlement.

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Products Pipelines

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions, except operating statistics)
Revenues	$	996	$	514	$	1,762	$	967
Operating expenses	(717)		(268)		(1,214)		(487)
Gain on divestitures and impairments, net	—		—		12		—
Earnings from equity investments	20		19		38		33
Segment EBDA	299		265		598		513
Certain Items(a)	—		28		—		43
Adjusted Segment EBDA	$	299	$	293	$	598	$	556
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	6			$	42
Volumetric data(b)
Gasoline(c)	1,017		1,046		979		969
Diesel fuel	372		418		371		398
Jet fuel	267		224		255		200
Total refined product volumes	1,656		1,688		1,605		1,567
Crude and condensate	478		510		482		508
Total delivery volumes (MBbl/d)	2,134		2,198		2,087		2,075

Certain Items affecting Segment EBDA

(a)Three and six month 2021 amounts include an increase in expense of $28 million related to a litigation reserve adjustment. Six month 2021 amount also includes an increase in expense of $15 million related to an environmental reserve adjustment.

Other

(b)Joint venture throughput is reported at our ownership share.

(c)Volumes include ethanol pipeline volumes.

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Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2022 and 2021:

Three Months Ended June 30, 2022 versus Three Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Southeast Refined Products	$	79	$	69	$	10
West Coast Refined Products	131		128		3
Crude and Condensate	89		96		(7)
Total Products Pipelines	$	299	$	293	$	6

Six Months Ended June 30, 2022 versus Six Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Southeast Refined Products	$	152	$	134	$	18
West Coast Refined Products	268		238		30
Crude and Condensate	178		184		(6)
Total Products Pipelines	$	598	$	556	$	42

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 20, 2022 and 2021:

•$10 million (14%) and $18 million (13%) increases, respectively, in Southeast Refined Products was primarily due to higher earnings at our Transmix processing operations primarily due to higher prices and volumes; and

•$3 million (2%) and $30 million (13%) increases, respectively, in West Coast Refined Products was primarily due to increased earnings driven by higher revenues on Pacific operations (SFPP) resulting from higher jet fuel volumes and West Coast terminals resulting from higher volumes. The year-to-date increase was also impacted by a gain on sale of land at Calnev Pipe Line LLC; partially offset by

•$7 million (7%) and $6 million (3%) decreases, respectively, in Crude and Condensate was primarily due to lower earnings from Double H pipeline resulting from decreased revenues due to lower volumes. Crude and Condensate Pipeline also had higher revenues of $401 million and $623 million, respectively, with corresponding increases in cost of sales, resulting from increased marketing activities.

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Terminals

	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
	(In millions, except operating statistics)
Revenues	$	450		$	433		$	880		$	853
Operating expenses	(216)			(191)			(415)			(388)
Gain (loss) on divestitures and impairments, net	12			(1)			9			—
Other income	—			—			4			—
Earnings from equity investments	4			4			8			7
Other, net	3			1			5			1
Segment EBDA	253			246			491			473
Certain Items	—			—			—			—
Adjusted Segment EBDA	$	253		$	246		$	491		$	473
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	7					$	18
Volumetric data(a)
Liquids leasable capacity (MMBbl)	78.9			79.0			78.9			79.0
Liquids utilization %(b)	90.8		%	94.1		%	90.8		%	94.1		%
Bulk transload tonnage (MMtons)	13.7			13.6			26.7			24.5

Other

(a)Volumes for facilities divested, idled and/or held for sale are excluded for all periods presented.

(b)The ratio of our tankage capacity in service to tankage capacity available for service.

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For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical region and included within the All others group. Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2022 and 2021:

Three Months Ended June 30, 2022 versus Three Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Mid Atlantic	$	24	$	17	$	7
Gulf Liquids	75		72		3
Gulf Central	35		33		2
Northeast	23		29		(6)
Marine operations	33		38		(5)
All others (including intrasegment eliminations)	63		57		6
Total Terminals	$	253	$	246	$	7

Six Months Ended June 30, 2022 versus Six Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Mid Atlantic	$	47	$	32	$	15
Gulf Liquids	152		144		8
Gulf Central	67		52		15
Northeast	45		55		(10)
Marine operations	71		80		(9)
All others (including intrasegment eliminations)	109		110		(1)
Total Terminals	$	491	$	473	$	18

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2022 and 2021:

•$7 million (41%) and $15 million (47%) increases, respectively, in the Mid Atlantic terminals was primarily due to higher handling rates and coal volumes at our Pier IX facility; and

•$3 million (4%) and $8 million (6%) increases, respectively, in the Gulf Liquids region was primarily due to increased revenues from contractual rate escalations and higher volumes and associated ancillary fees; and

•$2 million (6%) and $15 million (29%) increases, respectively, in the Gulf Central terminals was primarily due to higher volumes for petroleum coke handling activities, owing largely to refinery outages in the 2021 period associated with the February 2021 winter storm, increased revenues resulting from contractual rate escalations, and higher coal volumes. The year-to-date increase was also impacted by lower property tax expense at Battleground Oil Specialty Terminal Company LLC; partially offset by,

•$6 million (21%) and $10 million (18%) decreases, respectively, in the Northeast terminals was primarily driven by decreased revenues associated with lower utilization and rates on re-contracted tank positions at our Carteret and Perth Amboy facilities; and

•$5 million (13%) and $9 million (11%) decreases, respectively, in Marine operations was primarily due to lower average charter rates partially offset by higher fleet utilization.

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CO2

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In millions, except operating statistics)
Revenues	$	343	$	243	$	648	$	472
Operating expenses	(140)		(98)		(265)		(49)
Gain (loss) on impairments and divestitures, net	—		(3)		1		(3)
Earnings from equity investments	9		8		20		16
Segment EBDA	212		150		404		436
Certain Items(a)	(1)		1		15		6
Adjusted Segment EBDA	$	211	$	151	$	419	$	442
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	60			$	(23)
Volumetric data
SACROC oil production	19.7		20.2		19.5		19.8
Yates oil production	6.3		6.7		6.6		6.4
Katz and Goldsmith oil production	1.8		2.2		1.8		2.4
Tall Cotton oil production	1.0		1.0		1.0		1.0
Total oil production, net (MBbl/d)(b)	28.8		30.1		28.9		29.6
NGL sales volumes, net (MBbl/d)(b)	9.2		9.5		9.3		9.1
CO2 sales volumes, net (Bcf/d)	0.4		0.4		0.4		0.4
Realized weighted average oil price ($ per Bbl)	$	68.92	$	52.50	$	67.91	$	51.79
Realized weighted average NGL price ($ per Bbl)	$	41.86	$	22.58	$	42.77	$	21.42

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $(1) million and $15 million for the three and six months ended June 30, 2022, respectively, and $1 million and $6 million for the three and six months ended June 30, 2021, respectively, as changes in revenue related to non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales.

Other

(b)Net of royalties and outside working interests.

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Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2022 and 2021:

Three Months Ended June 30, 2022 versus Three Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Oil and Gas Producing activities	$	136	$	99	$	37
Source and Transportation activities	69		52		17
Subtotal	205		151		54
Energy Transition Ventures	6		—		6
Total CO2	$	211	$	151	$	60

Six Months Ended June 30, 2022 versus Six Months Ended June 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Oil and Gas Producing activities	$	278	$	334	$	(56)
Source and Transportation activities	131		108		23
Subtotal	409		442		(33)
Energy Transition Ventures	10		—		10
Total CO2	$	419	$	442	$	(23)

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2022 and 2021:

•$37 million (37%) increase and $56 million (17%) decrease, respectively, in Oil and Gas Producing activities. The second quarter increase was primarily due to higher realized crude oil and NGL prices which increased revenues by $63 million partially offset by higher operating expenses. The year-to-date decrease was primarily due to higher operating expenses of $172 million mainly driven by the benefit realized in the 2021 period from returning power to the grid by curtailing oil production during the February 2021 winter storm partially offset by higher realized crude oil and NGL prices which increased revenues by approximately $123 million; and

•$17 million (33%) and $23 million (21%) increases, respectively, in Source and Transportation activities primarily due to increased revenues related to higher CO2 sales prices.

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We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of June 30, 2022.

	Remaining 2022		2023		2024		2025		2026
Crude Oil(a)
Price ($ per Bbl)	$	61.19	$	61.10	$	58.88	$	59.08	$	66.47
Volume (MBbl/d)	25.20		19.00		11.60		6.75		2.10
NGLs
Price ($ per Bbl)	$	55.36	$	61.12
Volume (MBbl/d)	4.76		1.27
Midland-to-Cushing Basis Spread
Price ($ per Bbl)	$	0.53	$	0.54
Volume (MBbl/d)	23.65		4.50

(a)Includes West Texas Intermediate hedges.

DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests

	Three Months Ended June 30,				Earnings increase/(decrease)
	2022		2021
	(In millions, except percentages)
DD&A (GAAP)	$	(543)	$	(528)	$	(15)	(3)	%
General and administrative (GAAP)	$	(152)	$	(160)	$	8	5	%
Corporate benefit	8		10		(2)		(20)	%
Certain Items	—		—		—		—	%
General and administrative and corporate charges(a)	$	(144)	$	(150)	$	6	4	%
Interest, net (GAAP)	$	(355)	$	(377)	$	22	6	%
Certain Items(b)	(17)		(3)		(14)		(467)	%
Interest, net(a)	$	(372)	$	(380)	$	8	2	%
Net income attributable to noncontrolling interests (GAAP)	$	(18)	$	(17)	$	(1)	(6)	%
Certain Items(c)	—		—		—		—	%
Net income attributable to noncontrolling interests(a)	$	(18)	$	(17)	$	(1)	(6)	%

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	Six Months Ended June 30,				Earnings increase/(decrease)
	2022		2021
	(In millions, except percentages)
DD&A (GAAP)	$	(1,081)	$	(1,069)	$	(12)	(1)	%
General and administrative (GAAP)	$	(308)	$	(316)	$	8	3	%
Corporate benefit	19		18		1		6	%
Certain Items	—		—		—		—	%
General and administrative and corporate charges(a)	$	(289)	$	(298)	$	9	3	%
Interest, net (GAAP)	$	(688)	$	(754)	$	66	9	%
Certain Items(b)	(61)		(9)		(52)		(578)	%
Interest, net(a)	$	(749)	$	(763)	$	14	2	%
Net income attributable to noncontrolling interests (GAAP)	$	(35)	$	(33)	$	(2)	(6)	%
Certain Items(c)	—		—		—		—	%
Net income attributable to noncontrolling interests(a)	$	(35)	$	(33)	$	(2)	(6)	%

Certain items

(a)Amounts are adjusted for Certain Items.

(b)Three and six month 2022 amounts include decreases in interest expense of $14 million and $54 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt, primarily related to our floating-to-fixed LIBOR interest rate swaps which are not designated as accounting hedges and $3 million and $7 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and six month 2021 amounts include decreases of $4 million and $8 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions.

(c)Three and six month 2021 amounts each include less than $1 million of noncontrolling interests associated with Certain Items.

General and administrative expenses and corporate charges adjusted for Certain Items for the three and six months ended June 30, 2022 when compared with the respective prior year periods decreased $6 million and $9 million, respectively, primarily due to higher capitalized costs of $12 million and $21 million, respectively, reflecting higher capital spending partially offset by $6 million and $11 million, respectively, of higher labor, travel and legal costs.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our consolidated interest expense, net adjusted for Certain Items for the three and six months ended June 30, 2022 when compared with the respective prior year periods decreased $8 million and $14 million, respectively, primarily due to lower long-term average interest rates and long-term debt balances, partially offset by higher short-term rates.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of June 30, 2022 and December 31, 2021, approximately 9% and 21%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us.

Income Taxes

Our tax expense for the three months ended June 30, 2022 was approximately $184 million as compared with $237 million of tax benefit for the same period of 2021. The $421 million increase in tax expense is due primarily to federal and state taxes on higher pre-tax book income in the current year.

50

Our tax expense for the six months ended June 30, 2022 was approximately $378 million as compared with $114 million for the same period of 2021. The $264 million increase in tax expense was due primarily to federal and state taxes on higher pre-tax book income in the current year and the release of the valuation allowance on our investment in NGPL Holdings in the prior year.

Liquidity and Capital Resources

General

As of June 30, 2022, we had $100 million of “Cash and cash equivalents,” a decrease of $1,040 million from December 31, 2021. Additionally, as of June 30, 2022, we had borrowing capacity of approximately $3.0 billion under our credit facilities (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flows from operations, providing a source of funds of $2,648 million and $3,311 million in the first six months of 2022 and 2021, respectively. The period-to-period decrease is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any.

Our board of directors declared a quarterly dividend of $0.2775 per share for the second quarter of 2022, consistent with the dividend declared for the previous quarter.

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.

During the first quarter, upon maturity, we repaid EPNG’s 8.625% senior notes, our 4.15% corporate senior notes, and the 1.50% series of our Euro denominated debt.

On June 1, 2022, we repaid $1 billion of our 3.95% senior notes, due September 1, 2022 using short-term borrowings.

Short-term Liquidity

As of June 30, 2022, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion of credit facilities and associated commercial paper program. The loan commitments under our credit facilities can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our credit facilities and letters of credit reduce borrowings allowed under our $3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facilities and, as previously discussed, have consistently generated strong cash flows from operations.

As of June 30, 2022, our $2,970 million of short-term debt consisted primarily of senior notes that mature in the next twelve months and outstanding commercial paper borrowings. We intend to fund our debt, as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2021 was $2,646 million.

We had working capital (defined as current assets less current liabilities) deficits of $3,284 million and $1,992 million as of June 30, 2022 and December 31, 2021, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $1,292 million unfavorable change from year-end 2021 was primarily due to (i) a $1,040 million decrease in cash and cash equivalents which includes $1,190 million related to repayments of senior notes that matured in the first quarter of 2022 using cash on hand; (ii) a $936 million increase in commercial paper borrowings; and (iii) net unfavorable short-term fair value adjustments on derivative contracts of $422 million; partially offset by (i) a $613 million decrease in senior notes that mature in the next twelve months; (ii) a $310 million increase in restricted deposits primarily related to our derivative activity; (iii) a $128 million increase in inventories, primarily products inventory; (iv) a $62 million decrease in accrued interest; and (v) a $58 million decrease in accrued contingencies. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

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Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “—Results of Operations—Overview—Non-GAAP Financial Measures—DCF”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e., production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.

Our capital expenditures for the six months ended June 30, 2022, and the amount we expect to spend for the remainder of 2022 to sustain our assets and grow our business are as follows:

	Six Months Ended June 30, 2022		2022 Remaining		Total 2022
	(In millions)
Sustaining capital expenditures(a)(b)	$	338	$	592	$	930
Discretionary capital investments(b)(c)(d)	458		1,397		1,855

(a)Six months ended June 30, 2022, 2022 Remaining, and Total 2022 amounts include $47 million, $81 million, and $128 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “—Results of Operations—Non-GAAP Financial Measures—Supplemental Information.”

(b)Six months ended June 30, 2022 amount excludes $53 million due to decreases in accrued capital expenditures and contractor retainage and net changes in other.

(c)Six months ended June 30, 2022 amount includes $23 million of our contributions to certain unconsolidated joint ventures for capital investments. Both 2022 Remaining and Total 2022 amounts include $358 million for our acquisition of Mas CanAm, LLC.

(d)Amounts include our actual or estimated contributions to unconsolidated joint ventures, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2021 in our 2021 Form 10-K.

Commitments for the purchase of property, plant and equipment as of June 30, 2022 and December 31, 2021 were $392 million and $209 million, respectively. The increase of $183 million was primarily driven by an overall increase of capital commitments.

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Cash Flows

Operating Activities

Cash provided by operating activities decreased $663 million in the six months ended June 30, 2022 compared to the respective 2021 period primarily due to:

•a $617 million decrease in cash after adjusting the $652 million increase in net income by $1,269 million for the combined effects of the period-to-period net changes in non-cash items. This overall cash decrease primarily resulted from the benefit recognized in the 2021 period for largely nonrecurring earnings related to the February 2021 winter storm (see discussion above in “—Results of Operations”); and

•a $46 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities.

Investing Activities

Cash used in investing activities increased $561 million for the six months ended June 30, 2022 compared to the respective 2021 period primarily attributable to:

•a $409 million decrease in proceeds from sales of investments primarily due to $413 million received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period; and

•a $234 million increase in capital expenditures reflecting an overall increase of expansion capital projects in the 2022 period over the comparative 2021 period; partially offset by,

•a combined $62 million increase in cash related to distributions received from equity investments in excess of cumulative earnings and lower contributions to equity investees in the 2022 period compared with the 2021 period.

Financing Activities

Cash used in financing activities increased $266 million for the six months ended June 30, 2022 compared to the respective 2021 period primarily attributable to:

•$173 million cash used in repurchasing shares under our share buy-back program in the 2022 period; and

•a $58 million net increase in cash used related to debt activity as a result of higher net debt payments in the 2022 period compared to the 2021 period.

Dividends

We expect to declare dividends of $1.11 per share on our stock for 2022. The table below reflects our 2022 dividends declared:

Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
March 31, 2022	$	0.2775	April 20, 2022	May 2, 2022	May 16, 2022
June 30, 2022	0.2775		July 20, 2022	August 1, 2022	August 15, 2022

The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Part I, Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2021 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.

Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.

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Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), 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. Accordingly, with the exception of certain subsidiaries identified as subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or Subsidiary Issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.  Also, see Exhibit 10.1 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of June 30, 2022.”

All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors, (referred to as “affiliates”) are presented separately in the accompanying supplemental summarized combined financial information.

Excluding fair value adjustments, as of June 30, 2022 and December 31, 2021, the Obligated Group had $30,312 million and $31,608 million, respectively, of Guaranteed Notes outstanding.

Summarized combined balance sheet and income statement information for the Obligated Group follows:

Summarized Combined Balance Sheet Information	June 30, 2022		December 31, 2021
	(In millions)
Current assets	$	3,289	$	3,556
Current assets - affiliates	1,359		1,233
Noncurrent assets	60,978		61,754
Noncurrent assets - affiliates	509		508
Total Assets	$	66,135	$	67,051
Current liabilities	$	6,547	$	5,413
Current liabilities - affiliates	1,446		1,332
Noncurrent liabilities	30,491		32,310
Noncurrent liabilities - affiliates	1,046		1,047
Total Liabilities	39,530		40,102
Kinder Morgan, Inc.’s stockholders’ equity	26,605		26,949
Total Liabilities and Stockholders’ Equity	$	66,135	$	67,051

Summarized Combined Income Statement Information	Three Months Ended June 30, 2022		Six Months Ended June 30, 2022
	(In millions)
Revenues	$	4,756	$	8,733
Operating income	889		1,795
Net income	537		1,105

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2021, in Part II, Item 7A in our 2021 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 4.  Controls and Procedures.

As of June 30, 2022, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended June 30, 2022 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2021 Form 10-K. For more information on our risk management activities, refer to Part I, Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

Our Purchases of Our Class P Stock

Settlement Period	Total number of securities purchased(a)	Average price paid per security(b)		Total number of securities purchased as part of publicly announced plans(a)	Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs
April 1 to April 30, 2022	1,336,132	$	18.45	1,336,132	$	1,399,723,550
May 1 to May 31, 2022	1,563,243	18.19		1,563,243	1,371,291,985
June 1 to June 30, 2022	7,037,626	16.98		7,037,626	1,251,805,298
Total	9,937,001	$	17.37	9,937,001	$	1,251,805,298

(a)On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. After repurchase, the shares are canceled and no longer outstanding.

(b)Amount includes any commission or other costs to repurchase shares.

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.

Item 3.  Defaults Upon Senior Securities.

None. 

55

Item 4.  Mine Safety Disclosures.

Except for at one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank). We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended June 30, 2022.

Item 5.  Other Information.

None.

56

Item 6.  Exhibits.

Exhibit Number	Description
10.1	Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of June 30, 2022.
22.1	Subsidiary guarantors and issuers of guaranteed securities.
31.1	Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Chief Executive Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification by Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Operations for the three and six months ended June 30, 2022 and 2021; (ii) our Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2022 and 2021; (iii) our Consolidated Balance Sheets as of June 30, 2022 and December 31, 2021; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2022 and 2021; (v) our Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2022 and 2021; and (vi) the notes to our Consolidated Financial Statements.
104	Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.

57

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

KINDER MORGAN, INC.
	Registrant

Date:	July 22, 2022	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

58

EX-10.1

Exhibit 10.1

CROSS GUARANTEE AGREEMENT

This CROSS GUARANTEE AGREEMENT is dated as of November 26, 2014 (as amended, restated, supplemented or otherwise modified from time to time, this “Agreement”), by each of the signatories listed on the signature pages hereto and each of the other entities that becomes a party hereto pursuant to Section 19 (the “Guarantors” and individually, a “Guarantor”), for the benefit of the Guaranteed Parties (as defined below).

W I T N E S S E T H:

WHEREAS, Kinder Morgan, Inc., a Delaware corporation (“KMI”), and certain of its direct and indirect Subsidiaries have outstanding senior, unsecured Indebtedness and may from time to time issue additional senior, unsecured Indebtedness;

WHEREAS, each Guarantor, other than KMI, is a direct or indirect Subsidiary of KMI;

WHEREAS, each Guarantor desires to provide the guarantee set forth herein with respect to the Indebtedness of such Guarantors that constitutes the Guaranteed Obligations; and

WHEREAS, each Guarantor acknowledges that it will derive substantial direct and indirect benefit from the making of the guarantees hereby;

NOW, THEREFORE, in consideration of the premises, the Guarantors hereby agree with each other for the benefit of the Guaranteed Parties as follows:

1.Defined Terms.

(a)As used in this Agreement, the following terms have the meanings specified below:

“Agreement” has the meaning provided in the preamble hereto.

“Bankruptcy Code” means Title 11 of the United States Code, as now or hereafter in effect, or any successor thereto.

“Capital Stock” means, with respect to any Person, any and all shares, interests, rights to purchase, warrants, options, participations or other equivalents (however designated) of such Person’s equity, including (i) all common stock and preferred stock, any limited or general partnership interest and any limited liability company member interest, (ii) beneficial interests in trusts, and (iii) any other interest or participation that confers upon a Person the right to receive a share of the profits and losses of, or distribution of assets of, the issuing Person.

“CFC” means a Person that is a “controlled foreign corporation” within the meaning of Section 957 of the Internal Revenue Code of 1986, as amended.

“Commodity Exchange Act” means the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute.

Exhibit 10.1

“Consolidated Assets” means, at the date of any determination thereof, the total assets of KMI and its Subsidiaries as set forth on a consolidated balance sheet of KMI and its Subsidiaries for their most recently completed fiscal quarter, prepared in accordance with GAAP.

“Consolidated Tangible Assets” means, at the date of any determination thereof, Consolidated Assets after deducting therefrom the value, net of any applicable reserves and accumulated amortization, of all goodwill, trade names, trademarks, patents and other like intangible assets, all as set forth, or on a pro forma basis would be set forth, on a consolidated balance sheet of KMI and its Subsidiaries for their most recently completed fiscal quarter, prepared in accordance with GAAP.

“Domestic Subsidiary” means any Subsidiary of KMI organized under the laws of any jurisdiction within the United States.

“Excluded Subsidiary” means (i) any Subsidiary that is not a Wholly-owned Domestic Operating Subsidiary, (ii) any Domestic Subsidiary that is a Subsidiary of a CFC or any Domestic Subsidiary (including a disregarded entity for U.S. federal income tax purposes) substantially all of whose assets (held directly or through Subsidiaries) consist of Capital Stock of one or more CFCs or Indebtedness of such CFCs, (iii) any Immaterial Subsidiary, (iv) any Subsidiary listed on Schedule III, (v) each of Calnev Pipe Line LLC, SFPP, L.P., Kinder Morgan G.P., Inc. and EPEC Realty, Inc. and each of its Subsidiaries, (vi) any other Subsidiary that is not a Guarantor under the Revolving Credit Agreement Guarantee, (vii) any not-for-profit Subsidiary, (viii) any Subsidiary that is prohibited by a Requirement of Law from guaranteeing the Guaranteed Obligations, and (ix) any Subsidiary acquired by KMI or its Subsidiaries after the date of this Agreement to the extent, and so long as, the financing documentation governing any existing Indebtedness of such Subsidiary that survives such acquisition prohibits such Subsidiary from guaranteeing the Guaranteed Obligations; provided, that notwithstanding the foregoing, any Subsidiary that is party to the Revolving Credit Agreement Guarantee or that Guarantees any senior notes or senior debt securities issued by KMI (other than pursuant to this Agreement) shall not constitute an Excluded Subsidiary for so long as such Guarantee is in effect.

“Excluded Swap Obligation” means, with respect to any Guarantor, any Swap Obligation if, and to the extent that, all or a portion of the Guarantee of such Guarantor of such Swap Obligation (or any Guarantee thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) by virtue of such Guarantor’s failure for any reason to constitute an “eligible contract participant” as defined in the Commodity Exchange Act and the regulations thereunder at the time the Guarantee of such Guarantor becomes effective with respect to such Swap Obligation. If a Swap Obligation arises under a master agreement governing more than one swap, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to swaps for which such Guarantee is or becomes illegal.

“GAAP” means generally accepted accounting principles in the United States of America from time to time, including as set forth in the opinions, statements and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and the Financial Accounting Standards Board.

“Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra national bodies such as the European Union or the European Central Bank).

2

Exhibit 10.1

“Guarantee” of or by any Person (the “guarantor”) means any obligation, contingent or otherwise, of the guarantor guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, and including any obligation of the guarantor, direct or indirect, (i) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or to advance or supply funds for the purchase of) any security for the payment thereof, (ii) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness or other obligation of the payment thereof, (iii) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation or (iv) as an account party in respect of any letter of credit or letter of guaranty issued to support such Indebtedness or obligation; provided that the term Guarantee shall not include endorsements for collection or deposit in the ordinary course of business.

“Guarantee Termination Date” has the meaning set forth in Section 2(d).

“Guaranteed Obligations” means the Indebtedness set forth on Schedule I hereto, as such schedule may be amended from time to time in accordance with the terms of this Agreement; provided that the term “Guaranteed Obligations” shall exclude any Excluded Swap Obligations.

“Guaranteed Parties” means, collectively, (i) in the case of Guaranteed Obligations that are governed by trust indentures, the holders (as that term is defined in the applicable trust indenture) of such Guaranteed Obligations, (ii) in the case of Guaranteed Obligations that are governed by loan agreements, credit agreements, or similar agreements, the lenders providing such loans or credit, and (iii) in the case of Guaranteed Obligations with respect to Hedging Agreements, the counterparties under such agreements.

“Guarantor” has the meaning provided in the preamble hereto. Schedule II hereto, as such schedule may be amended from time to time in accordance with the terms of this Agreement, sets forth the name of each Guarantor.

“Hedging Agreement” means a financial instrument, agreement or security which hedges or is used to hedge or manage the risk associated with a change in interest rates, foreign currency exchange rates or commodity prices (but excluding any purchase, swap, derivative contract or similar agreement relating to power, electricity or any related commodity product).

“Immaterial Subsidiary” means any Subsidiary that is not a Material Subsidiary.

“Indebtedness” means, collectively, (i) any senior, unsecured obligation created or assumed by any Person for borrowed money, including all obligations of such Person evidenced by bonds, debentures, notes or similar instruments (other than surety, performance and guaranty bonds), and (ii) all payment obligations of any Person with respect to obligations under Hedging Agreements.

“Investment Grade Rating” means a rating equal to or higher than Baa3 by Moody’s and BBB- by S&P; provided, however, that if (i) either of Moody’s or S&P changes its rating system, such ratings shall be the equivalent ratings after such changes or (ii) Moody’s or S&P shall not make a rating of a Guaranteed Obligation publicly available, the references above to Moody’s or S&P or both of them, as the case may be, shall be to a nationally recognized U.S. rating agency or agencies, as the case may be, selected by KMI and the references to the ratings categories above shall be to the corresponding rating categories of such rating agency or rating agencies, as the case may be.

“Issuer” means the issuer, borrower, or other applicable primary obligor of a Guaranteed Obligation.

3

Exhibit 10.1

“KMI” has the meaning provided in the recitals hereto.

“Lien” means, with respect to any asset (i) any mortgage, deed of trust, lien, pledge, hypothecation, encumbrance, charge or security interest in, on or of such asset, and (ii) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset.

“Material Subsidiary” means, as at any date of determination, any Subsidiary of KMI whose total tangible assets (for purposes of the below, when combined with the tangible assets of such Subsidiary’s Subsidiaries, after eliminating intercompany obligations) as at such date of determination are greater than or equal to 5% of Consolidated Tangible Assets as of the last day of the fiscal quarter most recently ended for which financial statements of KMI have been filed with the SEC.

“Moody’s” means Moody’s Investors Service, Inc. and its successors.

“Operating Subsidiary” means any operating company that is a Subsidiary of KMI.

“Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

“Qualified ECP Guarantor” means, in respect of any Swap Obligation, each Guarantor that has total assets exceeding $10,000,000 at the time the relevant Guarantee becomes effective with respect to such Swap Obligation or such other person as constitutes an “eligible contract participant” under the Commodity Exchange Act or any regulations promulgated thereunder and can cause another person to qualify as an “eligible contract participant” at such time by entering into a keepwell under Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.    

“Rating Agencies” means Moody’s and S&P; provided that, if at the relevant time neither Moody’s nor S&P shall be rating the relevant Guaranteed Obligation, then “Rating Agencies” shall mean another nationally recognized rating service that rates such Guaranteed Obligation.

“Rating Date” means the date immediately prior to the earlier of (i) the occurrence of a Release Event and (ii) public notice of the intention to effect a Release Event.

“Rating Decline” means, with respect to a Guaranteed Obligation, the occurrence of the following on, or within 90 days after, the date of the occurrence of a Release Event or of public notice of the intention to effect a Release Event (which period may be extended so long as the rating of such Guaranteed Obligation is under publicly announced consideration for possible downgrade by either of the Rating Agencies): (i) in the event such Guaranteed Obligation is assigned an Investment Grade Rating by both Rating Agencies on the Rating Date, the rating of such Guaranteed Obligation by one or both of the Rating Agencies shall be below an Investment Grade Rating; or (ii) in the event such Guaranteed Obligation is rated below an Investment Grade Rating by either of the Rating Agencies on the Rating Date, any such below-Investment Grade Rating of such Guaranteed Obligation shall be decreased by one or more gradations (including gradations within rating categories as well as between rating categories).

“Release Event” has the meaning set forth in Section 6(b).

“Requirement of Law” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other

4

Exhibit 10.1

directive or requirement (whether or not having the force of law), including environmental laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

Revolving Credit Agreement” means the Revolving Credit Agreement, dated as of September 19, 2014, among KMI, the lenders party thereto and Barclays Bank PLC, as administrative agent, as such credit agreement may be amended, modified, supplemented or restated from time to time, or refunded, refinanced, restructured, replaced, renewed, repaid or extended from time to time (whether with the original agents and lenders or other agents or lenders or trustee or otherwise, and whether provided under the original credit agreement or other credit agreements or note indentures or otherwise), including, without limitation, increasing the amount of available borrowings or other Indebtedness thereunder.

“Revolving Credit Agreement Guarantee” means the Guarantee Agreement, dated as of November 26, 2014, made by the Subsidiaries of KMI party thereto in favor of Barclays Bank PLC, as administrative agent, for the benefit of the lenders and the issuing banks under the Revolving Credit Agreement, as such guarantee agreement may be amended, modified, supplemented or restated from time to time, and as it may be replaced or renewed from time to time in connection with any amendment, modification, supplement, restatement, refunding, refinancing, restructuring, replacement, renewal, repayment, or extension of any Revolving Credit Agreement from time to time.

“S&P” means Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc., and its successors.

“SEC” means the United States Securities and Exchange Commission.

“Subsidiary” means, with respect to any Person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or, in the case of a partnership, more than 50% of the general partner interests are, as of such date, owned, controlled or held, or (b) that is, as of such date, otherwise controlled, by the parent or one or more Subsidiaries of the parent or by the parent and one or more Subsidiaries of the parent. Unless the context otherwise clearly requires, references in this Agreement to a “Subsidiary” or the “Subsidiaries” refer to a Subsidiary or the Subsidiaries of KMI. Notwithstanding the foregoing, Plantation Pipe Line Company, a Delaware and Virginia corporation, shall not be a Subsidiary of KMI until such time as its assets and liabilities, profit or loss and cash flow are required under GAAP to be consolidated with those of KMI.

“Swap Obligation” means, with respect to any Guarantor, any obligation to pay or perform under any agreement, contract or transaction that constitutes a “swap” within the meaning of Section 1a(47) of the Commodity Exchange Act.

“Wholly-owned Domestic Operating Subsidiary” means any Wholly-owned Subsidiary that constitutes (i) a Domestic Subsidiary and (ii) an Operating Subsidiary.

“Wholly-owned Subsidiary” means a Subsidiary of which all issued and outstanding Capital Stock (excluding in the case of a corporation, directors’ qualifying shares) is directly or indirectly owned by KMI.

5

Exhibit 10.1

(b)    The words “hereof”, “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section references are to Sections of this Agreement unless otherwise specified. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”.

(c)    The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

2.    Guarantee.

(a)    Subject to the provisions of Section 2(b), each of the Guarantors hereby, jointly and severally, unconditionally and irrevocably, guarantees, as primary obligor and not merely as surety, for the benefit of the Guaranteed Parties, the prompt and complete payment when due (whether at the stated maturity, by acceleration or otherwise) of the Guaranteed Obligations; provided that each Guarantor shall be released from its respective guarantee obligations under this Agreement as provided in Section 6(b). Upon the failure of an Issuer to punctually pay any Guaranteed Obligation, each Guarantor shall, upon written demand by the applicable Guaranteed Party to such Guarantor, pay or cause to be paid such amounts.

(b)    Anything herein to the contrary notwithstanding, the maximum liability of each Guarantor hereunder shall in no event exceed the amount that can be guaranteed by such Guarantor under the Bankruptcy Code or any applicable laws relating to fraudulent conveyances, fraudulent transfers or the insolvency of debtors after giving full effect to the liability under this Agreement and its related contribution rights set forth in this Section 2, but before taking into account any liabilities under any other Guarantees.

(c)    Each Guarantor agrees that the Guaranteed Obligations may at any time and from time to time exceed the amount of the liability of such Guarantor hereunder (as a result of the limitations set forth in Section 2(b) or elsewhere in this Agreement) without impairing this Agreement or affecting the rights and remedies of any Guaranteed Party hereunder.

(d)    No payment or payments made by any Issuer, any of the Guarantors, any other guarantor or any other Person or received or collected by any Guaranteed Party from any Issuer, any of the Guarantors, any other guarantor or any other Person by virtue of any action or proceeding or any set-off or appropriation or application at any time or from time to time in reduction of or in payment of any Guaranteed Obligation shall be deemed to modify, reduce, release or otherwise affect the liability of any Guarantor hereunder, which shall, notwithstanding any such payment or payments, other than payments made by such Guarantor in respect of such Guaranteed Obligation or payments received or collected from such Guarantor in respect of such Guaranteed Obligation, remain liable for the Guaranteed Obligations up to the maximum liability of such Guarantor hereunder until all Guaranteed Obligations (other than any contingent indemnity obligations not then due and any letters of credit that remain outstanding which have been fully cash collateralized or otherwise back-stopped to the reasonable satisfaction of the applicable issuing bank) shall have been discharged by payment in full or shall have been deemed paid and discharged by defeasance pursuant to the terms of the instruments governing such Guaranteed Obligations (the “Guarantee Termination Date”).

(e)    If and to the extent required in order for the obligations of any Guarantor hereunder to be enforceable under applicable federal, state and other laws relating to the insolvency of debtors, the maximum liability of such Guarantor hereunder shall be limited to the greatest amount which can lawfully be guaranteed by such Guarantor under such laws, after giving effect to any rights of

6

Exhibit 10.1

contribution, reimbursement and subrogation arising hereunder. Each Guarantor acknowledges and agrees that, to the extent not prohibited by applicable law, (i) such Guarantor (as opposed to its creditors, representatives of creditors or bankruptcy trustee, including such Guarantor in its capacity as debtor in possession exercising any powers of a bankruptcy trustee) has no personal right under such laws to reduce, or request any judicial relief that has the effect of reducing, the amount of its liability under this Agreement, (ii) such Guarantor (as opposed to its creditors, representatives of creditors or bankruptcy trustee, including such Guarantor in its capacity as debtor in possession exercising any powers of a bankruptcy trustee) has no personal right to enforce the limitation set forth in this Section 2(e) or to reduce, or request judicial relief reducing, the amount of its liability under this Agreement, and (iii) the limitation set forth in this Section 2(e) may be enforced only to the extent required under such laws in order for the obligations of such Guarantor under this Agreement to be enforceable under such laws and only by or for the benefit of a creditor, representative of creditors or bankruptcy trustee of such Guarantor or other Person entitled, under such laws, to enforce the provisions hereof.

3.Right of Contribution. Each Guarantor hereby agrees that to the extent that a Guarantor shall have paid more than its proportionate share of any payment made hereunder (including by way of set-off rights being exercised against it), such Guarantor shall be entitled to seek and receive contribution from and against any other Guarantor hereunder who has not paid its proportionate share of such payment as set forth in this Section 3. To the extent that any Guarantor shall be required hereunder to pay any portion of any Guaranteed Obligation guaranteed hereunder exceeding the greater of (a) the amount of the value actually received by such Guarantor and its Subsidiaries from such Guaranteed Obligation and (b) the amount such Guarantor would otherwise have paid if such Guarantor had paid the aggregate amount of such Guaranteed Obligation guaranteed hereunder (excluding the amount thereof repaid by the Issuer of such Guaranteed Obligation) in the same proportion as such Guarantor’s net worth on the date enforcement is sought hereunder bears to the aggregate net worth of all the Guarantors on such date, then such Guarantor shall be reimbursed by such other Guarantors for the amount of such excess, pro rata, based on the respective net worth of such other Guarantors on such date; provided that any Guarantor’s right of reimbursement shall be subject to the terms and conditions of Section 5 hereof. For purposes of determining the net worth of any Guarantor in connection with the foregoing, all Guarantees of such Guarantor other than pursuant to this Agreement will be deemed to be enforceable and payable after its obligations pursuant to this Agreement. The provisions of this Section 3 shall in no respect limit the obligations and liabilities of any Guarantor to the Guaranteed Parties, and each Guarantor shall remain liable to the Guaranteed Parties for the full amount guaranteed by such Guarantor hereunder.

4.No Right of Set-off. No Guaranteed Party shall have, as a result of this Agreement, any right of set-off against any amount owing by such Guaranteed Party to or for the credit or the account of a Guarantor.

5.No Subrogation. Notwithstanding any payment or payments made by any of the Guarantors hereunder, no Guarantor shall be entitled to be subrogated to any of the rights (or if subrogated by operation of law, such Guarantor hereby waives such rights to the extent permitted by applicable law) of any Guaranteed Party against any Issuer or any other Guarantor or any collateral security or guarantee or right of offset held by any Guaranteed Party for the payment of any Guaranteed Obligation, nor shall any Guarantor seek or be entitled to seek any contribution or reimbursement from any Issuer or any other Guarantor in respect of payments made by such Guarantor hereunder, until the Guarantee Termination Date. If any amount shall be paid to any Guarantor on account of such subrogation, contribution or reimbursement rights at any time prior to the Guarantee Termination Date, such amount shall be held by such Guarantor in trust for the applicable Guaranteed Parties, segregated from other funds of such Guarantor, and shall, forthwith upon receipt by such Guarantor, be turned over to the applicable Guaranteed Parties in the exact form received by such Guarantor (duly indorsed by such

7

Exhibit 10.1

Guarantor to the applicable Guaranteed Parties if required), to be applied against the applicable Guaranteed Obligation, whether due or to become due.

6.Amendments, etc. with Respect to the Guaranteed Obligations; Waiver of Rights; Release.

(a)Each Guarantor shall remain obligated hereunder notwithstanding that, without any reservation of rights against any Guarantor and without notice to or further assent by any Guarantor, (i) any demand for payment of any Guaranteed Obligation made by any Guaranteed Party may be rescinded by such party and any Guaranteed Obligation continued, (ii) a Guaranteed Obligation, or the liability of any other party upon or for any part thereof, or any collateral security or guarantee therefor or right of offset with respect thereto, may, from time to time, in whole or in part, be renewed, extended, amended, modified, accelerated, compromised, waived, allowed to lapse, surrendered or released by any Guaranteed Party, (iii) the instruments governing any Guaranteed Obligation may be amended, modified, supplemented or terminated, in whole or in part, and (iv) any collateral security, guarantee or right of offset at any time held by any Guaranteed Party for the payment of any Guaranteed Obligation may be sold, exchanged, waived, allowed to lapse, surrendered or released. No Guaranteed Party shall have any obligation to protect, secure, perfect or insure any Lien at any time held by it as security for the Guaranteed Obligations or for this Agreement or any property subject thereto. When making any demand hereunder against any Guarantor, a Guaranteed Party may, but shall be under no obligation to, make a similar demand on the Issuer of the applicable Guaranteed Obligation or any other Guarantor or any other person, and any failure by a Guaranteed Party to make any such demand or to collect any payments from such Issuer or any other Guarantor or any other person or any release of such Issuer or any other Guarantor or any other person shall not relieve any Guarantor in respect of which a demand or collection is not made or any Guarantor not so released of its several obligations or liabilities hereunder, and shall not impair or affect the rights and remedies, express or implied, or as a matter of law, of any Guaranteed Party against any Guarantor. For the purposes hereof “demand” shall include the commencement and continuance of any legal proceedings.

(b)A Guarantor shall be automatically released from its guarantee hereunder upon release of such Guarantor from the Revolving Credit Agreement Guarantee, including upon consummation of any transaction resulting in such Guarantor ceasing to constitute a Subsidiary or upon any Guarantor becoming an Excluded Subsidiary (such transaction or event, a “Release Event”).

(c)Upon the occurrence of a Release Event, each Guaranteed Obligation for which such released Guarantor was the Issuer shall be automatically released from the provisions of this Agreement and shall cease to constitute a Guaranteed Obligation hereunder; provided that in the case of any Guaranteed Obligation that has been assigned an Investment Grade Rating by the Rating Agencies, such Guaranteed Obligation shall be so released, effective as of the 91st day after the occurrence of the Release Event, if and only if a Rating Decline with respect to such Guaranteed Obligation does not occur.

7.Guarantee Absolute and Unconditional.

(a)Each Guarantor waives any and all notice of the creation, contraction, incurrence, renewal, extension, amendment, waiver or accrual of any of the Guaranteed Obligations, and notice of or proof of reliance by any Guaranteed Party upon this Agreement or acceptance of this Agreement. To the fullest extent permitted by applicable law, each Guarantor waives diligence, promptness, presentment, protest and notice of protest, demand for payment or performance, notice of default or nonpayment, notice of acceptance and any other notice in respect of the Guaranteed Obligations or any part of them, and any defense arising by reason of any disability or other defense of any Issuer or any of the Guarantors with respect to the Guaranteed Obligations. Each Guarantor understands and agrees that this Agreement

8

Exhibit 10.1

shall be construed as a continuing, absolute and unconditional guarantee of payment without regard to (i) the validity, regularity or enforceability of any of the Guaranteed Obligations, the indenture, loan agreement, note or other instrument evidencing or governing any of the Guaranteed Obligations or any collateral security therefor or guarantee or right of offset with respect thereto at any time or from time to time held by any Guaranteed Party, (ii) any defense, set-off or counterclaim (other than a defense of payment or performance) that may at any time be available to or be asserted by any Issuer against any Guaranteed Party or (iii) any other circumstance whatsoever (with or without notice to or knowledge of any Issuer or such Guarantor) that constitutes, or might be construed to constitute, an equitable or legal discharge of any Issuer for any of the Guaranteed Obligations, or of such Guarantor under this Agreement, in bankruptcy or in any other instance. When pursuing its rights and remedies hereunder against any Guarantor, any Guaranteed Party may, but shall be under no obligation to, pursue such rights and remedies as it may have against the Issuer or any other Person or against any collateral security or guarantee for the Guaranteed Obligations or any right of offset with respect thereto, and any failure by any Guaranteed Party to pursue such other rights or remedies or to collect any payments from the Issuer or any such other Person or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of the Issuer or any such other Person or any such collateral security, guarantee or right of offset, shall not relieve such Guarantor of any liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of the other Guaranteed Parties against such Guarantor.

(b)This Agreement shall remain in full force and effect and be binding in accordance with and to the extent of its terms upon each Guarantor and the successors and assigns thereof and shall inure to the benefit of the Guaranteed Parties and their respective successors, indorsees, transferees and assigns until the Guarantee Termination Date.

8.Reinstatement. This Agreement shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Guaranteed Obligations is rescinded or must otherwise be restored or returned by any Guaranteed Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of any Issuer or any Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, any Issuer or any Guarantor or any substantial part of its property, or otherwise, all as though such payments had not been made.

9.Payments. Each Guarantor hereby guarantees that payments hereunder will be paid to the applicable Guaranteed Parties without set-off or counterclaim in dollars.

10.Representations and Warranties. Each Guarantor hereby represents and warrants to each Guaranteed Party that the following representations and warranties are true and correct in all material respects as of the date of this Agreement or as of the date such Guarantor became a party to this Agreement, as applicable:

(a)such Guarantor (i) is a corporation, partnership or limited liability company duly organized or formed, validly existing and in good standing under the laws of the state of its incorporation, organization or formation, (ii) has all requisite corporate, partnership, limited liability company or other power and all material governmental licenses, authorizations, consents and approvals required to carry on its business as now conducted and (iii) is duly qualified to do business and is in good standing in every jurisdiction in which the failure to be so qualified would have a material adverse effect on its ability to perform its obligations under this Agreement;

9

Exhibit 10.1

(b)such Guarantor has all requisite corporate (or other organizational) power and authority to execute and deliver and to perform its obligations under this Agreement, and all such actions have been duly authorized by all necessary proceedings on its behalf;

(c)this Agreement has been duly and validly executed and delivered by or on behalf of such Guarantor and constitutes the valid and legally binding agreement of such Guarantor, enforceable against such Guarantor in accordance with its terms, except (i) as may be limited by bankruptcy, insolvency, reorganization, moratorium, fraudulent transfer, fraudulent conveyance or other similar laws relating to or affecting the enforcement of creditors’ rights generally, and by general principles of equity (including principles of good faith, reasonableness, materiality and fair dealing) which may, among other things, limit the right to obtain equitable remedies (regardless of whether considered in a proceeding in equity or at law) and (ii) as to the enforceability of provisions for indemnification for violation of applicable securities laws, limitations thereon arising as a matter of law or public policy;

(d)no authorization, consent, approval, license or exemption of or registration, declaration or filing with any Governmental Authority is necessary for the valid execution and delivery of, or the performance by such Guarantor of its obligations hereunder, except those that have been obtained and such matters relating to performance as would ordinarily be done in the ordinary course of business after the date of this Agreement or as of the date such Guarantor became a party to this Agreement, as applicable; and

(e)neither the execution and delivery of, nor the performance by such Guarantor of its obligations under, this Agreement will (i) breach or violate any applicable Requirement of Law, (ii) result in any breach or violation of any of the terms, covenants, conditions or provisions of, or constitute a default under, or result in the creation or imposition of (or the obligation to create or impose) any Lien upon any of its property or assets (other than Liens created or contemplated by this Agreement) pursuant to the terms of, any indenture, mortgage, deed of trust, agreement or other instrument to which it or any of its Subsidiaries is party or by which any of its properties or assets, or those of any of its Subsidiaries is bound or to which it is subject, except for breaches, violations and defaults under clauses (i) and (ii) that neither individually nor in the aggregate could reasonably be expected to result in a material adverse effect on its ability to perform its obligations under this Agreement, or (iii) violate any provision of the organizational documents of such Guarantor.

11.Rights of Guaranteed Parties. Each Guarantor acknowledges and agrees that any changes in the identity of the Persons from time to time comprising the Guaranteed Parties gives rise to an equivalent change in the Guaranteed Parties, without any further act. Upon such an occurrence, the persons then comprising the Guaranteed Parties are vested with the rights, remedies and discretions of the Guaranteed Parties under this Agreement.

12.Notices.

(a)All notices, requests, demands and other communications to any Guarantor pursuant hereto shall be in writing and mailed, telecopied or delivered to such Guarantor in care of KMI, 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, Attention: Treasurer, Telecopy: (713) 445-8302.

(b)KMI will provide a copy of this Agreement, including the most recently amended schedules and supplements hereto, to any Guaranteed Party upon written request to the address set forth in Section 12(a); provided, however, that KMI’s obligations under this Section 12(b) shall be deemed satisfied if KMI has filed a copy of this Agreement, including the most recently amended schedules and

10

Exhibit 10.1

supplements hereto, with the SEC within three months preceding the date on which KMI receives such written request.

13.Counterparts. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts (including by facsimile or other electronic transmission), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Agreement signed by all the parties shall be lodged with KMI.

14.Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. The parties hereto shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.

15.Integration. This Agreement represents the agreement of each Guarantor with respect to the subject matter hereof, and there are no promises, undertakings, representations or warranties by any Guaranteed Party relative to the subject matter hereof not expressly set forth or referred to herein.

16.Amendments; No Waiver; Cumulative Remedies.

(a)None of the terms or provisions of this Agreement may be waived, amended, supplemented or otherwise modified except by a written instrument executed by the affected Guarantors and KMI.

(b)The Guarantors may amend or supplement this Agreement by a written instrument executed by all Guarantors:

(i) to cure any ambiguity, defect or inconsistency;

(ii) to reflect a change in the Guarantors or the Guaranteed Obligations made in accordance with this Agreement;

(iii) to make any change that would provide any additional rights or benefits to the Guaranteed Parties or that would not adversely affect the legal rights hereunder of any Guaranteed Party in any material respect; or

(iv) to conform this Agreement to any change made to the Revolving Credit Agreement or to the Revolving Credit Agreement Guarantee.

Except as set forth in this clause (b) or otherwise provided herein, the Guarantors may not amend, supplement or otherwise modify this Agreement prior to the Guarantee Termination Date without the prior written consent of the holders of the majority of the outstanding principal amount of the Guaranteed Obligations (excluding obligations with respect to Hedging Agreements). Notwithstanding the foregoing, in the case of an amendment that would reasonably be expected to adversely, materially and disproportionately affect Guaranteed Parties with Guaranteed Obligations existing under Hedging Agreements relative to the other Guaranteed Parties, the foregoing exclusion of obligations with respect to Hedging Agreements shall not apply, and the outstanding principal amount attributable to each such Guaranteed Party’s Guaranteed Obligations shall be deemed to be equal to the termination payment that

11

Exhibit 10.1

would be due to such Guaranteed Party as if the valuation date were an “Early Termination Date” under and calculated in accordance with each applicable Hedging Agreement.

(c)No Guaranteed Party shall by any act, delay, indulgence, omission or otherwise be deemed to have waived any right or remedy hereunder or to have acquiesced in any breach of any of the terms and conditions hereof. No failure to exercise, nor any delay in exercising, on the part of any Guaranteed Party, any right, power or privilege hereunder shall operate as a waiver thereof. No single or partial exercise of any right, power or privilege hereunder shall preclude any other or further exercise thereof or the exercise of any other right, power or privilege. A waiver by a Guaranteed Party of any right or remedy hereunder on any one occasion shall not be construed as a bar to any right or remedy that such Guaranteed Party would otherwise have on any future occasion.

(d)The rights, remedies, powers and privileges herein provided are cumulative, may be exercised singly or concurrently and are not exclusive of any other rights or remedies provided by law.

17.Section Headings. The Section headings used in this Agreement are for convenience of reference only and are not to affect the construction hereof or be taken into consideration in the interpretation hereof.

18.Successors and Assigns. This Agreement shall be binding upon the successors and assigns of each Guarantor and shall inure to the benefit of the Guaranteed Parties and their respective successors and permitted assigns, except that no Guarantor may assign, transfer or delegate any of its rights or obligations under this Agreement except pursuant to a transaction permitted by the Revolving Credit Agreement and in connection with a corresponding assignment under the Revolving Credit Agreement Guarantee.

19.Additional Guarantors.

(a)KMI shall cause each Subsidiary (other than any Excluded Subsidiary) formed or otherwise purchased or acquired after the date of this Agreement (including each Subsidiary that ceases to constitute an Excluded Subsidiary after the date of this Agreement) to execute a supplement to this Agreement and become a Guarantor within 45 days of the occurrence of the applicable event specified in this Section 19(a).

(b)Each Subsidiary of KMI that becomes, at the request of KMI, or that is required pursuant to Section 19(a) to become, a party to this Agreement shall become a Guarantor, with the same force and effect as if originally named as a Guarantor herein, for all purposes of this Agreement upon execution and delivery by such Subsidiary of a written supplement substantially in the form of Annex A hereto. The execution and delivery of any instrument adding an additional Guarantor as a party to this Agreement shall not require the consent of any other Guarantor hereunder. The rights and obligations of each Guarantor hereunder shall remain in full force and effect notwithstanding the addition of any new Guarantor as a party to this Agreement.

20.Additional Guaranteed Obligations. Any Indebtedness issued by a Guarantor or for which a Guarantor otherwise becomes obligated after the date of this Agreement shall become a Guaranteed Obligation upon the execution by all Guarantors of a notation of guarantee substantially in the form of Annex B hereto, which shall be affixed to the instrument or instruments evidencing such Indebtedness. Each such notation of guarantee shall be signed on behalf of each Guarantor by a duly authorized officer prior to the authentication or issuance of such Indebtedness.

12

Exhibit 10.1

21.GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

22.Keepwell. Each Qualified ECP Guarantor hereby jointly and severally absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each other Guarantor to honor all of its obligations under this Agreement in respect of Swap Obligations (provided, however, that each Qualified ECP Guarantor shall only be liable under this Section 22 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 22, or otherwise under this Agreement, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount). The obligations of each Qualified ECP Guarantor under this Section shall remain in full force and effect until the Guarantee Termination Date. Each Qualified ECP Guarantor intends that this Section 22 constitute, and this Section 22 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Guarantor for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

[Signature pages follow]

13

Exhibit 10.1

IN WITNESS WHEREOF, each of the undersigned has caused this Agreement to be duly executed and delivered by its duly authorized officer or other representative as of the day and year first above written.

GUARANTORS

KINDER MORGAN, INC.

By:        /s/ Anthony B. Ashley                

Name: Anthony B. Ashley

Title: Treasurer

AGNES B CRANE, LLC

AMERICAN PETROLEUM TANKERS II LLC

AMERICAN PETROLEUM TANKERS III LLC

AMERICAN PETROLEUM TANKERS IV LLC

AMERICAN PETROLEUM TANKERS LLC

AMERICAN PETROLEUM TANKERS PARENT LLC

AMERICAN PETROLEUM TANKERS V LLC

AMERICAN PETROLEUM TANKERS VI LLC

AMERICAN PETROLEUM TANKERS VII LLC

APT FLORIDA LLC

APT INTERMEDIATE HOLDCO LLC

APT NEW INTERMEDIATE HOLDCO LLC

APT PENNSYLVANIA LLC

APT SUNSHINE STATE LLC

AUDREY TUG LLC

BEAR CREEK STORAGE COMPANY, L.L.C.

BETTY LOU LLC

CAMINO REAL GATHERING COMPANY, L.L.C.

CANTERA GAS COMPANY LLC

CDE PIPELINE LLC

CENTRAL FLORIDA PIPELINE LLC

CHEYENNE PLAINS GAS PIPELINE COMPANY, L.L.C.

CIG GAS STORAGE COMPANY LLC

CIG PIPELINE SERVICES COMPANY, L.L.C.

CIMMARRON GATHERING LLC

COLORADO INTERSTATE GAS COMPANY, L.L.C.

COLORADO INTERSTATE ISSUING CORPORATION

COPANO DOUBLE EAGLE LLC

COPANO ENERGY FINANCE CORPORATION

COPANO ENERGY, L.L.C.

COPANO ENERGY SERVICES/UPPER GULF COAST LLC

COPANO FIELD SERVICES GP, L.L.C.

COPANO FIELD SERVICES/NORTH TEXAS, L.L.C.

COPANO FIELD SERVICES/SOUTH TEXAS LLC

COPANO FIELD SERVICES/UPPER GULF COAST LLC

COPANO LIBERTY, LLC

COPANO NGL SERVICES (MARKHAM), L.L.C.

COPANO NGL SERVICES LLC

COPANO PIPELINES GROUP, L.L.C.

[Signature Page to Cross Guarantee]

Exhibit 10.1

COPANO PIPELINES/NORTH TEXAS, L.L.C.

COPANO PIPELINES/ROCKY MOUNTAINS, LLC

COPANO PIPELINES/SOUTH TEXAS LLC

COPANO PIPELINES/UPPER GULF COAST LLC

COPANO PROCESSING LLC

COPANO RISK MANAGEMENT LLC

COPANO/WEBB-DUVAL PIPELINE LLC

CPNO SERVICES LLC

DAKOTA BULK TERMINAL, INC.

DELTA TERMINAL SERVICES LLC

EAGLE FORD GATHERING LLC

EL PASO CHEYENNE HOLDINGS, L.L.C.

EL PASO CITRUS HOLDINGS, INC.

EL PASO CNG COMPANY, L.L.C.

EL PASO ENERGY SERVICE COMPANY, L.L.C.

EL PASO LLC

EL PASO MIDSTREAM GROUP LLC

EL PASO NATURAL GAS COMPANY, L.L.C.

EL PASO NORIC INVESTMENTS III, L.L.C.

EL PASO PIPELINE CORPORATION

EL PASO PIPELINE GP COMPANY, L.L.C.

EL PASO PIPELINE HOLDING COMPANY, L.L.C.

EL PASO PIPELINE LP HOLDINGS, L.L.C.

EL PASO PIPELINE PARTNERS, L.P.

By El Paso Pipeline GP Company, L.L.C., its general partner

EL PASO PIPELINE PARTNERS OPERATING COMPANY, L.L.C.

EL PASO RUBY HOLDING COMPANY, L.L.C.

EL PASO TENNESSEE PIPELINE CO., L.L.C.

ELBA EXPRESS COMPANY, L.L.C.

ELIZABETH RIVER TERMINALS LLC

EMORY B CRANE, LLC

EPBGP CONTRACTING SERVICES LLC

EP ENERGY HOLDING COMPANY

EP RUBY LLC

EPTP ISSUING CORPORATION

FERNANDINA MARINE CONSTRUCTION MANAGEMENT LLC

FRANK L. CRANE, LLC

GENERAL STEVEDORES GP, LLC

GENERAL STEVEDORES HOLDINGS LLC

GLOBAL AMERICAN TERMINALS LLC

HAMPSHIRE LLC

HARRAH MIDSTREAM LLC

HBM ENVIRONMENTAL, INC.

ICPT, L.L.C

J.R. NICHOLLS LLC

JAVELINA TUG LLC

JEANNIE BREWER LLC

JV TANKER CHARTERER LLC

KINDER MORGAN (DELAWARE), INC.

KINDER MORGAN 2-MILE LLC

KINDER MORGAN ADMINISTRATIVE SERVICES TAMPA LLC

KINDER MORGAN ALTAMONT LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

KINDER MORGAN AMORY LLC

KINDER MORGAN ARROW TERMINALS HOLDINGS, INC.

KINDER MORGAN ARROW TERMINALS, L.P.

By Kinder Morgan River Terminals, LLC, its general partner

KINDER MORGAN BALTIMORE TRANSLOAD TERMINAL LLC

KINDER MORGAN BATTLEGROUND OIL LLC

KINDER MORGAN BORDER PIPELINE LLC

KINDER MORGAN BULK TERMINALS, INC.

KINDER MORGAN CARBON DIOXIDE TRANSPORTATION

COMPANY

KINDER MORGAN CO2 COMPANY, L.P.

By Kinder Morgan G.P., Inc., its general partner

KINDER MORGAN COCHIN LLC

KINDER MORGAN COLUMBUS LLC

KINDER MORGAN COMMERCIAL SERVICES LLC

KINDER MORGAN CRUDE & CONDENSATE LLC

KINDER MORGAN CRUDE OIL PIPELINES LLC

KINDER MORGAN CRUDE TO RAIL LLC

KINDER MORGAN CUSHING LLC

KINDER MORGAN DALLAS FORT WORTH RAIL TERMINAL LLC

KINDER MORGAN ENDEAVOR LLC

KINDER MORGAN ENERGY PARTNERS, L.P.

By Kinder Morgan G.P., Inc., its general partner

KINDER MORGAN EP MIDSTREAM LLC

KINDER MORGAN FINANCE COMPANY LLC

KINDER MORGAN FLEETING LLC

KINDER MORGAN FREEDOM PIPELINE LLC

KINDER MORGAN KEYSTONE GAS STORAGE LLC

KINDER MORGAN KMAP LLC

KINDER MORGAN LAS VEGAS LLC

KINDER MORGAN LINDEN TRANSLOAD TERMINAL LLC

KINDER MORGAN LIQUIDS TERMINALS LLC

KINDER MORGAN LIQUIDS TERMINALS ST. GABRIEL LLC

KINDER MORGAN MARINE SERVICES LLC

KINDER MORGAN MATERIALS SERVICES, LLC

KINDER MORGAN MID ATLANTIC MARINE SERVICES LLC

KINDER MORGAN NATGAS O&M LLC

KINDER MORGAN NORTH TEXAS PIPELINE LLC

KINDER MORGAN OPERATING L.P. “A”

By Kinder Morgan G.P., Inc., its general partner

KINDER MORGAN OPERATING L.P. “B”

By Kinder Morgan G.P., Inc., its general partner

KINDER MORGAN OPERATING L.P. “C”

By Kinder Morgan G.P., Inc., its general partner

KINDER MORGAN OPERATING L.P. “D”

By Kinder Morgan G.P., Inc., its general partner

KINDER MORGAN PECOS LLC

KINDER MORGAN PECOS VALLEY LLC

KINDER MORGAN PETCOKE GP LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

KINDER MORGAN PETCOKE, L.P.

By Kinder Morgan Petcoke GP LLC, its general partner

KINDER MORGAN PETCOKE LP LLC

KINDER MORGAN PETROLEUM TANKERS LLC

KINDER MORGAN PIPELINE LLC

KINDER MORGAN PIPELINES (USA) INC.

KINDER MORGAN PORT MANATEE TERMINAL LLC

KINDER MORGAN PORT SUTTON TERMINAL LLC

KINDER MORGAN PORT TERMINALS USA LLC

KINDER MORGAN PRODUCTION COMPANY LLC

KINDER MORGAN RAIL SERVICES LLC

KINDER MORGAN RESOURCES II LLC

KINDER MORGAN RESOURCES III LLC

KINDER MORGAN RESOURCES LLC

KINDER MORGAN RIVER TERMINALS LLC

KINDER MORGAN SERVICES LLC

KINDER MORGAN SEVEN OAKS LLC

KINDER MORGAN SOUTHEAST TERMINALS LLC

KINDER MORGAN TANK STORAGE TERMINALS LLC

KINDER MORGAN TEJAS PIPELINE LLC

KINDER MORGAN TERMINALS, INC.

KINDER MORGAN TEXAS PIPELINE LLC

KINDER MORGAN TEXAS TERMINALS, L.P.

By General Stevedores GP, LLC, its general partner

KINDER MORGAN TRANSMIX COMPANY, LLC

KINDER MORGAN TREATING LP

By KM Treating GP LLC, its general partner

KINDER MORGAN URBAN RENEWAL, L.L.C.

KINDER MORGAN UTICA LLC

KINDER MORGAN VIRGINIA LIQUIDS TERMINALS LLC

KINDER MORGAN WINK PIPELINE LLC

KINDERHAWK FIELD SERVICES LLC

KM CRANE LLC

KM DECATUR, INC.

KM EAGLE GATHERING LLC

KM GATHERING LLC

KM KASKASKIA DOCK LLC

KM LIQUIDS TERMINALS LLC

KM NORTH CAHOKIA LAND LLC

KM NORTH CAHOKIA SPECIAL PROJECT LLC

KM NORTH CAHOKIA TERMINAL PROJECT LLC

KM SHIP CHANNEL SERVICES LLC

KM TREATING GP LLC

KM TREATING PRODUCTION LLC

KMBT LLC

KMGP CONTRACTING SERVICES LLC

KMGP SERVICES COMPANY, INC.

KN TELECOMMUNICATIONS, INC.

KNIGHT POWER COMPANY LLC

LOMITA RAIL TERMINAL LLC

MILWAUKEE BULK TERMINALS LLC

MJR OPERATING LLC

MOJAVE PIPELINE COMPANY, L.L.C.

MOJAVE PIPELINE OPERATING COMPANY, L.L.C.

MR. BENNETT LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

MR. VANCE LLC

NASSAU TERMINALS LLC

NGPL HOLDCO INC.

NS 307 HOLDINGS INC.

PADDY RYAN CRANE, LLC

PALMETTO PRODUCTS PIPE LINE LLC

PI 2 PELICAN STATE LLC

PINNEY DOCK & TRANSPORT LLC

QUEEN CITY TERMINALS LLC

RAHWAY RIVER LAND LLC

RAZORBACK TUG LLC

RCI HOLDINGS, INC.

RIVER TERMINALS PROPERTIES GP LLC

RIVER TERMINAL PROPERTIES, L.P.

By River Terminals Properties GP LLC, its general partner

SCISSORTAIL ENERGY, LLC

SNG PIPELINE SERVICES COMPANY, L.L.C.

SOUTHERN GULF LNG COMPANY, L.L.C.

SOUTHERN LIQUEFACTION COMPANY LLC

SOUTHERN LNG COMPANY, L.L.C.

SOUTHERN NATURAL GAS COMPANY, L.L.C.

SOUTHERN NATURAL ISSUING CORPORATION

SOUTHTEX TREATERS LLC

SOUTHWEST FLORIDA PIPELINE LLC

SRT VESSELS LLC

STEVEDORE HOLDINGS, L.P.

By Kinder Morgan Petcoke GP LLC, its general partner

TAJON HOLDINGS, INC.

TEJAS GAS, LLC

TEJAS NATURAL GAS, LLC

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

TENNESSEE GAS PIPELINE ISSUING CORPORATION

TEXAN TUG LLC

TGP PIPELINE SERVICES COMPANY, L.L.C.

TRANS MOUNTAIN PIPELINE (PUGET SOUND) LLC

TRANSCOLORADO GAS TRANSMISSION COMPANY LLC

TRANSLOAD SERVICES, LLC

UTICA MARCELLUS TEXAS PIPELINE LLC

WESTERN PLANT SERVICES, INC.

WYOMING INTERSTATE COMPANY, L.L.C.

By:     /s/ Anthony B. Ashley                

Anthony Ashley

Vice President

[Signature Page to Cross Guarantee]

Exhibit 10.1

ANNEX A TO

THE CROSS GUARANTEE AGREEMENT

SUPPLEMENT NO. [ ] dated as of [                    ] to the CROSS GUARANTEE AGREEMENT dated as of [                    ] (the “Agreement”), among each of the Guarantors listed on the signature pages thereto and each of the other entities that becomes a party thereto pursuant to Section 19 of the Agreement (each such entity individually, a “Guarantor” and, collectively, the “Guarantors”). Unless otherwise defined herein, terms defined in the Agreement and used herein shall have the meanings given to them in the Agreement.

A.    The Guarantors consist of Kinder Morgan, Inc., a Delaware corporation (“KMI”), and certain of its direct and indirect Subsidiaries, and the Guarantors have entered into the Agreement in order to provide guarantees of certain of the Guarantors’ senior, unsecured Indebtedness outstanding from time to time.

B.    Section 19 of the Agreement provides that additional Subsidiaries may become Guarantors under the Agreement by execution and delivery of an instrument in the form of this Supplement. Each undersigned Subsidiary (each a “New Guarantor”) is executing this Supplement at the request of KMI or in accordance with the requirements of the Agreement to become a Guarantor under the Agreement.

Accordingly, each New Guarantor agrees as follows:

SECTION 1.    In accordance with Section 19 of the Agreement, each New Guarantor by its signature below becomes a Guarantor under the Agreement with the same force and effect as if originally named therein as a Guarantor and each New Guarantor hereby (a) agrees to all the terms and provisions of the Agreement applicable to it as a Guarantor thereunder and (b) represents and warrants that the representations and warranties made by it as a Guarantor thereunder are true and correct on and as of the date hereof. Each reference to a Guarantor in the Agreement shall be deemed to include each New Guarantor. The Agreement is hereby incorporated herein by reference.

SECTION 2.     Each New Guarantor represents and warrants to the Guaranteed Parties that this Supplement has been duly authorized, executed and delivered by it and constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms.

SECTION 3.    This Supplement may be executed by one or more of the parties to this Supplement on any number of separate counterparts (including by facsimile or other electronic transmission), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Supplement signed by all the parties shall be lodged with KMI. This Supplement shall become effective as to each New Guarantor when KMI shall have received a counterpart of this Supplement that bears the signature of such New Guarantor.

SECTION 4.    Except as expressly supplemented hereby, the Agreement shall remain in full force and effect.

SECTION 5.    THIS SUPPLEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

SECTION 6.    Any provision of this Supplement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or

Exhibit 10.1

unenforceability without invalidating the remaining provisions hereof and in the Agreement, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. The parties hereto shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.

SECTION 7.    All notices, requests and demands pursuant hereto shall be made in accordance with Section 12 of the Agreement. All communications and notices hereunder to each New Guarantor shall be given to it in care of KMI at the address set forth in Section 12 of the Agreement.

[Signature Pages Follow]

Exhibit 10.1

IN WITNESS WHEREOF, each New Guarantor has duly executed this Supplement to the Agreement as of the day and year first above written.

_________________________________

as Guarantor

By:______________________________

Name:

Title:

Exhibit 10.1

ANNEX B TO

THE CROSS GUARANTEE AGREEMENT

FORM OF NOTATION OF GUARANTEE

Subject to the limitations set forth in the Cross Guarantee Agreement, dated as of [•] (the “Guarantee Agreement”), the undersigned Guarantors hereby certify that this [Indebtedness] constitutes a Guaranteed Obligation, entitled to all the rights as such set forth in the Guarantee Agreement. The Guarantors may be released from their guarantees upon the terms and subject to the conditions provided in the Guarantee Agreement. Capitalized terms used but not defined in this notation of guarantee have the meanings assigned such terms in the Guarantee Agreement, a copy of which will be provided to [a holder of this instrument] upon request to [Issuer].

Schedule I of the Guarantee Agreement is hereby deemed to be automatically updated to include this [Indebtedness] thereon as a Guaranteed Obligation.

[GUARANTORS],

as Guarantor

By: ______________________________

Name:

Title:

Exhibit 10.1

SCHEDULE I

Guaranteed Obligations

Current as of: June 30, 2022

Issuer	Indebtedness	Maturity
Kinder Morgan, Inc.	3.150% bonds	January 15, 2023
Kinder Morgan, Inc.	Floating rate bonds	January 15, 2023
Kinder Morgan, Inc.	5.625% notes	November 15, 2023
Kinder Morgan, Inc.	4.30% notes	June 1, 2025
Kinder Morgan, Inc.	1.75% notes	November 15, 2026
Kinder Morgan, Inc.	6.70% bonds (Coastal)	February 15, 2027
Kinder Morgan, Inc.	2.250% notes	March 16, 2027
Kinder Morgan, Inc.	6.67% debentures	November 1, 2027
Kinder Morgan, Inc.	7.25% debentures	March 1, 2028
Kinder Morgan, Inc.	4.30% notes	March 1, 2028
Kinder Morgan, Inc.	6.95% bonds (Coastal)	June 1, 2028
Kinder Morgan, Inc.	8.05% bonds	October 15, 2030
Kinder Morgan, Inc.	2.00% notes	February 15, 2031
Kinder Morgan, Inc.	7.80% bonds	August 1, 2031
Kinder Morgan, Inc.	7.75% bonds	January 15, 2032
Kinder Morgan, Inc.	5.30% notes	December 1, 2034
Kinder Morgan, Inc.	7.75% bonds (Coastal)	October 15, 2035
Kinder Morgan, Inc.	6.40% notes	January 5, 2036
Kinder Morgan, Inc.	7.42% bonds (Coastal)	February 15, 2037
Kinder Morgan, Inc.	5.55% notes	June 1, 2045
Kinder Morgan, Inc.	5.050% notes	February 15, 2046
Kinder Morgan, Inc.	5.20% notes	March 1, 2048
Kinder Morgan, Inc.	3.25% notes	August 1, 2050
Kinder Morgan, Inc.	3.60% notes	February 15, 2051
Kinder Morgan, Inc.	7.45% debentures	March 1, 2098
Kinder Morgan, Inc.	$100 Million Letter of Credit Facility	November 30, 2022
Kinder Morgan Energy Partners, L.P.	3.45% bonds	February 15, 2023
Kinder Morgan Energy Partners, L.P.	3.50% bonds	September 1, 2023
Kinder Morgan Energy Partners, L.P.	4.15% bonds	February 1, 2024
Kinder Morgan Energy Partners, L.P.	4.25% bonds	September 1, 2024
Kinder Morgan Energy Partners, L.P.	7.40% bonds	March 15, 2031
Kinder Morgan Energy Partners, L.P.	7.75% bonds	March 15, 2032
Kinder Morgan Energy Partners, L.P.	7.30% bonds	August 15, 2033
Kinder Morgan Energy Partners, L.P.	5.80% bonds	March 15, 2035
Kinder Morgan Energy Partners, L.P.	6.50% bonds	February 1, 2037
Kinder Morgan Energy Partners, L.P.	6.95% bonds	January 15, 2038
Kinder Morgan Energy Partners, L.P.	6.50% bonds	September 1, 2039

Exhibit 10.1

	Schedule I
	(Guaranteed Obligations)
	Current as of: June 30, 2022
Issuer	Indebtedness	Maturity
Kinder Morgan Energy Partners, L.P.	6.55% bonds	September 15, 2040
Kinder Morgan Energy Partners, L.P.	6.375% bonds	March 1, 2041
Kinder Morgan Energy Partners, L.P.	5.625% bonds	September 1, 2041
Kinder Morgan Energy Partners, L.P.	5.00% bonds	August 15, 2042
Kinder Morgan Energy Partners, L.P.	5.00% bonds	March 1, 2043
Kinder Morgan Energy Partners, L.P.	5.50% bonds	March 1, 2044
Kinder Morgan Energy Partners, L.P.	5.40% bonds	September 1, 2044
Kinder Morgan Energy Partners, L.P.(1)	4.30% bonds	May 1, 2024
Kinder Morgan Energy Partners, L.P.(1)	7.50% bonds	November 15, 2040
Kinder Morgan Energy Partners, L.P.(1)	4.70% bonds	November 1, 2042
Tennessee Gas Pipeline Company, L.L.C.	7.00% bonds	March 15, 2027
Tennessee Gas Pipeline Company, L.L.C.	7.00% bonds	October 15, 2028
Tennessee Gas Pipeline Company, L.L.C.	2.90% bonds	March 1, 2030
Tennessee Gas Pipeline Company, L.L.C.	8.375% bonds	June 15, 2032
Tennessee Gas Pipeline Company, L.L.C.	7.625% bonds	April 1, 2037
El Paso Natural Gas Company, L.L.C.	7.50% bonds	November 15, 2026
El Paso Natural Gas Company, L.L.C.	3.50% bonds	February 15, 2032
El Paso Natural Gas Company, L.L.C.	8.375% bonds	June 15, 2032
Colorado Interstate Gas Company, L.L.C.	4.15% notes	August 15, 2026
Colorado Interstate Gas Company, L.L.C.	6.85% bonds	June 15, 2037
El Paso Tennessee Pipeline Co. L.L.C.	7.25% bonds	December 15, 2025
Other	Cora industrial revenue bonds	April 1, 2024
_________________________________________________ (1) The original issuer, El Paso Pipeline Partners, L.P. merged with and into Kinder Morgan Energy      Partners, L.P. effective January 1, 2015.

2

Exhibit 10.1

Schedule I

(Guaranteed Obligations)

Current as of: June 30, 2022

Hedging Agreements1
Issuer	Guaranteed Party	Date
Kinder Morgan, Inc.	Bank of America, N.A.	January 4, 2018
Kinder Morgan, Inc.	BNP Paribas	September 15, 2016
Kinder Morgan, Inc.	Citibank, N.A.	March 16, 2017
Kinder Morgan, Inc.	J. Aron & Company	December 23, 2011
Kinder Morgan, Inc.	SunTrust Bank	August 29, 2001
Kinder Morgan, Inc.	Barclays Bank PLC	November 26, 2014
Kinder Morgan, Inc.	Bank of Montreal	April 25, 2019
Kinder Morgan, Inc.	Bank of Tokyo-Mitsubishi, Ltd., New York Branch	November 26, 2014
Kinder Morgan, Inc.	Canadian Imperial Bank of Commerce	November 26, 2014
Kinder Morgan, Inc.	Commerzbank AG	August 22, 2019
Kinder Morgan, Inc.	Compass Bank	March 24, 2015
Kinder Morgan, Inc.	Credit Agricole Corporate and Investment Bank	November 26, 2014
Kinder Morgan, Inc.	Credit Suisse International	November 26, 2014
Kinder Morgan, Inc.	Deutsche Bank AG	November 26, 2014
Kinder Morgan, Inc.	ING Capital Markets LLC	November 26, 2014
Kinder Morgan, Inc.	Intesa Sanpaolo S.p.A.	July 1, 2019
Kinder Morgan, Inc.	JPMorgan Chase Bank, N.A.	February 19, 2015
Kinder Morgan, Inc.	Mizuho Capital Markets Corporation	November 26, 2014
Kinder Morgan, Inc.	Morgan Stanley Capital Services LLC	July 9, 2018
Kinder Morgan, Inc.	PNC Bank National Association	February 4, 2019
Kinder Morgan, Inc.	Royal Bank of Canada	November 26, 2014
Kinder Morgan, Inc.	SMBC Capital Markets, Inc.	April 26, 2017
Kinder Morgan, Inc.	The Bank of Nova Scotia	November 26, 2014
Kinder Morgan, Inc.	The Royal Bank of Scotland PLC	November 26, 2014
Kinder Morgan, Inc.	Societe Generale	November 26, 2014
Kinder Morgan, Inc.	The Toronto-Dominion Bank	October 2, 2017
Kinder Morgan, Inc.	UBS AG	November 26, 2014
Kinder Morgan, Inc.	Wells Fargo Bank, N.A.	November 26, 2014
Kinder Morgan Energy Partners, L.P.	Bank of America, N.A.	April 14, 1999
Kinder Morgan Energy Partners, L.P.	Bank of Tokyo-Mitsubishi, Ltd., New York Branch	November 23, 2004
Kinder Morgan Energy Partners, L.P.	Barclays Bank PLC	November 18, 2003
Kinder Morgan Energy Partners, L.P.	Canadian Imperial Bank of Commerce	August 4, 2011
Kinder Morgan Energy Partners, L.P.	Citibank, N.A.	March 14, 2002
Kinder Morgan Energy Partners, L.P.	Credit Agricole Corporate and Investment Bank	June 20, 2014
Kinder Morgan Energy Partners, L.P.	Credit Suisse International	May 14, 2010
_________________________________________________ 1 Guaranteed Obligations with respect to Hedging Agreements include International Swaps and Derivatives Association Master Agreements (“ISDAs”) and all transactions entered into pursuant to any ISDA listed on this Schedule I.

3

Exhibit 10.1

	Schedule I
	(Guaranteed Obligations)
	Current as of: June 30, 2022
Hedging Agreements1
Issuer	Guaranteed Party	Date
Kinder Morgan Energy Partners, L.P.	Deutsche Bank AG	April 2, 2009
Kinder Morgan Energy Partners, L.P.	ING Capital Markets LLC	September 21, 2011
Kinder Morgan Energy Partners, L.P.	J. Aron & Company	November 11, 2004
Kinder Morgan Energy Partners, L.P.	JPMorgan Chase Bank	August 29, 2001
Kinder Morgan Energy Partners, L.P.	Merrill Lynch Capital Services, Inc.	March 8, 2005
Kinder Morgan Energy Partners, L.P.	Mizuho Capital Markets Corporation	July 11, 2014
Kinder Morgan Energy Partners, L.P.	Morgan Stanley Capital Services Inc.	March 10, 2010
Kinder Morgan Energy Partners, L.P.	Royal Bank of Canada	March 12, 2009
Kinder Morgan Energy Partners, L.P.	The Royal Bank of Scotland PLC	March 20, 2009
Kinder Morgan Energy Partners, L.P.	The Bank of Nova Scotia	August 14, 2003
Kinder Morgan Energy Partners, L.P.	Societe Generale	July 18, 2014
Kinder Morgan Energy Partners, L.P.	SunTrust Bank	March 14, 2002
Kinder Morgan Energy Partners, L.P.	UBS AG	February 23, 2011
Kinder Morgan Energy Partners, L.P.	Wells Fargo Bank, N.A.	July 31, 2007
Kinder Morgan Texas Pipeline LLC	Bank of Montreal	April 25, 2019
Kinder Morgan Texas Pipeline LLC	Barclays Bank PLC	January 10, 2003
Kinder Morgan Texas Pipeline LLC	BNP Paribas	March 2, 2005
Kinder Morgan Texas Pipeline LLC	Canadian Imperial Bank of Commerce	December 18, 2006
Kinder Morgan Texas Pipeline LLC	Citibank, N.A.	February 22, 2005
Kinder Morgan Texas Pipeline LLC	Credit Suisse International	August 31, 2012
Kinder Morgan Texas Pipeline LLC	Deutsche Bank AG	June 13, 2007
Kinder Morgan Texas Pipeline LLC	ING Capital Markets LLC	April 17, 2014
Kinder Morgan Texas Pipeline LLC	Intesa Sanpaolo S.p.a	October 29, 2020
Kinder Morgan Production LLC	J. Aron & Company	June 12, 2006
Kinder Morgan Texas Pipeline LLC	J. Aron & Company	June 8, 2000
Kinder Morgan Texas Pipeline LLC	JPMorgan Chase Bank, N.A.	September 7, 2006
Kinder Morgan Texas Pipeline LLC	Macquarie Bank Limited	September 20, 2010
Kinder Morgan Texas Pipeline LLC	Merrill Lynch Commodities, Inc.	October 24, 2001
Kinder Morgan Texas Pipeline LLC	Natixis	June 13, 2011
Kinder Morgan Texas Pipeline LLC	Phillips 66 Company	March 30, 2015
Kinder Morgan Texas Pipeline LLC	PNC Bank, National Association	July 11, 2018
Kinder Morgan Texas Pipeline LLC	Royal Bank of Canada	October 18, 2018
Kinder Morgan Texas Pipeline LLC	The Bank of Nova Scotia	May 8, 2014
Kinder Morgan Texas Pipeline LLC	The Toronto Dominion Bank	September 14, 2021
Kinder Morgan Texas Pipeline LLC	Societe Generale	January 14, 2003
Kinder Morgan Texas Pipeline LLC	Wells Fargo Bank, N.A.	June 1, 2013
Copano Risk Management, LLC	Citibank, N.A.	July 21, 2008
Copano Risk Management, LLC	J. Aron & Company	December 12, 2005
Copano Risk Management, LLC	Morgan Stanley Capital Group Inc.	May 4, 2007
_________________________________________________ 1 Guaranteed Obligations with respect to Hedging Agreements include International Swaps and Derivatives Association Master Agreements (“ISDAs”) and all transactions entered into pursuant to any ISDA listed on this Schedule I.

4

Exhibit 10.1

SCHEDULE II Guarantors Current as of: June 30, 2022
Agnes B Crane, LLC	Copano Processing LLC
American Petroleum Tankers II LLC	Copano Risk Management LLC
American Petroleum Tankers III LLC	Copano Terminals LLC
American Petroleum Tankers IV LLC	Copano/Webb-Duval Pipeline LLC
American Petroleum Tankers LLC	CPNO Services LLC
American Petroleum Tankers Parent LLC	Dakota Bulk Terminal LLC
American Petroleum Tankers V LLC	Delta Terminal Services LLC
American Petroleum Tankers VI LLC	Eagle Ford Gathering LLC
American Petroleum Tankers VII LLC	El Paso Cheyenne Holdings, L.L.C.
American Petroleum Tankers VIII LLC	El Paso Citrus Holdings, Inc.
American Petroleum Tankers IX LLC	El Paso CNG Company, L.L.C.
American Petroleum Tankers X LLC	El Paso Energy Service Company, L.L.C.
American Petroleum Tankers XI LLC	El Paso LLC
APT Florida LLC	El Paso Midstream Group LLC
APT Intermediate Holdco LLC	El Paso Natural Gas Company, L.L.C.
APT New Intermediate Holdco LLC	El Paso Noric Investments III, L.L.C.
APT Pennsylvania LLC	El Paso Ruby Holding Company, L.L.C.
APT Sunshine State LLC	El Paso Tennessee Pipeline Co., L.L.C.
Arlington Storage Company, LLC	Elba Express Company, L.L.C.
Betty Lou LLC	Elizabeth River Terminals LLC
Camino Real Gas Gathering Company LLC	Emory B Crane, LLC
Camino Real Gathering Company, L.L.C.	EP Ruby LLC
Cantera Gas Company LLC	EPBGP Contracting Services LLC
CDE Pipeline LLC	EPTP Issuing Corporation
Central Florida Pipeline LLC	Frank L. Crane, LLC
Cheyenne Plains Gas Pipeline Company, L.L.C.	General Stevedores GP, LLC
CIG Gas Storage Company LLC	General Stevedores Holdings LLC
CIG Pipeline Services Company, L.L.C.	Harrah Midstream LLC
Colorado Interstate Gas Company, L.L.C.	HBM Environmental LLC
Colorado Interstate Issuing Corporation	Hiland Crude, LLC
Copano Double Eagle LLC	Hiland Partners Holdings LLC
Copano Energy Finance Corporation	HPH Oklahoma Gathering LLC
Copano Energy Services/Upper Gulf Coast LLC	ICPT, L.L.C
Copano Energy, L.L.C.	Independent Trading & Transportation
Copano Field Services GP, L.L.C.	Company I, L.L.C.
Copano Field Services/North Texas, L.L.C.	JV Tanker Charterer LLC
Copano Field Services/South Texas LLC	Kinder Morgan 2-Mile LLC
Copano Field Services/Upper Gulf Coast LLC	Kinder Morgan Administrative Services Tampa LLC
Copano Liberty, LLC	Kinder Morgan Altamont LLC
Copano Liquids Marketing LLC	Kinder Morgan Baltimore Transload Terminal LLC
Copano NGL Services (Markham), L.L.C.	Kinder Morgan Battleground Oil LLC
Copano NGL Services LLC	Kinder Morgan Border Pipeline LLC
Copano Pipelines Group, L.L.C.	Kinder Morgan Bulk Terminals LLC
Copano Pipelines/North Texas, L.L.C.	Kinder Morgan Carbon Dioxide Transportation
Copano Pipelines/Rocky Mountains, LLC	Company
Copano Pipelines/South Texas LLC	Kinder Morgan CO2 Company LLC
Copano Pipelines/Upper Gulf Coast LLC	Kinder Morgan Commercial Services LLC

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: June30, 2022
Kinder Morgan Contracting Services LLC	Kinder Morgan Portland Jet Line LLC
Kinder Morgan Crude & Condensate LLC	Kinder Morgan Portland Liquids Terminals LLC
Kinder Morgan Crude Marketing LLC	Kinder Morgan Portland Operating LLC
Kinder Morgan Crude Oil Pipelines LLC	Kinder Morgan Production Company LLC
Kinder Morgan Crude to Rail LLC	Kinder Morgan Products Terminals LLC
Kinder Morgan Cushing LLC	Kinder Morgan Rail Services LLC
Kinder Morgan Dallas Fort Worth Rail Terminal LLC	Kinder Morgan Resources II LLC
Kinder Morgan Deeprock North Holdco LLC	Kinder Morgan Resources III LLC
Kinder Morgan Endeavor LLC	Kinder Morgan RNG Holdco LLC
Kinder Morgan Energy Partners, L.P.	Kinder Morgan Scurry Connector LLC
Kinder Morgan Energy Transition Ventures LLC	Kinder Morgan Seven Oaks LLC
Kinder Morgan EP Midstream LLC	Kinder Morgan SNG Operator LLC
Kinder Morgan Finance Company LLC	Kinder Morgan Southeast Terminals LLC
Kinder Morgan Freedom Pipeline LLC	Kinder Morgan Tank Storage Terminals LLC
Kinder Morgan Galena Park West LLC	Kinder Morgan Tejas Pipeline LLC
Kinder Morgan GP LLC	Kinder Morgan Terminals, Inc.
Kinder Morgan IMT Holdco LLC	Kinder Morgan Terminals Wilmington LLC
Kinder Morgan, Inc.	Kinder Morgan Texas Pipeline LLC
Kinder Morgan Keystone Gas Storage LLC	Kinder Morgan Texas Terminals, L.P.
Kinder Morgan KMAP LLC	Kinder Morgan Transmix Company, LLC
Kinder Morgan Las Vegas LLC	Kinder Morgan Treating LP
Kinder Morgan Linden Transload Terminal LLC	Kinder Morgan Utica LLC
Kinder Morgan Liquids Terminals LLC	Kinder Morgan Vehicle Services LLC
Kinder Morgan Liquids Terminals St. Gabriel LLC	Kinder Morgan Virginia Liquids Terminals LLC
Kinder Morgan Louisiana Pipeline Holding LLC	Kinder Morgan Wink Pipeline LLC
Kinder Morgan Louisiana Pipeline LLC	KinderHawk Field Services LLC
Kinder Morgan Marine Services LLC	Kinetrex Energy Transportation, LLC
Kinder Morgan Materials Services, LLC	Kinetrex Holdco, Inc.
Kinder Morgan Mid Atlantic Marine Services LLC	KM Crane LLC
Kinder Morgan NatGas O&M LLC	KM Decatur LLC
Kinder Morgan NGPL Holdings LLC	KM Eagle Gathering LLC
Kinder Morgan North Texas Pipeline LLC	KM Gathering LLC
Kinder Morgan Operating LLC “A”	KM Kaskaskia Dock LLC
Kinder Morgan Operating LLC “B”	KM Liquids Terminals LLC
Kinder Morgan Operating LLC “C”	KM North Cahokia Land LLC
Kinder Morgan Operating LLC “D”	KM North Cahokia Special Project LLC
Kinder Morgan Pecos LLC	KM North Cahokia Terminal Project LLC
Kinder Morgan Pecos Valley LLC	KM Ship Channel Services LLC
Kinder Morgan Petcoke GP LLC	KM Treating GP LLC
Kinder Morgan Petcoke LP LLC	KM Treating Production LLC
Kinder Morgan Petcoke, L.P.	KM Utopia Operator LLC
Kinder Morgan Petroleum Tankers LLC	KMBT Legacy Holdings LLC
Kinder Morgan Pipeline LLC	KMBT LLC
Kinder Morgan Port Manatee Terminal LLC	KMGP Services Company, Inc.
Kinder Morgan Port Sutton Terminal LLC	KN Telecommunications, Inc.
Kinder Morgan Port Terminals USA LLC	Knight Power Company LLC
Kinder Morgan Portland Bulk LLC	Liberty High BTU LLC
Kinder Morgan Portland Holdings LLC	LNG Indy, LLC
Kinder Morgan Portland Intermediate Holdings I LLC	Lomita Rail Terminal LLC
Kinder Morgan Portland Intermediate Holdings II LLC	Milwaukee Bulk Terminals LLC

2

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: June30, 2022
MJR Operating LLC
Mojave Pipeline Company, L.L.C.
Mojave Pipeline Operating Company, L.L.C.
Paddy Ryan Crane, LLC
Palmetto Products Pipe Line LLC
PI 2 Pelican State LLC
Pinney Dock & Transport LLC
Prairie View High BTU LLC
Queen City Terminals LLC
Rahway River Land LLC
River Terminals Properties GP LLC
River Terminal Properties, L.P.
RNG Indy LLC
ScissorTail Energy, LLC
SNG Pipeline Services Company, L.L.C.
Southern Dome, LLC
Southern Gulf LNG Company, L.L.C.
Southern Liquefaction Company LLC
Southern LNG Company, L.L.C.
Southern Oklahoma Gathering LLC
SouthTex Treaters LLC
Southwest Florida Pipeline LLC
SRT Vessels LLC
Stagecoach Energy Solutions LLC
Stagecoach Gas Services LLC
Stagecoach Operating Services LLC
Stagecoach Pipeline & Storage Company LLC
Stevedore Holdings, L.P.
Tejas Gas, LLC
Tejas Natural Gas, LLC
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Issuing Corporation
Texan Tug LLC
TGP Pipeline Services Company, L.L.C.
TransColorado Gas Transmission Company LLC
Transload Services, LLC
Twin Bridges High BTU LLC
Twin Tier Pipeline LLC
Utica Marcellus Texas Pipeline LLC
Western Plant Services LLC
Wyoming Interstate Company, L.L.C.

3

Exhibit 10.1

SCHEDULE III
Excluded Subsidiaries

ANR Real Estate Corporation

Coastal Eagle Point Oil Company

Coastal Oil New England, Inc.

Colton Processing Facility

Coscol Petroleum Corporation

El Paso CGP Company, L.L.C.

El Paso Energy Capital Trust I

El Paso Energy E.S.T. Company

El Paso Energy International Company

El Paso Marketing Company, L.L.C.

El Paso Merchant Energy North America Company, L.L.C.

El Paso Merchant Energy-Petroleum Company

El Paso Reata Energy Company, L.L.C.

El Paso Remediation Company

El Paso Services Holding Company

EPEC Corporation

EPEC Oil Company Liquidating Trust

EPEC Polymers, Inc.

EPED Holding Company

KN Capital Trust I

KN Capital Trust III

Mesquite Investors, L.L.C.

Note: The Excluded Subsidiaries listed on this Schedule III may also be Excluded Subsidiaries pursuant to other exceptions set forth in the definition of “Excluded Subsidiary”.

EX-22.1

Exhibit 22.1

List of Guarantor Subsidiaries

The Cross Guarantee Agreement furnished as Exhibit 10.1 to this Quarterly Report on Form 10-Q sets forth, as of June 30, 2022, the registrant’s guarantor subsidiaries on Schedule II thereto and the guaranteed securities on Schedule I thereto.

EX-31.1

Exhibit 31.1

KINDER MORGAN, INC. AND SUBSIDIARIES

CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934,

AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Steven J. Kean, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Kinder Morgan, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States;

(c)evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 22, 2022	/s/ Steven J. Kean
		Steven J. Kean
		Chief Executive Officer

EX-31.2

Exhibit 31.2

KINDER MORGAN, INC. AND SUBSIDIARIES

CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934,

AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David P. Michels, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Kinder Morgan, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States;

(c)evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 22, 2022	/s/ David P. Michels
		David P. Michels
		Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

KINDER MORGAN, INC. AND SUBSIDIARIES

Exhibit 32.1 - CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Kinder Morgan, Inc. (the “Company”) for the quarterly period ended June 30, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to Kinder Morgan, Inc. and will be retained by Kinder Morgan, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Date:	July 22, 2022	/s/ Steven J. Kean
		Steven J. Kean
		Chief Executive Officer

EX-32.2

Exhibit 32.2

KINDER MORGAN, INC. AND SUBSIDIARIES

Exhibit 32.2 - CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Kinder Morgan, Inc. (the “Company”) for the quarterly period ended June 30, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to Kinder Morgan, Inc. and will be retained by Kinder Morgan, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Date:	July 22, 2022	/s/ David P. Michels
		David P. Michels
		Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2022	Jul. 21, 2022
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
Document Transition Report	false
Entity File Number	001-35081
Entity Registrant Name	KINDER MORGAN, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	80-0682103
Entity Address, Address Line One	1001 Louisiana Street
Entity Address, Address Line Two	Suite 1000
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	369-9000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		2,253,000,833
Entity Central Index Key	0001506307
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q2
Amendment Flag	false
Class P Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class P Common Stock
Trading Symbol	KMI
Security Exchange Name	NYSE
2.250% Senior Notes due 2027
Entity Information [Line Items]
Title of 12(b) Security	2.250% Senior Notes due 2027
Trading Symbol	KMI 27 A
Security Exchange Name	NYSE

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Revenues
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 Earnings (Loss) Per Share	$ 0.28	$ (0.34)	$ 0.57	$ 0.29
Diluted Earnings (Loss) Per Share	$ 0.28	$ (0.34)	$ 0.57	$ 0.29
Basic Weighted Average Shares Outstanding	2,265	2,265	2,266	2,264
Diluted Weighted Average Shares Outstanding	2,265	2,265	2,266	2,264
Services
Revenues
Revenues	$ 2,011	$ 1,889	$ 4,061	$ 3,806
Commodity sales
Revenues
Revenues	3,100	1,246	5,308	4,475
Other
Revenues
Revenues	$ 40	$ 15	$ 75	$ 80

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Statement of Comprehensive Income [Abstract]
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

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Statement of Comprehensive Income [Abstract]
Change in fair value of hedge derivatives, tax	$ 24	$ 47	$ 149	$ 94
Reclassification of change in fair value of derivatives to net income, tax	(48)	(9)	(89)	(27)
Benefit plan adjustments, tax	$ (1)	$ (1)	$ (5)	$ (5)

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
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	0	115
Deferred charges and other assets	1,311	1,649
Total Assets	69,390	70,416
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 debt
Outstanding	28,140	29,772
Debt fair value adjustments	412	902
Total long-term debt	28,552	30,674
Deferred income taxes	196	0
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

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Jun. 30, 2022	Dec. 31, 2021
Stockholders’ Equity
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	4,000,000,000	4,000,000,000
Common stock, shares issued (in shares)	2,257,464,962	2,267,391,527
Common stock, shares outstanding (in shares)	2,257,464,962	2,267,391,527

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 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)	0	(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)	0
Contributions from noncontrolling interests	0	3
Distributions to investment partner	0	(45)
Distributions to noncontrolling interests	(53)	(8)
Other, net	0	(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 and Cash Equivalents, beginning of period	1,140	1,184
Restricted Deposits, beginning of period	7	25
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
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments	(8)
ROU assets and operating lease obligations recognized including adjustments		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

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Impact of adoption of ASU 2020-06 (Note 4)	Adjusted balance	Common stock	Common stock Adjusted balance	Additional paid-in capital	Additional paid-in capital Impact of adoption of ASU 2020-06 (Note 4)	Additional paid-in capital Adjusted balance	Accumulated deficit	Accumulated deficit Adjusted balance	Accumulated other comprehensive loss	Accumulated other comprehensive loss Adjusted balance	Stockholders’ equity attributable to KMI	Stockholders’ equity attributable to KMI Impact of adoption of ASU 2020-06 (Note 4)	Stockholders’ equity attributable to KMI Adjusted balance	Non-controlling interests	Non-controlling interests Adjusted balance
Balance at Dec. 31, 2020	$ 31,838			$ 23		$ 41,756			$ (9,936)		$ (407)		$ 31,436			$ 402
Balance (shares) at Dec. 31, 2020				2,264
Restricted shares	37					37							37
Restricted shares (shares)				1
Net income (loss)	685								652				652			33
Distributions	(8)												0			(8)
Contributions	3												0			3
Dividends	(1,212)								(1,212)				(1,212)
Other	(1)												0			(1)
Other comprehensive income (loss)	(202)										(202)		(202)
Balance at Jun. 30, 2021	31,140			$ 23		41,793			(10,496)		(609)		30,711			429
Balance (shares) at Jun. 30, 2021				2,265
Balance at Dec. 31, 2020	$ 31,838			$ 23		41,756			(9,936)		(407)		31,436			402
Balance (shares) at Dec. 31, 2020				2,264
Accounting Standards Update	Accounting Standards Update 2020-06
Balance at Dec. 31, 2021	$ 31,921	$ (11)	$ 31,910	$ 23	$ 23	41,806	$ (11)	$ 41,795	(10,595)	$ (10,595)	(411)	$ (411)	30,823	$ (11)	$ 30,812	1,098	$ 1,098
Balance (shares) at Dec. 31, 2021				2,267	2,267
Balance at Mar. 31, 2021	32,603			$ 23		41,775			(9,124)		(487)		32,187			416
Balance (shares) at Mar. 31, 2021				2,264
Restricted shares	18					18							18
Restricted shares (shares)				1
Net income (loss)	(740)								(757)				(757)			17
Distributions	(5)												0			(5)
Contributions	1												0			1
Dividends	(615)								(615)				(615)
Other comprehensive income (loss)	(122)										(122)		(122)
Balance at Jun. 30, 2021	31,140			$ 23		41,793			(10,496)		(609)		30,711			429
Balance (shares) at Jun. 30, 2021				2,265
Balance at Dec. 31, 2021	31,921	$ (11)	$ 31,910	$ 23	$ 23	41,806	$ (11)	$ 41,795	(10,595)	$ (10,595)	(411)	$ (411)	30,823	$ (11)	$ 30,812	1,098	$ 1,098
Balance (shares) at Dec. 31, 2021				2,267	2,267
Repurchases of shares	(173)					(173)							(173)
Repurchases of shares (shares)				(10)
EP Trust I Preferred security conversions	1					1							1
Restricted shares	31					31							31
Net income (loss)	1,337								1,302				1,302			35
Distributions	(53)												0			(53)
Dividends	(1,247)								(1,247)				(1,247)
Other comprehensive income (loss)	(181)										(181)		(181)
Balance at Jun. 30, 2022	31,625			$ 23		41,654			(10,540)		(592)		30,545			1,080
Balance (shares) at Jun. 30, 2022				2,257
Balance at Mar. 31, 2022	31,707			$ 23		41,813			(10,544)		(674)		30,618			1,089
Balance (shares) at Mar. 31, 2022				2,267
Repurchases of shares	(172)					(172)							(172)
Repurchases of shares (shares)				(10)
Restricted shares	13					13							13
Net income (loss)	653								635				635			18
Distributions	(27)												0			(27)
Dividends	(631)								(631)				(631)
Other comprehensive income (loss)	82										82		82
Balance at Jun. 30, 2022	$ 31,625			$ 23		$ 41,654			$ (10,540)		$ (592)		$ 30,545			$ 1,080
Balance (shares) at Jun. 30, 2022				2,257

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General (Notes)

6 Months Ended

Jun. 30, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General

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

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Losses and Gains on Impairments, Divestitures and Other Write-downs (Notes)

6 Months Ended

Jun. 30, 2022

Investments [Abstract]

Impairments, Divestitures And Other Write-downs

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.

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Debt (Notes)

6 Months Ended

Jun. 30, 2022

Debt Disclosure [Abstract]

Debt

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.

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Stockholders' Equity (Notes)

6 Months Ended

Jun. 30, 2022

Stockholders' Equity Note [Abstract]

Stockholders' Equity

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)

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Risk Management (Notes)

6 Months Ended

Jun. 30, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management

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.

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Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 2022

Revenue from Contract with Customer [Abstract]

Revenue Recognition

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.

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Reportable Segments (Notes)

6 Months Ended

Jun. 30, 2022

Segment Reporting [Abstract]

Reportable Segments

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.

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Income Taxes (Notes)

6 Months Ended

Jun. 30, 2022

Income Tax Disclosure [Abstract]

Income Taxes

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.

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Litigation and Environmental (Notes)

6 Months Ended

Jun. 30, 2022

Commitments and Contingencies Disclosure [Abstract]

Litigation and Environmental

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.

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Recent Accounting Pronouncements (Notes)

6 Months Ended

Jun. 30, 2022

Accounting Standards Update and Change in Accounting Principle [Abstract]

Recent Accounting Pronouncements

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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General (Policies)

6 Months Ended

Jun. 30, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

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.

Goodwill

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

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.

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General (Tables)

6 Months Ended

Jun. 30, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Net Income for Shareholders and Participating Securities

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.

Schedule of Antidilutive Securities

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

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Debt (Tables)

6 Months Ended

Jun. 30, 2022

Debt Disclosure [Abstract]

Schedule of 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.

Schedule of Carrying Values and Estimated Fair Values of Debt 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.

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Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2022

Stockholders' Equity Note [Abstract]

Schedule of 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

Schedule of Accumulated Other Comprehensive Income

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)

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Risk Management (Tables)

6 Months Ended

Jun. 30, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions

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

Schedule of Interest Rate Derivatives

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.

Schedule of Foreign Exchange Contracts, Statement of Financial Position

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

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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)

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

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.

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

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.

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Revenue Recognition (Tables)

6 Months Ended

Jun. 30, 2022

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

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

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Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2022

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

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.

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2022

Income Tax Disclosure [Abstract]

Schedule of 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		%

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General - Organization and Basis of Presentation (Details) mi in Thousands, $ in Millions	Jul. 19, 2022 USD ($) assets	May 31, 2022 segment	Jun. 30, 2022 Bcf Terminals mi
General [Line Items]
Miles of pipeline | mi			83
Working capacity | Bcf			700
Number of reporting units | segment		7
Number of pipeline terminals owned interest in and/or operated | Terminals			141
Mas CanAm, LLC | Subsequent Event
General [Line Items]
Payments to acquire businesses | $	$ 358
Number of landfill assets | assets	3

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General - Schedule of Net Income Available to Shareholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Stockholders	$ 635	$ (757)	$ 1,302	$ 652
Less: Net Income Allocated to Restricted Stock Awards(a)	$ (2)	$ (3)	$ (6)	$ (6)
Basic Weighted Average Common Shares Outstanding	2,265	2,265	2,266	2,264
Basic Earnings (Loss) Per Share	$ 0.28	$ (0.34)	$ 0.57	$ 0.29
Class P Common Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Stockholders	$ 633	$ (760)	$ 1,296	$ 646
Unvested restricted stock awards | Class P Common Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Restricted stock awards outstanding	12		12

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General - Schedule of Antidilutive Securities (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Unvested restricted stock awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	12	12	13	12
Convertible trust preferred securities
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	3	3	3	3

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Losses and Gains on Impairments, Divestitures and Other Write-downs - Long-lived asset impairment (Details) $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($)
Natural Gas Pipelines
Finite-Lived Intangible Assets [Line Items]
Impairments of long-lived and intangible assets	$ 1,600

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Losses and Gains on Impairments, Divestitures and Other Write-downs - Investment in Ruby (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Jun. 30, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Current portion of debt		$ 2,970	$ 2,646
Ruby Pipeline Holding Company LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments		0	$ 0
Ruby Pipeline Holding Company LLC | Notes Receivable
Schedule of Equity Method Investments [Line Items]
Write-down of note receivable from Ruby	$ 117
Ruby Pipeline Holding Company LLC | Ruby Unsecured Notes Due April 1, 2022
Schedule of Equity Method Investments [Line Items]
Current portion of debt		$ 475

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Losses and Gains on Impairments, Divestitures and Other Write-downs - Sale of an interest in NGPL Holdings (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments	$ 4	$ 413
Gain on sale of interests in NGPL Holdings LLC	$ 0	206
NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments		413
Gain on sale of interests in NGPL Holdings LLC		$ 206
ArcLight Capital Partners, LLC | NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Percentage			25.00%
Brookfield | NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Percentage	37.50%
KMI | NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Percentage	37.50%

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Debt - Schedule of Debt Outstanding (Details) $ in Millions			6 Months Ended
	Feb. 23, 2022 USD ($)	Dec. 31, 2021 USD ($) $ / €	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)
Debt Instrument [Line Items]
Current portion of debt		$ 2,646	$ 2,970
Long-term debt		29,772	28,140
Total debt(f)		32,418	31,110
Debt fair value adjustments		$ 902	412
Proceeds from issuances of debt			4,622	$ 3,110
Foreign Currency Exchange Rate, Translation | $ / €		1.1370
Commercial paper notes(a)
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 936
Short-term Debt, Weighted Average Interest Rate on borrowings outstanding			1.90%
Current portion of other debt
Debt Instrument [Line Items]
Current portion of debt		47	$ 48
Trust I preferred securities, 4.75%, due March 2028 | Capital Trust I
Debt Instrument [Line Items]
Current portion of debt		111	111
Long-term debt		110	$ 109
Interest rate			4.75%
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035 | EPC Building LLC
Debt Instrument [Line Items]
Long-term debt		348	$ 339
Interest rate			3.967%
Other
Debt Instrument [Line Items]
Long-term debt		217	$ 215
$3.5 billion credit facility due August 20, 2026
Debt Instrument [Line Items]
Current portion of debt		0	0
Line of Credit Facility, Current Borrowing Capacity			3,500
$500 million credit facility due November 16, 2023
Debt Instrument [Line Items]
Current portion of debt		0	0
Line of Credit Facility, Current Borrowing Capacity			500
Senior notes
Debt Instrument [Line Items]
Long-term debt		29,097	27,477
Senior notes | 8.625%, due January 2022(b) | EPNG
Debt Instrument [Line Items]
Current portion of debt		$ 260	0
Interest rate		8.625%
Senior notes | 4.15%, due March 2022(b)
Debt Instrument [Line Items]
Current portion of debt		$ 375	0
Interest rate		4.15%
Senior notes | 1.50%, due March 2022(b)(c)
Debt Instrument [Line Items]
Current portion of debt		$ 853	0
Interest rate		1.50%
Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax		$ 38
Senior notes | 3.95% due September 2022(d)
Debt Instrument [Line Items]
Current portion of debt		1,000	$ 0
Interest rate			3.95%
Senior notes | 3.15% due January 2023
Debt Instrument [Line Items]
Current portion of debt		0	$ 1,000
Interest rate			3.15%
Senior notes | Floating rate, due January 2023(e)
Debt Instrument [Line Items]
Current portion of debt		0	$ 250
Senior notes | 3.45% due February 2023
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 625
Interest rate			3.45%
Senior notes | 3.50% , Due February 15, 2032 | EPNG
Debt Instrument [Line Items]
Long-term debt	$ 300
Interest rate	3.50%
Proceeds from issuances of debt	$ 298

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Debt - Credit Facility (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Line of Credit Facility [Line Items]
Line of credit facility	$ 2,970	$ 2,646
$3.5 billion credit facility due August 20, 2026
Line of Credit Facility [Line Items]
Line of credit facility	0	0
Line of Credit Facility, Current Borrowing Capacity	3,500
$500 million credit facility due November 16, 2023
Line of Credit Facility [Line Items]
Line of credit facility	0	0
Line of Credit Facility, Current Borrowing Capacity	500
Commercial paper program
Line of Credit Facility [Line Items]
Line of credit facility	936	$ 0
Credit Facilities
Line of Credit Facility [Line Items]
Line of credit facility	0
Letters of Credit Outstanding, Amount	81
Line of Credit Facility, Current Borrowing Capacity	$ 3,000

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Debt - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 31,522	$ 33,320
Estimated fair value(a)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	30,376	37,775
Estimated fair value(a) | Capital Trust I | Trust I preferred securities, 4.75%, due March 2028
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible debt	$ 203	$ 218

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Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		1 Months Ended	3 Months Ended		6 Months Ended		56 Months Ended
	Jul. 20, 2022	Jul. 21, 2022	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Jul. 21, 2022	Jul. 19, 2017
Class of Stock [Line Items]
Common share buy-back program, amount								$ 2,000
Common share buy-back program, average price per share					$ 17.37
Value of shares repurchased			$ 172		$ 173
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
Subsequent Event
Class of Stock [Line Items]
Common share buy-back program, average price per share		$ 16.63					$ 17.50
Value of shares repurchased		$ 102					$ 850
Per share cash dividend declared for the period	$ 0.2775
Common stock
Class of Stock [Line Items]
Shares repurchased			10		10
Common stock | Subsequent Event
Class of Stock [Line Items]
Shares repurchased		6					49

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Stockholders' Equity - Adoption of Accounting Pronouncement (Details) - USD ($) $ in Millions	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity	$ 31,625	$ 31,707	$ 31,921	$ 31,140	$ 32,603	$ 31,838
Additional paid-in capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity	$ 41,654	$ 41,813	41,806	$ 41,793	$ 41,775	$ 41,756
Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity			(11)
Cumulative Effect, Period of Adoption, Adjustment | Accounting Standards Update 2020-06
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized debt discount			14
Cumulative Effect, Period of Adoption, Adjustment | Additional paid-in capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity			(11)
Cumulative Effect, Period of Adoption, Adjustment | Additional paid-in capital | Accounting Standards Update 2020-06
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity			$ (11)

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Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Accumulated Other Comprehensive Loss [Line Items]
Balance	$ 31,921	$ 31,838
Balance	31,625	31,140
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Loss [Line Items]
Balance	(172)	(13)
Other comprehensive (loss) gain before reclassifications	(489)	(313)
Loss reclassified from accumulated other comprehensive loss	292	89
Net current-period change in accumulated other comprehensive (loss) income	(197)	(224)
Balance	(369)	(237)
Pension and other postretirement liability adjustments
Accumulated Other Comprehensive Loss [Line Items]
Balance	(239)	(394)
Other comprehensive (loss) gain before reclassifications	16	22
Loss reclassified from accumulated other comprehensive loss	0	0
Net current-period change in accumulated other comprehensive (loss) income	16	22
Balance	(223)	(372)
Total accumulated other comprehensive loss
Accumulated Other Comprehensive Loss [Line Items]
Balance	(411)	(407)
Other comprehensive (loss) gain before reclassifications	(473)	(291)
Loss reclassified from accumulated other comprehensive loss	292	89
Net current-period change in accumulated other comprehensive (loss) income	(181)	(202)
Balance	$ (592)	$ (609)

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Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts	6 Months Ended
	Jun. 30, 2022 Bcf MMBbls
Derivatives designated as hedging instruments | Crude oil fixed price
Derivative [Line Items]
Net open position	(19.0)
Derivatives designated as hedging instruments | Crude oil basis
Derivative [Line Items]
Net open position	(5.2)
Derivatives designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	(55.9)
Derivatives designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	(45.0)
Derivatives designated as hedging instruments | NGL fixed price
Derivative [Line Items]
Net open position	(0.8)
Derivatives not designated as hedging instruments | Crude oil fixed price
Derivative [Line Items]
Net open position	(1.1)
Derivatives not designated as hedging instruments | Crude oil basis
Derivative [Line Items]
Net open position	(6.6)
Derivatives not designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	(9.3)
Derivatives not designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	(22.5)
Derivatives not designated as hedging instruments | Natural Gas Options
Derivative [Line Items]
Net open position | Bcf	(0.4)
Derivatives not designated as hedging instruments | NGL fixed price
Derivative [Line Items]
Net open position	(1.1)

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Risk Management - Interest Rate Risk Management (Details) $ in Millions	Jun. 30, 2022 USD ($)
Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument | Fair value hedge
Derivative [Line Items]
Notional amount	$ 6,750
Variable-to-Fixed Interest Rate Contracts | Designated as Hedging Instrument | Cash flow hedge
Derivative [Line Items]
Notional amount	250
Variable-to-Fixed Interest Rate Contracts | Derivatives not designated as hedging instruments | Fair value hedge
Derivative [Line Items]
Notional amount	5,100
Fixed-To-Variable Interest Rate Contracts Q1 & Q2 2022 | Designated as Hedging Instrument | Fair value hedge
Derivative [Line Items]
Notional amount	400
Current Portion Of Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	100
Long-term Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	$ 6,650

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Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Jun. 30, 2022 USD ($)
Cash flow hedge | Cross-currency contracts | Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	$ 543

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Risk Management - Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Derivatives Asset	$ 215	$ 514
Derivatives Liability	(915)	(293)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	91	76
Derivatives Liability	(709)	(272)
Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	124	397
Derivatives Liability	(170)	(18)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset		41
Derivatives Liability	(36)	(3)
Derivatives designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives Asset	127	490
Derivatives Liability	(756)	(256)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	62	64
Derivatives Liability	(550)	(235)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivative contracts - current assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	58	61
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivative contracts - current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(357)	(141)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	4	3
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(193)	(94)
Derivatives designated as hedging instruments | Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	65	385
Derivatives Liability	(170)	(18)
Derivatives designated as hedging instruments | Interest rate contracts | Fair value of derivative contracts - current assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	6	101
Derivatives designated as hedging instruments | Interest rate contracts | Fair value of derivative contracts - current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(38)	(3)
Derivatives designated as hedging instruments | Interest rate contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	59	284
Derivatives designated as hedging instruments | Interest rate contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(132)	(15)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	0	41
Derivatives Liability	(36)	(3)
Derivatives designated as hedging instruments | Foreign currency contracts | Fair value of derivative contracts - current assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	0	35
Derivatives designated as hedging instruments | Foreign currency contracts | Fair value of derivative contracts - current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(9)	(3)
Derivatives designated as hedging instruments | Foreign currency contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	0	6
Derivatives designated as hedging instruments | Foreign currency contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(27)	0
Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives Asset	88	24
Derivatives Liability	(159)	(37)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	29	12
Derivatives Liability	(159)	(37)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivative contracts - current assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	18	11
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivative contracts - current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(117)	(31)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	11	1
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(42)	(6)
Derivatives not designated as hedging instruments | Interest rate contracts | Fair value of derivative contracts - current assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	59	12
Derivatives not designated as hedging instruments | Interest rate contracts | Fair value of derivative contracts - current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	$ 0	$ 0

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Risk Management - Derivative Assets Input Level (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 215	$ 514
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	91	76
Contracts available for netting	(90)	(53)
Cash collateral held	0	(20)
Net amount	1	3
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	52	56
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	39	20
Energy commodity derivative contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	124	397
Contracts available for netting	0	(9)
Cash collateral held	0	0
Net amount	124	388
Interest rate contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	124	397
Interest rate contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 0	0
Foreign currency contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount		41
Contracts available for netting		(3)
Cash collateral held		0
Net amount		38
Foreign currency contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount		0
Foreign currency contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount		41
Foreign currency contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount		$ 0

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Risk Management - Derivative Liabilities Input Level (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ (915)	$ (293)
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(709)	(272)
Contracts available for netting	90	53
Cash collateral posted	125	0
Net amount	(494)	(219)
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(96)	(15)
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(613)	(257)
Energy commodity derivative contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(170)	(18)
Contracts available for netting	0	9
Cash collateral posted	0	0
Net amount	(170)	(9)
Interest rate contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(170)	(18)
Interest rate contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Foreign currency contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(36)	(3)
Contracts available for netting	0	3
Cash collateral posted	0	0
Net amount	(36)	0
Foreign currency contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Foreign currency contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(36)	(3)
Foreign currency contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 0	$ 0

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Risk Management - Effect of Derivative Contracts on the Income Statement (Details) - Derivatives designated as hedging instruments - Derivatives in fair value hedging relationships - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Interest rate contracts | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives adjustments on commodity sales	$ (160)	$ 28	$ (476)	$ (189)
Hedged fixed rate debt
Derivative Instruments, Gain (Loss) [Line Items]
Cumulative amount of fair value hedging adjustments to hedged fixed rate debt	106		106
Hedged fixed rate debt | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives adjustments on commodity sales	$ 162	$ (28)	$ 482	$ 190

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Risk Management - Effect on Income Statement Locations (Details) - Derivatives in cash flow hedging relationships - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months			$ (267)
Derivatives designated as hedging instruments
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	$ (102)	$ (204)	(638)	$ (407)
Gain/(loss) reclassified from Accumulated OCI into income	(205)	(39)	(381)	(116)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	(70)	(215)	(569)	(374)
Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	3	1	6	2
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	(35)	10	(75)	(35)
Revenues—Commodity sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(185)	(53)	(317)	(73)
Costs of sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	7	(2)	17	2
Earnings from equity investments | Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	0	0	0	0
Other, net | Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ (27)	$ 16	(81)	(45)
Write-Down Of Hedged Inventory | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income			$ 5	$ 6

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Risk Management - Effect on Income Statement Not Designated (Details) - Derivatives not designated as hedging instruments - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (13)	$ (37)	$ (82)	$ (505)
Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) on settlement of derivative contracts	(38)	(7)	(20)	(455)
Revenues—Commodity sales | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(17)	(33)	(26)	(663)
Costs of sales | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(8)	(2)	(99)	160
Earnings from equity investments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	0	(2)	(5)	(2)
Interest, net | Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ 12	$ 0	$ 48	$ 0

XML

Risk Management - Credit Risks (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Credit Derivatives [Line Items]
Additional collateral, aggregate fair value if downgrade two notches	$ 358
Energy commodity derivative contracts
Credit Derivatives [Line Items]
Letter of credits outstanding, amount	0	$ 0
Initial Margin Requirements	184
Variation Margin Requirements	125
Cash collateral posted	125	0
Other current liabilities | Cash collateral held | Energy commodity derivative contracts
Credit Derivatives [Line Items]
Collateral posted		$ 14
Restricted Cash | Cash collateral held | Energy commodity derivative contracts
Credit Derivatives [Line Items]
Cash collateral posted	$ 309

XML

Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Revenue [Line Items]
Revenues from customers	$ 4,992	$ 2,906	$ 9,081	$ 8,401
Leasing services	331	321	645	637
Other	30	8	61	59
Total other revenues	159	244	363	(40)
Total revenues	5,151	3,150	9,444	8,361
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	3,363	1,960	6,156	6,070
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	996	514	1,762	967
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	449	433	878	852
CO2
Disaggregation of Revenue [Line Items]
Total revenues	343	243	648	472
Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	3,303	1,897	6,023	6,480
Leasing services	118	118	235	237
Other	16	(2)	31	39
Total other revenues	53	79	146	(379)
Total revenues	3,356	1,976	6,169	6,101
Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	942	467	1,661	872
Leasing services	49	43	93	86
Other	5	5	11	10
Total other revenues	54	47	101	95
Total revenues	996	514	1,762	967
Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from customers	301	289	591	566
Leasing services	149	144	289	287
Other	0	0	0	0
Total other revenues	149	144	289	287
Total revenues	450	433	880	853
Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from customers	440	269	821	514
Leasing services	15	15	28	27
Other	9	6	19	11
Total other revenues	(97)	(26)	(173)	(42)
Total revenues	343	243	648	472
Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from customers	6	(16)	(15)	(31)
Leasing services	0	1	0	0
Other	0	(1)	0	(1)
Total other revenues	0	0	0	(1)
Total revenues	6	(16)	(15)	(32)
Firm services
Disaggregation of Revenue [Line Items]
Revenues from customers	1,107	1,063	2,292	2,179
Firm services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	849	799	1,788	1,665
Firm services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	60	66	119	125
Firm services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from customers	198	198	386	389
Firm services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from customers	1	0	1	0
Firm services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from customers	(1)	0	(2)	0
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from customers	583	514	1,141	1,009
Fee-based services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	234	176	447	354
Fee-based services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	242	244	476	465
Fee-based services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from customers	96	84	194	165
Fee-based services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from customers	11	10	24	25
Fee-based services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from customers	0	0	0	0
Total services
Disaggregation of Revenue [Line Items]
Revenues from customers	1,690	1,577	3,433	3,188
Total services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	1,083	975	2,235	2,019
Total services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	302	310	595	590
Total services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from customers	294	282	580	554
Total services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from customers	12	10	25	25
Total services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from customers	(1)	0	(2)	0
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from customers	1,828	672	3,070	3,987
Natural gas sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	1,810	674	3,036	3,993
Natural gas sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	0	0	0	0
Natural gas sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from customers	0	0	0	0
Natural gas sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from customers	24	1	44	2
Natural gas sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from customers	(6)	(3)	(10)	(8)
Product sales
Disaggregation of Revenue [Line Items]
Revenues from customers	1,474	657	2,578	1,226
Product sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	410	248	752	468
Product sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	640	157	1,066	282
Product sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from customers	7	7	11	12
Product sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from customers	404	258	752	487
Product sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from customers	13	(13)	(3)	(23)
Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from customers	3,302	1,329	5,648	5,213
Total revenues	3,100	1,246	5,308	4,475
Total commodity sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	2,220	922	3,788	4,461
Total commodity sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from customers	640	157	1,066	282
Total commodity sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from customers	7	7	11	12
Total commodity sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from customers	428	259	796	489
Total commodity sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from customers	7	(16)	(13)	(31)
Sales
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(202)	(85)	(343)	(736)
Sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(81)	(37)	(120)	(655)
Sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	0	(1)	(3)	(1)
Sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	0	0	0	0
Sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(121)	(47)	(220)	(80)
Sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	$ 0	$ 0	$ 0	$ 0

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Revenue Recognition - Contract Balances (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Contract Assets
Contract assets balances	$ 42	$ 39
Transfer to Accounts receivable	22
Contract Liabilities
Contract liabilities balances	215	$ 212
Transfer to Revenues	$ 59

XML

Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Jun. 30, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue allocated to remaining performance obligations for contracted revenue	$ 27,722
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2022-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	6 months
Revenue allocated to remaining performance obligations for contracted revenue	$ 2,279
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 3,895
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 3,173
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 2,635
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 2,319
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition
Revenue allocated to remaining performance obligations for contracted revenue	$ 13,421

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Reportable Segments - Revenues (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Segment Reporting Information [Line Items]
Revenues	$ 5,151	$ 3,150	$ 9,444	$ 8,361
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	6	(16)	(15)	(32)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	3,363	1,960	6,156	6,070
Natural Gas Pipelines | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	7	(16)	(13)	(31)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	996	514	1,762	967
Terminals
Segment Reporting Information [Line Items]
Revenues	449	433	878	852
Terminals | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(1)	0	(2)	(1)
CO2
Segment Reporting Information [Line Items]
Revenues	$ 343	$ 243	$ 648	$ 472

XML

Reportable Segments - EBDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Segment Reporting Information [Line Items]
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	(152)	(160)	(308)	(316)
Income Tax (Expense) Benefit	(184)	237	(378)	(114)
Net Income (Loss)	653	(740)	1,337	685
Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	1,898	91	3,811	2,955
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
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)
Natural Gas Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	1,134	(570)	2,318	1,533
Products Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	299	265	598	513
Terminals | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	253	246	491	473
CO2 | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	$ 212	$ 150	$ 404	$ 436

XML

Reportable Segments - Assets (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Assets	$ 69,390	$ 70,416
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
Assets	1,040	2,226
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	47,780	47,746
Products Pipelines
Segment Reporting Information [Line Items]
Assets	9,221	9,088
Terminals
Segment Reporting Information [Line Items]
Assets	8,428	8,513
CO2
Segment Reporting Information [Line Items]
Assets	$ 2,921	$ 2,843

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ 184	$ (237)	$ 378	$ 114
Effective tax rate	22.00%	24.30%	22.00%	14.30%
Statutory federal rate	21.00%	21.00%	21.00%	21.00%

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Litigation and Environmental - Other Commercial Matters (Details) - Pending Litigation $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($)	Jun. 01, 2018 projects
Hiland Partners Holdings, LLC
Loss Contingencies [Line Items]
Infrastructures to Build for Settlement | projects		10
Loss Contingency, Damages Sought, Value	$ 276
Freeport LNG Marketing, LLC Case
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 104

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Litigation and Environmental - General (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Estimated Litigation Liability	$ 178	$ 231

XML

Litigation and Environmental - PHMSA Enforcement Matter (Details) - Pipeline and Hazardous Materials Safety Administration - Subsequent Event - KMLT	Jul. 11, 2022 USD ($) violations
Loss Contingencies [Line Items]
Alleged Department of Transportation Violations	16
Violations Subject to Proposed Compliance Agreement	3
Loss Contingency, Estimate of Possible Loss | $	$ 455,000

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Litigation and Environmental - Portland Harbor (Details) - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) Terminals Parties
Environmental Protection Agency | KMLT
Site Contingency [Line Items]
Number of Parties Involved In Site Cleanup Allocation Negotiations | Parties	90
Number of Liquid Terminals | Terminals	2
Environmental Protection Agency | KMLT | Pro Forma
Site Contingency [Line Items]
Estimated Remedy Implementation Period	10 years
Environmental Remediation Expense | $	$ 2,800
Environmental Protection Agency | KMBT
Site Contingency [Line Items]
Number of Liquid Terminals | Terminals	2
State and Federal Trustees | KMLT
Site Contingency [Line Items]
Loss Contingency, Damages Sought, Value | $	$ 5

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Litigation and Environmental - Arizona Uranium Mines (Details) - Uranium Mines in Arizona - EPNG - mines		240 Months Ended
	Apr. 16, 2019	Dec. 31, 1969
Loss Contingencies [Line Items]
Number of Uranium Mines		20
Percentage of Response Costs	35.00%

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Litigation and Environmental - Lower Passaic River (Details) - Pending Litigation $ in Millions		6 Months Ended
	Mar. 04, 2016 USD ($) mi	Jun. 30, 2022 USD ($) Parties mi
Lower Passaic River Study Area
Site Contingency [Line Items]
Miles of river		17
Number of Parties at a Joint Defense Group | Parties		44
Lower Passaic River Study Area | EPA preferred alternative estimate
Site Contingency [Line Items]
Environmental Remediation Expense | $	$ 1,700
Lower Passaic River Study Area | Clean Up Implementation
Site Contingency [Line Items]
Estimated Remedy Implementation Period		6 years
Lower Passaic River Study Area, Lower Portion
Site Contingency [Line Items]
Miles of river	8	8
Upper Passai River Study Area, Upper Portion | Pro Forma
Site Contingency [Line Items]
Miles of river		9
Environmental Remediation Expense | $		$ 440

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Litigation and Environmental - Louisiana Governmental Coastal Zone Erosion Litigation (Details) - Coastal Zone	Mar. 29, 2019 Parties	Nov. 08, 2013 Parties	Jun. 30, 2022 cases
Judicial District of Louisiana
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number			40
Judicial District of Louisiana | TGP
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number			1
Judicial District of Louisiana | SNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number			1
Parish of Plaquemines, Louisiana | TGP
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants | Parties		17
Parish Orleans, Louisiana | SNG
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants | Parties	10

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Litigation and Environmental - Walnut Creek (Details) - State of California - SFPP $ in Millions				6 Months Ended
	Dec. 16, 2021 USD ($)	Dec. 08, 2020 bbl	Nov. 20, 2020 bbl	Jun. 30, 2022
Environmental Remediation Estimated Spill Volume | bbl		1,000	8.1
Environmental Remediation Expense | $	$ 2.5
Estimated Remedy Implementation Period				18 months

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Litigation and Environmental - Environmental Matters General (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Accrual for Environmental Loss Contingencies	$ 235	$ 243
Recorded Third-Party Environmental Recoveries Receivable	$ 12	$ 12

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Recent Accounting Pronouncements (Details) - Fixed-to-Variable Interest Rate Contracts - Derivatives in fair value hedging relationships - Designated as Hedging Instrument $ in Millions	Jun. 30, 2022 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Notional amount	$ 6,750
SOFR
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Notional amount	$ 725