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 September 30, 2021

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
1.500% Senior Notes due 2022	KMI 22	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 October 21, 2021, the registrant had 2,267,425,507 Class P shares 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 Nine Months Ended September 30, 2021 and 2020		4
	Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, 2021 and 2020		5
	Consolidated Balance Sheets - as of September 30, 2021 and December 31, 2020		6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2021 and 2020		7
	Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 30, 2021 and 2020		9
	Notes to Consolidated Financial Statements		11
	Note 1.	General	11
	Note 2.	Acquisitions	12
	Note 3.	Losses and Gains on Impairments, Divestitures and Other Write-downs	14
	Note 4.	Debt	16
	Note 5.	Stockholders’ Equity	17
	Note 6.	Risk Management	18
	Note 7.	Revenue Recognition	23
	Note 8.	Reportable Segments	26
	Note 9.	Income Taxes	27
	Note 10.	Litigation and Environmental	28
	Note 11.	Recent Accounting Pronouncements	32
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		34
	Results of Operations		35
	Overview		35
	Consolidated Earnings Results (GAAP)		37
	Non-GAAP Financial Measures		40
	Segment Earnings Results		43
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		51
	Income Taxes		52
	Liquidity and Capital Resources		52
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		56
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		57
Item 4.	Controls and Procedures		57
	PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings		57
Item 1A.	Risk Factors		57
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		57
Item 3.	Defaults Upon Senior Securities		57
Item 4.	Mine Safety Disclosures		57
Item 5.	Other Information		57
Item 6.	Exhibits		59
	Signature		60

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	EPA	=	U.S. Environmental Protection Agency
Bbl	=	barrel	FASB	=	Financial Accounting Standards Board
BBtu	=	billion British Thermal Units	FERC	=	Federal Energy Regulatory Commission
Bcf	=	billion cubic feet	GAAP	=	U.S. Generally Accepted Accounting Principles
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	LLC	=	limited liability company
			LIBOR	=	London Interbank Offered Rate
CO2	=	carbon dioxide or our CO2 business segment	MBbl	=	thousand barrels
COVID-19	=	Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturn	MMBbl	=	million barrels
			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
			ROU	=	Right-of-Use
EBITDA	=	earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investments	U.S.	=	United States of America
			WTI	=	West Texas Intermediate

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, our proposed acquisition of Kinetrex Energy and our capital projects, including expected completion timing and benefits of the acquisition and 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 impacts of the COVID-19 pandemic and the pace and extent of economic recovery; 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 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, 2020 (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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenues
Services	$	1,928	$	1,881	$	5,734	$	5,664
Commodity sales	1,868		982		6,343		2,772
Other	28		56		108		149
Total Revenues	3,824		2,919		12,185		8,585
Operating Costs, Expenses and Other
Costs of sales	1,559		655		4,504		1,759
Operations and maintenance	614		643		1,710		1,869
Depreciation, depletion and amortization	526		539		1,595		1,636
General and administrative	174		153		490		461
Taxes, other than income taxes	106		100		324		295
Loss on impairments and divestitures, net (Note 3)	4		11		1,602		1,987
Other income, net	(3)		(1)		(6)		(2)
Total Operating Costs, Expenses and Other	2,980		2,100		10,219		8,005
Operating Income	844		819		1,966		580
Other Income (Expense)
Earnings from equity investments	169		194		392		562
Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)
Interest, net	(368)		(383)		(1,122)		(1,214)
Other, net (Note 3)	21		14		264		32
Total Other Expense	(199)		(207)		(522)		(719)
Income (Loss) Before Income Taxes	645		612		1,444		(139)
Income Tax Expense	(134)		(140)		(248)		(304)
Net Income (Loss)	511		472		1,196		(443)
Net Income Attributable to Noncontrolling Interests	(16)		(17)		(49)		(45)
Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	495	$	455	$	1,147	$	(488)
Class P Shares
Basic and Diluted Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)
Basic and Diluted Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263

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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net income (loss)	$	511	$	472	$	1,196	$	(443)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively)	(131)		(56)		(444)		(16)
Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively)	92		(5)		181		72
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)	—		—		—		1
Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively)	6		5		28		21
Total other comprehensive (loss) income	(33)		(56)		(235)		78
Comprehensive income (loss)	478		416		961		(365)
Comprehensive income attributable to noncontrolling interests	(16)		(17)		(49)		(45)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$	462	$	399	$	912	$	(410)

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

5

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except per share amounts, unaudited)

	September 30, 2021		December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents	$	102	$	1,184
Restricted deposits	177		25
Accounts receivable	1,433		1,293
Fair value of derivative contracts	199		185
Inventories	457		348
Other current assets	318		168
Total current assets	2,686		3,203
Property, plant and equipment, net	35,576		35,836
Investments	7,620		7,917
Goodwill	20,033		19,851
Other intangibles, net	1,744		2,453
Deferred income taxes	303		536
Deferred charges and other assets	1,678		2,177
Total Assets	$	69,640	$	71,973
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,822	$	2,558
Accounts payable	1,189		837
Accrued interest	332		525
Accrued taxes	284		267
Accrued contingencies	246		307
Other current liabilities	952		580
Total current liabilities	5,825		5,074
Long-term liabilities and deferred credits
Long-term debt
Outstanding	28,988		30,838
Debt fair value adjustments	1,014		1,293
Total long-term debt	30,002		32,131
Other long-term liabilities and deferred credits	2,160		2,202
Total long-term liabilities and deferred credits	32,162		34,333
Total Liabilities	37,987		39,407
Commitments and contingencies (Notes 4 and 10)
Redeemable Noncontrolling Interest	661		728
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding	23		23
Additional paid-in capital	41,788		41,756
Accumulated deficit	(10,617)		(9,936)
Accumulated other comprehensive loss	(642)		(407)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,552		31,436
Noncontrolling interests	440		402
Total Stockholders’ Equity	30,992		31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	69,640	$	71,973

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)
	Nine Months Ended September 30,
	2021		2020
Cash Flows From Operating Activities
Net income (loss)	$	1,196	$	(443)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	1,595		1,636
Deferred income taxes	236		164
Amortization of excess cost of equity investments	56		99
Loss on impairments and divestitures, net (Note 3)	1,602		1,987
Gain on sale of interest in equity investment (Note 3)	(206)		—
Earnings from equity investments	(392)		(562)
Distributions from equity investment earnings	535		487
Changes in components of working capital
Accounts receivable	(119)		238
Inventories	(89)		41
Other current assets	(90)		14
Accounts payable	362		(107)
Accrued interest, net of interest rate swaps	(177)		(208)
Accrued taxes	15		(25)
Other current liabilities	71		(93)
Rate reparations, refunds and other litigation reserve adjustments	(97)		48
Other, net	(58)		6
Net Cash Provided by Operating Activities	4,440		3,282
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	(1,518)		(16)
Capital expenditures	(894)		(1,351)
Proceeds from sales of investments	417		907
Contributions to investments	(36)		(365)
Distributions from equity investments in excess of cumulative earnings	121		105
Other, net	(1)		(56)
Net Cash Used in Investing Activities	(1,911)		(776)
Cash Flows From Financing Activities
Issuances of debt	4,950		3,888
Payments of debt	(6,459)		(3,991)
Debt issue costs	(20)		(23)
Dividends	(1,828)		(1,764)
Repurchases of shares	—		(50)
Contributions from investment partner and noncontrolling interests	4		11
Distributions to investment partner	(67)		(60)
Distributions to noncontrolling interests	(14)		(11)
Other, net	(25)		(13)
Net Cash Used in Financing Activities	(3,459)		(2,013)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	—		(3)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(930)		490
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	279	$	699

7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
	Nine Months Ended September 30,
	2021		2020
Cash and Cash Equivalents, beginning of period	$	1,184	$	185
Restricted Deposits, beginning of period	25		24
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209
Cash and Cash Equivalents, end of period	102		632
Restricted Deposits, end of period	177		67
Cash, Cash Equivalents, and Restricted Deposits, end of period	279		699
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(930)	$	490
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	$	35	$	15
Increase in property, plant and equipment from both accruals and contractor retainage	4
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,313		1,440
Cash paid during the period for income taxes, net	8		202

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
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)	$	30,711	$	429	$	31,140
Restricted shares	2			(5)						(5)				(5)
Net income						495				495		16		511
Distributions										—		(6)		(6)
Contributions										—		1		1
Dividends						(616)				(616)				(616)
Other comprehensive loss								(33)		(33)				(33)
Balance at September 30, 2021	2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992

	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at June 30, 2020	2,261	$	23	$	41,731	$	(9,802)	$	(199)	$	31,753	$	371	$	32,124
Restricted shares	3			5						5				5
Net income						455				455		17		472
Distributions										—		(4)		(4)
Contributions										—		2		2
Dividends						(598)				(598)				(598)
Other comprehensive loss								(56)		(56)				(56)
Balance at September 30, 2020	2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945

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

9

KINDER MORGAN, INC. AND SUBSIDIARIES

 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)

(In millions, unaudited)

	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at December 31, 2020	2,264	$	23	$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838
Restricted shares	3			32						32				32
Net income						1,147				1,147		49		1,196
Distributions										—		(14)		(14)
Contributions										—		4		4
Dividends						(1,828)				(1,828)				(1,828)
Other										—		(1)		(1)
Other comprehensive loss								(235)		(235)				(235)
Balance at September 30, 2021	2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992

	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at December 31, 2019	2,265	$	23	$	41,745	$	(7,693)	$	(333)	$	33,742	$	344	$	34,086
Repurchases of shares	(4)			(50)						(50)				(50)
Restricted shares	3			41						41				41
Net (loss) income						(488)				(488)		45		(443)
Distributions										—		(11)		(11)
Contributions										—		8		8
Dividends						(1,764)				(1,764)				(1,764)
Other comprehensive income								78		78				78
Balance at September 30, 2020	2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945

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

10

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, 144 terminals, and 700 billion cubic feet of working natural gas storage capacity. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, 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 2020 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

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, 2021 evaluation, we grouped our businesses into six 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; and (vi) Terminals. See Note 3 for results of our May 31, 2021 goodwill impairment test.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares 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 which include dividend equivalent payments, do not participate in excess distributions over earnings.

11

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders	$	495	$	455	$	1,147	$	(488)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(4)		(3)		(10)		(9)
Net Income (Loss) Allocated to Class P Stockholders	$	491	$	452	$	1,137	$	(497)
Basic Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263
Basic Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)

(a)As of September 30, 2021, there were approximately 13 million restricted stock awards outstanding.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	3	3	3	3

2. Acquisitions

As of September 30, 2021, our preliminary allocation of the purchase price for significant acquisitions completed during the nine months ended September 30, 2021 are detailed below.

					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Deferred charges & other		Goodwill		Current liabilities		Long-term liabilities
			(In millions)
(1)	8/21	Kinetrex Energy	$	318	$	17	$	49	$	262	$	64	$	(6)	$	(68)
(2)	7/21	Stagecoach Gas Services LLC	1,228		52		1,041		23		118		(6)		—

Pro Forma Information

Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1, 2021 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of operations.

(1) Kinetrex Energy Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.

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(2) Stagecoach Acquisition

On July 9, 2021, we completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,228 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation relates to customer contracts with a weighted average amortization period of less than 2 years. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP. The acquired assets complement and expand our natural gas pipeline and storage business and are included in our Natural Gas Pipelines business segment.

Goodwill

After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, the excess purchase price is assigned to goodwill. Goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience. Of our acquisitions made during the nine months ended September 30, 2021, goodwill of $118 million associated with our Stagecoach acquisition is tax deductible and we apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.

Changes in the amounts of our goodwill for the nine months ended September 30, 2021 are summarized by reporting unit as follows:

	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		Products Pipelines		Products Pipelines Terminals		Terminals		Energy Transition Ventures		Total
	(In millions)
Goodwill as of December 31, 2020	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	—	$	19,851
Acquisitions	118		—		—		—		—		—		64		182
Goodwill as of September 30, 2021	$	14,367	$	2,343	$	928	$	1,378	$	151	$	802	$	64	$	20,033

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

We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and nine months ended September 30, 2021 and 2020:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	—	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		—		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Loss (gain) on divestitures of long-lived assets and other write-downs	—		11		(1)		11
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21
Terminals
Impairment of long-lived and intangible assets	14		—		14		5
CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Gain on divestitures of long-lived assets, net	(11)		—		(8)		—
Other loss (gain) on divestitures of long-lived assets, net	1		—		(3)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	4	$	11	$	1,513	$	1,987

(a)See below for a further discussion of these items.

Impairments

Long-lived Assets

During the second quarter 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. The long-lived asset impairment test involved two steps. Step one was an assessment as to whether the asset’s net book value was expected to be recovered from the estimated undiscounted future cash flows. To compute the estimated undiscounted future cash flows we included an unfavorable adjustment for upcoming contract expirations. With this inclusion, our South Texas gathering and processing assets failed step one. In step two, we utilized an income approach to estimate fair value and compared it to the carrying value. We applied an approximate 8.5% discount rate, a Level 3 input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the nine months ended September 30, 2021.

During the first half of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment which resulted in a non-cash impairment of long-lived assets within our CO2 business segment shown in the above table during the nine months ended September 30, 2020.

Goodwill

The results of our May 31, 2021 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. The fair value estimates used in the goodwill impairment test are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect

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to market multiples, comparable sales transactions, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding future cash flows based on production growth rate assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit.

During the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 and Natural Gas Pipelines business segments during the nine months ended September 30, 2020 as shown in the table above.

As conditions warrant, we routinely evaluate our assets for potential triggering events that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.

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 $412 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the nine months ended September 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

Other Write-downs

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, driven by the recent impairment by Ruby of its assets, which is included within “Earnings from equity investments” in our accompanying consolidated statement of operations for the nine months ended September 30, 2021. The impairment at Ruby was the result of upcoming contract expirations and additional uncertainty identified in late February 2021 regarding the proposed development of a third party liquefied natural gas exporting facility that could significantly increase the demand for its services.

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4. Debt

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

	September 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026(a)	$	—	$	—
$500 million credit facility due November 16, 2023(a)	—		—
Commercial paper notes	160		—
Current portion of senior notes
5.00%, due February 2021(b)	—		750
3.50%, due March 2021(b)	—		750
5.80%, due March 2021(b)	—		400
5.00%, due October 2021(c)	—		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(d)	869		—
3.95% due September 2022	1,000		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,822		2,558
Long-term debt (excluding current portion)
Senior notes	28,306		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	353		364
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	219		223
Total long-term debt	28,988		30,838
Total debt(e)	$	31,810	$	33,396

(a)On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.

(b)We repaid the principal amounts on these senior notes during the first quarter of 2021.

(c)These notes were repaid on July 1, 2021.

(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The September 30, 2021 balance is reported above at the exchange rate of 1.1580 U.S. dollars per Euro. As of September 30, 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 $54 million related to these notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance sheets. 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 6 “Risk Management—Foreign Currency Risk Management”).

(e)Excludes our “Debt fair value adjustments” which, as of September 30, 2021 and December 31, 2020, increased our total debt balances by $1,014 million and $1,293 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 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million. These notes are guaranteed through the cross guarantee agreement discussed above.

Credit Facilities and Restrictive Covenants

On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under the New Credit Facility may be used for working capital and other general corporate purposes. On the same date, we also entered into a first amendment (the “Amendment”) to our existing Revolving Credit Agreement, dated as of November 16, 2018 (as amended prior to the Amendment, the “Existing Credit

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Facility”). The Amendment provides for certain amendments to the Existing Credit Facility to, among other things, reduce the Existing Credit Facility’s borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder. The combined credit facilities continue to support our $4 billion commercial paper program.

Depending on the type of loan request, our credit facility borrowings under our New Credit Facility bear interest at either (i) LIBOR adjusted for a eurocurrency funding reserve plus an applicable margin ranging from 1.000% to 1.750% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) LIBOR for a one-month Eurodollar loan adjusted for a eurocurrency funding reserve, plus 1%, plus, in each case, an applicable margin ranging from 0.100% to 0.750% per annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.100% to 0.250%. The New Credit Facility also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available.

The New Credit Facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the New Credit Facility) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. The New Credit Facility also restricts our ability to make certain restricted payments if an event of default (as defined in the New Credit Facility) has occurred and is continuing or would occur and be continuing.

As of September 30, 2021, we had no borrowings outstanding under our credit facilities, $160 million in borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of September 30, 2021 was $3,759 million. As of September 30, 2021, 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: 

	September 30, 2021				December 31, 2020
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
	(In millions)
Total debt	$	32,824	$	37,797	$	34,689	$	39,622

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2021 and December 31, 2020.

5. Stockholders’ Equity

Class P Stock

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. Since December 2017, in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $575 million.

Dividends

The following table provides information about our per share dividends:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.81	$	0.7875
Per share cash dividend paid in the period	0.27		0.2625		0.8025		0.775

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On October 20, 2021, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended September 30, 2021, which is payable on November 15, 2021 to shareholders of record as of the close of business on November 1, 2021.

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” in 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		Foreign currency translation adjustments		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	(444)		—		28		(416)
Loss reclassified from accumulated other comprehensive loss	181		—		—		181
Net current-period change in accumulated other comprehensive loss	(263)		—		28		(235)
Balance as of September 30, 2021	$	(276)	$	—	$	(366)	$	(642)

	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2019	$	(7)	$	—	$	(326)	$	(333)
Other comprehensive (loss) gain before reclassifications	(16)		1		21		6
Loss reclassified from accumulated other comprehensive loss	72		—		—		72
Net current-period change in accumulated other comprehensive (loss) income	56		1		21		78
Balance as of September 30, 2020	$	49	$	1	$	(305)	$	(255)

6.  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.

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Energy Commodity Price Risk Management

As of September 30, 2021, 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	(15.9)	MMBbl
Crude oil basis	(6.4)	MMBbl
Natural gas fixed price	(29.5)	Bcf
Natural gas basis	(27.1)	Bcf
NGL fixed price	(1.0)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.4)	MMBbl
Crude oil basis	(8.7)	MMBbl
Natural gas fixed price	(8.7)	Bcf
Natural gas basis	(22.8)	Bcf
NGL fixed price	(1.9)	MMBbl

As of September 30, 2021, 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 2025.

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 September 30, 2021:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	7,100	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	6,250		Mark-to-Market	December 2022

(a)The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

During the nine months ended September 30, 2021, we entered into fixed-to-variable interest rate swap agreements with a combined notional principal amount of $375 million. These agreements were designated as accounting hedges and convert a portion of our fixed rate debt to variable rates through February 2028. In addition, we entered into variable-to-fixed interest rate swap agreements with a combined notional principal amount of $3,750 million. These agreements were not designated as accounting hedges and effectively fixed our LIBOR exposure for a portion of our fixed-to-variable interest rate swaps for 2022.

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 September 30, 2021:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$	1,358	Cash flow hedge	March 2027

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

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

Fair Value of Derivative Contracts
		Derivatives Asset				Derivatives Liability
		September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	13	$	42	$	(256)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		33		(96)		(8)
Subtotal		14		75		(352)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	127		119		(4)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	350		575		(14)		(7)
Subtotal		477		694		(18)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	49		—		(6)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		138		—		—
Subtotal		69		138		(6)		(6)
Total		560		907		(376)		(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	10		24		(63)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		—		(3)		—
Subtotal		14		24		(66)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		—		—
Subtotal		1		—		(1)		—
Total		15		24		(67)		(21)
Total derivatives		$	575	$	931	$	(443)	$	(78)

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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 September 30, 2021
Energy commodity derivative contracts(a)	$	15	$	13	$	—	$	28	$	(26)	$	—	$	2
Interest rate contracts	—		478		—		478		(9)		—		469
Foreign currency contracts	—		69		—		69		(6)		—		63
As of December 31, 2020
Energy commodity derivative contracts(a)	$	6	$	93	$	—	$	99	$	(35)	$	—	$	64
Interest rate contracts	—		694		—		694		(2)		—		692
Foreign currency contracts	—		138		—		138		(6)		—		132

	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 September 30, 2021
Energy commodity derivative contracts(a)	$	(111)	$	(307)	$	—	$	(418)	$	26	$	135	$	(257)
Interest rate contracts	—		(19)		—		(19)		9		—		(10)
Foreign currency contracts	—		(6)		—		(6)		6		—		—
As of December 31, 2020
Energy commodity derivative contracts(a)	$	(7)	$	(56)	$	—	$	(63)	$	35	$	(8)	$	(36)
Interest rate contracts	—		(10)		—		(10)		2		—		(8)
Foreign currency contracts	—		(6)		—		(6)		6		—		—

(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 in 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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	(39)	$	(50)	$	(228)	$	409
Hedged fixed rate debt(a)	Interest, net	$	39	$	50	$	229	$	(418)

(a)As of September 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $473 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 September 30,					Three Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(140)	$	(143)	Revenues—Commodity sales	$	(94)	$	(47)
					Costs of sales	8		(7)
Interest rate contracts	1		—		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(33)		70		Other, net	(34)		61
Total	$	(172)	$	(73)	Total	$	(120)	$	6

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(514)	$	(29)	Revenues—Commodity sales	$	(167)	$	(145)
					Costs of sales	10		(12)
Interest rate contracts	3		(9)		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(68)		17		Other, net	(79)		64
Total	$	(579)	$	(21)	Total	$	(236)	$	(94)

(a)We expect to reclassify approximately $181 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2021 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 nine months ended September 30, 2021, we recognized gains of $6 million 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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(40)	$	87	$	(703)	$	353
	Costs of sales	(7)		12		154		18
	Earnings from equity investments	(2)		—		(4)		—
Total(a)		$	(49)	$	99	$	(553)	$	371

(a)The three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480 million, respectively, and the three and nine months ended September 30, 2020 amounts include approximate gains of $96 million and $349 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

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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 September 30, 2021 and December 31, 2020, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2021, we had cash margins of $165 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2020, we had cash margins of $3 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at September 30, 2021 represents the net of our initial margin requirements of $30 million and counterparty variation margin requirements of $135 million. 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 September 30, 2021, 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 $177 million of additional collateral.

7. 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 September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	836	$	66	$	181	$	1	$	(2)	$	1,082
Fee-based services	190		244		93		10		—		537
Total services	1,026		310		274		11		(2)		1,619
Commodity sales
Natural gas sales	1,097		—		—		7		(3)		1,101
Product sales	372		247		8		279		(11)		895
Total commodity sales	1,469		247		8		286		(14)		1,996
Total revenues from contracts with customers	2,495		557		282		297		(16)		3,615
Other revenues(c)
Leasing services(d)	119		42		140		15		—		316
Derivatives adjustments on commodity sales	(71)		—		—		(63)		—		(134)
Other	12		6		—		8		1		27
Total other revenues	60		48		140		(40)		1		209
Total revenues	$	2,555	$	605	$	422	$	257	$	(15)	$	3,824

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	Three Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	818	$	69	$	185	$	1	$	(2)	$	1,071
Fee-based services	173		228		91		8		3		503
Total services	991		297		276		9		1		1,574
Commodity sales
Natural gas sales	507		—		—		1		(2)		506
Product sales	158		97		5		180		(5)		435
Total commodity sales	665		97		5		181		(7)		941
Total revenues from contracts with customers	1,656		394		281		190		(6)		2,515
Other revenues(c)
Leasing services(d)	119		42		143		13		—		317
Derivatives adjustments on commodity sales	(6)		—		—		46		—		40
Other	40		6		—		2		(1)		47
Total other revenues	153		48		143		61		(1)		404
Total revenues	$	1,809	$	442	$	424	$	251	$	(7)	$	2,919

	Nine Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,501	$	191	$	570	$	1	$	(2)	$	3,261
Fee-based services	544		709		258		35		—		1,546
Total services	3,045		900		828		36		(2)		4,807
Commodity sales
Natural gas sales	5,090		—		—		9		(11)		5,088
Product sales	840		529		20		766		(34)		2,121
Total commodity sales	5,930		529		20		775		(45)		7,209
Total revenues from contracts with customers	8,975		1,429		848		811		(47)		12,016
Other revenues(c)
Leasing services(d)	356		128		427		42		—		953
Derivatives adjustments on commodity sales	(726)		(1)		—		(143)		—		(870)
Other	51		16		—		19		—		86
Total other revenues	(319)		143		427		(82)		—		169
Total revenues	$	8,656	$	1,572	$	1,275	$	729	$	(47)	$	12,185

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	Nine Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,479	$	215	$	563	$	1	$	(2)	$	3,256
Fee-based services	523		670		307		31		1		1,532
Total services	3,002		885		870		32		(1)		4,788
Commodity sales
Natural gas sales	1,385		—		—		1		(5)		1,381
Product sales	396		255		11		546		(22)		1,186
Total commodity sales	1,781		255		11		547		(27)		2,567
Total revenues from contracts with customers	4,783		1,140		881		579		(28)		7,355
Other revenues(c)
Leasing services(d)	346		126		404		34		—		910
Derivatives adjustments on commodity sales	35		—		—		173		—		208
Other	91		16		—		6		(1)		112
Total other revenues	472		142		404		213		(1)		1,230
Total revenues	$	5,255	$	1,282	$	1,285	$	792	$	(29)	$	8,585

(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 (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 6 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 September 30, 2021 and December 31, 2020, our contract asset balances were $62 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $14 million was transferred to accounts receivable during the nine months ended September 30, 2021. As of September 30, 2021 and December 31, 2020, our contract liability balances were $217 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $63 million was recognized as revenue during the nine months ended September 30, 2021.

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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 September 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2021	$	1,178
2022	4,022
2023	3,186
2024	2,711
2025	2,277
Thereafter	14,018
Total	$	27,392

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.

8.  Reportable Segments

Financial information by segment follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,541	$	1,803	$	8,611	$	5,229
Intersegment revenues	14		6		45		26
Products Pipelines	605		442		1,572		1,282
Terminals
Revenues from external customers	421		423		1,273		1,282
Intersegment revenues	1		1		2		3
CO2	257		251		729		792
Corporate and intersegment eliminations	(15)		(7)		(47)		(29)
Total consolidated revenues	$	3,824	$	2,919	$	12,185	$	8,585

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,069	$	1,091	$	2,602	$	2,284
Products Pipelines	279		223		792		719
Terminals	216		246		689		732
CO2	163		156		599		(453)
Total Segment EBDA	1,727		1,716		4,682		3,282
DD&A	(526)		(539)		(1,595)		(1,636)
Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)
General and administrative and corporate charges	(167)		(150)		(465)		(472)
Interest, net	(368)		(383)		(1,122)		(1,214)
Income tax expense	(134)		(140)		(248)		(304)
Total consolidated net income (loss)	$	511	$	472	$	1,196	$	(443)

	September 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	47,576	$	48,597
Products Pipelines	9,118		9,182
Terminals	8,507		8,639
CO2	2,808		2,478
Corporate assets(b)	1,631		3,077
Total consolidated assets	$	69,640	$	71,973

(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, and other income, 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.

9.  Income Taxes

Income tax expense included in our accompanying consolidated statements of operations is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(In millions, except percentages)
Income tax expense	$	134		$	140		$	248		$	304
Effective tax rate	20.8		%	22.9		%	17.2		%	(218.7)		%

The effective tax rate for the three months ended September 30, 2021 is slightly lower than the statutory federal rate of 21% primarily due to dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

The effective tax rates for the three months ended September 30, 2020 is higher than the statutory federal rate of 21% primarily due to state income taxes.

The effective tax rate for the nine months ended September 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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The effective tax rate for the nine months ended September 30, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to the $1,600 million impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit. This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus and PPL.

While we would normally expect a federal income tax benefit from our loss before income taxes for the nine months ended September 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for these periods.

10.   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 contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

SFPP FERC Proceedings

The FERC approved the SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the EL Settlement were fully accrued on or before December 31, 2020.

The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two-year period preceding the filing date of their complaints and/or prospective refunds in protest cases from the date of protest, and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings at the FERC that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million in rate refunds and unspecified rate reductions as of the date of their complaints in 2014 and 2018. The claims pleaded by the shippers are expected to change due to the passage of time and interest. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. We do not believe the ultimate resolution of the shipper complaints and protests seeking rate reductions or refunds in the ongoing proceedings will have a material adverse impact on 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.  Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its 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 have “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. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash

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impairment of our investment in GLNG partially offset by our share of earnings recognized by 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. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending.

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. Eni USA’s second arbitration sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the second arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from pursuing the second arbitration, including the breach of contract and negligent misrepresentation claims therein. On October 4, 2021, the U.S. Supreme Court denied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration and the claims asserted therein.

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. ALSS also sought a declaration on substantially the same allegations asserted previously by Eni USA in arbitration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project gave rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also sought a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. On July 15, 2021, the arbitration tribunal delivered a Final Award on the merits of all claims submitted to the tribunal and denied all of ALSS’s claims with prejudice.

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 has 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 makes 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. Hiland Partners denies and will vigorously defend 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 $98 million, plus attorney fees and interest. We believe that our declaration of force majeure is valid and appropriate and intend to vigorously defend against Freeport’s 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

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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.

General

As of September 30, 2021 and December 31, 2020, our total reserve for legal matters was $192 million and $273 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, NGL, natural gas or CO2.

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 by the EPA to be more than $3 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 asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.

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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 obligate them 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 May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. The defendants appealed that decision. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing. On August 5, 2021, the Fifth Circuit remanded the case to the U.S. District Court to

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determine whether there is federal officer jurisdiction. The case remains effectively stayed pending a ruling by the U.S. District Court on the federal officer issue. 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.

Louisiana Landowner Coastal Erosion Litigation

Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including four cases against TGP, three cases against SNG, and one case against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. We will continue to vigorously defend the remaining cases.

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 September 30, 2021 and December 31, 2020, we have accrued a total reserve for environmental liabilities in the amount of $242 million and $250 million, respectively. In addition, as of both September 30, 2021 and December 31, 2020, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.

11. Recent Accounting Pronouncements

Reference Rate Reform (Topic 848)

On March 12, 2020, the FASB issued Accounting Standards Update (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. 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.

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The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of Topic 848 to our financial statements.

ASU No. 2020-06

On August 5, 2020, the FASB issued 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 EPS 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. ASU No. 2020-06 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2021-05

On July 19, 2021, the FASB issued ASU No. 2021-05, “Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments.” This ASU requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or rate as an operating lease if another classification (i.e. sales-type or direct financing) would trigger a day-one loss. ASU No. 2021-05 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

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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 2020 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2020 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2020 Form 10-K; and (iv) “Risk Factors” in our 2020 Form 10-K.

Long-lived Asset Impairment

During the second quarter 2021 we recognized a non-cash, long-lived asset impairment of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipeline business segment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024.

Stagecoach Acquisition

On July 9, 2021, we completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,228 million, including a preliminary purchase price adjustment for working capital. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP. The acquired assets are included in our Natural Gas Pipelines business segment.

Kinetrex Energy Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets are included as part of our new Energy Transition Ventures group within our CO2 business segment.

Sale of an Interest in NGPL Holdings LLC

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 $412 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the nine months ended September 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

February 2021 Winter Storm

Our year-to-date earnings reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below. Some of the transactions executed during the winter storm remain subject to risks, including counterparty financial risk, potential disputed purchases and sales and potential legislative or regulatory action in response to, or litigation arising out of, the unprecedented circumstances of the winter storm, which could adversely affect our future earnings, cash flows and financial condition.

2021 Dividends and Discretionary Capital

We expect to declare dividends of $1.08 per share for 2021, a 3% increase from the 2020 declared dividends of $1.05 per share. Excluding the recent acquisitions, we expect to invest $0.8 billion in expansion projects and contributions to joint ventures during 2021.

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The expectations for 2021 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 8, “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 nine months ended September 30, 2021 and 2020 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, 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, 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 (loss) per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

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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 “—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. In prior periods Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—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 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 September 30, 2021, by subtracting the following amounts from our debt balance of $32,824 million: (i) cash and cash equivalents of $102 million; (ii) debt fair value adjustments of $1,014 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $90 million for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that 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 September 30,
	2021		2020		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,069	$	1,091	$	(22)	(2)	%
Products Pipelines	279		223		56		25	%
Terminals	216		246		(30)		(12)	%
CO2	163		156		7		4	%
Total Segment EBDA	1,727		1,716		11		1	%
DD&A	(526)		(539)		13		2	%
Amortization of excess cost of equity investments	(21)		(32)		11		34	%
General and administrative and corporate charges	(167)		(150)		(17)		(11)	%
Interest, net	(368)		(383)		15		4	%
Income before income taxes	645		612		33		5	%
Income tax expense	(134)		(140)		6		4	%
Net income	511		472		39		8	%
Net income attributable to noncontrolling interests	(16)		(17)		1		6	%
Net income attributable to Kinder Morgan, Inc.	$	495	$	455	$	40	9	%

	Nine Months Ended September 30,
	2021		2020		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	2,602	$	2,284	$	318	14	%
Products Pipelines	792		719		73		10	%
Terminals	689		732		(43)		(6)	%
CO2	599		(453)		1,052		232	%
Total Segment EBDA	4,682		3,282		1,400		43	%
DD&A	(1,595)		(1,636)		41		3	%
Amortization of excess cost of equity investments	(56)		(99)		43		43	%
General and administrative and corporate charges	(465)		(472)		7		1	%
Interest, net	(1,122)		(1,214)		92		8	%
Income (loss) before income taxes	1,444		(139)		1,583		1,139	%
Income tax expense	(248)		(304)		56		18	%
Net income (loss)	1,196		(443)		1,639		370	%
Net income attributable to noncontrolling interests	(49)		(45)		(4)		(9)	%
Net income (loss) attributable to Kinder Morgan, Inc.	$	1,147	$	(488)	$	1,635	335	%

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

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Net income attributable to Kinder Morgan, Inc. increased $40 million and $1,635 million for the three and nine months ended September 30, 2021, respectively, as compared to the respective prior year periods. The third quarter increase in results were impacted by higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals and Natural Gas Pipelines business segments and higher general and administrative and corporate charges expense. The year-to-date increase was primarily impacted by higher earnings from our Natural Gas Pipelines and CO2 business segments primarily related to the February 2021 winter storm and therefore largely nonrecurring, and a decrease of $362 million of impairments in 2021 as compared to 2020 primarily reflecting the $1,600 million pre-tax non-cash asset impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in 2021 compared to the combined $1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO2 business segment. The impacts of the long-lived asset impairments for both periods were partially offset by associated tax benefits. The year-to-date increase was also impacted by higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals business segment.

Certain Items Affecting Consolidated Earnings Results

	Three Months Ended September 30,
	2021						2020
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,069	$	21	$	1,090	$	1,091	$	(9)	$	1,082	$	8
Products Pipelines	279		1		280		223		46		269		11
Terminals	216		17		233		246		—		246		(13)
CO2	163		(9)		154		156		(2)		154		—
Total Segment EBDA(a)	1,727		30		1,757		1,716		35		1,751		6
DD&A and amortization of excess cost of equity investments	(547)		—		(547)		(571)		—		(571)		24
General and administrative and corporate charges(a)	(167)		—		(167)		(150)		11		(139)		(28)
Interest, net(a)	(368)		(8)		(376)		(383)		(8)		(391)		15
Income before income taxes	645		22		667		612		38		650		17
Income tax expense(b)	(134)		(12)		(146)		(140)		(8)		(148)		2
Net income	511		10		521		472		30		502		19
Net income attributable to noncontrolling interests(a)	(16)		—		(16)		(17)		—		(17)		1
Net income attributable to Kinder Morgan, Inc.	$	495	$	10	$	505	$	455	$	30	$	485	$	20

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	Nine Months Ended September 30,
	2021						2020
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	2,602	$	1,646	$	4,248	$	2,284	$	993	$	3,277	$	971
Products Pipelines	792		44		836		719		50		769		67
Terminals	689		17		706		732		—		732		(26)
CO2	599		(3)		596		(453)		938		485		111
Total Segment EBDA(a)	4,682		1,704		6,386		3,282		1,981		5,263		1,123
DD&A and amortization of excess cost of equity investments	(1,651)		—		(1,651)		(1,735)		—		(1,735)		84
General and administrative and corporate charges(a)	(465)		—		(465)		(472)		36		(436)		(29)
Interest, net(a)	(1,122)		(17)		(1,139)		(1,214)		(8)		(1,222)		83
Income (loss) before income taxes	1,444		1,687		3,131		(139)		2,009		1,870		1,261
Income tax expense(b)	(248)		(439)		(687)		(304)		(114)		(418)		(269)
Net income (loss)	1,196		1,248		2,444		(443)		1,895		1,452		992
Net income attributable to noncontrolling interests(a)	(49)		—		(49)		(45)		—		(45)		(4)
Net income (loss) attributable to Kinder Morgan, Inc.	$	1,147	$	1,248	$	2,395	$	(488)	$	1,895	$	1,407	$	988

(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 attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) increased by $20 million and $988 million for the three and nine months ended September 30, 2021, respectively, as compared to the respective prior year periods. The third quarter increase was primarily due to higher earnings from our Products Pipelines and Natural Gas Pipelines business segments and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment. The year-to-date increase was impacted by higher earnings from our Natural Gas Pipelines and CO2 business segments primarily related to the February 2021 winter storm, and therefore largely nonrecurring, higher earnings from our Products Pipelines business segment and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment.

39

Non-GAAP Financial Measures

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	495	$	455	$	1,147	$	(488)
Total Certain Items	10		30		1,248		1,895
Adjusted Earnings(a)	505		485		2,395		1,407
DD&A and amortization of excess cost of equity investments for DCF(b)	612		662		1,854		2,012
Income tax expense for DCF(a)(b)	165		171		754		484
Cash taxes(b)	(12)		(49)		(56)		(57)
Sustaining capital expenditures(b)	(241)		(177)		(558)		(477)
Other items(c)	(16)		(7)		(22)		(22)
DCF	$	1,013	$	1,085	$	4,367	$	3,347

Adjusted Segment EBDA to Adjusted EBITDA to DCF

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Natural Gas Pipelines	$	1,090	$	1,082	$	4,248	$	3,277
Products Pipelines	280		269		836		769
Terminals	233		246		706		732
CO2	154		154		596		485
Adjusted Segment EBDA(a)	1,757		1,751		6,386		5,263
General and administrative and corporate charges(a)	(167)		(139)		(465)		(436)
Joint venture DD&A and income tax expense(a)(b)	84		114		270		343
Net income attributable to noncontrolling interests(a)	(16)		(17)		(49)		(45)
Adjusted EBITDA	1,658		1,709		6,142		5,125
Interest, net(a)	(376)		(391)		(1,139)		(1,222)
Cash taxes(b)	(12)		(49)		(56)		(57)
Sustaining capital expenditures(b)	(241)		(177)		(558)		(477)
Other items(c)	(16)		(7)		(22)		(22)
DCF	$	1,013	$	1,085	$	4,367	$	3,347
Adjusted Earnings per share	$	0.22	$	0.21	$	1.05	$	0.62
Weighted average shares outstanding for dividends(d)	2,279		2,276		2,278		2,276
DCF per share	$	0.44	$	0.48	$	1.92	$	1.47
Declared dividends per share	$	0.27	$	0.2625	$	0.81	$	0.7875

(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.

40

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)(a)	$	495	$	455	$	1,147	$	(488)
Certain Items:
Fair value amortization	(7)		(5)		(15)		(17)
Legal, environmental and taxes other than income tax reserves	—		46		112		38
Change in fair value of derivative contracts(b)	22		(6)		64		(10)
Loss on impairments, divestitures and other write-downs, net(c)	4		11		1,515		382
Loss on impairments of goodwill(d)	—		—		—		1,600
COVID-19 costs	—		11		—		11
Income tax Certain Items	(12)		(8)		(439)		(114)
Other	3		(19)		11		5
Total Certain Items(e)	10		30		1,248		1,895
DD&A and amortization of excess cost of equity investments	547		571		1,651		1,735
Income tax expense(f)	146		148		687		418
Joint venture DD&A and income tax expense(f)(g)	84		114		270		343
Interest, net(f)	376		391		1,139		1,222
Adjusted EBITDA	$	1,658	$	1,709	$	6,142	$	5,125

(a)In prior periods, Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.

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

(c)Three and nine months ended September 30, 2021 amounts include a non-cash impairment of $14 million related to the reclassification of an asset to held for sale within our Terminals business segment, offset partially by a gain of $10 million on the sale of assets within our CO2 business segment. Nine months ended September 30, 2021 amount also includes 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 lower expectations regarding the volumes and rates associated with re-contracting and a write-down of $117 million, reported within “Earnings from equity investments” on the accompanying consolidated statement of operations, on a long-term subordinated note receivable from an equity investee, Ruby, offset partially by a pre-tax gain of $206 million, reported within “Other, net” on the accompanying consolidated statement of operations, associated with the sale of a partial interest in our equity investment in NGPL Holdings. Nine months ended September 30, 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment. Except as otherwise noted above, these amounts are reported within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of operations.

(d)Nine months ended September 30, 2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, respectively.

(e)Three months ended September 30, 2021 and 2020 amounts include $2 million and $(4) million, respectively, and nine months ended September 30, 2021 and 2020 amounts include $129 million and $(4) million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.

(f)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.

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

41

Supplemental Information

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
DD&A (GAAP)	$	526	$	539	$	1,595	$	1,636
Amortization of excess cost of equity investments (GAAP)	21		32		56		99
DD&A and amortization of excess cost of equity investments	547		571		1,651		1,735
Joint venture DD&A	65		91		203		277
DD&A and amortization of excess cost of equity investments for DCF	$	612	$	662	$	1,854	$	2,012
Income tax expense (GAAP)	$	134	$	140	$	248	$	304
Certain Items	12		8		439		114
Income tax expense(a)	146		148		687		418
Unconsolidated joint venture income tax expense(a)(b)	19		23		67		66
Income tax expense for DCF(a)	$	165	$	171	$	754	$	484
Additional joint venture information
Unconsolidated joint venture DD&A	$	76	$	101	$	236	$	306
Less: Consolidated joint venture partners’ DD&A	11		10		33		29
Joint venture DD&A	65		91		203		277
Unconsolidated joint venture income tax expense(a)(b)	19		23		67		66
Joint venture DD&A and income tax expense(a)	$	84	$	114	$	270	$	343
Unconsolidated joint venture cash taxes(b)	$	(13)	$	(41)	$	(47)	$	(51)
Unconsolidated joint venture sustaining capital expenditures	$	(29)	$	(32)	$	(81)	$	(84)
Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(2)		(5)		(4)
Joint venture sustaining capital expenditures	$	(27)	$	(30)	$	(76)	$	(80)

(a)Amounts are adjusted for Certain Items.

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

42

Segment Earnings Results

Natural Gas Pipelines

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	2,555	$	1,809	$	8,656	$	5,255
Operating expenses	(1,634)		(878)		(4,981)		(2,455)
Loss on impairments and divestitures, net	—		(11)		(1,599)		(1,011)
Other income	—		—		2		1
Earnings from equity investments	144		169		311		484
Other, net	4		2		213		10
Segment EBDA	1,069		1,091		2,602		2,284
Certain Items(a)	21		(9)		1,646		993
Adjusted Segment EBDA	$	1,090	$	1,082	$	4,248	$	3,277
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	8			$	971
Volumetric data(b)
Transport volumes (BBtu/d)	38,527		37,475		38,593		37,887
Sales volumes (BBtu/d)	2,616		2,382		2,480		2,330
Gathering volumes (BBtu/d)	2,808		2,925		2,662		3,109
NGLs (MBbl/d)	29		22		30		27

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $21 million and $1,646 million for the three and nine months ended September 30, 2021, respectively, and $(9) million and $993 million for the three and nine months ended September 30, 2020, respectively. Three and nine months ended September 30, 2021 amounts include decreases in revenues of $14 million and $36 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash asset impairment loss of $1,600 million resulting from lower expectations regarding the volumes and rates associated with re-contracting related to our South Texas gathering and processing assets, 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 partially offset by a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings. Three and nine months ended September 30, 2020 amounts both include an increase in revenues of $(14) million of amortization of regulatory liabilities, largely offset by non-cash amounts related to mark-to-market derivative contracts. Nine months ended September 30, 2020 amount also includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit.

Other

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

43

Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Midstream	$	29	11%
East Region	8		1%
West Region	(29)		(11)%
Total Natural Gas Pipelines	$	8	1	%

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Midstream	$	998	123%
East Region	25		1%
West Region	(52)		(7)%
Total Natural Gas Pipelines	$	971	30	%

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 nine-month periods ended September 30, 2021 and 2020:

•$29 million (11%) and $998 million (123%) increases, respectively, in Midstream were primarily due to (i) higher equity earnings due to the Permian Highway Pipeline being placed in service in January 2021; (ii) higher sales margins driven by higher commodity prices on our Texas intrastate natural gas pipeline operations; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets. The year-to-date increase was also impacted by higher commodity prices as a result of the February 2021 winter storm on our South Texas assets and Texas intrastate natural gas pipeline operations partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations on our Oklahoma assets. Overall Midstream’s revenues increased primarily due to higher commodity prices which was partially offset by corresponding increases in costs of sales;

•$8 million (1%) and $25 million (1%) increases, respectively, in the East Region were primarily due to our July 2021 acquisition of the Stagecoach assets partially offset by lower earnings on Fayetteville Express Pipeline LLC driven by lower revenues resulting from contract expirations. The year-to-date increase was also impacted by higher earnings from TGP due to weather-driven increases in reservation and park and loan revenues mostly during the first quarter of 2021 and increased earnings from Elba Liquefaction Company, L.L.C. resulting from the liquefaction units of the Elba Liquefaction project being fully operational as of August 2020; and

•$29 million (11%) and $52 million (7%) decreases, respectively, in the West Region were primarily due to lower earnings from Wyoming Interstate Company, LLC, Colorado Interstate Gas Company, L.L.C. and Cheyenne Plains Gas Pipeline Company, L.L.C. driven by lower revenues due to contract expirations and lower equity earnings from Ruby. The third quarter decrease was also impacted by lower earnings from EPNG driven by lower park and loan revenues.

44

Products Pipelines

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	605	$	442	$	1,572	$	1,282
Operating expenses	(341)		(233)		(828)		(585)
Loss on impairments and divestitures, net	—		—		—		(21)
Earnings from equity investments	15		14		48		42
Other, net	—		—		—		1
Segment EBDA	279		223		792		719
Certain Items(a)	1		46		44		50
Adjusted Segment EBDA	$	280	$	269	$	836	$	769
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	11			$	67
Volumetric data(b)
Gasoline(c)	1,023		941		987		888
Diesel fuel	389		383		395		371
Jet fuel	250		160		217		184
Total refined product volumes	1,662		1,484		1,599		1,443
Crude and condensate	491		530		503		570
Total delivery volumes (MBbl/d)	2,153		2,014		2,102		2,013

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $1 million and $44 million for the three and nine months ended September 30, 2021, respectively, and $46 million and $50 million for the three and nine months ended September 30, 2020, respectively. Nine month 2021 amount includes increases in expense of $28 million and $15 million related to a litigation reserve and an environmental reserve adjustment, respectively. Three and nine month 2020 amounts both include a $46 million unfavorable rate case reserve adjustment. Nine month 2020 amount also includes a non-cash loss on impairment of our Belton Terminal of $21 million partially offset by a $17 million favorable adjustment for tax reserves, other than income taxes.

Other

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

(c)Volumes include ethanol pipeline volumes.

45

Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	17	15	%
Southeast Refined Products	6		10	%
Crude and Condensate	(12)		(12)	%
Total Products Pipelines	$	11	4	%

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	38	11	%
Southeast Refined Products	39		25	%
Crude and Condensate	(10)		(4)	%
Total Products Pipelines	$	67	9	%

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 nine-month periods ended September 30, 2021 and 2020:

•$17 million (15%) and $38 million (11%) increases, respectively, in West Coast Refined Products were primarily due to increased earnings on Pacific (SFPP), and to a lesser extent, on Calnev Pipe Line LLC and West Coast terminals driven by higher revenues from the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expense primarily as a result of higher integrity management spending on SFPP;

•$6 million (10%) and $39 million (25%) increases, respectively, in Southeast Refined Products were primarily due to South East Terminals resulting from increased revenues from higher volumes driven by continued recovery of volumes from 2020. The year-to-date increase was also driven by higher 2021 earnings at our Transmix processing operations primarily due to higher prices and first quarter 2020 unfavorable inventory adjustments, and an increase in equity earnings from Products (SE) Pipe Line primarily due to product net gains resulting from higher prices; and

•$12 million (12%) and $10 million (4%) decreases, respectively, in Crude and Condensate were primarily due to decreased earnings from the Bakken Crude assets and KM Condensate Processing Facility (KMCC - Splitter) partially offset by increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC). The Bakken Crude assets’ decreased earnings were driven by lower volumes, contracts renewed at lower average rates, and contract expirations partially offset by lower field operating expenses. KMCC - Splitter’s decreased earnings were driven by higher field maintenance expenses. KMCC’s increased earnings were primarily due to higher deficiency revenues and lower field operating expense partially offset by contract expirations. Bakken Crude assets’ and KMCC’s year-to-date changes respectively, were also impacted by first quarter 2020 unfavorable inventory valuation adjustments. In addition, increased marketing activities within KMCC have resulted in third quarter and year-to-date increases in revenues with corresponding increases in cost of sales.

46

Terminals

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(In millions, except operating statistics)
Revenues	$	422		$	424		$	1,275		$	1,285
Operating expenses	(200)			(185)			(588)			(570)
Loss on impairments and divestitures, net	(14)			—			(14)			(5)
Other income	4			—			4			—
Earnings from equity investments	3			7			10			19
Other, net	1			—			2			3
Segment EBDA	216			246			689			732
Certain Items(a)	17			—			17			—
Adjusted Segment EBDA	$	233		$	246		$	706		$	732
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	(13)					$	(26)
Volumetric data(b)
Liquids leasable capacity (MMBbl)	79.9			79.6			79.9			79.6
Liquids utilization %(c)	94.2		%	96.3		%	94.2		%	96.3		%
Bulk transload tonnage (MMtons)	13.5			11.3			38.1			35.4

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $17 million for both three and nine months ended September 30, 2021 primarily resulting from a pre-tax non-cash impairment loss of $14 million related to the reclassification of an asset to held for sale.

Other

(b)Volumes for assets sold are excluded for all periods presented.

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

47

Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Marine operations	$	(15)	(29)	%
Gulf Central	5		19	%
Mid Atlantic	4		40	%
Northeast	(2)		(7)	%
All others (including intrasegment eliminations)	(5)		(4)	%
Total Terminals	$	(13)	(5)	%

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Marine operations	$	(39)	(25)	%
Gulf Central	(7)		(8)	%
Mid Atlantic	8		21	%
Northeast	9		13	%
All others (including intrasegment eliminations)	3		1	%
Total Terminals	$	(26)	(4)	%

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 nine-month periods ended September 30, 2021 and 2020:

•$15 million (29%) and $39 million (25%) decreases, respectively, in Marine operations were primarily due to lower fleet utilization and average charter rates;

•$5 million (19%) increase and $7 million (8%) decrease, respectively, in the Gulf Central terminals. The third quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol, petroleum coke, and coal volumes. The year-to-date decrease in earnings was primarily driven by unfavorable petroleum coke volumes due to refinery outages associated with the February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC;

•$4 million (40%) and $8 million (21%) increases, respectively, in the Mid Atlantic terminals were primarily due to higher coal volumes at our Pier IX facility; and

•$2 million (7%) decrease and $9 million (13%) increase, respectively, in the Northeast terminals. The year-to-date increase was primarily driven by increased revenues associated with higher throughput levels and new contracts.

48

CO2

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	257	$	251	$	729	$	792
Operating expenses	(112)		(99)		(161)		(312)
Gain (loss) on impairments and divestitures, net	11		—		8		(950)
Earnings from equity investments	7		4		23		17
Segment EBDA	163		156		599		(453)
Certain Items(a)	(9)		(2)		(3)		938
Adjusted Segment EBDA	$	154	$	154	$	596	$	485
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	—			$	111
Volumetric data
SACROC oil production	20.1		21.2		19.9		22.1
Yates oil production	6.5		6.4		6.5		6.7
Katz and Goldsmith oil production	2.1		2.6		2.3		2.8
Tall Cotton oil production	1.1		1.4		1.0		1.9
Total oil production, net (MBbl/d)(b)	29.8		31.6		29.7		33.5
NGL sales volumes, net (MBbl/d)(b)	9.7		9.1		9.3		9.4
CO2 sales volumes, net (Bcf/d)	0.4		0.4		0.4		0.5
Realized weighted average oil price ($ per Bbl)	$	53.03	$	54.83	$	52.21	$	53.28
Realized weighted average NGL price ($ per Bbl)	$	28.01	$	17.65	$	23.73	$	17.77

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $(9) million and $(3) million for the three and nine months ended September 30, 2021, respectively, and $(2) million and $938 million for the three and nine months ended September 30, 2020, respectively. Nine month 2020 amount primarily resulted from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on our oil and gas producing assets.

Other

(b)Net of royalties and outside working interests.

Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing activities	$	(42)	(40)	%
Source and Transportation activities	40		82	%
Subtotal	(2)		(1)	%
Energy Transition Ventures	2		n/a
Total CO2	$	—	—	%

49

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing activities	$	73	23	%
Source and Transportation activities	36		22	%
Subtotal	109		22	%
Energy Transition Ventures	2		n/a
Total CO2	$	111	23	%

n/a - not applicable

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 nine-month periods ended September 30, 2021 and 2020:

•$42 million (40%) decrease and $73 million (23%) increase, respectively, in Oil and Gas Producing activities. The third quarter decrease was primarily due to a settlement for a terminated affiliate purchase contract with Source and Transportation activities which increased operating expenses by $38 million and lower crude oil sales revenues of $14 million due to lower volumes and realized prices partially offset by higher realized NGL prices which increased revenues by $12 million. The year-to-date increase was primarily due to lower operating expenses of $118 million driven by a benefit in the 2021 period realized from returning power to the grid by curtailing oil production during the February 2021 winter storm, net of the impact of the terminated affiliate contract noted above, and higher realized NGL prices which increased revenues by $27 million, partially offset by lower crude oil volumes which decreased revenues by $45 million, driven in part, by the curtailed oil production and by lower realized crude oil prices which decreased revenues by $22 million; and

•$40 million (82%) and $36 million (22%) increases, respectively, in Source and Transportation activities primarily due to a settlement for a terminated affiliate sales contract with Oil and Gas Producing activities which resulted in an increase in revenues of $38 million. The year-to-date increase was also impacted by a decrease in revenues of $19 million related to lower CO2 sales volumes partially offset by an increase in equity earnings of $6 million and lower operating expenses of $5 million.

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 September 30, 2021.

	Remaining 2021		2022		2023		2024		2025
Crude Oil(a)
Price ($ per Bbl)	$	50.38	$	53.41	$	51.70	$	50.97	$	52.19
Volume (MBbl/d)	25.70		17.00		11.20		5.90		2.85
NGLs
Price ($ per Bbl)	$	36.39	$	47.76
Volume (MBbl/d)	6.03		2.56
Midland-to-Cushing Basis Spread
Price ($ per Bbl)	$	0.26	$	0.59
Volume (MBbl/d)	24.55		14.00

(a)Includes West Texas Intermediate hedges.

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

	Three Months Ended September 30,				Earnings increase/(decrease)
	2021		2020
	(In millions, except percentages)
DD&A (GAAP)	$	(526)	$	(539)	$	13	2	%
General and administrative (GAAP)	$	(174)	$	(153)	$	(21)	(14)	%
Corporate benefit	7		3		4		133	%
Certain Items(a)	—		11		(11)		(100)	%
General and administrative and corporate charges(b)	$	(167)	$	(139)	$	(28)	(20)	%
Interest, net (GAAP)	$	(368)	$	(383)	$	15	4	%
Certain Items(c)	(8)		(8)		—		—	%
Interest, net(b)	$	(376)	$	(391)	$	15	4	%
Net income attributable to noncontrolling interests (GAAP)	$	(16)	$	(17)	$	1	6	%
Certain Items(d)	—		—		—		—	%
Net income attributable to noncontrolling interests(b)	$	(16)	$	(17)	$	1	6	%

	Nine Months Ended September 30,				Earnings increase/(decrease)
	2021		2020
	(In millions, except percentages)
DD&A (GAAP)	$	(1,595)	$	(1,636)	$	41	3	%
General and administrative (GAAP)	$	(490)	$	(461)	$	(29)	(6)	%
Corporate benefit (charges)	25		(11)		36		327	%
Certain Items(a)	—		36		(36)		(100)	%
General and administrative and corporate charges(b)	$	(465)	$	(436)	$	(29)	(7)	%
Interest, net (GAAP)	$	(1,122)	$	(1,214)	$	92	8	%
Certain Items(c)	(17)		(8)		(9)		(113)	%
Interest, net(b)	$	(1,139)	$	(1,222)	$	83	7	%
Net income attributable to noncontrolling interests (GAAP)	$	(49)	$	(45)	$	(4)	(9)	%
Certain Items(d)	—		—		—		—	%
Net income attributable to noncontrolling interests(b)	$	(49)	$	(45)	$	(4)	(9)	%

Certain items

(a)Three and nine month 2020 amounts both include an increase in expense of $11 million related to costs incurred associated with COVID-19 mitigation. Nine month 2020 amount also includes an increase in expense of $23 million associated with the non-cash fair value adjustment of and the dividend accrual prior to the sale of our investment in Pembina common stock.

(b)Amounts are adjusted for Certain Items.

(c)Three and nine month 2021 amounts include decreases in interest expense of $7 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and nine month 2020 amounts include (i) decreases in interest expense of $5 million and $17 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) a decrease in expense of $3 million and an increase in expense of $11 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.

(d)Three and nine months ended September 30, 2021 and 2020 amounts each include less than $1 million of noncontrolling interests associated with Certain Items.

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General and administrative expenses and corporate charges adjusted for Certain Items for the three and nine months ended September 30, 2021 when compared with the respective prior year periods increased $28 million and $29 million, respectively, primarily due to lower capitalized costs of $18 million and $41 million, respectively, reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment, non-recurring cost savings realized in the 2020 period as a result of the global pandemic of $10 million and $17 million, respectively, and higher benefit-related costs of $10 million and $16 million, respectively, partially offset by $12 million and $36 million, respectively, of cost savings in the 2021 period associated with organizational efficiency efforts, and lower pension costs of $4 million and $14 million, respectively.

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 nine months ended September 30, 2021 when compared with the respective prior year periods decreased $15 million and $83 million, respectively, primarily due to lower long-term debt balances, lower LIBOR rates, and lower long-term interest rates, partially offset by lower capitalized interest.

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 September 30, 2021 and December 31, 2020, approximately 15% and 16%, 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. The percentage at September 30, 2021 includes our variable-to-fixed interest rate derivative contracts not designated as hedging instruments which hedge our exposure through 2021. For more information on our interest rate swaps, see Note 6 “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 September 30, 2021 was approximately $134 million as compared with $140 million of expense for the same period of 2020. The $6 million decrease in tax expense was due to a slightly lower 2021 effective tax rate caused by multiple factors.

Our tax expense for the nine months ended September 30, 2021 was approximately $248 million as compared with $304 million of expense for the same period of 2020. The $56 million decrease in tax expense was due primarily to (i) the prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment, (ii) higher dividend-received deductions in 2021, and (iii) the current year release of the valuation allowance on our investment in NGPL Holdings, partially offset by federal and state taxes on higher pre-tax book income in 2021 and the refund of alternative minimum tax sequestration credits in 2020.

Liquidity and Capital Resources

General

As of September 30, 2021, we had $102 million of “Cash and cash equivalents,” a decrease of $1,082 million from December 31, 2020. We used $1.2 billion of cash on hand to complete the acquisition on July 9, 2021 of subsidiaries of Stagecoach. Additionally, as of September 30, 2021, we had borrowing capacity of approximately $3.8 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 $4,440 million and $3,282 million in the first nine months of 2021 and 2020, respectively. The period-to-period increase 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.

Our board of directors declared a quarterly dividend of $0.27 per share for the third quarter of 2021, consistent with the dividend declared for the previous quarter. We expect to fully fund our dividend payments as well as our discretionary spending for 2021 without funding from the capital markets.

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On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million which were used to repay maturing senior notes.

On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 and amended our existing facility (the “Existing Facility”) to reduce the borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder (together, the “Credit Facilities”).

Short-term Liquidity

As of September 30, 2021, 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 New 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. We do not anticipate any significant limitations from the impacts of COVID-19 with respect to our ability to access funding through our Credit Facilities.

As of September 30, 2021, our $2,822 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through cash on hand, 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, 2020 was $2,558 million.

We had working capital (defined as current assets less current liabilities) deficits of $3,139 million and $1,871 million as of September 30, 2021 and December 31, 2020, 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 $1,268 million unfavorable change from year-end 2020 was primarily due to (i) a $1,082 million decrease in cash and cash equivalents primarily resulting from utilizing cash on hand to acquire subsidiaries of Stagecoach; (ii) a net unfavorable short-term fair value adjustment of $253 million on derivative contract assets and liabilities in 2021; (iii) an increase in accounts payable, net of change in accounts receivable, of $212 million; (iv) a $160 million increase in commercial paper borrowings; and (iv) an increase of $104 million in senior notes that mature in the next twelve months, partially offset by (i) a $193 million decrease in accrued interest; (ii) an increase of $152 million in restricted deposits primarily related to margin calls in our derivative activities; (iii) a $109 million increase in inventories, primarily storage gas and product inventories; and (iv) a $61 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.

Counterparty Creditworthiness

Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices, or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. The balance of our allowance for credit losses as of September 30, 2021 and December 31, 2020, was $2 million and $26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets.

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 that 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

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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 that 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 a maintenance/sustaining or as an expansion capital expenditure 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 nine months ended September 30, 2021, and the amount we expect to spend for the remainder of 2021 to sustain and grow our businesses are as follows:

	Nine Months Ended September 30, 2021		2021 Remaining		Total 2021
	(In millions)
Sustaining capital expenditures(a)(b)	$	558	$	300	$	858
Discretionary capital investments(b)(c)(d)	2,049		256		2,305

(a)Nine months ended September 30, 2021, 2021 Remaining, and Total 2021 amounts include $76 million, $31 million, and $107 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “Non-GAAP Financial Measures—Supplemental Information.”

(b)Nine months ended September 30, 2021 amount excludes $6 million due to increases in accrued capital expenditures and contractor retainage and net changes in other.

(c)Nine months ended September 30, 2021 amount includes $135 million of our contributions to certain unconsolidated joint ventures for capital investments. Both Nine months ended September 30, 2021 and Total 2021 amounts also include $1,508 million for our acquisitions of Stagecoach and Kinetrex.

(d)Amounts include our actual or estimated contributions to certain equity investees, 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, 2020 in our 2020 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2021 and December 31, 2020 were $201 million and $141 million, respectively. The increase of $60 million was primarily driven by capital commitments related to our Terminals business segment.

Cash Flows

Operating Activities

Cash provided by operating activities increased $1,158 million in the nine months ended September 30, 2021 compared to the respective 2020 period primarily due to:

•a $1,206 million increase in cash after adjusting the $1,639 million increase in net income by $433 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) loss from impairments and divestitures, net (see discussion above in “—Results of Operations”); (ii) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “—General and Basis of Presentation”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred

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income taxes; and (v) earnings from equity investments (including a non-cash write-down of a related party note receivable from Ruby); partially offset by,

•a $48 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by payments for litigation matters in the 2021 period which was partially offset by a net increase in working capital items and higher distributions from equity investment earnings in the 2021 period compared to the 2020 period.

Investing Activities

Cash used in investing activities increased $1,135 million for the nine months ended September 30, 2021 compared to the respective 2020 period primarily attributable to:

•a $1,502 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,197 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 2 “Acquisitions” to our consolidated financial statements for further information regarding these transactions; and

•a $490 million decrease in cash primarily due to $412 million of net proceeds received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period, versus the $907 million of proceeds received from the sale of Pembina shares in the 2020 period. See Note 3 “Losses and Gains on Impairments, Divestitures and Other Write-downs” to our consolidated financial statements for further information regarding the transaction of the sale of an interest in NGPL Holdings; partially offset by,

•a $457 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and

•a $329 million decrease in cash used for contributions to equity investees driven primarily by lower contributions to Permian Highway Pipeline LLC and SNG in the 2021 period compared with the 2020 period.

Financing Activities

Cash used in financing activities increased $1,446 million for the nine months ended September 30, 2021 compared to the respective 2020 period primarily attributable to:

•a $1,403 million net increase in cash used related to debt activity as a result of higher net debt payments in the 2021 period compared to the 2020 period.

Dividends

We expect to declare dividends of $1.08 per share on our stock for 2021. The table below reflects our 2021 dividends declared:

Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
March 31, 2021	$	0.27	April 21, 2021	April 30, 2021	May 17, 2021
June 30, 2021	0.27		July 21, 2021	August 2, 2021	August 16, 2021
September 30, 2021	0.27		October 20, 2021	November 1, 2021	November 15, 2021

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 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 2020 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 are expected to 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, 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 subsidiary issuers and guarantors, 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 September 30, 2021.”

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 September 30, 2021 and December 31, 2020, the Obligated Group had $30,994 million and $32,563 million, respectively, of Guaranteed Notes outstanding.

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

Summarized Combined Balance Sheet Information	September 30, 2021		December 31, 2020
	(In millions)
Current assets	$	2,412	$	2,957
Current assets - affiliates	1,118		1,151
Noncurrent assets	62,129		61,783
Noncurrent assets - affiliates	507		616
Total Assets	$	66,166	$	66,507
Current liabilities	$	5,390	$	4,528
Current liabilities - affiliates	1,269		1,209
Noncurrent liabilities	31,803		33,907
Noncurrent liabilities - affiliates	1,006		1,078
Total Liabilities	39,468		40,722
Redeemable noncontrolling interest	661		728
Kinder Morgan, Inc.’s stockholders’ equity	26,037		25,057
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	66,166	$	66,507

Summarized Combined Income Statement Information	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	(In millions)
Revenues	$	3,472	$	11,211
Operating income	699		1,697
Net income	373		937

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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, 2020, in Item 7A in our 2020 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 6 “Risk Management” to our consolidated financial statements.

Item 4.  Controls and Procedures.

As of September 30, 2021, 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 September 30, 2021 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 10 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 2020 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 6 “Risk Management” to our consolidated financial statements.

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

None. 

Item 3.  Defaults Upon Senior Securities.

None. 

Item 4.  Mine Safety Disclosures.

The Company does 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), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. The Company has 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 September 30, 2021.

Item 5.  Other Information.

Effective October 20, 2021, our board of directors approved the Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (the “Amended Director Plan”), which amends and restates the previous Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors dated January 1, 2015, as

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amended (the “Previous Plan”). The Amended Director Plan amends and restates the Previous Plan to increase the number of shares available for issuance under the Amended Director Plan.

The Amended Director Plan is administered by our Compensation Committee, and our board of directors has sole discretion to terminate the plan at any time. The Amended Director Plan recognizes that the compensation to be paid to each non-employee director is fixed by our board of directors, and that the compensation is payable in cash. Under the plan, in lieu of receiving some or all of the compensation in cash, non-employee directors, referred to as “eligible directors,” may elect to receive shares of our common stock. Each election generally will be at or around the first board of directors meeting in January of each year and will be effective for the entire calendar year. An eligible director may make a new election each year. The total number of shares of common stock authorized under the plan is 1,190,000.

Each annual election to receive shares of common stock will be evidenced by an agreement between us and the electing director that will contain the terms and conditions of such election. Shares issued under the plan pursuant to an election may be subject to forfeiture restrictions that lapse on the earlier of the director’s death or the date set forth in the agreement, which will be no later than the end of the calendar year to which the cash compensation relates. Until the forfeiture restrictions lapse, shares issued under the plan may not be sold, assigned, transferred, exchanged or pledged by an eligible director. In the event a director’s service as a director is terminated prior to the lapse of the forfeiture restrictions for any reason other than death or the director’s failure to be elected as a director at a stockholders meeting at which the director is considered for election, the director will, for no consideration, forfeit to us all shares then subject to the restrictions. If, prior to the lapse of the restrictions, the director is not elected as a director at a stockholders meeting at which the director is considered for election, the restrictions will lapse with respect to 50% of the director’s shares then subject to such restrictions, and the director will, for no consideration, forfeit to us the remaining shares.

The number of shares to be issued to an eligible director electing to receive any portion of annual compensation in the form of shares will equal the dollar amount elected to be received in the form of shares, divided by the closing price of our common stock on the NYSE on the day the cash compensation is awarded or, if the NYSE is not open for trading on such day, the most recent trading day (the fair market value), rounded up to the nearest ten shares. An eligible director electing to receive any portion of annual compensation in the form of shares will receive cash equal to the difference between:

•the total cash compensation awarded to such director and

•the number of shares to be issued to such director with respect to the amount determined by the director, multiplied by the fair market value of a share.

This cash payment will be payable in four equal installments, on or before March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded; provided that the installment payments will be adjusted to include dividend equivalent payments with respect to the shares during the period in which the shares are subject to forfeiture restrictions.

The foregoing is a summary of the principal provisions of the Amended Director Plan. The summary does not purport to be complete and is qualified in its entirety by reference to the full text of the Amended Director Plan, which is filed as Exhibit 10.4.

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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 September 30, 2021.
10.2	*	Revolving Credit Agreement, dated August 20, 2021 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed August 25, 2021 (File No. 001-35081)).
10.3	*	First Amendment to Revolving Credit Agreement, dated August 20, 2021 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to KMI's Current Report on Form 8-K filed August 25, 2021 (File 001-35081)).
10.4		Second Amended and Restated Stock Compensation Plan for Non-Employee Directors.
10.5		2021 Form of Non-Employee Director Stock Compensation Agreement.
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 nine months ended September 30, 2021 and 2020; (ii) our Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2021 and 2020; (iii) our Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2021 and 2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2021 and 2020; 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.

_______

*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.

59

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:	October 22, 2021	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

60

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: September 30, 2021

Issuer	Indebtedness	Maturity
Kinder Morgan, Inc.	1.500% notes	March 16, 2022
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.	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, 2021
Kinder Morgan Energy Partners, L.P.	4.15% bonds	March 1, 2022
Kinder Morgan Energy Partners, L.P.	3.95% bonds	September 1, 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: September 30, 2021
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.	8.625% bonds	January 15, 2022
El Paso Natural Gas Company, L.L.C.	7.50% bonds	November 15, 2026
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: September 30, 2021

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: September 30, 2021
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.	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: September 30, 2021
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	Kinetrex Energy Transportation, LLC
Copano Field Services/Upper Gulf Coast LLC	Kinetrex Holdco, Inc.
Copano Liberty, LLC	Kinder Morgan 2-Mile LLC
Copano Liquids Marketing LLC	Kinder Morgan Administrative Services Tampa LLC
Copano NGL Services (Markham), L.L.C.	Kinder Morgan Altamont LLC
Copano NGL Services LLC	Kinder Morgan Baltimore Transload Terminal LLC
Copano Pipelines Group, L.L.C.	Kinder Morgan Battleground Oil LLC
Copano Pipelines/North Texas, L.L.C.	Kinder Morgan Border Pipeline LLC
Copano Pipelines/Rocky Mountains, LLC	Kinder Morgan Bulk Terminals LLC
Copano Pipelines/South Texas LLC	Kinder Morgan Carbon Dioxide Transportation
Copano Pipelines/Upper Gulf Coast LLC	Company

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: September30, 2021
Kinder Morgan CO2 Company LLC	Kinder Morgan Products Terminals LLC
Kinder Morgan Commercial Services LLC	Kinder Morgan Rail Services LLC
Kinder Morgan Contracting Services LLC	Kinder Morgan Resources II LLC
Kinder Morgan Crude & Condensate LLC	Kinder Morgan Resources III LLC
Kinder Morgan Crude Marketing LLC	Kinder Morgan Resources LLC
Kinder Morgan Crude Oil Pipelines LLC	Kinder Morgan Scurry Connector LLC
Kinder Morgan Crude to Rail LLC	Kinder Morgan Seven Oaks LLC
Kinder Morgan Cushing LLC	Kinder Morgan SNG Operator LLC
Kinder Morgan Dallas Fort Worth Rail Terminal LLC	Kinder Morgan Southeast Terminals LLC
Kinder Morgan Deeprock North Holdco LLC	Kinder Morgan Tank Storage Terminals LLC
Kinder Morgan Endeavor LLC	Kinder Morgan Tejas Pipeline LLC
Kinder Morgan Energy Partners, L.P.	Kinder Morgan Terminals, Inc.
Kinder Morgan Energy Transition Ventures LLC	Kinder Morgan Terminals Wilmington LLC
Kinder Morgan EP Midstream LLC	Kinder Morgan Texas Pipeline LLC
Kinder Morgan Finance Company LLC	Kinder Morgan Texas Terminals, L.P.
Kinder Morgan Freedom Pipeline LLC	Kinder Morgan Transmix Company, LLC
Kinder Morgan Galena Park West LLC	Kinder Morgan Treating LP
Kinder Morgan GP LLC	Kinder Morgan Utica LLC
Kinder Morgan IMT Holdco LLC	Kinder Morgan Vehicle Services LLC
Kinder Morgan, Inc.	Kinder Morgan Virginia Liquids Terminals LLC
Kinder Morgan Keystone Gas Storage LLC	Kinder Morgan Wink Pipeline LLC
Kinder Morgan KMAP LLC	KinderHawk Field Services LLC
Kinder Morgan Las Vegas LLC	KM Crane LLC
Kinder Morgan Linden Transload Terminal LLC	KM Decatur LLC
Kinder Morgan Liquids Terminals LLC	KM Eagle Gathering LLC
Kinder Morgan Liquids Terminals St. Gabriel LLC	KM Gathering LLC
Kinder Morgan Louisiana Pipeline Holding LLC	KM Kaskaskia Dock LLC
Kinder Morgan Louisiana Pipeline LLC	KM Liquids Terminals LLC
Kinder Morgan Marine Services LLC	KM North Cahokia Land LLC
Kinder Morgan Materials Services, LLC	KM North Cahokia Special Project LLC
Kinder Morgan Mid Atlantic Marine Services LLC	KM North Cahokia Terminal Project LLC
Kinder Morgan NatGas O&M LLC	KM Ship Channel Services LLC
Kinder Morgan NGPL Holdings LLC	KM Treating GP LLC
Kinder Morgan North Texas Pipeline LLC	KM Treating Production LLC
Kinder Morgan Operating LLC “A”	KM Utopia Operator LLC
Kinder Morgan Operating LLC “B”	KMBT Legacy Holdings LLC
Kinder Morgan Operating LLC “C”	KMBT LLC
Kinder Morgan Operating LLC “D”	KMGP Services Company, Inc.
Kinder Morgan Pecos LLC	KN Telecommunications, Inc.
Kinder Morgan Pecos Valley LLC	Knight Power Company LLC
Kinder Morgan Petcoke GP LLC	Liberty High BTU LLC
Kinder Morgan Petcoke LP LLC	LNG Indy, LLC
Kinder Morgan Petcoke, L.P.	Lomita Rail Terminal LLC
Kinder Morgan Petroleum Tankers LLC	Milwaukee Bulk Terminals LLC
Kinder Morgan Pipeline LLC	MJR Operating LLC
Kinder Morgan Port Manatee Terminal LLC	Mojave Pipeline Company, L.L.C.
Kinder Morgan Port Sutton Terminal LLC	Mojave Pipeline Operating Company, L.L.C.
Kinder Morgan Port Terminals USA LLC	Paddy Ryan Crane, LLC
Kinder Morgan Portland Jet Line LLC	Palmetto Products Pipe Line LLC
Kinder Morgan Production Company LLC	PI 2 Pelican State LLC

2

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: September30, 2021
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 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
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-10.4

Exhibit 10.4

KINDER MORGAN, INC.SECOND AMENDED AND RESTATED STOCK COMPENSATION PLAN
FOR NON-EMPLOYEE DIRECTORS

1.Purpose of the Plan. The Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (the "Plan") is intended to promote the interests of Kinder Morgan, Inc. (the "Company") and its stockholders by aligning the compensation of the non-employee members of the board of directors of the Company (the "Board") with stockholders' interests.

2.Compensation Committee. The Plan shall be administered by the Compensation Committee of the Board (the "Committee"), which shall be constituted so as to permit the Plan to comply with Rule 16b-3 promulgated by the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Subject to the provisions of the Plan, the Committee shall be authorized to interpret the Plan, to establish, amend and rescind such rules and regulations as it deems necessary for the proper administration of the Plan, and to make all other determinations necessary or advisable for its administration. The Committee may correct any defect or supply any omission or reconcile any inconsistency in the Plan in the manner and to the extent it shall deem desirable to carry it into effect. The interpretation by the Committee of the Plan shall be conclusive upon all participants.

3.Eligible Participants. Only directors of the Company who are not salaried employees of the Company or of an affiliate of the Company (each, a "Non-Employee Director") are eligible to participate in the Plan.

4.Stock Subject to the Plan. The aggregate number of shares of Class P common stock of the Company, $0.01 par value ("Stock"), which may be issued under the Plan shall not exceed 1,190,000, subject to adjustment as provided in Paragraph 7. Stock issued under the Plan shall be either authorized but previously unissued shares of Stock or shares of Stock reacquired by the Company, including shares of Stock purchased in the open market, and shares of Stock held in the treasury of the Company. The Company shall register with the Securities and Exchange Commission the issuance of the Stock subject to the Plan.

5.Awards. The compensation to be paid to Non-Employee Directors is fixed by the Board, generally annually. That compensation is expected to include an annual retainer payable in cash. It also may include other cash compensation ("Cash Compensation") that may be used as provided in this Plan. In lieu of receiving such Cash Compensation in cash, a Non-Employee Director may elect to receive any portion or all of such Cash Compensation in the form of Stock as provided herein. Such election shall be evidenced by an agreement (the "Stock Compensation

Agreement") between the Company and such Non-Employee Director, which agreement shall contain the terms and conditions of such award. Such election shall be made generally at or around the first Board meeting in January of each calendar year and will be effective for the entire calendar year. A Non-Employee Director may make a new election each calendar year.

The shares of Stock to be issued to a Non-Employee Director electing to receive any portion of his or her Cash Compensation in the form of Stock may be issued subject to certain Forfeiture Restrictions (as defined below), the terms of which shall be set forth in the Stock Compensation Agreement, provided that such Forfeiture Restrictions shall lapse no later than the end of the calendar year to which the Cash Compensation underlying the Stock relates.

6.Number of Shares of Stock to be Issued. The number of shares of Stock to be issued to a Non-Employee Director electing to receive any portion or all of his or her Cash Compensation in the form of Stock shall equal the Cash Compensation elected to be paid in the form of Stock, divided by the closing price of the Stock on the New York Stock Exchange on the day the Cash Compensation is awarded (such price, the "Fair Market Value"), rounded up to the nearest ten shares of Stock. The Stock shall be issuable as specified in the Stock Compensation Agreement. A Non-Employee Director electing to receive any portion or all of his or her Cash Compensation in the form of Stock shall receive cash (the "Cash Payment") equal to (i) the total Cash Compensation awarded to such Non-Employee Director, minus (ii) the number of shares of Stock to be issued to such Non-Employee Director pursuant to his or her election multiplied by the Fair Market Value of a share of Stock. For illustrative purposes only, if a Non-Employee Director elected to receive an award of Cash Compensation of $100,000 in the form of 50% Stock and 50% cash, and the Fair Market Value of the Stock was $44.50, the Non-Employee Director would receive 1,130 shares of Stock ($50,000 ÷ $44.50 = 1,123.6 shares of Stock, rounded up to the nearest ten shares of Stock). The Cash Payment would equal $49,715 ($100,000 – (1,130 x $44.50)). The Cash Payment shall be payable to the Non-Employee Director in four equal installments on the March 31, June 30, September 30 and December 31 of the calendar year in which such Cash Compensation is awarded; provided that such installments shall be adjusted to include any cash dividends paid by the Company on the shares during any period in which such shares are subject to Forfeiture Restrictions.

7.Adjustment. In the event of a merger, reorganization, consolidation, recapitalization, separation, liquidation, Stock dividend, Stock split or other change in the structure of the Company affecting the Stock, such adjustment shall be made in the number of shares of Stock available under the Plan, as may be determined to be appropriate and equitable by the Board, in its sole discretion, to prevent dilution or enlargement of rights.

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8.Restrictions on Resale. Any Stock acquired by a Non-Employee Director under this Plan may be sold only pursuant to an effective registration statement or pursuant to an exemption from the Securities Act of 1933 ("Securities Act"), including sales pursuant to Rule 144 thereunder. The Committee may, in its sole discretion, impose additional restrictions on disposition by a Non-Employee Director and an obligation of the Non-Employee Director to forfeit and surrender the Stock to the Company under certain circumstances ("Forfeiture Restrictions"). Such restrictions shall be set forth in the Stock Compensation Agreement. The Company may place a legend on the certificates for such Stock evidencing these restrictions.

9.Change in Control. Upon the occurrence of a Change in Control (as defined below), the Committee may take any action with respect to Stock issued but still subject to Forfeiture Restrictions that it deems appropriate, including but not limited to causing such Forfeiture Restrictions to lapse; provided, however, that if a Change in Control occurs and, in connection with or as a result of such Change in Control, Richard D. Kinder no longer holds or does not continue to hold the office of Chairman of the Company, to the extent any shares of Stock are subject to Forfeiture Restrictions, such Forfeiture Restrictions shall lapse, and the Company shall thereupon deliver or cause to be delivered to each Non-Employee Director or legal representative the certificate or certificates for such shares of Stock, free of any legend provided in Section 8. As used herein, the term "Change in Control" shall mean the occurrence of any of the following events:

(a)the acquisition by any Person or group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), including any group acting for the purpose of acquiring, holding or disposing of securities (within the meaning of Rule 13d-5(b)(1) under the Exchange Act), other than the Permitted Holder, of beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act, or any successor provision), of more than 20% of either the then outstanding shares of common stock of the Company or the total voting power of the then outstanding Voting Stock of the Company; provided that for purposes of this clause (a), the following acquisitions shall not constitute a Change in Control: (i) any acquisition directly or indirectly by the Company; (ii) any acquisition directly from the Company; (iii) any acquisition by a Benefit Plan; or (iv) any reorganization, merger, consolidation, sale or similar transaction or series of related transactions which complies with clauses (i), (ii) and (iii) of clause (b) of this definition of Change in Control;

(b)a reorganization, merger or consolidation involving the Company, or sale of all or substantially all of the assets of the Company, or similar transaction or series of related transactions, in each case, unless, following such reorganization, merger, consolidation, sale or transaction, (i) 50% or more of the then outstanding shares of common stock of the corporation, or common equity securities of an entity other than a corporation, resulting from such

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reorganization, merger, consolidation, sale or transaction (including an entity or ultimate parent of an entity which as a result of such transaction owns the Company or all or substantially all of the assets of the Company) and of the combined voting power of the then outstanding Voting Stock of such corporation or other entity are beneficially owned, directly or indirectly, by all or substantially all of the Persons who were the beneficial owners of the outstanding common stock of the Company immediately prior to such reorganization, merger, consolidation, sale or transaction in substantially the same proportions as their ownership, immediately prior to such reorganization, merger, consolidation, sale or transaction, of the outstanding common stock of the Company; (ii) no Person (excluding the Permitted Holder or a Benefit Plan or any Person beneficially owning, immediately prior to such reorganization, merger, consolidation, sale or transaction, directly or indirectly, 20% or more of the common stock of the Company then outstanding or 20% or more of the combined voting power of the Voting Stock of the Company then outstanding) beneficially owns, directly or indirectly, 20% or more of the then outstanding shares of common stock of such corporation, or common equity securities of such entity other than a corporation, resulting from such reorganization, merger, consolidation, sale or transaction or the combined voting power of the then outstanding Voting Stock of such corporation or other entity; and (iii) at least a majority of the members of the board of directors of the corporation, or the body which is most analogous to the board of directors of a corporation if not a corporation, resulting from such reorganization, merger, consolidation, sale or transaction were members of the Incumbent Board (defined below) at the time of the initial agreement or initial action by the Board providing for such reorganization, merger, consolidation, sale or transaction;

(c)individuals who as of the Effective Date constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board then in office; provided that the Incumbent Board (i) shall include, except as provided in clause (ii), any individual becoming a director after the Effective Date whose election by the Board or nomination for election by the Company's stockholders was approved by a vote of at least two-thirds (2/3) of the directors then comprising the Incumbent Board, and (ii) shall exclude any director whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board, or any agreement intended to avoid or settle the results of any such actual or threatened solicitation; or

(d)the approval by the stockholders of the Company of a plan of complete liquidation of the Company.

For purposes of this Section, the following definitions shall apply:

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"Benefit Plan" means any employee benefit plan of the Company or any subsidiary of the Company, and any trust or Person organized, appointed or established by the Company for or pursuant to the terms of any such plan, which plan, trust or Person was maintained prior to a Change in Control.

"Permitted Holder" means Richard D. Kinder.

"Person" means a natural person or an entity.

"Voting Stock" means, (i) with respect to a corporation, all securities of such corporation of any class or series that are entitled to vote generally in the election of, or to appoint by contract, directors of such corporation (excluding any class or series that would be entitled so to vote by reason of the occurrence of any contingency, so long as such contingency has not occurred) and (ii) with respect to an entity which is not a corporation, all securities of any class or series that are entitled to vote generally in the election of, or to appoint by contract, members of the body which is most analogous to the board of directors of a corporation.

10.Tax Withholding. To the extent required by applicable federal, state and local law, a Non-Employee Director shall make arrangements satisfactory to the Company for the payment of any withholding tax obligations that arise in connection with the Plan. The Company shall not be required to issue any Stock under the Plan until such obligations are satisfied.

11.Effective Date. This Plan, as amended and restated, shall be effective on October 20, 2021.

12.No Right to Continue as a Director. Nothing contained in the Plan or any agreement hereunder will confer upon any participant in the Plan any right to continue to serve as a director of the Company or any right to receive compensation other than as fixed by the Board from time to time.

13.No Stockholder Rights Conferred. Nothing contained in the Plan or any agreement hereunder will confer upon any participant in the Plan any rights of a common stockholder of the Company unless and until a share of Stock is validly issued to such participant in accordance with the terms hereof.

14.Termination, Amendment and Modification of Plan. The Board may at any time terminate or suspend, and may at any time and from time to time and in any respect amend or modify, the Plan; provided, however, that if any applicable law or regulation or the requirements of any stock exchange on which the Stock is listed or quoted requires that any such amendment

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or modification must be approved by the Company's stockholders, the Board shall not make any such modification or amendment without approval of the Company's stockholders in such manner and to such degree as is required by the applicable law, regulation or stock exchange requirement.

15.Code Section 409A. The Plan and all awards granted hereunder are intended to comply with, or otherwise be exempt from, Section 409A of the Internal Revenue Code of 1986, as amended ("Section 409A"). The Plan and all awards shall be administered, interpreted, and construed in a manner consistent with Section 409A or an exemption therefrom. Should any provision of the Plan, any award hereunder, or any other agreement or arrangement contemplated by the Plan be found not to comply with, or otherwise be exempt from, the provisions of Section 409A, such provision shall be modified and given effect (retroactively if necessary), in the sole discretion of the Committee, and without the consent of the affected Non-Employee Director, in such manner as the Committee determines to be necessary or appropriate to comply with, or to effectuate an exemption from, Section 409A.

16.Governing Law. To the extent not preempted by any laws of the United States, the Plan shall be construed, regulated, interpreted and administered according to the laws of the State of Texas.

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EX-10.5

Exhibit 10.5

KINDER MORGAN, INC.

NON-EMPLOYEE DIRECTOR

STOCK COMPENSATION AGREEMENT

Stock Compensation Agreement made effective the [___] day of January, 20[__] between Kinder Morgan, Inc., a Delaware corporation (the "Company"), and [_________] ("Director").

1.Award. The Company has made an award of Cash Compensation (as defined below), a portion of which Director is electing to receive in the form of Class P common stock of the Company, $0.01 par value ("Stock"), subject to the terms and conditions contained herein and in the Plan (as defined below).

a.Cash Compensation. As contemplated by the Second Amended and Restated Kinder Morgan, Inc. Stock Compensation Plan for Non-Employee Directors (the "Plan"), $[_________] of cash compensation which Director may elect to receive in the form of Stock (the "Cash Compensation") has been awarded to Director for the 20[__] calendar year.

b.Election to Receive Stock in Lieu of Cash. In accordance with the terms of the Plan, Director hereby elects to receive $[__] of the Cash Compensation in the form of Stock. Director shall receive [__] shares of Stock ("Shares") and $[__] in cash (the "Cash Payment"), as calculated in accordance with the terms of the Plan. The Shares shall be issued upon acceptance hereof by Director and certificates therefor will be delivered to Director upon satisfaction of the conditions of this Agreement. The Cash Payment shall be paid in installments of $[__] each on or before March 31, June 30, September 30 and December 31 of 20[__], or as soon as administratively practicable thereafter; provided that such installments shall be adjusted to include any cash dividends paid by the Company on the Shares during any period in which the Shares are subject to Forfeiture Restrictions (as hereinafter defined).

c.Plan Incorporated. Director acknowledges receipt of a copy of the Plan and agrees that the election to receive such Cash Compensation in the form of Stock shall be subject to all of the terms and conditions set forth in the Plan, including future amendments thereto, if any, pursuant to the terms thereof, which Plan is incorporated herein by reference as a part of this Agreement.

2.Shares. Director hereby accepts the Shares when issued and agrees with respect thereto as follows:

a.Forfeiture Restrictions. To the extent then subject to the Forfeiture Restrictions (as hereinafter defined), the Shares issued hereunder may not be sold, assigned, transferred, exchanged, pledged, hypothecated or encumbered by Director, and no such sale, assignment, transfer, exchange, pledge, hypothecation or encumbrance, whether made or created by voluntary act of Director or any agent of Director or by operation of law, shall

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be recognized by, or be binding upon, or shall in any manner affect the rights of, the Company or any agent or any custodian holding certificates for the Shares. Except as provided in paragraph (b) below, in the event that Director's service as a director of the Company is terminated prior to the lapse of the Forfeiture Restrictions as provided in (b) below, Director shall, for no consideration, forfeit to the Company all Shares to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and the obligation to forfeit and surrender Shares to the Company upon such termination of service as a director are herein referred to as "Forfeiture Restrictions."

b.Lapse of Forfeiture Restrictions. The Forfeiture Restrictions shall lapse and cease to apply to the Shares on the earlier of (i) July [__], 20[__] (the "Vesting Date"), or (ii) the date of Director's death.

If Director's service as a director of the Company is terminated prior to the Vesting Date because of Director's failure to be elected as a director at a stockholders meeting at which Director is considered for election, the Forfeiture Restrictions shall lapse and cease to apply to fifty percent (50%) of the Shares, and Director shall, for no consideration, forfeit to the Company the remaining fifty percent (50%) of the Shares.

Shares with respect to which Forfeiture Restrictions have lapsed shall cease to be subject to any Forfeiture Restrictions, and the Company shall provide Director a certificate (without the legend referenced in Section 2(d) below) representing the Shares as to which the Forfeiture Restrictions have lapsed.

c.Rights as a Stockholder. Unless otherwise provided in this Agreement, Director shall have the right to receive distributions with respect to the Shares awarded hereby, to vote such Shares, and to enjoy all other rights of a holder of Stock.

d.Certificates. The Company may, in its discretion, reflect ownership of the Shares through the issuance of stock certificates, or in book-entry form, without stock certificates, on its books and records. If the Company elects to issue certificates, one or more certificates evidencing the Shares shall be issued by the Company in Director's name, or at the option of the Company, in the name of a nominee of the Company, pursuant to which Director shall have voting rights and shall be entitled to receive all distributions unless and until the Shares are forfeited pursuant to the provisions of this Agreement. Each certificate shall bear the following legend:

THIS CERTIFICATE AND THE STOCK REPRESENTED HEREBY ARE SUBJECT TO THE TERMS AND CONDITIONS (INCLUDING FORFEITURE AND RESTRICTIONS AGAINST TRANSFER) CONTAINED IN THE KINDER MORGAN, INC. STOCK COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS AND AN AGREEMENT ENTERED INTO BETWEEN THE REGISTERED OWNER AND KINDER MORGAN, INC. A RELEASE FROM SUCH TERMS AND CONDITIONS SHALL BE OBTAINED ONLY IN ACCORDANCE WITH THE PROVISIONS OF SUCH PLAN AND AGREEMENT, A COPY OF

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EACH OF WHICH IS ON FILE IN THE OFFICE OF THE SECRETARY OF KINDER MORGAN, INC.

Until the Forfeiture Restrictions have lapsed, (i) Director shall not be entitled to delivery of the stock certificate, (ii) the Company shall retain custody of the stock certificate, and (iii) Director may not sell, transfer, pledge, exchange, hypothecate or otherwise dispose of the Shares. A breach by Director of the terms and conditions of this Agreement shall cause a forfeiture of the Shares by Director. Upon request of the Committee, Director shall deliver to the Company a stock power, endorsed in blank, relating to the Shares then subject to the Forfeiture Restrictions. Upon the lapse of the Forfeiture Restrictions without forfeiture, the Company shall deliver to Director a certificate without legend evidencing the vested Shares with respect to which Forfeiture Restrictions have lapsed, and shall retain a certificate representing unvested Shares still subject to Forfeiture Restrictions. Notwithstanding any other provisions of this Agreement, the issuance or delivery of any shares of Stock (whether subject to restrictions or unrestricted) may be postponed for such period as may be required to comply with applicable requirements of any national securities exchange or any requirements of any law or regulation applicable to the issuance or delivery of such units. The Company shall not be obligated to issue or deliver any shares of Stock if the issuance or delivery thereof shall constitute a violation of any provision of any law or of any regulation of any governmental authority or any national securities exchange.

3.Status of Shares. Director agrees that, notwithstanding anything to the contrary herein, the Shares may not be sold, transferred, pledged, exchanged, hypothecated or otherwise disposed of in any manner that would constitute a violation of any applicable federal or state securities laws. Director also agrees that (i) certificates shall bear the legend or legends as the Committee deems appropriate in order to assure compliance with applicable securities laws, (ii) the Company may refuse to register the transfer of the Shares on the transfer records of the Company if such proposed transfer would in the opinion of counsel satisfactory to the Company constitute a violation of any applicable securities law, and (iii) the Company may give related instructions to its transfer agent, if any, to stop registration of the transfer of the Shares.

4.Changes in Capital Structure. If the outstanding shares of Stock or other securities of the Company, or both, shall at any time be changed or exchanged by declaration of a stock dividend, stock split, combination of stock, or recapitalization, the number and kind of shares of Stock shall be appropriately and equitably adjusted in accordance with the terms of the Plan.

5.Status as Director. For purposes of this Agreement, Director shall be considered to be in service as a director of the Company as long as Director remains a director of the Company or any successor entity. Any question as to whether and when there has been a termination of such service, and the cause of such termination, shall be determined by the Committee in its sole discretion, and its determination shall be final.

6.Committee's Powers. No provision contained in this Agreement shall in any way terminate, modify or alter, or be construed or interpreted as terminating, modifying or

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altering, any of the powers, rights or authority vested in the Committee pursuant to the terms of the Plan, including, without limitation, the Committee's rights to make certain determinations and elections with respect to the Shares.

7.Binding Effect. The provisions of the Plan and the terms and conditions of this Agreement shall, in accordance with their terms, be binding upon, and inure to the benefit of, all successors of Director, including, without limitation, Director's estate and the executors, administrators, or trustees thereof, heirs and legatees, and any receiver, trustee in bankruptcy, or representative of creditors of Director. This Agreement shall be binding upon and inure to the benefit of any successors to the Company.

8.Agreement Subject to Plan. This Agreement is subject to the Plan. The terms and provisions of the Plan (including any subsequent amendments thereto) are hereby incorporated herein by reference thereto. In the event of a conflict between any term or provision contained herein and a term or provision of the Plan, the applicable terms and provisions of the Plan will govern and prevail. All definitions of words and terms contained in the Plan shall be applicable to this Agreement.

9.Governing Law. To the extent not preempted by any laws of the United States, the Plan shall be construed, regulated, interpreted and administered according to the laws of the State of Texas.

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Exhibit 10.5

IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly authorized, and Director has executed this Agreement, all effective as of the date of first above written.

KINDER MORGAN, INC.

By: ______________________________

Name: [______________]

Title: [______________]

DIRECTOR

By: ______________________________

Name: ______________________________

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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 September 30, 2021, 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:	October 22, 2021	/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:	October 22, 2021	/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 September 30, 2021, 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:	October 22, 2021	/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 September 30, 2021, 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:	October 22, 2021	/s/ David P. Michels
		David P. Michels
		Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2021	Oct. 21, 2021
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
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		2,267,425,507
Entity Central Index Key	0001506307
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3
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
1.500% Senior Notes due 2022
Entity Information [Line Items]
Title of 12(b) Security	1.500% Senior Notes due 2022
Trading Symbol	KMI 22
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

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Revenues
Revenues	$ 3,824	$ 2,919	$ 12,185	$ 8,585
Operating Costs, Expenses and Other
Costs of sales	1,559	655	4,504	1,759
Operations and maintenance	614	643	1,710	1,869
Depreciation, depletion and amortization	526	539	1,595	1,636
General and administrative	174	153	490	461
Taxes, other than income taxes	106	100	324	295
Loss on impairments and divestitures, net (Note 3)	4	11	1,602	1,987
Other income, net	(3)	(1)	(6)	(2)
Total Operating Costs, Expenses and Other	2,980	2,100	10,219	8,005
Operating Income	844	819	1,966	580
Other Income (Expense)
Earnings from equity investments	169	194	392	562
Amortization of excess cost of equity investments	(21)	(32)	(56)	(99)
Interest, net	(368)	(383)	(1,122)	(1,214)
Other, net (Note 3)	21	14	264	32
Total Other Expense	(199)	(207)	(522)	(719)
Income (Loss) Before Income Taxes	645	612	1,444	(139)
Income Tax Expense	(134)	(140)	(248)	(304)
Net Income (Loss)	511	472	1,196	(443)
Net Income Attributable to Noncontrolling Interests	(16)	(17)	(49)	(45)
Net Income (Loss) Attributable to Kinder Morgan, Inc.	$ 495	$ 455	$ 1,147	$ (488)
Class P Shares
Basic Earnings (Loss) Per Share	$ 0.22	$ 0.20	$ 0.50	$ (0.22)
Diluted Earnings (Loss) Per Share	$ 0.22	$ 0.20	$ 0.50	$ (0.22)
Basic Weighted Average Shares Outstanding	2,267	2,263	2,265	2,263
Diluted Weighted Average Shares Outstanding	2,267	2,263	2,265	2,263
Services
Revenues
Revenues	$ 1,928	$ 1,881	$ 5,734	$ 5,664
Commodity sales
Revenues
Revenues	1,868	982	6,343	2,772
Other
Revenues
Revenues	$ 28	$ 56	$ 108	$ 149

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 511	$ 472	$ 1,196	$ (443)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively)	(131)	(56)	(444)	(16)
Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively)	92	(5)	181	72
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)	0	0	0	1
Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively)	6	5	28	21
Total other comprehensive (loss) income	(33)	(56)	(235)	78
Comprehensive income (loss)	478	416	961	(365)
Comprehensive income attributable to noncontrolling interests	(16)	(17)	(49)	(45)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$ 462	$ 399	$ 912	$ (410)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Statement of Comprehensive Income [Abstract]
Change in fair value of hedge derivatives, tax benefit	$ 41	$ 17	$ 135	$ 5
Reclassification of change in fair value of derivatives to net income (loss), tax (benefit) expense	(28)	1	(55)	(22)
Foreign currency translation adjustments, tax expense	0	0	0	0
Benefit plan adjustments, tax expense	$ (2)	$ (2)	$ (7)	$ (7)

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 102	$ 1,184
Restricted deposits	177	25
Accounts receivable	1,433	1,293
Fair value of derivative contracts	199	185
Inventories	457	348
Other current assets	318	168
Total current assets	2,686	3,203
Property, plant and equipment, net	35,576	35,836
Investments	7,620	7,917
Goodwill	20,033	19,851
Other intangibles, net	1,744	2,453
Deferred income taxes	303	536
Deferred charges and other assets	1,678	2,177
Total Assets	69,640	71,973
Current Liabilities
Current portion of debt	2,822	2,558
Accounts payable	1,189	837
Accrued interest	332	525
Accrued taxes	284	267
Accrued contingencies	246	307
Other current liabilities	952	580
Total current liabilities	5,825	5,074
Long-term debt
Outstanding	28,988	30,838
Debt fair value adjustments	1,014	1,293
Total long-term debt	30,002	32,131
Other long-term liabilities and deferred credits	2,160	2,202
Total long-term liabilities and deferred credits	32,162	34,333
Total Liabilities	37,987	39,407
Commitments and contingencies (Notes 4 and 10)
Redeemable Noncontrolling Interest	661	728
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding	23	23
Additional paid-in capital	41,788	41,756
Accumulated deficit	(10,617)	(9,936)
Accumulated other comprehensive loss	(642)	(407)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,552	31,436
Noncontrolling interests	440	402
Total Stockholders’ Equity	30,992	31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$ 69,640	$ 71,973

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2021	Dec. 31, 2020
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)	2,267,381,482	2,264,257,336
Common stock, shares outstanding (in shares)	2,267,381,482	2,264,257,336

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash Flows From Operating Activities
Net income (loss)	$ 1,196	$ (443)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	1,595	1,636
Deferred income taxes	236	164
Amortization of excess cost of equity investments	56	99
Loss on impairments and divestitures, net (Note 3)	1,602	1,987
Gain on sale of interest in equity investment (Note 3)	(206)	0
Earnings from equity investments	(392)	(562)
Distributions from equity investment earnings	535	487
Changes in components of working capital
Accounts receivable	(119)	238
Inventories	(89)	41
Other current assets	(90)	14
Accounts payable	362	(107)
Accrued interest, net of interest rate swaps	(177)	(208)
Accrued taxes	15	(25)
Other current liabilities	71	(93)
Rate reparations, refunds and other litigation reserve adjustments	(97)	48
Other, net	(58)	6
Net Cash Provided by Operating Activities	4,440	3,282
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	(1,518)	(16)
Capital expenditures	(894)	(1,351)
Proceeds from sales of investments	417	907
Contributions to investments	(36)	(365)
Distributions from equity investments in excess of cumulative earnings	121	105
Other, net	(1)	(56)
Net Cash Used in Investing Activities	(1,911)	(776)
Cash Flows From Financing Activities
Issuances of debt	4,950	3,888
Payments of debt	(6,459)	(3,991)
Debt issue costs	(20)	(23)
Dividends	(1,828)	(1,764)
Repurchases of shares	0	(50)
Contributions from investment partner and noncontrolling interests	4	11
Distributions to investment partner	(67)	(60)
Distributions to noncontrolling interests	(14)	(11)
Other, net	(25)	(13)
Net Cash Used in Financing Activities	(3,459)	(2,013)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	(3)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(930)	490
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209	209
Cash and Cash Equivalents, beginning of period	1,184	185
Restricted Deposits, beginning of period	25	24
Cash and Cash Equivalents, end of period	102	632
Restricted Deposits, end of period	177	67
Cash, Cash Equivalents, and Restricted Deposits, end of period	279	699
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	35	15
Increase in property, plant and equipment from both accruals and contractor retainage	4
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,313	1,440
Cash paid during the period for income taxes, net	$ 8	$ 202

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Common stock	Additional paid-in capital	Accumulated deficit	Accumulated other comprehensive loss	Stockholders’ equity attributable to KMI	Non-controlling interests
Balance at Dec. 31, 2019	$ 34,086	$ 23	$ 41,745	$ (7,693)	$ (333)	$ 33,742	$ 344
Balance (shares) at Dec. 31, 2019		2,265
Repurchases of shares	(50)		(50)			(50)
Repurchases of shares (shares)		(4)
Restricted shares	41		41			41
Restricted shares (shares)		3
Net income (loss)	(443)			(488)		(488)	45
Distributions	(11)					0	(11)
Contributions	8					0	8
Dividends	(1,764)			(1,764)		(1,764)
Other comprehensive income (loss)	78				78	78
Balance at Sep. 30, 2020	31,945	$ 23	41,736	(9,945)	(255)	31,559	386
Balance (shares) at Sep. 30, 2020		2,264
Balance at Jun. 30, 2020	32,124	$ 23	41,731	(9,802)	(199)	31,753	371
Balance (shares) at Jun. 30, 2020		2,261
Restricted shares	5		5			5
Restricted shares (shares)		3
Net income (loss)	472			455		455	17
Distributions	(4)					0	(4)
Contributions	2					0	2
Dividends	(598)			(598)		(598)
Other comprehensive income (loss)	(56)				(56)	(56)
Balance at Sep. 30, 2020	31,945	$ 23	41,736	(9,945)	(255)	31,559	386
Balance (shares) at Sep. 30, 2020		2,264
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	32		32			32
Restricted shares (shares)		3
Net income (loss)	1,196			1,147		1,147	49
Distributions	(14)					0	(14)
Contributions	4					0	4
Dividends	(1,828)			(1,828)		(1,828)
Other	(1)					0	(1)
Other comprehensive income (loss)	(235)				(235)	(235)
Balance at Sep. 30, 2021	30,992	$ 23	41,788	(10,617)	(642)	30,552	440
Balance (shares) at Sep. 30, 2021		2,267
Balance at Jun. 30, 2021	31,140	$ 23	41,793	(10,496)	(609)	30,711	429
Balance (shares) at Jun. 30, 2021		2,265
Restricted shares	(5)		(5)			(5)
Restricted shares (shares)		2
Net income (loss)	511			495		495	16
Distributions	(6)					0	(6)
Contributions	1					0	1
Dividends	(616)			(616)		(616)
Other comprehensive income (loss)	(33)				(33)	(33)
Balance at Sep. 30, 2021	$ 30,992	$ 23	$ 41,788	$ (10,617)	$ (642)	$ 30,552	$ 440
Balance (shares) at Sep. 30, 2021		2,267

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General (Notes)

9 Months Ended

Sep. 30, 2021

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, 144 terminals, and 700 billion cubic feet of working natural gas storage capacity. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, 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 2020 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

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, 2021 evaluation, we grouped our businesses into six 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; and (vi) Terminals. See Note 3 for results of our May 31, 2021 goodwill impairment test.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares 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 which 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 shares and participating securities:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders	$	495	$	455	$	1,147	$	(488)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(4)		(3)		(10)		(9)
Net Income (Loss) Allocated to Class P Stockholders	$	491	$	452	$	1,137	$	(497)
Basic Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263
Basic Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)

(a)As of September 30, 2021, there were approximately 13 million restricted stock awards outstanding.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	3	3	3	3

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Acquisitions (Notes)

9 Months Ended

Sep. 30, 2021

Business Combination and Asset Acquisition [Abstract]

Acquisitions

2. Acquisitions

As of September 30, 2021, our preliminary allocation of the purchase price for significant acquisitions completed during the nine months ended September 30, 2021 are detailed below.

					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Deferred charges & other		Goodwill		Current liabilities		Long-term liabilities
			(In millions)
(1)	8/21	Kinetrex Energy	$	318	$	17	$	49	$	262	$	64	$	(6)	$	(68)
(2)	7/21	Stagecoach Gas Services LLC	1,228		52		1,041		23		118		(6)		—

Pro Forma Information

Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1, 2021 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of operations.

(1) Kinetrex Energy Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.

(2) Stagecoach Acquisition

On July 9, 2021, we completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,228 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation relates to customer contracts with a weighted average amortization period of less than 2 years. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP. The acquired assets complement and expand our natural gas pipeline and storage business and are included in our Natural Gas Pipelines business segment.

Goodwill

After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, the excess purchase price is assigned to goodwill. Goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience. Of our acquisitions made during the nine months ended September 30, 2021, goodwill of $118 million associated with our Stagecoach acquisition is tax deductible and we apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.

Changes in the amounts of our goodwill for the nine months ended September 30, 2021 are summarized by reporting unit as follows:

	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		Products Pipelines		Products Pipelines Terminals		Terminals		Energy Transition Ventures		Total
	(In millions)
Goodwill as of December 31, 2020	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	—	$	19,851
Acquisitions	118		—		—		—		—		—		64		182
Goodwill as of September 30, 2021	$	14,367	$	2,343	$	928	$	1,378	$	151	$	802	$	64	$	20,033

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

9 Months Ended

Sep. 30, 2021

Impairments [Abstract]

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

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

We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and nine months ended September 30, 2021 and 2020:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	—	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		—		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Loss (gain) on divestitures of long-lived assets and other write-downs	—		11		(1)		11
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21
Terminals
Impairment of long-lived and intangible assets	14		—		14		5
CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Gain on divestitures of long-lived assets, net	(11)		—		(8)		—
Other loss (gain) on divestitures of long-lived assets, net	1		—		(3)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	4	$	11	$	1,513	$	1,987

(a)See below for a further discussion of these items.

Impairments

Long-lived Assets

During the second quarter 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. The long-lived asset impairment test involved two steps. Step one was an assessment as to whether the asset’s net book value was expected to be recovered from the estimated undiscounted future cash flows. To compute the estimated undiscounted future cash flows we included an unfavorable adjustment for upcoming contract expirations. With this inclusion, our South Texas gathering and processing assets failed step one. In step two, we utilized an income approach to estimate fair value and compared it to the carrying value. We applied an approximate 8.5% discount rate, a Level 3 input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the nine months ended September 30, 2021.

During the first half of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment which resulted in a non-cash impairment of long-lived assets within our CO2 business segment shown in the above table during the nine months ended September 30, 2020.

Goodwill

The results of our May 31, 2021 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. The fair value estimates used in the goodwill impairment test are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect

to market multiples, comparable sales transactions, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding future cash flows based on production growth rate assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit.

During the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 and Natural Gas Pipelines business segments during the nine months ended September 30, 2020 as shown in the table above.

As conditions warrant, we routinely evaluate our assets for potential triggering events that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.

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 $412 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the nine months ended September 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

Other Write-downs

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, driven by the recent impairment by Ruby of its assets, which is included within “Earnings from equity investments” in our accompanying consolidated statement of operations for the nine months ended September 30, 2021. The impairment at Ruby was the result of upcoming contract expirations and additional uncertainty identified in late February 2021 regarding the proposed development of a third party liquefied natural gas exporting facility that could significantly increase the demand for its services.

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Debt (Notes)

9 Months Ended

Sep. 30, 2021

Debt Disclosure [Abstract]

Debt

4. Debt

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

	September 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026(a)	$	—	$	—
$500 million credit facility due November 16, 2023(a)	—		—
Commercial paper notes	160		—
Current portion of senior notes
5.00%, due February 2021(b)	—		750
3.50%, due March 2021(b)	—		750
5.80%, due March 2021(b)	—		400
5.00%, due October 2021(c)	—		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(d)	869		—
3.95% due September 2022	1,000		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,822		2,558
Long-term debt (excluding current portion)
Senior notes	28,306		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	353		364
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	219		223
Total long-term debt	28,988		30,838
Total debt(e)	$	31,810	$	33,396

(a)On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.

(b)We repaid the principal amounts on these senior notes during the first quarter of 2021.

(c)These notes were repaid on July 1, 2021.

(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The September 30, 2021 balance is reported above at the exchange rate of 1.1580 U.S. dollars per Euro. As of September 30, 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 $54 million related to these notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance sheets. 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 6 “Risk Management—Foreign Currency Risk Management”).

(e)Excludes our “Debt fair value adjustments” which, as of September 30, 2021 and December 31, 2020, increased our total debt balances by $1,014 million and $1,293 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 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million. These notes are guaranteed through the cross guarantee agreement discussed above.

Credit Facilities and Restrictive Covenants

On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under the New Credit Facility may be used for working capital and other general corporate purposes. On the same date, we also entered into a first amendment (the “Amendment”) to our existing Revolving Credit Agreement, dated as of November 16, 2018 (as amended prior to the Amendment, the “Existing Credit

Facility”). The Amendment provides for certain amendments to the Existing Credit Facility to, among other things, reduce the Existing Credit Facility’s borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder. The combined credit facilities continue to support our $4 billion commercial paper program.

Depending on the type of loan request, our credit facility borrowings under our New Credit Facility bear interest at either (i) LIBOR adjusted for a eurocurrency funding reserve plus an applicable margin ranging from 1.000% to 1.750% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) LIBOR for a one-month Eurodollar loan adjusted for a eurocurrency funding reserve, plus 1%, plus, in each case, an applicable margin ranging from 0.100% to 0.750% per annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.100% to 0.250%. The New Credit Facility also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available.

The New Credit Facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the New Credit Facility) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. The New Credit Facility also restricts our ability to make certain restricted payments if an event of default (as defined in the New Credit Facility) has occurred and is continuing or would occur and be continuing.

As of September 30, 2021, we had no borrowings outstanding under our credit facilities, $160 million in borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of September 30, 2021 was $3,759 million. As of September 30, 2021, 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: 

	September 30, 2021				December 31, 2020
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
	(In millions)
Total debt	$	32,824	$	37,797	$	34,689	$	39,622

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2021 and December 31, 2020.

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Stockholders' Equity (Notes)

9 Months Ended

Sep. 30, 2021

Stockholders' Equity Note [Abstract]

Stockholders' Equity

5. Stockholders’ Equity

Class P Stock

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. Since December 2017, in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $575 million.

Dividends

The following table provides information about our per share dividends:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.81	$	0.7875
Per share cash dividend paid in the period	0.27		0.2625		0.8025		0.775

On October 20, 2021, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended September 30, 2021, which is payable on November 15, 2021 to shareholders of record as of the close of business on November 1, 2021.

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” in 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		Foreign currency translation adjustments		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	(444)		—		28		(416)
Loss reclassified from accumulated other comprehensive loss	181		—		—		181
Net current-period change in accumulated other comprehensive loss	(263)		—		28		(235)
Balance as of September 30, 2021	$	(276)	$	—	$	(366)	$	(642)

	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2019	$	(7)	$	—	$	(326)	$	(333)
Other comprehensive (loss) gain before reclassifications	(16)		1		21		6
Loss reclassified from accumulated other comprehensive loss	72		—		—		72
Net current-period change in accumulated other comprehensive (loss) income	56		1		21		78
Balance as of September 30, 2020	$	49	$	1	$	(305)	$	(255)

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Risk Management (Notes)

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management

6.  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 September 30, 2021, 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	(15.9)	MMBbl
Crude oil basis	(6.4)	MMBbl
Natural gas fixed price	(29.5)	Bcf
Natural gas basis	(27.1)	Bcf
NGL fixed price	(1.0)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.4)	MMBbl
Crude oil basis	(8.7)	MMBbl
Natural gas fixed price	(8.7)	Bcf
Natural gas basis	(22.8)	Bcf
NGL fixed price	(1.9)	MMBbl

As of September 30, 2021, 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 2025.

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 September 30, 2021:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	7,100	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	6,250		Mark-to-Market	December 2022

(a)The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

During the nine months ended September 30, 2021, we entered into fixed-to-variable interest rate swap agreements with a combined notional principal amount of $375 million. These agreements were designated as accounting hedges and convert a portion of our fixed rate debt to variable rates through February 2028. In addition, we entered into variable-to-fixed interest rate swap agreements with a combined notional principal amount of $3,750 million. These agreements were not designated as accounting hedges and effectively fixed our LIBOR exposure for a portion of our fixed-to-variable interest rate swaps for 2022.

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 September 30, 2021:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$	1,358	Cash flow hedge	March 2027

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

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

Fair Value of Derivative Contracts
		Derivatives Asset				Derivatives Liability
		September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	13	$	42	$	(256)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		33		(96)		(8)
Subtotal		14		75		(352)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	127		119		(4)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	350		575		(14)		(7)
Subtotal		477		694		(18)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	49		—		(6)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		138		—		—
Subtotal		69		138		(6)		(6)
Total		560		907		(376)		(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	10		24		(63)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		—		(3)		—
Subtotal		14		24		(66)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		—		—
Subtotal		1		—		(1)		—
Total		15		24		(67)		(21)
Total derivatives		$	575	$	931	$	(443)	$	(78)

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 September 30, 2021
Energy commodity derivative contracts(a)	$	15	$	13	$	—	$	28	$	(26)	$	—	$	2
Interest rate contracts	—		478		—		478		(9)		—		469
Foreign currency contracts	—		69		—		69		(6)		—		63
As of December 31, 2020
Energy commodity derivative contracts(a)	$	6	$	93	$	—	$	99	$	(35)	$	—	$	64
Interest rate contracts	—		694		—		694		(2)		—		692
Foreign currency contracts	—		138		—		138		(6)		—		132

	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 September 30, 2021
Energy commodity derivative contracts(a)	$	(111)	$	(307)	$	—	$	(418)	$	26	$	135	$	(257)
Interest rate contracts	—		(19)		—		(19)		9		—		(10)
Foreign currency contracts	—		(6)		—		(6)		6		—		—
As of December 31, 2020
Energy commodity derivative contracts(a)	$	(7)	$	(56)	$	—	$	(63)	$	35	$	(8)	$	(36)
Interest rate contracts	—		(10)		—		(10)		2		—		(8)
Foreign currency contracts	—		(6)		—		(6)		6		—		—

(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 in 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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	(39)	$	(50)	$	(228)	$	409
Hedged fixed rate debt(a)	Interest, net	$	39	$	50	$	229	$	(418)

(a)As of September 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $473 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 September 30,					Three Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(140)	$	(143)	Revenues—Commodity sales	$	(94)	$	(47)
					Costs of sales	8		(7)
Interest rate contracts	1		—		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(33)		70		Other, net	(34)		61
Total	$	(172)	$	(73)	Total	$	(120)	$	6

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(514)	$	(29)	Revenues—Commodity sales	$	(167)	$	(145)
					Costs of sales	10		(12)
Interest rate contracts	3		(9)		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(68)		17		Other, net	(79)		64
Total	$	(579)	$	(21)	Total	$	(236)	$	(94)

(a)We expect to reclassify approximately $181 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2021 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 nine months ended September 30, 2021, we recognized gains of $6 million 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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(40)	$	87	$	(703)	$	353
	Costs of sales	(7)		12		154		18
	Earnings from equity investments	(2)		—		(4)		—
Total(a)		$	(49)	$	99	$	(553)	$	371

(a)The three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480 million, respectively, and the three and nine months ended September 30, 2020 amounts include approximate gains of $96 million and $349 million, respectively. These gains and 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 September 30, 2021 and December 31, 2020, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2021, we had cash margins of $165 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2020, we had cash margins of $3 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at September 30, 2021 represents the net of our initial margin requirements of $30 million and counterparty variation margin requirements of $135 million. 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 September 30, 2021, 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 $177 million of additional collateral.

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Revenue Recognition (Notes)

9 Months Ended

Sep. 30, 2021

Revenue from Contract with Customer [Abstract]

Revenue Recognition

7. 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 September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	836	$	66	$	181	$	1	$	(2)	$	1,082
Fee-based services	190		244		93		10		—		537
Total services	1,026		310		274		11		(2)		1,619
Commodity sales
Natural gas sales	1,097		—		—		7		(3)		1,101
Product sales	372		247		8		279		(11)		895
Total commodity sales	1,469		247		8		286		(14)		1,996
Total revenues from contracts with customers	2,495		557		282		297		(16)		3,615
Other revenues(c)
Leasing services(d)	119		42		140		15		—		316
Derivatives adjustments on commodity sales	(71)		—		—		(63)		—		(134)
Other	12		6		—		8		1		27
Total other revenues	60		48		140		(40)		1		209
Total revenues	$	2,555	$	605	$	422	$	257	$	(15)	$	3,824

	Three Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	818	$	69	$	185	$	1	$	(2)	$	1,071
Fee-based services	173		228		91		8		3		503
Total services	991		297		276		9		1		1,574
Commodity sales
Natural gas sales	507		—		—		1		(2)		506
Product sales	158		97		5		180		(5)		435
Total commodity sales	665		97		5		181		(7)		941
Total revenues from contracts with customers	1,656		394		281		190		(6)		2,515
Other revenues(c)
Leasing services(d)	119		42		143		13		—		317
Derivatives adjustments on commodity sales	(6)		—		—		46		—		40
Other	40		6		—		2		(1)		47
Total other revenues	153		48		143		61		(1)		404
Total revenues	$	1,809	$	442	$	424	$	251	$	(7)	$	2,919

	Nine Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,501	$	191	$	570	$	1	$	(2)	$	3,261
Fee-based services	544		709		258		35		—		1,546
Total services	3,045		900		828		36		(2)		4,807
Commodity sales
Natural gas sales	5,090		—		—		9		(11)		5,088
Product sales	840		529		20		766		(34)		2,121
Total commodity sales	5,930		529		20		775		(45)		7,209
Total revenues from contracts with customers	8,975		1,429		848		811		(47)		12,016
Other revenues(c)
Leasing services(d)	356		128		427		42		—		953
Derivatives adjustments on commodity sales	(726)		(1)		—		(143)		—		(870)
Other	51		16		—		19		—		86
Total other revenues	(319)		143		427		(82)		—		169
Total revenues	$	8,656	$	1,572	$	1,275	$	729	$	(47)	$	12,185

	Nine Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,479	$	215	$	563	$	1	$	(2)	$	3,256
Fee-based services	523		670		307		31		1		1,532
Total services	3,002		885		870		32		(1)		4,788
Commodity sales
Natural gas sales	1,385		—		—		1		(5)		1,381
Product sales	396		255		11		546		(22)		1,186
Total commodity sales	1,781		255		11		547		(27)		2,567
Total revenues from contracts with customers	4,783		1,140		881		579		(28)		7,355
Other revenues(c)
Leasing services(d)	346		126		404		34		—		910
Derivatives adjustments on commodity sales	35		—		—		173		—		208
Other	91		16		—		6		(1)		112
Total other revenues	472		142		404		213		(1)		1,230
Total revenues	$	5,255	$	1,282	$	1,285	$	792	$	(29)	$	8,585

(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 (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 6 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 September 30, 2021 and December 31, 2020, our contract asset balances were $62 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $14 million was transferred to accounts receivable during the nine months ended September 30, 2021. As of September 30, 2021 and December 31, 2020, our contract liability balances were $217 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $63 million was recognized as revenue during the nine months ended September 30, 2021.

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 September 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2021	$	1,178
2022	4,022
2023	3,186
2024	2,711
2025	2,277
Thereafter	14,018
Total	$	27,392

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)

9 Months Ended

Sep. 30, 2021

Segment Reporting [Abstract]

Reportable Segments

8.  Reportable Segments

Financial information by segment follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,541	$	1,803	$	8,611	$	5,229
Intersegment revenues	14		6		45		26
Products Pipelines	605		442		1,572		1,282
Terminals
Revenues from external customers	421		423		1,273		1,282
Intersegment revenues	1		1		2		3
CO2	257		251		729		792
Corporate and intersegment eliminations	(15)		(7)		(47)		(29)
Total consolidated revenues	$	3,824	$	2,919	$	12,185	$	8,585

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,069	$	1,091	$	2,602	$	2,284
Products Pipelines	279		223		792		719
Terminals	216		246		689		732
CO2	163		156		599		(453)
Total Segment EBDA	1,727		1,716		4,682		3,282
DD&A	(526)		(539)		(1,595)		(1,636)
Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)
General and administrative and corporate charges	(167)		(150)		(465)		(472)
Interest, net	(368)		(383)		(1,122)		(1,214)
Income tax expense	(134)		(140)		(248)		(304)
Total consolidated net income (loss)	$	511	$	472	$	1,196	$	(443)

	September 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	47,576	$	48,597
Products Pipelines	9,118		9,182
Terminals	8,507		8,639
CO2	2,808		2,478
Corporate assets(b)	1,631		3,077
Total consolidated assets	$	69,640	$	71,973

(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, and other income, 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)

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

Income Taxes

9.  Income Taxes

Income tax expense included in our accompanying consolidated statements of operations is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(In millions, except percentages)
Income tax expense	$	134		$	140		$	248		$	304
Effective tax rate	20.8		%	22.9		%	17.2		%	(218.7)		%

The effective tax rate for the three months ended September 30, 2021 is slightly lower than the statutory federal rate of 21% primarily due to dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

The effective tax rates for the three months ended September 30, 2020 is higher than the statutory federal rate of 21% primarily due to state income taxes.

The effective tax rate for the nine months ended September 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.

The effective tax rate for the nine months ended September 30, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to the $1,600 million impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit. This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus and PPL.

While we would normally expect a federal income tax benefit from our loss before income taxes for the nine months ended September 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for these periods.

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Litigation and Environmental (Notes)

9 Months Ended

Sep. 30, 2021

Commitments and Contingencies Disclosure [Abstract]

Litigation and Environmental

10.   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 contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

SFPP FERC Proceedings

The FERC approved the SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the EL Settlement were fully accrued on or before December 31, 2020.

The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two-year period preceding the filing date of their complaints and/or prospective refunds in protest cases from the date of protest, and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings at the FERC that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million in rate refunds and unspecified rate reductions as of the date of their complaints in 2014 and 2018. The claims pleaded by the shippers are expected to change due to the passage of time and interest. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. We do not believe the ultimate resolution of the shipper complaints and protests seeking rate reductions or refunds in the ongoing proceedings will have a material adverse impact on 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.  Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its 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 have “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. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash

impairment of our investment in GLNG partially offset by our share of earnings recognized by 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. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending.

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. Eni USA’s second arbitration sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the second arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from pursuing the second arbitration, including the breach of contract and negligent misrepresentation claims therein. On October 4, 2021, the U.S. Supreme Court denied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration and the claims asserted therein.

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. ALSS also sought a declaration on substantially the same allegations asserted previously by Eni USA in arbitration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project gave rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also sought a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. On July 15, 2021, the arbitration tribunal delivered a Final Award on the merits of all claims submitted to the tribunal and denied all of ALSS’s claims with prejudice.

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 has 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 makes 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. Hiland Partners denies and will vigorously defend 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 $98 million, plus attorney fees and interest. We believe that our declaration of force majeure is valid and appropriate and intend to vigorously defend against Freeport’s 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.

General

As of September 30, 2021 and December 31, 2020, our total reserve for legal matters was $192 million and $273 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, NGL, natural gas or CO2.

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 by the EPA to be more than $3 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 asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.

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 obligate them 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 May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. The defendants appealed that decision. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing. On August 5, 2021, the Fifth Circuit remanded the case to the U.S. District Court to

determine whether there is federal officer jurisdiction. The case remains effectively stayed pending a ruling by the U.S. District Court on the federal officer issue. 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.

Louisiana Landowner Coastal Erosion Litigation

Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including four cases against TGP, three cases against SNG, and one case against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. We will continue to vigorously defend the remaining cases.

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 September 30, 2021 and December 31, 2020, we have accrued a total reserve for environmental liabilities in the amount of $242 million and $250 million, respectively. In addition, as of both September 30, 2021 and December 31, 2020, 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)

9 Months Ended

Sep. 30, 2021

Accounting Standards Update and Change in Accounting Principle [Abstract]

Recent Accounting Pronouncements

11. Recent Accounting Pronouncements

Reference Rate Reform (Topic 848)

On March 12, 2020, the FASB issued Accounting Standards Update (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. 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 is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of Topic 848 to our financial statements.

ASU No. 2020-06

On August 5, 2020, the FASB issued 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 EPS 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. ASU No. 2020-06 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2021-05

On July 19, 2021, the FASB issued ASU No. 2021-05, “Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments.” This ASU requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or rate as an operating lease if another classification (i.e. sales-type or direct financing) would trigger a day-one loss. ASU No. 2021-05 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

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General (Policies)

9 Months Ended

Sep. 30, 2021

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 2020 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, 2021 evaluation, we grouped our businesses into six 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; and (vi) Terminals. See Note 3 for results of our May 31, 2021 goodwill impairment test.

Earnings per Share

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares 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 which include dividend equivalent payments, do not participate in excess distributions over earnings.

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General (Tables)

9 Months Ended

Sep. 30, 2021

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 shares and participating securities:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders	$	495	$	455	$	1,147	$	(488)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(4)		(3)		(10)		(9)
Net Income (Loss) Allocated to Class P Stockholders	$	491	$	452	$	1,137	$	(497)
Basic Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263
Basic Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)

(a)As of September 30, 2021, there were approximately 13 million restricted stock awards outstanding.

Schedule of Antidilutive Securities

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	3	3	3	3

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2021

Business Combination and Asset Acquisition [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

As of September 30, 2021, our preliminary allocation of the purchase price for significant acquisitions completed during the nine months ended September 30, 2021 are detailed below.

					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Deferred charges & other		Goodwill		Current liabilities		Long-term liabilities
			(In millions)
(1)	8/21	Kinetrex Energy	$	318	$	17	$	49	$	262	$	64	$	(6)	$	(68)
(2)	7/21	Stagecoach Gas Services LLC	1,228		52		1,041		23		118		(6)		—

Schedule of Goodwill

Changes in the amounts of our goodwill for the nine months ended September 30, 2021 are summarized by reporting unit as follows:

	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		Products Pipelines		Products Pipelines Terminals		Terminals		Energy Transition Ventures		Total
	(In millions)
Goodwill as of December 31, 2020	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	—	$	19,851
Acquisitions	118		—		—		—		—		—		64		182
Goodwill as of September 30, 2021	$	14,367	$	2,343	$	928	$	1,378	$	151	$	802	$	64	$	20,033

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

9 Months Ended

Sep. 30, 2021

Impairments [Abstract]

Schedule of Impairments

We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and nine months ended September 30, 2021 and 2020:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	—	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		—		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Loss (gain) on divestitures of long-lived assets and other write-downs	—		11		(1)		11
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21
Terminals
Impairment of long-lived and intangible assets	14		—		14		5
CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Gain on divestitures of long-lived assets, net	(11)		—		(8)		—
Other loss (gain) on divestitures of long-lived assets, net	1		—		(3)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	4	$	11	$	1,513	$	1,987

(a)See below for a further discussion of these items.

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Debt (Tables)

9 Months Ended

Sep. 30, 2021

Debt Disclosure [Abstract]

Schedule of Debt

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

	September 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026(a)	$	—	$	—
$500 million credit facility due November 16, 2023(a)	—		—
Commercial paper notes	160		—
Current portion of senior notes
5.00%, due February 2021(b)	—		750
3.50%, due March 2021(b)	—		750
5.80%, due March 2021(b)	—		400
5.00%, due October 2021(c)	—		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(d)	869		—
3.95% due September 2022	1,000		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,822		2,558
Long-term debt (excluding current portion)
Senior notes	28,306		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	353		364
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	219		223
Total long-term debt	28,988		30,838
Total debt(e)	$	31,810	$	33,396

(a)On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.

(b)We repaid the principal amounts on these senior notes during the first quarter of 2021.

(c)These notes were repaid on July 1, 2021.

(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The September 30, 2021 balance is reported above at the exchange rate of 1.1580 U.S. dollars per Euro. As of September 30, 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 $54 million related to these notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance sheets. 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 6 “Risk Management—Foreign Currency Risk Management”).

(e)Excludes our “Debt fair value adjustments” which, as of September 30, 2021 and December 31, 2020, increased our total debt balances by $1,014 million and $1,293 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: 

	September 30, 2021				December 31, 2020
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
	(In millions)
Total debt	$	32,824	$	37,797	$	34,689	$	39,622

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Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2021

Stockholders' Equity Note [Abstract]

Schedule of Dividends

The following table provides information about our per share dividends:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.81	$	0.7875
Per share cash dividend paid in the period	0.27		0.2625		0.8025		0.775

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		Foreign currency translation adjustments		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	(444)		—		28		(416)
Loss reclassified from accumulated other comprehensive loss	181		—		—		181
Net current-period change in accumulated other comprehensive loss	(263)		—		28		(235)
Balance as of September 30, 2021	$	(276)	$	—	$	(366)	$	(642)

	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2019	$	(7)	$	—	$	(326)	$	(333)
Other comprehensive (loss) gain before reclassifications	(16)		1		21		6
Loss reclassified from accumulated other comprehensive loss	72		—		—		72
Net current-period change in accumulated other comprehensive (loss) income	56		1		21		78
Balance as of September 30, 2020	$	49	$	1	$	(305)	$	(255)

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Risk Management (Tables)

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of September 30, 2021, 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	(15.9)	MMBbl
Crude oil basis	(6.4)	MMBbl
Natural gas fixed price	(29.5)	Bcf
Natural gas basis	(27.1)	Bcf
NGL fixed price	(1.0)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.4)	MMBbl
Crude oil basis	(8.7)	MMBbl
Natural gas fixed price	(8.7)	Bcf
Natural gas basis	(22.8)	Bcf
NGL fixed price	(1.9)	MMBbl

Schedule of Interest Rate Derivatives

The following table summarizes our outstanding interest rate contracts as of September 30, 2021:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	7,100	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	6,250		Mark-to-Market	December 2022

(a)The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

Schedule of Foreign Exchange Contracts, Statement of Financial Position

The following table summarizes our outstanding foreign currency contracts as of September 30, 2021:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$	1,358	Cash flow hedge	March 2027

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

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

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

Fair Value of Derivative Contracts
		Derivatives Asset				Derivatives Liability
		September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	13	$	42	$	(256)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		33		(96)		(8)
Subtotal		14		75		(352)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	127		119		(4)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	350		575		(14)		(7)
Subtotal		477		694		(18)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	49		—		(6)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		138		—		—
Subtotal		69		138		(6)		(6)
Total		560		907		(376)		(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	10		24		(63)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		—		(3)		—
Subtotal		14		24		(66)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		—		—
Subtotal		1		—		(1)		—
Total		15		24		(67)		(21)
Total derivatives		$	575	$	931	$	(443)	$	(78)

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 September 30, 2021
Energy commodity derivative contracts(a)	$	15	$	13	$	—	$	28	$	(26)	$	—	$	2
Interest rate contracts	—		478		—		478		(9)		—		469
Foreign currency contracts	—		69		—		69		(6)		—		63
As of December 31, 2020
Energy commodity derivative contracts(a)	$	6	$	93	$	—	$	99	$	(35)	$	—	$	64
Interest rate contracts	—		694		—		694		(2)		—		692
Foreign currency contracts	—		138		—		138		(6)		—		132

	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 September 30, 2021
Energy commodity derivative contracts(a)	$	(111)	$	(307)	$	—	$	(418)	$	26	$	135	$	(257)
Interest rate contracts	—		(19)		—		(19)		9		—		(10)
Foreign currency contracts	—		(6)		—		(6)		6		—		—
As of December 31, 2020
Energy commodity derivative contracts(a)	$	(7)	$	(56)	$	—	$	(63)	$	35	$	(8)	$	(36)
Interest rate contracts	—		(10)		—		(10)		2		—		(8)
Foreign currency contracts	—		(6)		—		(6)		6		—		—

(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 in 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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	(39)	$	(50)	$	(228)	$	409
Hedged fixed rate debt(a)	Interest, net	$	39	$	50	$	229	$	(418)

(a)As of September 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $473 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 September 30,					Three Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(140)	$	(143)	Revenues—Commodity sales	$	(94)	$	(47)
					Costs of sales	8		(7)
Interest rate contracts	1		—		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(33)		70		Other, net	(34)		61
Total	$	(172)	$	(73)	Total	$	(120)	$	6

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(514)	$	(29)	Revenues—Commodity sales	$	(167)	$	(145)
					Costs of sales	10		(12)
Interest rate contracts	3		(9)		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(68)		17		Other, net	(79)		64
Total	$	(579)	$	(21)	Total	$	(236)	$	(94)

(a)We expect to reclassify approximately $181 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2021 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 nine months ended September 30, 2021, we recognized gains of $6 million 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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(40)	$	87	$	(703)	$	353
	Costs of sales	(7)		12		154		18
	Earnings from equity investments	(2)		—		(4)		—
Total(a)		$	(49)	$	99	$	(553)	$	371

(a)The three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480 million, respectively, and the three and nine months ended September 30, 2020 amounts include approximate gains of $96 million and $349 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

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Revenue Recognition (Tables)

9 Months Ended

Sep. 30, 2021

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 September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	836	$	66	$	181	$	1	$	(2)	$	1,082
Fee-based services	190		244		93		10		—		537
Total services	1,026		310		274		11		(2)		1,619
Commodity sales
Natural gas sales	1,097		—		—		7		(3)		1,101
Product sales	372		247		8		279		(11)		895
Total commodity sales	1,469		247		8		286		(14)		1,996
Total revenues from contracts with customers	2,495		557		282		297		(16)		3,615
Other revenues(c)
Leasing services(d)	119		42		140		15		—		316
Derivatives adjustments on commodity sales	(71)		—		—		(63)		—		(134)
Other	12		6		—		8		1		27
Total other revenues	60		48		140		(40)		1		209
Total revenues	$	2,555	$	605	$	422	$	257	$	(15)	$	3,824

	Three Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	818	$	69	$	185	$	1	$	(2)	$	1,071
Fee-based services	173		228		91		8		3		503
Total services	991		297		276		9		1		1,574
Commodity sales
Natural gas sales	507		—		—		1		(2)		506
Product sales	158		97		5		180		(5)		435
Total commodity sales	665		97		5		181		(7)		941
Total revenues from contracts with customers	1,656		394		281		190		(6)		2,515
Other revenues(c)
Leasing services(d)	119		42		143		13		—		317
Derivatives adjustments on commodity sales	(6)		—		—		46		—		40
Other	40		6		—		2		(1)		47
Total other revenues	153		48		143		61		(1)		404
Total revenues	$	1,809	$	442	$	424	$	251	$	(7)	$	2,919

	Nine Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,501	$	191	$	570	$	1	$	(2)	$	3,261
Fee-based services	544		709		258		35		—		1,546
Total services	3,045		900		828		36		(2)		4,807
Commodity sales
Natural gas sales	5,090		—		—		9		(11)		5,088
Product sales	840		529		20		766		(34)		2,121
Total commodity sales	5,930		529		20		775		(45)		7,209
Total revenues from contracts with customers	8,975		1,429		848		811		(47)		12,016
Other revenues(c)
Leasing services(d)	356		128		427		42		—		953
Derivatives adjustments on commodity sales	(726)		(1)		—		(143)		—		(870)
Other	51		16		—		19		—		86
Total other revenues	(319)		143		427		(82)		—		169
Total revenues	$	8,656	$	1,572	$	1,275	$	729	$	(47)	$	12,185

	Nine Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,479	$	215	$	563	$	1	$	(2)	$	3,256
Fee-based services	523		670		307		31		1		1,532
Total services	3,002		885		870		32		(1)		4,788
Commodity sales
Natural gas sales	1,385		—		—		1		(5)		1,381
Product sales	396		255		11		546		(22)		1,186
Total commodity sales	1,781		255		11		547		(27)		2,567
Total revenues from contracts with customers	4,783		1,140		881		579		(28)		7,355
Other revenues(c)
Leasing services(d)	346		126		404		34		—		910
Derivatives adjustments on commodity sales	35		—		—		173		—		208
Other	91		16		—		6		(1)		112
Total other revenues	472		142		404		213		(1)		1,230
Total revenues	$	5,255	$	1,282	$	1,285	$	792	$	(29)	$	8,585

(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 (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 6 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 September 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2021	$	1,178
2022	4,022
2023	3,186
2024	2,711
2025	2,277
Thereafter	14,018
Total	$	27,392

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Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2021

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

Financial information by segment follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,541	$	1,803	$	8,611	$	5,229
Intersegment revenues	14		6		45		26
Products Pipelines	605		442		1,572		1,282
Terminals
Revenues from external customers	421		423		1,273		1,282
Intersegment revenues	1		1		2		3
CO2	257		251		729		792
Corporate and intersegment eliminations	(15)		(7)		(47)		(29)
Total consolidated revenues	$	3,824	$	2,919	$	12,185	$	8,585

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,069	$	1,091	$	2,602	$	2,284
Products Pipelines	279		223		792		719
Terminals	216		246		689		732
CO2	163		156		599		(453)
Total Segment EBDA	1,727		1,716		4,682		3,282
DD&A	(526)		(539)		(1,595)		(1,636)
Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)
General and administrative and corporate charges	(167)		(150)		(465)		(472)
Interest, net	(368)		(383)		(1,122)		(1,214)
Income tax expense	(134)		(140)		(248)		(304)
Total consolidated net income (loss)	$	511	$	472	$	1,196	$	(443)

	September 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	47,576	$	48,597
Products Pipelines	9,118		9,182
Terminals	8,507		8,639
CO2	2,808		2,478
Corporate assets(b)	1,631		3,077
Total consolidated assets	$	69,640	$	71,973

(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, and other income, 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)

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

Schedule of Income Taxes

Income tax expense included in our accompanying consolidated statements of operations is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(In millions, except percentages)
Income tax expense	$	134		$	140		$	248		$	304
Effective tax rate	20.8		%	22.9		%	17.2		%	(218.7)		%

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General - Organization and Basis of Presentation (Details) mi in Thousands	9 Months Ended
	Sep. 30, 2021 Bcf mi Terminals segment
General [Line Items]
Miles of pipeline | mi	83
Number of pipeline terminals owned interest in and/or operated | Terminals	144
Working capacity | Bcf	700
Number of reporting units | segment	6

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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		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Common Stockholders	$ 495	$ 455	$ 1,147	$ (488)
Less: Net Income allocated to restricted stock awards(a)	$ (4)	$ (3)	$ (10)	$ (9)
Basic Weighted Average Common Shares Outstanding	2,267	2,263	2,265	2,263
Basic Earnings (Loss) Per Share	$ 0.22	$ 0.20	$ 0.50	$ (0.22)
Class P Common Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Common Stockholders	$ 491	$ 452	$ 1,137	$ (497)
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	13		13

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General - Schedule of Antidilutive Securities (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Unvested restricted stock awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	13	13	13	13
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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Acquisitions - Acquisitions (Details) $ in Millions			9 Months Ended
	Aug. 20, 2021 USD ($) numberOfRNGFacilities	Jul. 09, 2021 USD ($) Bcf Terminals	Sep. 30, 2021 USD ($) Bcf Terminals	Dec. 31, 2020 USD ($)
Business Acquisition [Line Items]
Goodwill			$ 20,033	$ 19,851
Number of pipeline terminals owned interest in and/or operated | Terminals			144
Working capacity | Bcf			700
Kinetrex Energy
Business Acquisition [Line Items]
Purchase price	$ 318
Current assets	17
Property, plant & equipment	49
Deferred charges & other	262
Goodwill	64
Current liabilities	(6)
Long-term liabilities	(68)
Payments to acquire businesses	$ 318
Number of landfill-based RNG facilities | numberOfRNGFacilities	3
Business combination, customer relationship	$ 199
Weighted average amortization period, customer contracts			10 years
Kinetrex Energy | RNG Facility in Indiana
Business Acquisition [Line Items]
Equity method investments	$ 63
Ownership percentage			50.00%
Stagecoach Gas Services LLC
Business Acquisition [Line Items]
Purchase price		$ 1,228
Current assets		52
Property, plant & equipment		1,041
Deferred charges & other		23
Goodwill		118
Current liabilities		(6)
Long-term liabilities		0
Payments to acquire businesses		$ 1,228
Number of pipeline terminals owned interest in and/or operated | Terminals		4
Working capacity | Bcf		41
Weighted average amortization period, customer contracts			2 years

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Acquisitions - Schedule of Goodwill (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
Business Acquisition [Line Items]
Goodwill, beginning balance	$ 19,851
Acquisitions	182
Goodwill, ending balance	20,033
Stagecoach Gas Services LLC
Business Acquisition [Line Items]
Business Acquisition, Goodwill, Expected Tax Deductible Amount	118
Natural Gas Pipelines Regulated
Business Acquisition [Line Items]
Goodwill, beginning balance	14,249
Acquisitions	118
Goodwill, ending balance	14,367
Natural Gas Pipelines Nonregulated
Business Acquisition [Line Items]
Goodwill, beginning balance	2,343
Acquisitions	0
Goodwill, ending balance	2,343
CO2
Business Acquisition [Line Items]
Goodwill, beginning balance	928
Acquisitions	0
Goodwill, ending balance	928
Products Pipelines, Pipelines
Business Acquisition [Line Items]
Goodwill, beginning balance	1,378
Acquisitions	0
Goodwill, ending balance	1,378
Products Pipelines Terminals
Business Acquisition [Line Items]
Goodwill, beginning balance	151
Acquisitions	0
Goodwill, ending balance	151
Terminals
Business Acquisition [Line Items]
Goodwill, beginning balance	802
Acquisitions	0
Goodwill, ending balance	802
Energy Transition Ventures
Business Acquisition [Line Items]
Goodwill, beginning balance	0
Acquisitions	64
Goodwill, ending balance	$ 64

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Losses and Gains on Divestitures, Impairments and Other Write-downs – Schedule of Pre-tax Loss (Gain) on Impairments and Divestitures (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Finite-Lived Intangible Assets [Line Items]
Impairment of goodwill					$ 1,600
Gain on sale of interests in NGPL Holdings LLC				$ (206)	0
Loss (gain) on divestitures of long-lived assets and other write-downs	$ 4		$ 11	1,602	1,987
Pre-tax loss on impairments, divestitures and other write-downs, net	4		11	1,513	1,987
Corporate and intersegment eliminations
Finite-Lived Intangible Assets [Line Items]
Other loss (gain) on divestitures of long-lived assets, net	1		0	(3)	0
Natural Gas Pipelines
Finite-Lived Intangible Assets [Line Items]
Impairments of long-lived and intangible assets	0		0	1,600	0
Impairment of goodwill	0		0	0	1,000
Loss (gain) on divestitures of long-lived assets and other write-downs	$ 0		11	$ (1)	11
Natural Gas Pipelines | Valuation Technique, Discounted Cash Flow
Finite-Lived Intangible Assets [Line Items]
Estimated Weighted Average Cost Of Capital	8.50%			8.50%
Natural Gas Pipelines | NGPL Holdings, LLC
Finite-Lived Intangible Assets [Line Items]
Gain on sale of interests in NGPL Holdings LLC	$ 0		0	$ (206)	0
Natural Gas Pipelines | Ruby Pipeline Holding Company LLC
Finite-Lived Intangible Assets [Line Items]
Loss on write-down of related party note receivable	0	$ 117	0	117	0
Products Pipelines
Finite-Lived Intangible Assets [Line Items]
Impairments of long-lived and intangible assets	0		0	0	21
Terminals
Finite-Lived Intangible Assets [Line Items]
Impairment of long-lived and intangible assets	14		0	14	5
CO2
Finite-Lived Intangible Assets [Line Items]
Impairments of long-lived and intangible assets	0		0	0	350
Impairment of goodwill	0		0	0	600
Loss (gain) on divestitures of long-lived assets and other write-downs	$ (11)		$ 0	$ (8)	$ 0

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Losses and Gains on Divestitures, Impairments and Other Write-downs- Sale of an interest in NGPL Holdings (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments			$ 417	$ 907
Gain on sale of interests in NGPL Holdings LLC			206	0
NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments			412
Related party promissory note receivable from NGPL Holdings					$ 500
Interest rate					6.75%
NGPL Holdings, LLC | Natural Gas Pipelines
Schedule of Equity Method Investments [Line Items]
Gain on sale of interests in NGPL Holdings LLC	$ 0	$ 0	$ 206	$ 0
ArcLight Capital Partners, LLC
Schedule of Equity Method Investments [Line Items]
Related party promissory note receivable from NGPL Holdings					$ 125
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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Losses and Gains on Divestitures, Impairments and Other Write-downs - Other Write-downs (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Natural Gas Pipelines | Ruby Pipeline Holding Company LLC
Finite-Lived Intangible Assets [Line Items]
Write-down of note receivable from Ruby	$ 0	$ 117	$ 0	$ 117	$ 0

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Debt - Schedule of Debt Outstanding (Details) $ in Millions		9 Months Ended
	Feb. 11, 2021 USD ($)	Sep. 30, 2021 USD ($) $ / €	Sep. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
Current portion of debt		$ 2,822		$ 2,558
Total long-term debt		28,988		30,838
Total debt(e)		31,810		33,396
Debt fair value adjustments		1,014		1,293
Proceeds from issuances of debt		$ 4,950	$ 3,888
Foreign Currency Exchange Rate, Translation | $ / €		1.1580
Commercial paper notes
Debt Instrument [Line Items]
Current portion of debt		$ 160		0
Line of Credit Facility, Maximum Borrowing Capacity		4,000
Current portion of other debt
Debt Instrument [Line Items]
Current portion of debt		47		47
Trust I preferred securities, 4.75%, due March 2028 | Capital Trust I
Debt Instrument [Line Items]
Current portion of debt		111		111
Total long-term debt		$ 110		110
Interest rate		4.75%
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035 | EPC Building LLC
Debt Instrument [Line Items]
Total long-term debt		$ 353		364
Interest rate		3.967%
Other
Debt Instrument [Line Items]
Total long-term debt		$ 219		223
Senior notes
Debt Instrument [Line Items]
Total long-term debt		28,306		30,141
Senior notes | 5.00%, due February 2021(b)
Debt Instrument [Line Items]
Current portion of debt		0		$ 750
Interest rate				5.00%
Senior notes | 3.50%, due March 2021(b)
Debt Instrument [Line Items]
Current portion of debt		0		$ 750
Interest rate				3.50%
Senior notes | 5.80%, due March 2021(b)
Debt Instrument [Line Items]
Current portion of debt		0		$ 400
Interest rate				5.80%
Senior notes | 5.00%, due October 2021(c)
Debt Instrument [Line Items]
Current portion of debt		0		$ 500
Interest rate				5.00%
Senior notes | 8.625%, due January 2022 | EPNG
Debt Instrument [Line Items]
Current portion of debt		$ 260		$ 0
Interest rate		8.625%
Senior notes | 4.15%, due March 2022
Debt Instrument [Line Items]
Current portion of debt		$ 375		0
Interest rate		4.15%
Senior notes | 3.95% due September 2022
Debt Instrument [Line Items]
Current portion of debt		$ 1,000		0
Interest rate		3.95%
Senior notes | 1.50%, due March 2022(d)
Debt Instrument [Line Items]
Current portion of debt		$ 869		$ 0
Interest rate		1.50%
Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax		$ 54
Senior notes | 3.60%, due February 2051
Debt Instrument [Line Items]
Total long-term debt	$ 750
Interest rate	3.60%
Proceeds from issuances of debt	$ 741

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Debt - Credit Facility (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Line of Credit Facility [Line Items]
Line of credit facility	$ 2,822	$ 2,558
$3.5 billion credit facility due August 20, 2026
Line of Credit Facility [Line Items]
Line of credit facility	0	0
Borrowing Capacity, Optional Increase	1,000
Line of Credit Facility, Current Borrowing Capacity	$ 3,500
Maximum ratio of consolidated net indebtedness to consolidated earnings before interest income taxes DDA and other non-cash adjustments	5.50
$3.5 billion credit facility due August 20, 2026 | Eurodollar [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
$3.5 billion credit facility due August 20, 2026 | Fed Funds Effective Rate Overnight Index Swap Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
$3.5 billion credit facility due August 20, 2026 | Minimum
Line of Credit Facility [Line Items]
Standby fee rate	0.10%
$3.5 billion credit facility due August 20, 2026 | Minimum | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
$3.5 billion credit facility due August 20, 2026 | Minimum | LIBOR Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.10%
$3.5 billion credit facility due August 20, 2026 | Maximum
Line of Credit Facility [Line Items]
Standby fee rate	0.25%
$3.5 billion credit facility due August 20, 2026 | Maximum | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
$3.5 billion credit facility due August 20, 2026 | Maximum | LIBOR Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
$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 notes
Line of Credit Facility [Line Items]
Line of credit facility	160	$ 0
Line of Credit Facility, Maximum Borrowing Capacity	4,000
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	$ 3,759

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Debt - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 32,824	$ 34,689
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 37,797	$ 39,622

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Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		9 Months Ended		46 Months Ended
	Oct. 20, 2021	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	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						$ 17.71
Value of shares repurchased					$ 50	$ 575
Per share cash dividend declared for the period		$ 0.27	$ 0.2625	$ 0.81	$ 0.7875
Per share cash dividend paid in the period		$ 0.27	$ 0.2625	$ 0.8025	$ 0.775
Subsequent Event
Class of Stock [Line Items]
Per share cash dividend declared for the period	$ 0.27
Common stock
Class of Stock [Line Items]
Shares repurchased					4	32

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Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Accumulated Other Comprehensive Loss [Line Items]
Balance	$ 31,838	$ 34,086
Balance	30,992	31,945
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Loss [Line Items]
Balance	(13)	(7)
Other comprehensive (loss) gain before reclassifications	(444)	(16)
Loss reclassified from accumulated other comprehensive loss	181	72
Net current-period change in accumulated other comprehensive (loss) income	(263)	56
Balance	(276)	49
Foreign currency translation adjustments
Accumulated Other Comprehensive Loss [Line Items]
Balance	0	0
Other comprehensive (loss) gain before reclassifications	0	1
Loss reclassified from accumulated other comprehensive loss	0	0
Net current-period change in accumulated other comprehensive (loss) income	0	1
Balance	0	1
Pension and other postretirement liability adjustments
Accumulated Other Comprehensive Loss [Line Items]
Balance	(394)	(326)
Other comprehensive (loss) gain before reclassifications	28	21
Loss reclassified from accumulated other comprehensive loss	0	0
Net current-period change in accumulated other comprehensive (loss) income	28	21
Balance	(366)	(305)
Total accumulated other comprehensive loss
Accumulated Other Comprehensive Loss [Line Items]
Balance	(407)	(333)
Other comprehensive (loss) gain before reclassifications	(416)	6
Loss reclassified from accumulated other comprehensive loss	181	72
Net current-period change in accumulated other comprehensive (loss) income	(235)	78
Balance	$ (642)	$ (255)

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Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts	9 Months Ended
	Sep. 30, 2021 Bcf MMBbls
Derivatives designated as hedging instruments | Crude oil fixed price
Derivative [Line Items]
Net open position	(15.9)
Derivatives designated as hedging instruments | Crude oil basis
Derivative [Line Items]
Net open position	(6.4)
Derivatives designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	(29.5)
Derivatives designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	(27.1)
Derivatives designated as hedging instruments | NGL fixed price
Derivative [Line Items]
Net open position	(1.0)
Derivatives not designated as hedging instruments | Crude oil fixed price
Derivative [Line Items]
Net open position	(1.4)
Derivatives not designated as hedging instruments | Crude oil basis
Derivative [Line Items]
Net open position	(8.7)
Derivatives not designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	(8.7)
Derivatives not designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	(22.8)
Derivatives not designated as hedging instruments | NGL fixed price
Derivative [Line Items]
Net open position	(1.9)

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Risk Management - Interest Rate Risk Management (Details) $ in Millions	Sep. 30, 2021 USD ($)
Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument | Fair Value Hedging
Derivative [Line Items]
Notional amount	$ 7,100
Fixed-To-Variable Interest Rate Contracts Q1 2021 | Designated as Hedging Instrument | Fair Value Hedging
Derivative [Line Items]
Notional amount	375
Variable-to-Fixed Interest Rate Contracts | Designated as Hedging Instrument | Derivatives in cash flow hedging relationships
Derivative [Line Items]
Notional amount	250
Variable-to-Fixed Interest Rate Contracts | Derivatives not designated as hedging instruments | Fair Value Hedging
Derivative [Line Items]
Notional amount	6,250
Variable-to-Fixed Interest Rate Contracts 2021 | Derivatives not designated as hedging instruments | Fair Value Hedging
Derivative [Line Items]
Notional amount	3,750
Current Portion Of Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	750
Long-term Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	$ 6,350

XML

Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Sep. 30, 2021 USD ($)
Derivatives in cash flow hedging relationships | Cross-currency contracts
Derivative [Line Items]
Notional amount	$ 1,358

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Risk Management - Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivatives Asset	$ 575	$ 931
Derivatives Liability	(443)	(78)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	28	99
Derivatives Liability	(418)	(63)
Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	478	694
Derivatives Liability	(19)	(10)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	69	138
Derivatives Liability	(6)	(6)
Derivatives designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives Asset	560	907
Derivatives Liability	(376)	(57)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	14	75
Derivatives Liability	(352)	(41)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	13	42
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(256)	(33)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	1	33
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(96)	(8)
Derivatives designated as hedging instruments | Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	477	694
Derivatives Liability	(18)	(10)
Derivatives designated as hedging instruments | Interest rate contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	127	119
Derivatives designated as hedging instruments | Interest rate contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(4)	(3)
Derivatives designated as hedging instruments | Interest rate contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	350	575
Derivatives designated as hedging instruments | Interest rate contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(14)	(7)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	69	138
Derivatives Liability	(6)	(6)
Derivatives designated as hedging instruments | Foreign currency contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	49	0
Derivatives designated as hedging instruments | Foreign currency contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(6)	(6)
Derivatives designated as hedging instruments | Foreign currency contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	20	138
Derivatives designated as hedging instruments | Foreign currency contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	0	0
Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives Asset	15	24
Derivatives Liability	(67)	(21)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	14	24
Derivatives Liability	(66)	(21)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	10	24
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(63)	(21)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	4	0
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(3)	0
Derivatives not designated as hedging instruments | Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	1	0
Derivatives Liability	(1)	0
Derivatives not designated as hedging instruments | Interest rate contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	0	0
Derivatives not designated as hedging instruments | Interest rate contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(1)	0
Derivatives not designated as hedging instruments | Interest rate contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	1	0
Derivatives not designated as hedging instruments | Interest rate contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	$ 0	$ 0

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Risk Management - Derivative Assets Input Level (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 575	$ 931
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	28	99
Contracts available for netting	(26)	(35)
Cash collateral held	0	0
Net amount	2	64
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	15	6
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	13	93
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	478	694
Contracts available for netting	(9)	(2)
Cash collateral held	0	0
Net amount	469	692
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	478	694
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	69	138
Contracts available for netting	(6)	(6)
Cash collateral held	0	0
Net amount	63	132
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	69	138
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 - Derivative Liabilities Input Level (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ (443)	$ (78)
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(418)	(63)
Contracts available for netting	26	35
Cash collateral posted	135	(8)
Net amount	(257)	(36)
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(111)	(7)
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(307)	(56)
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	(19)	(10)
Contracts available for netting	9	2
Cash collateral posted	0	0
Net amount	(10)	(8)
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	(19)	(10)
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	(6)	(6)
Contracts available for netting	6	6
Cash collateral posted	0	0
Net amount	0	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	(6)	(6)
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		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Interest rate contracts | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives adjustments on commodity sales	$ (39)	$ (50)	$ (228)	$ 409
Hedged fixed rate debt
Derivative Instruments, Gain (Loss) [Line Items]
Cumulative amount of fair value hedging adjustments to hedged fixed rate debt	473		473
Hedged fixed rate debt | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives adjustments on commodity sales	$ 39	$ 50	$ 229	$ (418)

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Risk Management - Effect on Income Statement Locations (Details) - Derivatives in cash flow hedging relationships - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months			$ (181)
Derivatives designated as hedging instruments
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	$ (172)	$ (73)	(579)	$ (21)
Gain/(loss) reclassified from Accumulated OCI into income	(120)	6	(236)	(94)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	(140)	(143)	(514)	(29)
Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	1	0	3	(9)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	(33)	70	(68)	17
Revenues—Commodity sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(94)	(47)	(167)	(145)
Cost of sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	8	(7)	10	(12)
Earnings from Equity Investments | Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	0	(1)	0	(1)
Other, net | Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ (34)	$ 61	(79)	$ 64
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			$ 6

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Risk Management - Effect on Income Statement Not Designated (Details) - Derivatives Not Designated as Accounting Hedges - Energy commodity derivative contracts - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (49)	$ 99	$ (553)	$ 371
Gain/(loss) on settlement of derivative contracts	(24)	96	(480)	349
Revenues—Commodity sales
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(40)	87	(703)	353
Cost of sales
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(7)	12	154	18
Earnings from Equity Investments
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (2)	$ 0	$ (4)	$ 0

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Risk Management - Credit Risks (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	$ 177
Energy commodity derivative contracts
Credit Derivatives [Line Items]
Letter of credits outstanding, amount	0	$ 0
Initial Margin Requirements	30
Variation Margin Requirements	135
Cash collateral posted	135	(8)
Other current liabilities | Cash collateral held | Energy commodity derivative contracts
Credit Derivatives [Line Items]
Collateral posted		$ 3
Restricted Cash | Cash collateral held | Energy commodity derivative contracts
Credit Derivatives [Line Items]
Cash collateral posted	$ 165

XML

Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 3,615	$ 2,515	$ 12,016	$ 7,355
Leasing services	316	317	953	910
Other	27	47	86	112
Total other revenues	209	404	169	1,230
Total revenues	3,824	2,919	12,185	8,585
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	2,541	1,803	8,611	5,229
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	605	442	1,572	1,282
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	421	423	1,273	1,282
CO2
Disaggregation of Revenue [Line Items]
Total revenues	257	251	729	792
Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,495	1,656	8,975	4,783
Leasing services	119	119	356	346
Other	12	40	51	91
Total other revenues	60	153	(319)	472
Total revenues	2,555	1,809	8,656	5,255
Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	557	394	1,429	1,140
Leasing services	42	42	128	126
Other	6	6	16	16
Total other revenues	48	48	143	142
Total revenues	605	442	1,572	1,282
Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	282	281	848	881
Leasing services	140	143	427	404
Other	0	0	0	0
Total other revenues	140	143	427	404
Total revenues	422	424	1,275	1,285
Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	297	190	811	579
Leasing services	15	13	42	34
Other	8	2	19	6
Total other revenues	(40)	61	(82)	213
Total revenues	257	251	729	792
Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(16)	(6)	(47)	(28)
Leasing services	0	0	0	0
Other	1	(1)	0	(1)
Total other revenues	1	(1)	0	(1)
Total revenues	(15)	(7)	(47)	(29)
Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,082	1,071	3,261	3,256
Firm services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	836	818	2,501	2,479
Firm services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	66	69	191	215
Firm services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	181	185	570	563
Firm services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	1	1	1
Firm services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(2)	(2)	(2)	(2)
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	537	503	1,546	1,532
Fee-based services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	190	173	544	523
Fee-based services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	244	228	709	670
Fee-based services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	93	91	258	307
Fee-based services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10	8	35	31
Fee-based services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	3	0	1
Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,619	1,574	4,807	4,788
Total services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,026	991	3,045	3,002
Total services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	310	297	900	885
Total services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	274	276	828	870
Total services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11	9	36	32
Total services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(2)	1	(2)	(1)
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,101	506	5,088	1,381
Natural gas sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,097	507	5,090	1,385
Natural gas sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
Natural gas sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
Natural gas sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7	1	9	1
Natural gas sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(3)	(2)	(11)	(5)
Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	895	435	2,121	1,186
Product sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	372	158	840	396
Product sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	247	97	529	255
Product sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8	5	20	11
Product sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	279	180	766	546
Product sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(11)	(5)	(34)	(22)
Commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,996	941	7,209	2,567
Total revenues	1,868	982	6,343	2,772
Commodity sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,469	665	5,930	1,781
Commodity sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	247	97	529	255
Commodity sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8	5	20	11
Commodity sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	286	181	775	547
Commodity sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(14)	(7)	(45)	(27)
Sales
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(134)	40	(870)	208
Sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(71)	(6)	(726)	35
Sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	0	0	(1)	0
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	(63)	46	(143)	173
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	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Contract Assets
Contract assets balances	$ 62	$ 20
Transfer to Accounts receivable	14
Contract Liabilities
Contract liabilities balances	217	$ 239
Transfer to Revenues	$ 63

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Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Sep. 30, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue allocated to remaining performance obligations for contracted revenue	$ 27,392
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	3 months
Revenue allocated to remaining performance obligations for contracted revenue	$ 1,178
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2022-01-01
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	$ 4,022
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	$ 3,186
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	$ 2,711
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	$ 2,277
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
Revenue allocated to remaining performance obligations for contracted revenue	$ 14,018

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Reportable Segments Reportable Segments Revenues (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Segment Reporting Information [Line Items]
Revenues	$ 3,824	$ 2,919	$ 12,185	$ 8,585
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(15)	(7)	(47)	(29)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	2,541	1,803	8,611	5,229
Natural Gas Pipelines | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(14)	(6)	(45)	(26)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	605	442	1,572	1,282
Terminals
Segment Reporting Information [Line Items]
Revenues	421	423	1,273	1,282
Terminals | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(1)	(1)	(2)	(3)
CO2
Segment Reporting Information [Line Items]
Revenues	$ 257	$ 251	$ 729	$ 792

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Reportable Segments Reportable Segments EBDA (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Segment Reporting Information [Line Items]
DD&A	$ (526)	$ (539)	$ (1,595)	$ (1,636)
Amortization of excess cost of equity investments	(21)	(32)	(56)	(99)
General and administrative and corporate charges	(174)	(153)	(490)	(461)
Income Tax Expense	(134)	(140)	(248)	(304)
Net Income (Loss)	511	472	1,196	(443)
Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	1,727	1,716	4,682	3,282
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
DD&A	(526)	(539)	(1,595)	(1,636)
Amortization of excess cost of equity investments	(21)	(32)	(56)	(99)
General and administrative and corporate charges	(167)	(150)	(465)	(472)
Interest, net	(368)	(383)	(1,122)	(1,214)
Income Tax Expense	(134)	(140)	(248)	(304)
Natural Gas Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	1,069	1,091	2,602	2,284
Products Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	279	223	792	719
Terminals | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	216	246	689	732
CO2 | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	$ 163	$ 156	$ 599	$ (453)

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Reportable Segments Reportable Segments Assets (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Assets	$ 69,640	$ 71,973
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
Assets	1,631	3,077
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	47,576	48,597
Products Pipelines
Segment Reporting Information [Line Items]
Assets	9,118	9,182
Terminals
Segment Reporting Information [Line Items]
Assets	8,507	8,639
CO2
Segment Reporting Information [Line Items]
Assets	$ 2,808	$ 2,478

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Segment Reporting Information [Line Items]
Income tax expense	$ 134	$ 140	$ 248	$ 304
Effective tax rate	20.80%	22.90%	17.20%	(218.70%)
Statutory federal rate	21.00%	21.00%	21.00%	21.00%
Impairment of goodwill				$ 1,600

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Litigation and Environmental - Federal Energy Regulatory Commission Proceedings (Details) - Pending Litigation $ in Millions	9 Months Ended
	Sep. 30, 2021 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
Reparations, Refunds, and Rate Reductions Not Resolved in East Line Settlement | Unfavorable Regulatory Action | Federal Energy Regulatory Commission | SFPP
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	50
Freeport LNG Marketing, LLC Case
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 98

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Litigation and Environmental - General (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Estimated Litigation Liability	$ 192	$ 273

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Litigation and Environmental - Portland Harbor (Details) - Environmental Protection Agency - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Billions	9 Months Ended
	Sep. 30, 2021 USD ($) Parties Terminals
GATX Terminals Corporation (n/k/a KMLT)
Site Contingency [Line Items]
Number of Parties Involved In Site Cleanup Allocation Negotiations | Parties	90
Number of Liquid Terminals	2
GATX Terminals Corporation (n/k/a KMLT) | Pro Forma
Site Contingency [Line Items]
Estimated Remedy Implementation Period	10 years
Environmental Remediation Expense | $	$ 3
KMBT
Site Contingency [Line Items]
Number of Liquid Terminals	2

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Litigation and Environmental - Lower Passaic River (Details) - Pending Litigation $ in Millions	Oct. 04, 2021 USD ($) mi	Oct. 05, 2016	Mar. 04, 2016 USD ($) mi	Sep. 30, 2021 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 | Subsequent Event | Pro Forma
Site Contingency [Line Items]
Miles of river	9
Environmental Remediation Expense | $	$ 440

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Litigation and Environmental - Environmental Matters (Details)				240 Months Ended
	Apr. 16, 2019	Mar. 29, 2019 Parties	Nov. 08, 2013 Parties	Dec. 31, 1969 mines	Sep. 30, 2021 cases
Parish of Plaquemines, Louisiana | Coastal Zone | TGP
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants | Parties			17
Parish Orleans, Louisiana | Coastal Zone | SNG
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants | Parties		10
Judicial District of Louisiana | Coastal Zone
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					40
Judicial District of Louisiana | Coastal Zone | TGP
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					1
Judicial District of Louisiana | Coastal Zone | SNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					1
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | TGP and SNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					1
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | TGP
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					4
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | SNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					3
Uranium Mines in Arizona | EPNG
Loss Contingencies [Line Items]
Number of Uranium Mines | mines				20
Percentage of Response Costs	35.00%

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Litigation and Environmental - Environmental Matters General (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Accrual for Environmental Loss Contingencies	$ 242	$ 250
Recorded Third-Party Environmental Recoveries Receivable	$ 12	$ 12