10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

F O R M  10-Q  

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 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,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

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

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

As of July 22, 2021, the registrant had 2,266,520,797 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 Six Months Ended June 30, 2021 and 2020		4
	Consolidated Statements of Comprehensive (Loss) Income - Three and Six Months Ended June 30, 2021 and 2020		5
	Consolidated Balance Sheets - as of June 30, 2021 and December 31, 2020		6
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2021 and 2020		7
	Consolidated Statements of Stockholders’ Equity - Three and Six Months Ended June 30, 2021 and 2020		9
	Notes to Consolidated Financial Statements		11
	Note 1	General	11
	Note 2	Losses and Gains on Impairments, Divestitures and Other Write-downs	13
	Note 3	Debt	15
	Note 4	Stockholders’ Equity	16
	Note 5	Risk Management	17
	Note 6	Revenue Recognition	22
	Note 7	Reportable Segments	25
	Note 8	Income Taxes	26
	Note 9	Litigation and Environmental	27
	Note 10	Recent Accounting Pronouncements	31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		33
	Results of Operations		34
	Overview		34
	Consolidated Earnings Results (GAAP)		36
	Non-GAAP Financial Measures		39
	Segment Earnings Results		42
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		50
	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		58
	Signature		59

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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues
Services	$	1,889	$	1,791	$	3,806	$	3,783
Commodity sales	1,246		723		4,475		1,790
Other	15		46		80		93
Total Revenues	3,150		2,560		8,361		5,666
Operating Costs, Expenses and Other
Costs of sales	936		441		2,945		1,104
Operations and maintenance	582		606		1,096		1,226
Depreciation, depletion and amortization	528		532		1,069		1,097
General and administrative	160		155		316		308
Taxes, other than income taxes	108		103		218		195
Loss on impairments and divestitures, net (Note 2)	1,602		1,005		1,598		1,976
Other income, net	(2)		—		(3)		(1)
Total Operating Costs, Expenses and Other	3,914		2,842		7,239		5,905
Operating (Loss) Income	(764)		(282)		1,122		(239)
Other Income (Expense)
Earnings from equity investments	157		176		223		368
Amortization of excess cost of equity investments	(13)		(35)		(35)		(67)
Interest, net	(377)		(395)		(754)		(831)
Other, net (Note 2)	20		16		243		18
Total Other Expense	(213)		(238)		(323)		(512)
(Loss) Income Before Income Taxes	(977)		(520)		799		(751)
Income Tax Benefit (Expense)	237		(104)		(114)		(164)
Net (Loss) Income	(740)		(624)		685		(915)
Net Income Attributable to Noncontrolling Interests	(17)		(13)		(33)		(28)
Net (Loss) Income Attributable to Kinder Morgan, Inc.	$	(757)	$	(637)	$	652	$	(943)
Class P Shares
Basic and Diluted (Loss) Earnings Per Share	$	(0.34)	$	(0.28)	$	0.29	$	(0.42)
Basic and Diluted Weighted Average Shares Outstanding	2,265		2,261		2,264		2,263

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

4

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In millions, unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net (loss) income	$	(740)	$	(624)	$	685	$	(915)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $47, $57, $94 and $(12), respectively)	(157)		(189)		(313)		40
Reclassification of change in fair value of derivatives to net (loss) income (net of tax expense of $9, $14, $27 and $23, respectively)	30		47		89		77
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)	—		—		—		1
Benefit plan adjustments (net of tax expense of $1, $2, $5 and $5, respectively)	5		5		22		16
Total other comprehensive (loss) income	(122)		(137)		(202)		134
Comprehensive (loss) income	(862)		(761)		483		(781)
Comprehensive income attributable to noncontrolling interests	(17)		(13)		(33)		(28)
Comprehensive (loss) income attributable to Kinder Morgan, Inc.	$	(879)	$	(774)	$	450	$	(809)

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)

	June 30, 2021		December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents	$	1,365	$	1,184
Restricted deposits	604		25
Accounts receivable	1,416		1,293
Fair value of derivative contracts	221		185
Inventories	396		348
Other current assets	281		168
Total current assets	4,283		3,203
Property, plant and equipment, net	34,570		35,836
Investments	7,650		7,917
Goodwill	19,851		19,851
Other intangibles, net	1,585		2,453
Deferred income taxes	492		536
Deferred charges and other assets	1,744		2,177
Total Assets	$	70,175	$	71,973
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,183	$	2,558
Accounts payable	949		837
Accrued interest	479		525
Accrued taxes	217		267
Accrued contingencies	232		307
Other current liabilities	999		580
Total current liabilities	5,059		5,074
Long-term liabilities and deferred credits
Long-term debt
Outstanding	30,008		30,838
Debt fair value adjustments	1,069		1,293
Total long-term debt	31,077		32,131
Other long-term liabilities and deferred credits	2,216		2,202
Total long-term liabilities and deferred credits	33,293		34,333
Total Liabilities	38,352		39,407
Commitments and contingencies (Notes 3 and 9)
Redeemable Noncontrolling Interest	683		728
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,604,747 and 2,264,257,336 shares, respectively, issued and outstanding	23		23
Additional paid-in capital	41,793		41,756
Accumulated deficit	(10,496)		(9,936)
Accumulated other comprehensive loss	(609)		(407)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,711		31,436
Noncontrolling interests	429		402
Total Stockholders’ Equity	31,140		31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	70,175	$	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)
	Six Months Ended June 30,
	2021		2020
Cash Flows From Operating Activities
Net income (loss)	$	685	$	(915)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	1,069		1,097
Deferred income taxes	105		28
Amortization of excess cost of equity investments	35		67
Loss on impairments and divestitures, net (Note 2)	1,598		1,976
Gain on sale of interest in equity investment (Note 2)	(206)		—
Earnings from equity investments	(223)		(368)
Distributions from equity investment earnings	346		317
Changes in components of working capital
Accounts receivable	(130)		335
Inventories	(51)		28
Other current assets	(31)		48
Accounts payable	145		(182)
Accrued interest, net of interest rate swaps	(42)		(65)
Accrued taxes	(51)		(23)
Other current liabilities	195		(96)
Rate reparations, refunds and other litigation reserve adjustments	(102)		(12)
Other, net	(31)		(3)
Net Cash Provided by Operating Activities	3,311		2,232
Cash Flows From Investing Activities
Capital expenditures	(545)		(963)
Proceeds from sales of investments	413		907
Contributions to investments	(26)		(225)
Distributions from equity investments in excess of cumulative earnings	48		86
Other, net	(1)		(46)
Net Cash Used in Investing Activities	(111)		(241)
Cash Flows From Financing Activities
Issuances of debt	3,110		2,652
Payments of debt	(4,273)		(3,037)
Debt issue costs	(12)		(11)
Dividends	(1,212)		(1,166)
Repurchases of shares	—		(50)
Contributions from investment partner and noncontrolling interests	3		9
Distributions to investment partner	(45)		(38)
Distributions to noncontrolling interests	(8)		(7)
Other, net	(3)		(1)
Net Cash Used in Financing Activities	(2,440)		(1,649)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	—		(5)
Net Increase in Cash, Cash Equivalents and Restricted Deposits	760		337
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	1,969	$	546

7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
	Six Months Ended June 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	1,365		526
Restricted Deposits, end of period	604		20
Cash, Cash Equivalents, and Restricted Deposits, end of period	1,969		546
Net Increase in Cash, Cash Equivalents and Restricted Deposits	$	760	$	337
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	$	28	$	8
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	807		891
Cash paid during the period for income taxes, net	8		136

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 March 31, 2021	2,264	$	23	$	41,775	$	(9,124)	$	(487)	$	32,187	$	416	$	32,603
Restricted shares	1			18						18				18
Net (loss) income						(757)				(757)		17		(740)
Distributions										—		(5)		(5)
Contributions										—		1		1
Dividends						(615)				(615)				(615)
Other comprehensive loss								(122)		(122)				(122)
Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)	$	30,711	$	429	$	31,140

	Common stock
	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 March 31, 2020	2,261	$	23	$	41,713	$	(8,568)	$	(62)	$	33,106	$	358	$	33,464
Restricted shares				18						18				18
Net (loss) income						(637)				(637)		13		(624)
Distributions										—		(4)		(4)
Contributions										—		4		4
Dividends						(597)				(597)				(597)
Other comprehensive loss								(137)		(137)				(137)
Balance at June 30, 2020	2,261	$	23	$	41,731	$	(9,802)	$	(199)	$	31,753	$	371	$	32,124

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	1			37						37				37
Net income						652				652		33		685
Distributions										—		(8)		(8)
Contributions										—		3		3
Dividends						(1,212)				(1,212)				(1,212)
Other										—		(1)		(1)
Other comprehensive loss								(202)		(202)				(202)
Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)	$	30,711	$	429	$	31,140

	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				36						36				36
Net (loss) income						(943)				(943)		28		(915)
Distributions										—		(7)		(7)
Contributions										—		6		6
Dividends						(1,166)				(1,166)				(1,166)
Other comprehensive income								134		134				134
Balance at June 30, 2020	2,261	$	23	$	41,731	$	(9,802)	$	(199)	$	31,753	$	371	$	32,124

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 and 144 terminals. 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.

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 billion, 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.

Kinetrex Energy Acquisition

On July 16, 2021, we announced an agreement to acquire Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $310 million. 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 as well as signed commercial agreements to begin construction on three additional landfill based RNG facilities. The transaction requires regulatory approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and is expected to close in the third quarter of 2021.

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 this purpose, we have 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 2 for results of our May 31, 2021 goodwill impairment test.

11

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 (loss) income available to shareholders of Class P shares and participating securities:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net (Loss) Income Available to Stockholders	$	(757)	$	(637)	$	652	$	(943)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(3)		(3)		(6)		(6)
Net (Loss) Income Allocated to Class P Stockholders	$	(760)	$	(640)	$	646	$	(949)
Basic Weighted Average Shares Outstanding	2,265		2,261		2,264		2,263
Basic (Loss) Earnings Per Share	$	(0.34)	$	(0.28)	$	0.29	$	(0.42)

(a)As of June 30, 2021, there were approximately 12 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 June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	12	12	12	12
Convertible trust preferred securities	3	3	3	3

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2. 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 six months ended June 30, 2021 and 2020:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	1,600	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		1,000		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Gain on divestitures of long-lived assets	(1)		—		(1)		—
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21
Terminals
Impairment of long-lived and intangible assets	—		5		—		5
Loss on divestitures of long-lived assets	1		—		—		—
CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Loss on divestitures of long-lived assets	3		—		3		—
Other gain on divestitures of long-lived assets	(1)		—		(4)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	1,602	$	1,005	$	1,509	$	1,976

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

Impairments

Long-lived Assets

During the quarter ended June 30, 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. The long-lived asset impairment test involves two steps. Step one is an assessment as to whether the asset’s net book value is 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 the 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, which we believe represented the estimated weighted average cost of capital of a theoretical market participant.

During the six months ended June 30, 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 six months ended June 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 tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the three months ended June 30, 2020, we conducted our annual test of the recoverability of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 business segment during the six months ended June 30, 2020 and within our Natural Gas Pipelines business segment during the three and six months ended June 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 $413 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 six months ended June 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. 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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3. Debt

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

	June 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023	$	—	$	—
Commercial paper notes	—		—
Current portion of senior notes
5.00%, due February 2021(a)	—		750
3.50%, due March 2021(a)	—		750
5.80%, due March 2021(a)	—		400
5.00%, due October 2021(b)	500		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(c)	890		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,183		2,558
Long-term debt (excluding current portion)
Senior notes	29,320		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	357		364
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	221		223
Total long-term debt	30,008		30,838
Total debt(d)	$	32,191	$	33,396

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

(b)These notes were repaid on July 1, 2021. As of June 30, 2021, $506 million for the repayment of these maturing notes and associated accrued interest were held in escrow and included in the accompanying consolidated balance sheet within “Restricted deposits.”

(c)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The June 30, 2021 balance is reported above at the exchange rate of 1.1858 U.S. dollars per Euro. As of June 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 $75 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 5 “Risk Management—Foreign Currency Risk Management”).

(d)Excludes our “Debt fair value adjustments” which, as of June 30, 2021 and December 31, 2020, increased our total debt balances by $1,069 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 Facility

As of June 30, 2021, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of June 30, 2021 was $3,919 million. As of June 30, 2021, we were in compliance with all required covenants.

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Fair Value of Financial Instruments

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

	June 30, 2021				December 31, 2020
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
	(In millions)
Total debt	$	33,260	$	38,498	$	34,689	$	39,622

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

4. 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.54	$	0.525
Per share cash dividend paid in the period	0.27		0.2625		0.5325		0.5125

On July 21, 2021, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended June 30, 2021, which is payable on August 16, 2021 to shareholders of record as of the close of business on August 2, 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	(313)		—		22		(291)
Loss reclassified from accumulated other comprehensive loss	89		—		—		89
Net current-period change in accumulated other comprehensive loss	(224)		—		22		(202)
Balance as of June 30, 2021	$	(237)	$	—	$	(372)	$	(609)

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	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 gain before reclassifications	40		1		16		57
Loss reclassified from accumulated other comprehensive loss	77		—		—		77
Net current-period change in accumulated other comprehensive (loss) income	117		1		16		134
Balance as of June 30, 2020	$	110	$	1	$	(310)	$	(199)

5.  Risk Management

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

Energy Commodity Price Risk Management

As of June 30, 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	(7.9)	MMBbl
Natural gas fixed price	(31.7)	Bcf
Natural gas basis	(26.2)	Bcf
NGL fixed price	(1.0)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.2)	MMBbl
Crude oil basis	(9.8)	MMBbl
Natural gas fixed price	(3.4)	Bcf
Natural gas basis	(15.8)	Bcf
NGL fixed price	(2.1)	MMBbl

As of June 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.

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Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of June 30, 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	2,500		Mark-to-Market	December 2021

(a)The principal amount of hedged senior notes consisted of $250 million included in “Current portion of debt” and $6,850 million included in “Long-term debt” on our accompanying consolidated balance sheet.

During the three months ended March 31, 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 rate through February 2028.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of June 30, 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
		June 30, 2021		December 31, 2020		June 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)	$	18	$	42	$	(206)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	2		33		(87)		(8)
Subtotal		20		75		(293)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	118		119		(3)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	395		575		(12)		(7)
Subtotal		513		694		(15)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	67		—		(8)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	38		138		—		—
Subtotal		105		138		(8)		(6)
Total		638		907		(316)		(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	18		24		(46)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(5)		—
Subtotal		18		24		(51)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
Subtotal		—		—		(1)		—
Total		18		24		(52)		(21)
Total derivatives		$	656	$	931	$	(368)	$	(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 June 30, 2021
Energy commodity derivative contracts(a)	$	18	$	20	$	—	$	38	$	(35)	$	—	$	3
Interest rate contracts	—		513		—		513		(5)		—		508
Foreign currency contracts	—		105		—		105		(8)		—		97
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 June 30, 2021
Energy commodity derivative contracts(a)	$	(46)	$	(298)	$	—	$	(344)	$	35	$	55	$	(254)
Interest rate contracts	—		(16)		—		(16)		5		—		(11)
Foreign currency contracts	—		(8)		—		(8)		8		—		—
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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	28	$	26	$	(189)	$	459
Hedged fixed rate debt(a)	Interest, net	$	(28)	$	(28)	$	190	$	(468)

(a)As of June 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $512 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

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Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended June 30,					Three Months Ended June 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(215)	$	(273)	Revenues—Commodity sales	$	(53)	$	(84)
					Costs of sales	(2)		(2)
Interest rate contracts	1		(1)		Earnings from equity investments(c)	—		—
Foreign currency contracts	10		28		Other, net	16		25
Total	$	(204)	$	(246)	Total	$	(39)	$	(61)

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,					Six Months Ended June 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(374)	$	114	Revenues—Commodity sales	$	(73)	$	(98)
					Costs of sales	2		(5)
Interest rate contracts	2		(9)		Earnings from equity investments(c)	—		—
Foreign currency contracts	(35)		(53)		Other, net	(45)		3
Total	$	(407)	$	52	Total	$	(116)	$	(100)

(a)We expect to reclassify approximately $121 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 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 six months ended June 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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(33)	$	149	$	(663)	$	266
	Costs of sales	(2)		2		160		6
	Earnings from equity investments	(2)		—		(2)		—
Total(a)		$	(37)	$	151	$	(505)	$	272

(a)The three and six months ended June 30, 2021 amounts include approximate losses of $7 million and $455 million, respectively, and the three and six months ended June 30, 2020 amounts include approximate gains of $179 million and $253 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 June 30, 2021 and December 31, 2020, we had no

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outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2021, we had cash margins of $77 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 June 30, 2021 represents the net of our initial margin requirements of $22 million and counterparty variation margin requirements of $55 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 June 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 $169 million of additional collateral.

6. Revenue Recognition

Disaggregation of Revenues

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

	Three Months Ended June 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	799	$	66	$	198	$	—	$	—	$	1,063
Fee-based services	176		244		84		10		—		514
Total services	975		310		282		10		—		1,577
Commodity sales
Natural gas sales	674		—		—		1		(3)		672
Product sales	248		157		7		258		(13)		657
Total commodity sales	922		157		7		259		(16)		1,329
Total revenues from contracts with customers	1,897		467		289		269		(16)		2,906
Other revenues(c)
Leasing services(d)	118		43		144		15		1		321
Derivatives adjustments on commodity sales	(37)		(1)		—		(47)		—		(85)
Other	(2)		5		—		6		(1)		8
Total other revenues	79		47		144		(26)		—		244
Total revenues	$	1,976	$	514	$	433	$	243	$	(16)	$	3,150

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	Three Months Ended June 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)	$	796	$	67	$	189	$	—	$	—	$	1,052
Fee-based services	157		182		95		10		(2)		442
Total services	953		249		284		10		(2)		1,494
Commodity sales
Natural gas sales	377		—		—		—		(1)		376
Product sales	102		49		3		134		(4)		284
Total commodity sales	479		49		3		134		(5)		660
Total revenues from contracts with customers	1,432		298		287		144		(7)		2,154
Other revenues(c)
Leasing services(d)	114		42		132		11		—		299
Derivatives adjustments on commodity sales	(11)		—		—		75		—		64
Other	36		5		—		2		—		43
Total other revenues	139		47		132		88		—		406
Total revenues	$	1,571	$	345	$	419	$	232	$	(7)	$	2,560

	Six Months Ended June 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)	$	1,665	$	125	$	389	$	—	$	—	$	2,179
Fee-based services	354		465		165		25		—		1,009
Total services	2,019		590		554		25		—		3,188
Commodity sales
Natural gas sales	3,993		—		—		2		(8)		3,987
Product sales	468		282		12		487		(23)		1,226
Total commodity sales	4,461		282		12		489		(31)		5,213
Total revenues from contracts with customers	6,480		872		566		514		(31)		8,401
Other revenues(c)
Leasing services(d)	237		86		287		27		—		637
Derivatives adjustments on commodity sales	(655)		(1)		—		(80)		—		(736)
Other	39		10		—		11		(1)		59
Total other revenues	(379)		95		287		(42)		(1)		(40)
Total revenues	$	6,101	$	967	$	853	$	472	$	(32)	$	8,361

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	Six Months Ended June 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)	$	1,661	$	146	$	378	$	—	$	—	$	2,185
Fee-based services	350		442		216		23		(2)		1,029
Total services	2,011		588		594		23		(2)		3,214
Commodity sales
Natural gas sales	878		—		—		—		(3)		875
Product sales	238		158		6		366		(17)		751
Total commodity sales	1,116		158		6		366		(20)		1,626
Total revenues from contracts with customers	3,127		746		600		389		(22)		4,840
Other revenues(c)
Leasing services(d)	227		84		261		21		—		593
Derivatives adjustments on commodity sales	41		—		—		127		—		168
Other	51		10		—		4		—		65
Total other revenues	319		94		261		152		—		826
Total revenues	$	3,446	$	840	$	861	$	541	$	(22)	$	5,666

(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 5 for additional information related to our derivative contracts.

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

Contract Balances

As of June 30, 2021 and December 31, 2020, our contract asset balances were $48 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $12 million was transferred to accounts receivable during the six months ended June 30, 2021. As of June 30, 2021 and December 31, 2020, our contract liability balances were $232 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $45 million was recognized as revenue during the six months ended June 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 June 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Six months ended December 31, 2021	$	2,232
2022	3,766
2023	3,040
2024	2,590
2025	2,191
Thereafter	13,776
Total	$	27,595

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

7.  Reportable Segments

Financial information by segment follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,960	$	1,565	$	6,070	$	3,426
Intersegment revenues	16		6		31		20
Products Pipelines	514		345		967		840
Terminals
Revenues from external customers	433		418		852		859
Intersegment revenues	—		1		1		2
CO2	243		232		472		541
Corporate and intersegment eliminations	(16)		(7)		(32)		(22)
Total consolidated revenues	$	3,150	$	2,560	$	8,361	$	5,666

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	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	(570)	$	(3)	$	1,533	$	1,193
Products Pipelines	265		227		513		496
Terminals	246		229		473		486
CO2	150		146		436		(609)
Total Segment EBDA	91		599		2,955		1,566
DD&A	(528)		(532)		(1,069)		(1,097)
Amortization of excess cost of equity investments	(13)		(35)		(35)		(67)
General and administrative and corporate charges	(150)		(157)		(298)		(322)
Interest, net	(377)		(395)		(754)		(831)
Income tax benefit (expense)	237		(104)		(114)		(164)
Total consolidated net (loss) income	$	(740)	$	(624)	$	685	$	(915)

	June 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	46,445	$	48,597
Products Pipelines	9,138		9,182
Terminals	8,555		8,639
CO2	2,433		2,478
Corporate assets(b)	3,604		3,077
Total consolidated assets	$	70,175	$	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.

8.  Income Taxes

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
	(In millions, except percentages)
Income tax (benefit) expense	$	(237)		$	104		$	114		$	164
Effective tax rate	24.3		%	(20.0)		%	14.3		%	(21.8)		%

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

The effective tax rate for the six months ended June 30, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

The effective tax rate for the three months ended June 30, 2020 is “negative” and lower than the statutory federal rate of 21% due to the $1,000 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 dividend-received deductions from our investments in Citrus and PPL.

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The effective tax rate for the six months ended June 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 three and six months ended June 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for these periods.

9.   Litigation and Environmental

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose 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. By its second Notice of Arbitration, Eni USA 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 to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the 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 re-arbitrating both the breach of contract and negligent misrepresentation claims. On April 15, 2021, Eni USA filed a petition for writ of certiorari with the U.S. Supreme Court seeking review of the Delaware Supreme Court’s decision. This petition remains pending.

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 $225 million. Hiland Partners denies and will vigorously defend against these claims.

Pipeline Integrity and Releases

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

General

As of June 30, 2021 and December 31, 2020, our total reserve for legal matters was $185 million and $273 million, respectively.

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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

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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. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved 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. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.

On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins.

In addition, the EPA and numerous PRPs, including EPEC Polymers, 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 Polymers, 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 ROD as well as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the ongoing discussions with the EPA conclude, or the FS is completed and the RI/FS is finalized, 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, 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 case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August

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10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Fifth Circuit. 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 June 30, 2021 and December 31, 2020, we have accrued a total reserve for environmental liabilities in the amount of $248 million and $250 million, respectively. In addition, as of both June 30, 2021 and December 31, 2020, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.

10. 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 quarter ended June 30, 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 billion, 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.

Kinetrex Energy Acquisition

On July 16, 2021, we announced an agreement to acquire Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $310 million. 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 as well as signed commercial agreements to begin construction on three additional landfill based RNG facilities. Once they all become operational next year, total annual RNG production from the four sites is estimated to be over 4 Bcf. The transaction requires regulatory approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and is expected to close in the third quarter of 2021.

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 $413 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 six months ended June 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 7, “Reportable Segments”) and Net (loss) income attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA and Net Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the three and six months ended June 30, 2021 and 2020 present Segment EBDA and Net (loss) income 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 (loss) income 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 (loss) income 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 (Loss) Income 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 (loss) income 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 (loss) income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic (loss) earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

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DCF

DCF is calculated by adjusting Net (loss) income 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 (loss) income 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 (Loss) Income 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 (loss) income attributable to Kinder Morgan, Inc. In prior periods Net (loss) income was considered the comparable GAAP measure and has been updated to Net (loss) income 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 (Loss) Income 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 June 30, 2021, by subtracting the following amounts from our debt balance of $33,260 million: (i) cash and cash equivalents of $1,365 million (which, as of June 30, 2021, the cash and cash equivalents component of Net Debt includes “Restricted deposits” of approximately $506 million held in escrow that were used on July 1, 2021 for the repayment of senior notes plus associated accrued interest); (ii) debt fair value adjustments of $1,069 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $125 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 June 30,
	2021		2020		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	(570)	$	(3)	$	(567)	(18,900)	%
Products Pipelines	265		227		38		17	%
Terminals	246		229		17		7	%
CO2	150		146		4		3	%
Total Segment EBDA	91		599		(508)		(85)	%
DD&A	(528)		(532)		4		1	%
Amortization of excess cost of equity investments	(13)		(35)		22		63	%
General and administrative and corporate charges	(150)		(157)		7		4	%
Interest, net	(377)		(395)		18		5	%
Loss before income taxes	(977)		(520)		(457)		(88)	%
Income tax benefit (expense)	237		(104)		341		328	%
Net loss	(740)		(624)		(116)		(19)	%
Net income attributable to noncontrolling interests	(17)		(13)		(4)		(31)	%
Net loss attributable to Kinder Morgan, Inc.	$	(757)	$	(637)	$	(120)	(19)	%

	Six Months Ended June 30,
	2021		2020		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,533	$	1,193	$	340	28	%
Products Pipelines	513		496		17		3	%
Terminals	473		486		(13)		(3)	%
CO2	436		(609)		1,045		172	%
Total Segment EBDA	2,955		1,566		1,389		89	%
DD&A	(1,069)		(1,097)		28		3	%
Amortization of excess cost of equity investments	(35)		(67)		32		48	%
General and administrative and corporate charges	(298)		(322)		24		7	%
Interest, net	(754)		(831)		77		9	%
Income (loss) before income taxes	799		(751)		1,550		206	%
Income tax expense	(114)		(164)		50		30	%
Net income (loss)	685		(915)		1,600		175	%
Net income attributable to noncontrolling interests	(33)		(28)		(5)		(18)	%
Net income (loss) attributable to Kinder Morgan, Inc.	$	652	$	(943)	$	1,595	169	%

(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 loss attributable to Kinder Morgan, Inc. increased $120 million for the three months ended June 30, 2021 and Net income attributable to Kinder Morgan, Inc. increased $1,595 million for the six months ended June 30, 2021 as compared to the respective prior year periods. The second quarter increased loss was primarily due to a $1,600 million pre-tax non-cash impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in 2021 resulting from anticipated lower volumes and rates on contract renewals compared to the $1 billion non-cash impairment of goodwill associated with our Natural Gas Pipelines Non-Regulated reporting unit recognized in 2020. 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 $350 million of impairments in 2021 as compared to 2020 reflecting the $1,600 million pre-tax non-cash asset impairment loss in 2021 in our Natural Gas Pipeline business segment 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. In addition to the above, the second quarter and year-to-date changes were favorably impacted by higher earnings from our Products Pipelines business segment, lower interest expense, DD&A expense (including amortization of excess cost of equity investments), and general and administrative and corporate charges expense.

Certain Items Affecting Consolidated Earnings Results

	Three Months Ended June 30,
	2021						2020
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	(570)	$	1,634	$	1,064	$	(3)	$	1,019	$	1,016	$	48
Products Pipelines	265		28		293		227		—		227		66
Terminals	246		—		246		229		—		229		17
CO2	150		1		151		146		10		156		(5)
Total Segment EBDA(a)	91		1,663		1,754		599		1,029		1,628		126
DD&A and amortization of excess cost of equity investments	(541)		—		(541)		(567)		—		(567)		26
General and administrative and corporate charges(a)	(150)		—		(150)		(157)		—		(157)		7
Interest, net(a)	(377)		(3)		(380)		(395)		(1)		(396)		16
(Loss) income before income taxes	(977)		1,660		683		(520)		1,028		508		175
Income tax benefit (expense)(b)	237		(387)		(150)		(104)		(10)		(114)		(36)
Net (loss) income	(740)		1,273		533		(624)		1,018		394		139
Net income attributable to noncontrolling interests(a)	(17)		—		(17)		(13)		—		(13)		(4)
Net (loss) income attributable to Kinder Morgan, Inc.	$	(757)	$	1,273	$	516	$	(637)	$	1,018	$	381	$	135

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	Six Months Ended June 30,
	2021						2020
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,533	$	1,625	$	3,158	$	1,193	$	1,002	$	2,195	$	963
Products Pipelines	513		43		556		496		4		500		56
Terminals	473		—		473		486		—		486		(13)
CO2	436		6		442		(609)		940		331		111
Total Segment EBDA(a)	2,955		1,674		4,629		1,566		1,946		3,512		1,117
DD&A and amortization of excess cost of equity investments	(1,104)		—		(1,104)		(1,164)		—		(1,164)		60
General and administrative and corporate charges(a)	(298)		—		(298)		(322)		25		(297)		(1)
Interest, net(a)	(754)		(9)		(763)		(831)		—		(831)		68
Income (loss) before income taxes	799		1,665		2,464		(751)		1,971		1,220		1,244
Income tax expense(b)	(114)		(427)		(541)		(164)		(106)		(270)		(271)
Net income (loss)	685		1,238		1,923		(915)		1,865		950		973
Net income attributable to noncontrolling interests(a)	(33)		—		(33)		(28)		—		(28)		(5)
Net income (loss) attributable to Kinder Morgan, Inc.	$	652	$	1,238	$	1,890	$	(943)	$	1,865	$	922	$	968

(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 $135 million and $968 million for the three and six months ended June 30, 2021, respectively, as compared to the respective prior year periods. The second quarter increase was primarily due to higher earnings from our Products Pipelines and Natural Gas Pipelines business segments and lower DD&A expense and interest expense. 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 interest expense and DD&A expense.

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Non-GAAP Financial Measures

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)	$	(757)	$	(637)	$	652	$	(943)
Total Certain Items	1,273		1,018		1,238		1,865
Adjusted Earnings(a)	516		381		1,890		922
DD&A and amortization of excess cost of equity investments for DCF(b)	604		659		1,242		1,350
Income tax expense for DCF(a)(b)	170		132		589		313
Cash taxes(b)	(45)		(5)		(44)		(8)
Sustaining capital expenditures(b)	(210)		(159)		(317)		(300)
Other items(c)	(10)		(7)		(6)		(15)
DCF	$	1,025	$	1,001	$	3,354	$	2,262

Adjusted Segment EBDA to Adjusted EBITDA to DCF

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Natural Gas Pipelines	$	1,064	$	1,016	$	3,158	$	2,195
Products Pipelines	293		227		556		500
Terminals	246		229		473		486
CO2	151		156		442		331
Adjusted Segment EBDA(a)	1,754		1,628		4,629		3,512
General and administrative and corporate charges(a)	(150)		(157)		(298)		(297)
Joint venture DD&A and income tax expense(a)(b)	83		110		186		229
Net income attributable to noncontrolling interests(a)	(17)		(13)		(33)		(28)
Adjusted EBITDA	1,670		1,568		4,484		3,416
Interest, net(a)	(380)		(396)		(763)		(831)
Cash taxes(b)	(45)		(5)		(44)		(8)
Sustaining capital expenditures(b)	(210)		(159)		(317)		(300)
Other items(c)	(10)		(7)		(6)		(15)
DCF	$	1,025	$	1,001	$	3,354	$	2,262
Adjusted Earnings per share	$	0.23	$	0.17	$	0.83	$	0.40
Weighted average shares outstanding for dividends(d)	2,277		2,274		2,277		2,275
DCF per share	$	0.45	$	0.44	$	1.47	$	0.99
Declared dividends per share	$	0.27	$	0.2625	$	0.54	$	0.525

(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net (Loss) Income 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 non-cash compensation associated with our restricted stock program, non-cash pension expense and pension contributions.

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)(a)	$	(757)	$	(637)	$	652	$	(943)
Certain Items:
Fair value amortization	(4)		(4)		(8)		(12)
Legal, environmental and taxes other than income tax reserves	28		—		112		(8)
Change in fair value of derivative contracts(b)	28		32		42		(4)
Loss on impairments, divestitures and other write-downs, net(c)	1,600		—		1,511		371
Loss on impairments of goodwill(d)	—		1,000		—		1,600
Income tax Certain Items	(387)		(10)		(427)		(106)
Other	8		—		8		24
Total Certain Items(e)	1,273		1,018		1,238		1,865
DD&A and amortization of excess cost of equity investments	541		567		1,104		1,164
Income tax expense(f)	150		114		541		270
Joint venture DD&A and income tax expense(f)(g)	83		110		186		229
Interest, net(f)	380		396		763		831
Adjusted EBITDA	$	1,670	$	1,568	$	4,484	$	3,416

(a)In prior periods, Net (loss) income was considered the comparable GAAP measure and has been updated to Net (loss) income 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 six months ended June 30, 2021 amounts include a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from anticipated lower volumes and rates on contract renewals. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings, offset partially by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby. Six months ended June 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, which are reported within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of operations.

(d)Three and six months ended June 30, 2020 amounts include a non-cash impairment of goodwill associated with our Natural Gas Pipelines Non-Regulated reporting unit. Six months ended June 30, 2020 amount also includes a non-cash impairment of goodwill associated with our CO2 reporting unit.

(e)2021 amount includes $127 million and 2020 amount includes less than $1 million 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.

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Supplemental Information

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
DD&A (GAAP)	$	528	$	532	$	1,069	$	1,097
Amortization of excess cost of equity investments (GAAP)	13		35		35		67
DD&A and amortization of excess cost of equity investments	541		567		1,104		1,164
Joint venture DD&A	63		92		138		186
DD&A and amortization of excess cost of equity investments for DCF	$	604	$	659	$	1,242	$	1,350
Income tax (benefit) expense (GAAP)	$	(237)	$	104	$	114	$	164
Certain Items	387		10		427		106
Income tax expense(a)	150		114		541		270
Unconsolidated joint venture income tax expense(a)(b)	20		18		48		43
Income tax expense for DCF(a)	$	170	$	132	$	589	$	313
Additional joint venture information
Unconsolidated joint venture DD&A	$	74	$	102	$	160	$	205
Less: Consolidated joint venture partners’ DD&A	11		10		22		19
Joint venture DD&A	63		92		138		186
Unconsolidated joint venture income tax expense(a)(b)	20		18		48		43
Joint venture DD&A and income tax expense(a)	$	83	$	110	$	186	$	229
Unconsolidated joint venture cash taxes(b)	$	(34)	$	(6)	$	(34)	$	(10)
Unconsolidated joint venture sustaining capital expenditures	$	(32)	$	(26)	$	(52)	$	(52)
Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(1)		(3)		(2)
Joint venture sustaining capital expenditures	$	(30)	$	(25)	$	(49)	$	(50)

(a)Amounts are adjusted for Certain Items.

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

41

Segment Earnings Results

Natural Gas Pipelines

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	1,976	$	1,571	$	6,101	$	3,446
Operating expenses	(1,077)		(729)		(3,347)		(1,577)
Loss on impairments and divestitures, net	(1,599)		(1,000)		(1,599)		(1,000)
Other income	1		—		2		1
Earnings from equity investments	126		151		167		315
Other, net	3		4		209		8
Segment EBDA	(570)		(3)		1,533		1,193
Certain Items(a)	1,634		1,019		1,625		1,002
Adjusted Segment EBDA	$	1,064	$	1,016	$	3,158	$	2,195
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	48			$	963
Volumetric data(b)
Transport volumes (BBtu/d)	36,537		35,080		36,878		36,704
Sales volumes (BBtu/d)	2,561		2,112		2,411		2,303
Gathering volumes (BBtu/d)	2,667		3,043		2,588		3,202
NGLs (MBbl/d)	30		29		30		30

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $1,634 million and $1,625 million for the three and six months ended June 30, 2021, respectively, and $1,019 million and $1,002 million for the three and six months ended June 30, 2020, respectively. Three and six months ended June 30, 2021 amounts include a pre-tax non-cash asset impairment loss of $1,600 million resulting from anticipated lower volumes and rates on contract renewals related to our South Texas gathering and processing assets and decreases in revenues of $16 million and $22 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings, partially offset by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a certain litigation matter. Three and six months ended June 30, 2020 amounts primarily resulted from a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit and a decrease in revenues of $23 million and an increase in revenues of $1 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales.

Other

(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.

42

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

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

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Midstream	$	68	29%
West Region	(18)		(7)%
East Region	(2)		—%
Total Natural Gas Pipelines	$	48	5	%

Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Midstream	$	969	177%
West Region	(23)		(4)%
East Region	17		2%
Total Natural Gas Pipelines	$	963	44	%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:

•$68 million (29%) and $969 million (177%) increases, respectively, in Midstream were primarily due to (i) higher sales margins driven by higher commodity prices on our Texas intrastate natural gas pipeline operations; (ii) higher volumes on our Hiland Midstream assets; and (iii) higher equity earnings due to the Permian Highway Pipeline being placed in service in January 2021. These increases were partially offset by lower earnings on KinderHawk and South Texas assets due to lower volumes. 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 to certain purchase contracts 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;

•$18 million (7%) and $23 million (4%) decreases, respectively, in the West Region were primarily due to lower earnings from Wyoming Interstate Company, LLC and Colorado Interstate Gas Company, L.L.C. as a result of lower revenues due to contract expirations; and

•$2 million (—%) decrease and $17 million (2%) increase, respectively, in the East Region were primarily due to (i) lower earnings on Fayetteville Express Pipeline LLC driven by lower revenues as a result of contract expirations; (ii) higher earnings from TGP due to weather-driven increases in reservation and park and loan revenues mostly during first quarter of 2021; and (iii) 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.

43

Products Pipelines

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	514	$	345	$	967	$	840
Operating expenses	(268)		(131)		(487)		(352)
Loss on impairments and divestitures, net	—		—		—		(21)
Earnings from equity investments	19		13		33		28
Other, net	—		—		—		1
Segment EBDA	265		227		513		496
Certain Items(a)	28		—		43		4
Adjusted Segment EBDA	$	293	$	227	$	556	$	500
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	66			$	56
Volumetric data(b)
Gasoline(c)	1,046		762		969		862
Diesel fuel	418		371		398		365
Jet fuel	224		98		200		196
Total refined product volumes	1,688		1,231		1,567		1,423
Crude and condensate	510		479		508		590
Total delivery volumes (MBbl/d)	2,198		1,710		2,075		2,013

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $28 million and $43 million for the three and six months ended June 30, 2021, respectively, and $4 million for the six months ended June 30, 2020. Three and six month 2021 amounts include increases in expense of $28 million related to an adjustment to a litigation reserve. Six month 2021 amount also includes an increase in expense of $15 million related to an environmental reserve adjustment. Six month 2020 amount includes a non-cash loss on impairment of our Belton Terminal of $21 million and 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.

44

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

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

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	34	36	%
Southeast Refined Products	20		41	%
Crude and Condensate	12		14	%
Total Products Pipelines	$	66	29	%

Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	21	10	%
Southeast Refined Products	33		33	%
Crude and Condensate	2		1	%
Total Products Pipelines	$	56	11	%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:

•$34 million (36%) and $21 million (10%) increases, respectively, in West Coast Refined Products were primarily due to increased earnings on Pacific (SFPP) and Calnev Pipe Line LLC driven by higher revenues from the recovery of volumes in second quarter 2021 compared to 2020 which was impacted by COVID, partially offset by an increase in expense related to an adjustment to a litigation reserve on SFPP. The year-to-date increase was partially offset by higher operating expense primarily as a result of higher integrity management spending on SFPP;

•$20 million (41%) and $33 million (33%) increases, respectively, in Southeast Refined Products were primarily due to an increase in equity earnings from Products (SE) Pipe Line and increased revenues from our South East Terminals as a result of higher volumes and from our Transmix processing operations primarily due to higher prices. The year-to-date increase was also driven by higher 2021 earnings at our Transmix processing operations primarily due to first quarter 2020 unfavorable inventory adjustments and by product net gains as a result of higher prices and volumes on South East Terminals; and

•$12 million (14%) and $2 million (1%) increases, respectively, in Crude and Condensate were primarily due to increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s increased earnings were primarily due to higher deficiency revenues partially offset by contract expirations. The Bakken Crude assets’ second quarter increase in earnings was primarily driven by higher commodity prices and higher volumes. Bakken Crude assets’ year-to-date increase in earnings was impacted by lower field operating expenses partially offset by renegotiated contracts at lower average rates and by contract expirations. KMCC and Bakken Crude assets year-to-date increases were also due to lower operating expenses attributable to first quarter 2020 unfavorable inventory valuation adjustments.

45

Terminals

	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
	(In millions, except operating statistics)
Revenues	$	433		$	419		$	853		$	861
Operating expenses	(191)			(193)			(388)			(385)
Loss on impairments and divestitures, net	(1)			(5)			—			(5)
Earnings from equity investments	4			7			7			12
Other, net	1			1			1			3
Segment EBDA	246			229			473			486
Certain Items	—			—			—			—
Adjusted Segment EBDA	$	246		$	229		$	473		$	486
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	17					$	(13)
Volumetric data(a)
Liquids leasable capacity (MMBbl)	79.9			79.6			79.9			79.6
Liquids utilization %(b)	93.6		%	95.6		%	93.6		%	95.6		%
Bulk transload tonnage (MMtons)	13.6			11.1			24.6			24.0

Other

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

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

46

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

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

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Northeast	$	8	38	%
Midwest	6		50	%
Mid Atlantic	6		50	%
Gulf Central	3		10	%
Marine operations	(14)		(27)	%
All others (including intrasegment eliminations)	8		8	%
Total Terminals	$	17	7	%

Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Northeast	$	11	24	%
Midwest	5		17	%
Mid Atlantic	4		14	%
Gulf Central	(12)		(19)	%
Marine operations	(24)		(23)	%
All others (including intrasegment eliminations)	3		1	%
Total Terminals	$	(13)	(3)	%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:

•$8 million (38%) and $11 million (24%) increases, respectively, in the Northeast terminals were primarily driven by increased revenues associated with higher throughput levels and new contracts;

•$6 million (50%) and $5 million (17%) increases, respectively, in the Midwest terminals were primarily the result of an impairment associated with our Muscatine facility realized in the second quarter of 2020;

•$6 million (50%) and $4 million (14%) increases, respectively, in the Mid Atlantic terminals were primarily due to higher coal volumes at our Pier IX facility;

•$3 million (10%) increase and $12 million (19%) decrease, respectively, in the Gulf Central terminals. The second quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol 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; and

•$14 million (27%) and $24 million (23%) decreases, respectively, in Marine operations were primarily due to lower fleet utilization and average charter rates.

47

CO2

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	243	$	232	$	472	$	541
Operating expenses	(98)		(91)		(49)		(213)
Loss on impairments and divestitures, net	(3)		—		(3)		(950)
Earnings from equity investments	8		5		16		13
Segment EBDA	150		146		436		(609)
Certain Items(a)	1		10		6		940
Adjusted Segment EBDA	$	151	$	156	$	442	$	331
Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	(5)			$	111
Volumetric data
SACROC oil production	20.2		22.0		19.8		22.6
Yates oil production	6.7		6.7		6.4		6.9
Katz and Goldsmith oil production	2.2		2.5		2.4		2.9
Tall Cotton oil production	1.0		1.8		1.0		2.1
Total oil production, net (MBbl/d)(b)	30.1		33.0		29.6		34.5
NGL sales volumes, net (MBbl/d)(b)	9.5		9.4		9.1		9.6
CO2 sales volumes, net (Bcf/d)	0.4		0.4		0.4		0.5
Realized weighted average oil price ($ per Bbl)	$	52.50	$	50.31	$	51.79	$	52.56
Realized weighted average NGL price ($ per Bbl)	$	22.58	$	15.84	$	21.42	$	17.84

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $1 million and $6 million for the three and six months ended June 30, 2021, respectively, and $10 million and $940 million for the three and six months ended June 30, 2020, respectively. Six 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.

48

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

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

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing activities	$	(8)	(7)	%
Source and Transportation activities	3		6	%
Total CO2	$	(5)	(3)	%

Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020

	Adjusted Segment EBDA increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing activities	$	115	53	%
Source and Transportation activities	(4)		(4)	%
Total CO2	$	111	34	%

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:

•$8 million (7%) decrease and $115 million (53%) increase, respectively, in Oil and Gas Producing activities. The second quarter decrease was primarily due to higher operating and other expenses of $8 million and lower revenues of $12 million due to lower crude oil volumes partially offset by higher realized crude oil and NGL prices that resulted in increased revenues of $15 million. The year-to-date increase was primarily due to lower operating expenses of $156 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, partially offset by lower volumes resulting in decreased revenues of $37 million, driven in part, by the curtailed oil production and lower realized crude oil prices which decreased revenues by $8 million; and

•$3 million (6%) increase and $4 million (4%) decrease, respectively, in Source and Transportation activities. The second quarter increase was primarily due to an increase in equity earnings offset by a decrease in revenues related to lower CO2 sales prices. The year-to-date decrease was primarily due to a decrease in revenues of $17 million related to lower CO2 sales volumes partially offset by lower operating expenses of $7 million and an increase in equity earnings.

49

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of June 30, 2021.

	Remaining 2021		2022		2023		2024		2025
Crude Oil(a)
Price ($ per Bbl)	$	50.38	$	52.68	$	49.86	$	47.76	$	49.95
Volume (MBbl/d)	25.70		16.20		9.25		3.80		1.40
NGLs
Price ($ per Bbl)	$	33.81	$	48.06
Volume (MBbl/d)	5.70		1.36
Midland-to-Cushing Basis Spread
Price ($ per Bbl)	$	0.26	$	0.73
Volume (MBbl/d)	24.55		10.25

(a)Includes West Texas Intermediate hedges.

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

	Three Months Ended June 30,				Earnings increase/(decrease)
	2021		2020
	(In millions, except percentages)
DD&A (GAAP)	$	(528)	$	(532)	$	4	1	%
General and administrative (GAAP)	$	(160)	$	(155)	$	(5)	(3)	%
Corporate benefit (charges)	10		(2)		12		600	%
Certain Items(a)	—		—		—		—	%
General and administrative and corporate charges(b)	$	(150)	$	(157)	$	7	4	%
Interest, net (GAAP)	$	(377)	$	(395)	$	18	5	%
Certain Items(c)	(3)		(1)		(2)		(200)	%
Interest, net(b)	$	(380)	$	(396)	$	16	4	%
Net income attributable to noncontrolling interests (GAAP)	$	(17)	$	(13)	$	(4)	(31)	%
Certain Items(d)	—		—		—		—	%
Net income attributable to noncontrolling interests(b)	$	(17)	$	(13)	$	(4)	(31)	%

50

	Six Months Ended June 30,				Earnings increase/(decrease)
	2021		2020
	(In millions, except percentages)
DD&A (GAAP)	$	(1,069)	$	(1,097)	$	28	3	%
General and administrative (GAAP)	$	(316)	$	(308)	$	(8)	(3)	%
Corporate benefit (charges)	18		(14)		32		229	%
Certain Items(a)	—		25		(25)		(100)	%
General and administrative and corporate charges(b)	$	(298)	$	(297)	$	(1)	—	%
Interest, net (GAAP)	$	(754)	$	(831)	$	77	9	%
Certain Items(c)	(9)		—		(9)		—	%
Interest, net(b)	$	(763)	$	(831)	$	68	8	%
Net income attributable to noncontrolling interests (GAAP)	$	(33)	$	(28)	$	(5)	(18)	%
Certain Items(d)	—		—		—		—	%
Net income attributable to noncontrolling interests(b)	$	(33)	$	(28)	$	(5)	(18)	%

Certain items

(a)Six month 2020 amount 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 six month 2021 amounts include decreases in interest expense of $4 million and $8 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and six month 2020 amounts include (i) decreases in interest expense of $4 million and $12 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $3 million and $14 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 six months ended June 30, 2021 and 2020 amounts each include less than $1 million of noncontrolling interests associated with Certain Items.

General and administrative expenses and corporate charges adjusted for Certain Items decreased $7 million for the three months ended June 30, 2021 and increased $1 million for the six months ended June 30, 2021, when compared with the respective prior year periods primarily due to $12 million and $24 million, respectively, of cost savings associated with organizational efficiency efforts and lower pension costs of $6 million and $10 million, respectively, partially offset by lower capitalized costs of $7 million and $23 million, respectively, reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment and higher benefit-related costs of $4 million and $6 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 six months ended June 30, 2021 when compared with the respective prior year periods decreased $16 million and $68 million, respectively, primarily due to lower weighted average long-term debt balances and lower LIBOR and 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 June 30, 2021 and December 31, 2020, approximately 14% 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. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

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

51

Income Taxes

Our tax benefit for the three months ended June 30, 2021 was approximately $237 million as compared with $104 million of expense for the same period of 2020. The $341 million decrease in tax expense was due to the prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment.

Our tax expense for the six months ended June 30, 2021 was approximately $114 million as compared with $164 million for the same period of 2020. The $50 million decrease in tax expense was due primarily to the prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment and the current year release of the valuation allowance on our investment in NGPL Holdings, offset by federal and state taxes on higher pre-tax book income in the 2021 period and the refund of alternative minimum tax sequestration credits in the 2020 period.

Liquidity and Capital Resources

General

As of June 30, 2021, we had $1,365 million of “Cash and cash equivalents,” an increase of $181 million from December 31, 2020. As of June 30, 2021, our “Restricted deposits” included $506 million held in escrow for the repayment of senior notes and accrued interest made on July 1, 2021. We also used $1.2 billion of cash on hand to complete the acquisition on July 9, 2021 of subsidiaries of Stagecoach. Additionally, as of June 30, 2021, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility (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 facility 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 $3,311 million and $2,232 million in the first six 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. We believe our current cash on hand, our cash flows from operations, and our borrowing capacity under our revolving credit facility are more than adequate to allow us to manage our cash requirements, including maturing debt, through 2021; 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 second 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.

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.

Short-term Liquidity

As of June 30, 2021, our principal sources of short-term liquidity are (i) cash from operations; (ii) our $4.0 billion revolving credit facility and associated commercial paper program; and (iii) cash and cash equivalents. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Letters of credit and commercial paper borrowings reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility 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 facility.

As of June 30, 2021, our $2,183 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 $776 million and $1,871 million as of June 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 $1,095 million favorable change from year-end 2020 was primarily due to (i) a decrease of approximately $375 million in senior notes that mature in the next twelve months; (ii) a $604

52

million increase in restricted deposits primarily related to cash held in escrow for $506 million in senior notes and accrued interest that were repaid on July 1, 2021; (iii) a $181 million increase in cash and cash equivalents; and (iv) a $75 million decrease in accrued contingencies, partially offset by a $176 million increase in current regulatory liabilities and a net unfavorable short-term fair value adjustment of $164 million on derivative contract assets and liabilities in 2021. 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 June 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 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 six months ended June 30, 2021, and the amount we expect to spend for the remainder of 2021 to sustain and grow our businesses are as follows:

	Six Months Ended June 30, 2021		2021 Remaining		Total 2021
	(In millions)
Sustaining capital expenditures(a)(b)	$	317	$	557	$	874
Discretionary capital investments(b)(c)(d)	302		1,683		1,985

(a)Six months ended June 30, 2021, 2021 Remaining, and Total 2021 amounts include $49 million, $60 million, and $109 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.”

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(b)Six months ended June 30, 2021 amount excludes $45 million due to decreases in accrued capital expenditures and contractor retainage and net changes in other.

(c)Six months ended June 30, 2021 amount includes $70 million of our contributions to certain unconsolidated joint ventures for capital investments. Both 2021 Remaining and Total 2021 amounts include $1.2 billion for our acquisition of subsidiaries of Stagecoach.

(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 June 30, 2021 and December 31, 2020 were $227 million and $141 million, respectively. The increase of $86 million was primarily driven by capital commitments related to our Terminals and Natural Gas Pipelines business segments.

Cash Flows

Operating Activities

Cash provided by operating activities increased $1,079 million in the six months ended June 30, 2021 compared to the respective 2020 period primarily due to:

•a $1,178 million increase in cash after adjusting the $1,600 million increase in net income by $422 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 “—Results of Operations”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred 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 $99 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 a net unfavorable change in the timing of accounts receivable collections and trade payable payments in the 2021 period compared to the 2020 period. The decrease was also driven by payments for litigation matters in the 2021 period.

Investing Activities

Cash used in investing activities decreased $130 million for the six months ended June 30, 2021 compared to the respective 2020 period primarily attributable to:

•a $418 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and

•a $199 million decrease in cash used for contributions to equity investees driven by lower contributions to Permian Highway Pipeline and SNG in the 2021 period compared with the 2020 period; partially offset by,

•a $494 million decrease in cash primarily due to $413 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 2 “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.

Financing Activities

Cash used in financing activities increased $791 million for the six months ended June 30, 2021 compared to the respective 2020 period primarily attributable to:

•a $779 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.

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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

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 June 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 June 30, 2021 and December 31, 2020, the Obligated Group had $31,369 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	June 30, 2021		December 31, 2020
	(In millions)
Current assets	$	3,996	$	2,957
Current assets - affiliates	1,195		1,151
Noncurrent assets	59,088		61,783
Noncurrent assets - affiliates	507		616
Total Assets	$	64,786	$	66,507
Current liabilities	$	4,654	$	4,528
Current liabilities - affiliates	1,213		1,209
Noncurrent liabilities	32,887		33,907
Noncurrent liabilities - affiliates	945		1,078
Total Liabilities	39,699		40,722
Redeemable noncontrolling interest	683		728
Kinder Morgan, Inc.’s stockholders’ equity	24,404		25,057
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	64,786	$	66,507

Summarized Combined Income Statement Information	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(In millions)
Revenues	$	2,837	$	7,739
Operating (loss) income	(831)		998
Net (loss) income	(813)		564

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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 5 “Risk Management” to our consolidated financial statements.

Item 4.  Controls and Procedures.

As of June 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 June 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 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2020 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 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 June 30, 2021.

Item 5.  Other Information.

None.

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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 June 30, 2021.
10.2	Kinder Morgan, Inc. 2021 Amended and Restated Long Term Incentive Plan (filed as Exhibit 4.5 to Post-Effective Amendment No. 1 to KMI’s Registration Statement on Form S-8 filed July 16, 2021 (File No. 333-205430)).
10.3	2021 Form of Employee Restricted Stock Unit 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 six months ended June 30, 2021 and 2020; (ii) our Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2021 and 2020; (iii) our Consolidated Balance Sheets as of June 30, 2021 and December 31, 2020; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2021 and 2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and six months ended June 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.

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SIGNATURE

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

KINDER MORGAN, INC.
	Registrant

Date:	July 23, 2021	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

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EX-10.1

Exhibit 10.1

CROSS GUARANTEE AGREEMENT

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

W I T N E S S E T H:

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

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

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

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

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

1.Defined Terms.

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

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

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

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

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

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

Exhibit 10.1

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

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

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

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

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

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

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

2

Exhibit 10.1

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

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

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

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

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

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

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

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

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

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

3

Exhibit 10.1

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

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

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

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

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

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

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

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

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

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

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

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

4

Exhibit 10.1

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

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

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

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

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

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

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

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

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

5

Exhibit 10.1

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

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

2.    Guarantee.

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

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

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

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

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

6

Exhibit 10.1

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

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

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

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

7

Exhibit 10.1

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

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

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

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

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

7.Guarantee Absolute and Unconditional.

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

8

Exhibit 10.1

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

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

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

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

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

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

9

Exhibit 10.1

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

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

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

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

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

12.Notices.

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

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

10

Exhibit 10.1

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

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

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

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

16.Amendments; No Waiver; Cumulative Remedies.

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

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

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

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

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

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

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

11

Exhibit 10.1

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

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

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

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

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

19.Additional Guarantors.

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

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

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

12

Exhibit 10.1

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

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

[Signature pages follow]

13

Exhibit 10.1

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

GUARANTORS

KINDER MORGAN, INC.

By:        /s/ Anthony B. Ashley                

Name: Anthony B. Ashley

Title: Treasurer

AGNES B CRANE, LLC

AMERICAN PETROLEUM TANKERS II LLC

AMERICAN PETROLEUM TANKERS III LLC

AMERICAN PETROLEUM TANKERS IV LLC

AMERICAN PETROLEUM TANKERS LLC

AMERICAN PETROLEUM TANKERS PARENT LLC

AMERICAN PETROLEUM TANKERS V LLC

AMERICAN PETROLEUM TANKERS VI LLC

AMERICAN PETROLEUM TANKERS VII LLC

APT FLORIDA LLC

APT INTERMEDIATE HOLDCO LLC

APT NEW INTERMEDIATE HOLDCO LLC

APT PENNSYLVANIA LLC

APT SUNSHINE STATE LLC

AUDREY TUG LLC

BEAR CREEK STORAGE COMPANY, L.L.C.

BETTY LOU LLC

CAMINO REAL GATHERING COMPANY, L.L.C.

CANTERA GAS COMPANY LLC

CDE PIPELINE LLC

CENTRAL FLORIDA PIPELINE LLC

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

CIG GAS STORAGE COMPANY LLC

CIG PIPELINE SERVICES COMPANY, L.L.C.

CIMMARRON GATHERING LLC

COLORADO INTERSTATE GAS COMPANY, L.L.C.

COLORADO INTERSTATE ISSUING CORPORATION

COPANO DOUBLE EAGLE LLC

COPANO ENERGY FINANCE CORPORATION

COPANO ENERGY, L.L.C.

COPANO ENERGY SERVICES/UPPER GULF COAST LLC

COPANO FIELD SERVICES GP, L.L.C.

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

COPANO FIELD SERVICES/SOUTH TEXAS LLC

COPANO FIELD SERVICES/UPPER GULF COAST LLC

COPANO LIBERTY, LLC

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

COPANO NGL SERVICES LLC

COPANO PIPELINES GROUP, L.L.C.

[Signature Page to Cross Guarantee]

Exhibit 10.1

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

COPANO PIPELINES/ROCKY MOUNTAINS, LLC

COPANO PIPELINES/SOUTH TEXAS LLC

COPANO PIPELINES/UPPER GULF COAST LLC

COPANO PROCESSING LLC

COPANO RISK MANAGEMENT LLC

COPANO/WEBB-DUVAL PIPELINE LLC

CPNO SERVICES LLC

DAKOTA BULK TERMINAL, INC.

DELTA TERMINAL SERVICES LLC

EAGLE FORD GATHERING LLC

EL PASO CHEYENNE HOLDINGS, L.L.C.

EL PASO CITRUS HOLDINGS, INC.

EL PASO CNG COMPANY, L.L.C.

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

EL PASO LLC

EL PASO MIDSTREAM GROUP LLC

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

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

EL PASO PIPELINE CORPORATION

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

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

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

EL PASO PIPELINE PARTNERS, L.P.

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

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

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

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

ELBA EXPRESS COMPANY, L.L.C.

ELIZABETH RIVER TERMINALS LLC

EMORY B CRANE, LLC

EPBGP CONTRACTING SERVICES LLC

EP ENERGY HOLDING COMPANY

EP RUBY LLC

EPTP ISSUING CORPORATION

FERNANDINA MARINE CONSTRUCTION MANAGEMENT LLC

FRANK L. CRANE, LLC

GENERAL STEVEDORES GP, LLC

GENERAL STEVEDORES HOLDINGS LLC

GLOBAL AMERICAN TERMINALS LLC

HAMPSHIRE LLC

HARRAH MIDSTREAM LLC

HBM ENVIRONMENTAL, INC.

ICPT, L.L.C

J.R. NICHOLLS LLC

JAVELINA TUG LLC

JEANNIE BREWER LLC

JV TANKER CHARTERER LLC

KINDER MORGAN (DELAWARE), INC.

KINDER MORGAN 2-MILE LLC

KINDER MORGAN ADMINISTRATIVE SERVICES TAMPA LLC

KINDER MORGAN ALTAMONT LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

KINDER MORGAN AMORY LLC

KINDER MORGAN ARROW TERMINALS HOLDINGS, INC.

KINDER MORGAN ARROW TERMINALS, L.P.

By Kinder Morgan River Terminals, LLC, its general partner

KINDER MORGAN BALTIMORE TRANSLOAD TERMINAL LLC

KINDER MORGAN BATTLEGROUND OIL LLC

KINDER MORGAN BORDER PIPELINE LLC

KINDER MORGAN BULK TERMINALS, INC.

KINDER MORGAN CARBON DIOXIDE TRANSPORTATION

COMPANY

KINDER MORGAN CO2 COMPANY, L.P.

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

KINDER MORGAN COCHIN LLC

KINDER MORGAN COLUMBUS LLC

KINDER MORGAN COMMERCIAL SERVICES LLC

KINDER MORGAN CRUDE & CONDENSATE LLC

KINDER MORGAN CRUDE OIL PIPELINES LLC

KINDER MORGAN CRUDE TO RAIL LLC

KINDER MORGAN CUSHING LLC

KINDER MORGAN DALLAS FORT WORTH RAIL TERMINAL LLC

KINDER MORGAN ENDEAVOR LLC

KINDER MORGAN ENERGY PARTNERS, L.P.

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

KINDER MORGAN EP MIDSTREAM LLC

KINDER MORGAN FINANCE COMPANY LLC

KINDER MORGAN FLEETING LLC

KINDER MORGAN FREEDOM PIPELINE LLC

KINDER MORGAN KEYSTONE GAS STORAGE LLC

KINDER MORGAN KMAP LLC

KINDER MORGAN LAS VEGAS LLC

KINDER MORGAN LINDEN TRANSLOAD TERMINAL LLC

KINDER MORGAN LIQUIDS TERMINALS LLC

KINDER MORGAN LIQUIDS TERMINALS ST. GABRIEL LLC

KINDER MORGAN MARINE SERVICES LLC

KINDER MORGAN MATERIALS SERVICES, LLC

KINDER MORGAN MID ATLANTIC MARINE SERVICES LLC

KINDER MORGAN NATGAS O&M LLC

KINDER MORGAN NORTH TEXAS PIPELINE LLC

KINDER MORGAN OPERATING L.P. “A”

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

KINDER MORGAN OPERATING L.P. “B”

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

KINDER MORGAN OPERATING L.P. “C”

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

KINDER MORGAN OPERATING L.P. “D”

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

KINDER MORGAN PECOS LLC

KINDER MORGAN PECOS VALLEY LLC

KINDER MORGAN PETCOKE GP LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

KINDER MORGAN PETCOKE, L.P.

By Kinder Morgan Petcoke GP LLC, its general partner

KINDER MORGAN PETCOKE LP LLC

KINDER MORGAN PETROLEUM TANKERS LLC

KINDER MORGAN PIPELINE LLC

KINDER MORGAN PIPELINES (USA) INC.

KINDER MORGAN PORT MANATEE TERMINAL LLC

KINDER MORGAN PORT SUTTON TERMINAL LLC

KINDER MORGAN PORT TERMINALS USA LLC

KINDER MORGAN PRODUCTION COMPANY LLC

KINDER MORGAN RAIL SERVICES LLC

KINDER MORGAN RESOURCES II LLC

KINDER MORGAN RESOURCES III LLC

KINDER MORGAN RESOURCES LLC

KINDER MORGAN RIVER TERMINALS LLC

KINDER MORGAN SERVICES LLC

KINDER MORGAN SEVEN OAKS LLC

KINDER MORGAN SOUTHEAST TERMINALS LLC

KINDER MORGAN TANK STORAGE TERMINALS LLC

KINDER MORGAN TEJAS PIPELINE LLC

KINDER MORGAN TERMINALS, INC.

KINDER MORGAN TEXAS PIPELINE LLC

KINDER MORGAN TEXAS TERMINALS, L.P.

By General Stevedores GP, LLC, its general partner

KINDER MORGAN TRANSMIX COMPANY, LLC

KINDER MORGAN TREATING LP

By KM Treating GP LLC, its general partner

KINDER MORGAN URBAN RENEWAL, L.L.C.

KINDER MORGAN UTICA LLC

KINDER MORGAN VIRGINIA LIQUIDS TERMINALS LLC

KINDER MORGAN WINK PIPELINE LLC

KINDERHAWK FIELD SERVICES LLC

KM CRANE LLC

KM DECATUR, INC.

KM EAGLE GATHERING LLC

KM GATHERING LLC

KM KASKASKIA DOCK LLC

KM LIQUIDS TERMINALS LLC

KM NORTH CAHOKIA LAND LLC

KM NORTH CAHOKIA SPECIAL PROJECT LLC

KM NORTH CAHOKIA TERMINAL PROJECT LLC

KM SHIP CHANNEL SERVICES LLC

KM TREATING GP LLC

KM TREATING PRODUCTION LLC

KMBT LLC

KMGP CONTRACTING SERVICES LLC

KMGP SERVICES COMPANY, INC.

KN TELECOMMUNICATIONS, INC.

KNIGHT POWER COMPANY LLC

LOMITA RAIL TERMINAL LLC

MILWAUKEE BULK TERMINALS LLC

MJR OPERATING LLC

MOJAVE PIPELINE COMPANY, L.L.C.

MOJAVE PIPELINE OPERATING COMPANY, L.L.C.

MR. BENNETT LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

MR. VANCE LLC

NASSAU TERMINALS LLC

NGPL HOLDCO INC.

NS 307 HOLDINGS INC.

PADDY RYAN CRANE, LLC

PALMETTO PRODUCTS PIPE LINE LLC

PI 2 PELICAN STATE LLC

PINNEY DOCK & TRANSPORT LLC

QUEEN CITY TERMINALS LLC

RAHWAY RIVER LAND LLC

RAZORBACK TUG LLC

RCI HOLDINGS, INC.

RIVER TERMINALS PROPERTIES GP LLC

RIVER TERMINAL PROPERTIES, L.P.

By River Terminals Properties GP LLC, its general partner

SCISSORTAIL ENERGY, LLC

SNG PIPELINE SERVICES COMPANY, L.L.C.

SOUTHERN GULF LNG COMPANY, L.L.C.

SOUTHERN LIQUEFACTION COMPANY LLC

SOUTHERN LNG COMPANY, L.L.C.

SOUTHERN NATURAL GAS COMPANY, L.L.C.

SOUTHERN NATURAL ISSUING CORPORATION

SOUTHTEX TREATERS LLC

SOUTHWEST FLORIDA PIPELINE LLC

SRT VESSELS LLC

STEVEDORE HOLDINGS, L.P.

By Kinder Morgan Petcoke GP LLC, its general partner

TAJON HOLDINGS, INC.

TEJAS GAS, LLC

TEJAS NATURAL GAS, LLC

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

TENNESSEE GAS PIPELINE ISSUING CORPORATION

TEXAN TUG LLC

TGP PIPELINE SERVICES COMPANY, L.L.C.

TRANS MOUNTAIN PIPELINE (PUGET SOUND) LLC

TRANSCOLORADO GAS TRANSMISSION COMPANY LLC

TRANSLOAD SERVICES, LLC

UTICA MARCELLUS TEXAS PIPELINE LLC

WESTERN PLANT SERVICES, INC.

WYOMING INTERSTATE COMPANY, L.L.C.

By:     /s/ Anthony B. Ashley                

Anthony Ashley

Vice President

[Signature Page to Cross Guarantee]

Exhibit 10.1

ANNEX A TO

THE CROSS GUARANTEE AGREEMENT

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

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

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

Accordingly, each New Guarantor agrees as follows:

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

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

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

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

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

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

Exhibit 10.1

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

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

[Signature Pages Follow]

Exhibit 10.1

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

_________________________________

as Guarantor

By:______________________________

Name:

Title:

Exhibit 10.1

ANNEX B TO

THE CROSS GUARANTEE AGREEMENT

FORM OF NOTATION OF GUARANTEE

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

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

[GUARANTORS],

as Guarantor

By: ______________________________

Name:

Title:

Exhibit 10.1

SCHEDULE I

Guaranteed Obligations

Current as of: June 30, 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: June 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)	5.00% bonds	October 1, 2021
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: June 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: June 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	Societe Generale	January 14, 2003
Kinder Morgan Texas Pipeline LLC	Wells Fargo Bank, N.A.	June 1, 2013
Copano Risk Management, LLC	Citibank, N.A.	July 21, 2008
Copano Risk Management, LLC	J. Aron & Company	December 12, 2005
Copano Risk Management, LLC	Morgan Stanley Capital Group Inc.	May 4, 2007
_________________________________________________ 1 Guaranteed Obligations with respect to Hedging Agreements include International Swaps and Derivatives Association Master Agreements (“ISDAs”) and all transactions entered into pursuant to any ISDA listed on this Schedule I.

4

Exhibit 10.1

SCHEDULE II Guarantors Current as of: June 30, 2021
Agnes B Crane, LLC	Copano Risk Management LLC
American Petroleum Tankers II LLC	Copano Terminals LLC
American Petroleum Tankers III LLC	Copano/Webb-Duval Pipeline LLC
American Petroleum Tankers IV LLC	CPNO Services LLC
American Petroleum Tankers LLC	Dakota Bulk Terminal LLC
American Petroleum Tankers Parent LLC	Delta Terminal Services LLC
American Petroleum Tankers V LLC	Eagle Ford Gathering LLC
American Petroleum Tankers VI LLC	El Paso Cheyenne Holdings, L.L.C.
American Petroleum Tankers VII LLC	El Paso Citrus Holdings, Inc.
American Petroleum Tankers VIII LLC	El Paso CNG Company, L.L.C.
American Petroleum Tankers IX LLC	El Paso Energy Service Company, L.L.C.
American Petroleum Tankers X LLC	El Paso LLC
American Petroleum Tankers XI LLC	El Paso Midstream Group LLC
APT Florida LLC	El Paso Natural Gas Company, L.L.C.
APT Intermediate Holdco LLC	El Paso Noric Investments III, L.L.C.
APT New Intermediate Holdco LLC	El Paso Ruby Holding Company, L.L.C.
APT Pennsylvania LLC	El Paso Tennessee Pipeline Co., L.L.C.
APT Sunshine State LLC	Elba Express Company, L.L.C.
Betty Lou LLC	Elizabeth River Terminals LLC
Camino Real Gas Gathering Company LLC	Emory B Crane, LLC
Camino Real Gathering Company, L.L.C.	EP Ruby LLC
Cantera Gas Company LLC	EPBGP Contracting Services LLC
CDE Pipeline LLC	EPTP Issuing Corporation
Central Florida Pipeline LLC	Frank L. Crane, LLC
Cheyenne Plains Gas Pipeline Company, L.L.C.	General Stevedores GP, LLC
CIG Gas Storage Company LLC	General Stevedores Holdings LLC
CIG Pipeline Services Company, L.L.C.	Harrah Midstream LLC
Colorado Interstate Gas Company, L.L.C.	HBM Environmental LLC
Colorado Interstate Issuing Corporation	Hiland Crude, LLC
Copano Double Eagle LLC	Hiland Partners Holdings LLC
Copano Energy Finance Corporation	HPH Oklahoma Gathering LLC
Copano Energy Services/Upper Gulf Coast LLC	ICPT, L.L.C
Copano Energy, L.L.C.	Independent Trading & Transportation
Copano Field Services GP, L.L.C.	Company I, L.L.C.
Copano Field Services/North Texas, L.L.C.	JV Tanker Charterer LLC
Copano Field Services/South Texas LLC	Kinder Morgan 2-Mile LLC
Copano Field Services/Upper Gulf Coast LLC	Kinder Morgan Administrative Services Tampa LLC
Copano Liberty, LLC	Kinder Morgan Altamont LLC
Copano Liquids Marketing LLC	Kinder Morgan Baltimore Transload Terminal
Copano NGL Services (Markham), L.L.C.	LLC
Copano NGL Services LLC	Kinder Morgan Battleground Oil LLC
Copano Pipelines Group, L.L.C.	Kinder Morgan Border Pipeline LLC
Copano Pipelines/North Texas, L.L.C.	Kinder Morgan Bulk Terminals LLC
Copano Pipelines/Rocky Mountains, LLC	Kinder Morgan Carbon Dioxide Transportation
Copano Pipelines/South Texas LLC	Company
Copano Pipelines/Upper Gulf Coast LLC	Kinder Morgan CO2 Company LLC
Copano Processing LLC	Kinder Morgan Commercial Services LLC

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: June 30, 2021
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	Kinder Morgan Southeast Terminals LLC
LLC	Kinder Morgan Tank Storage Terminals LLC
Kinder Morgan Deeprock North Holdco LLC	Kinder Morgan Tejas Pipeline LLC
Kinder Morgan Endeavor LLC	Kinder Morgan Terminals, Inc.
Kinder Morgan Energy Partners, L.P.	Kinder Morgan Terminals Wilmington LLC
Kinder Morgan Energy Transition Ventures LLC	Kinder Morgan Texas Pipeline LLC
Kinder Morgan EP Midstream LLC	Kinder Morgan Texas Terminals, L.P.
Kinder Morgan Finance Company LLC	Kinder Morgan Transmix Company, LLC
Kinder Morgan Freedom Pipeline LLC	Kinder Morgan Treating LP
Kinder Morgan Galena Park West LLC	Kinder Morgan Urban Renewal, L.L.C.
Kinder Morgan IMT Holdco LLC	Kinder Morgan Utica LLC
Kinder Morgan, Inc.	Kinder Morgan Vehicle Services LLC
Kinder Morgan Keystone Gas Storage LLC	Kinder Morgan Virginia Liquids Terminals LLC
Kinder Morgan KMAP LLC	Kinder Morgan Wink Pipeline LLC
Kinder Morgan Las Vegas LLC	KinderHawk Field Services LLC
Kinder Morgan Linden Transload Terminal LLC	KM Crane LLC
Kinder Morgan Liquids Terminals LLC	KM Decatur LLC
Kinder Morgan Liquids Terminals St. Gabriel LLC	KM Eagle Gathering LLC
Kinder Morgan Louisiana Pipeline Holding LLC	KM Gathering LLC
Kinder Morgan Louisiana Pipeline LLC	KM Kaskaskia Dock LLC
Kinder Morgan Marine Services LLC	KM Liquids Terminals LLC
Kinder Morgan Materials Services, LLC	KM North Cahokia Land LLC
Kinder Morgan Mid Atlantic Marine Services LLC	KM North Cahokia Special Project LLC
Kinder Morgan NatGas O&M LLC	KM North Cahokia Terminal Project LLC
Kinder Morgan NGPL Holdings LLC	KM Ship Channel Services LLC
Kinder Morgan North Texas Pipeline LLC	KM Treating GP LLC
Kinder Morgan Operating LLC “A”	KM Treating Production LLC
Kinder Morgan Operating LLC “B”	KM Utopia Operator LLC
Kinder Morgan Operating LLC “C”	KMBT Legacy Holdings LLC
Kinder Morgan Operating LLC “D”	KMBT LLC
Kinder Morgan Pecos LLC	KMGP Services Company, Inc.
Kinder Morgan Pecos Valley LLC	KN Telecommunications, Inc.
Kinder Morgan Petcoke GP LLC	Knight Power Company LLC
Kinder Morgan Petcoke LP LLC	Lomita Rail Terminal LLC
Kinder Morgan Petcoke, L.P.	Milwaukee Bulk Terminals LLC
Kinder Morgan Petroleum Tankers LLC	MJR Operating LLC
Kinder Morgan Pipeline LLC	Mojave Pipeline Company, L.L.C.
Kinder Morgan Port Manatee Terminal LLC	Mojave Pipeline Operating Company, L.L.C.
Kinder Morgan Port Sutton Terminal LLC	Paddy Ryan Crane, LLC
Kinder Morgan Port Terminals USA LLC	Palmetto Products Pipe Line LLC
Kinder Morgan Portland Jet Line LLC	PI 2 Pelican State LLC
Kinder Morgan Production Company LLC	Pinney Dock & Transport LLC
Kinder Morgan Products Terminals LLC	Queen City Terminals LLC
Kinder Morgan Rail Services LLC	Rahway River Land LLC

2

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: June 30, 2021
River Terminals Properties GP LLC
River Terminal Properties, L.P.
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
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
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-10.3

Exhibit 10.3

(July 2021)

FORM OF1

KINDER MORGAN, INC.

RESTRICTED STOCK UNIT AGREEMENT

This Restricted Stock Unit Agreement (“Agreement”) is made and entered into effective as of the Date of Grant indicated below (“Date of Grant”), by and between Kinder Morgan, Inc., a Delaware corporation (“Company”), and the Employee named below (“Employee”). The defined term “Employer” shall include, where applicable, the Company and affiliates and entities in which the Company has an ownership interest, directly or indirectly. Capitalized terms that are used but not defined herein have the meaning ascribed to them in the Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan (the “Plan”).

Name of Employee:

Employee Identifier:

Date of Grant:

WHEREAS, the Company has adopted the Plan, pursuant to which Awards of Restricted Stock Units may be granted; and

WHEREAS, the Committee has determined that it is in the best interests of the Company and its stockholders to grant the Award of Restricted Stock Units provided for herein.

1.    Award. The Company hereby grants to the Employee on the Date of Grant an Award consisting of, in the aggregate, the following Restricted Stock Units (the “Restricted Stock Units”):

Each Restricted Stock Unit represents the right to receive one share of Stock, subject to the terms and conditions set forth in this Agreement and the Plan

(a)    Account. The Restricted Stock Units shall be credited to a separate account maintained for the Employee on the books and records of the Company (the “Account”). All amounts credited to the Account shall continue for all purposes to be part of the general assets of the Company.

(b)    Plan Incorporated. The Employee acknowledges receipt of a copy of the Plan and agrees that this Award of Restricted Stock Units 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.

1 Additional provisions applicable to Performance Compensation Awards are indicated with brackets throughout this form.

(c)    Consideration. This grant of Restricted Stock Units is made in consideration of the services to be rendered by the Employee to the Employer and the Employee’s compliance with the covenants set forth herein.

2.    Vesting.

(a)    Vesting Schedule. Except as otherwise provided herein, provided that the Employee’s employment with the Employer has not terminated prior to the “Vesting Date” (set forth below), [and provided, further, that the Performance Goals set forth in Exhibit I have been achieved as determined by the Committee,] the Restricted Stock Units will vest in accordance with the following schedule (with the period prior to vesting, during which the restrictions set forth in Section 3 apply, referred to as the “Restricted Period”):

Vesting Date Number of Restricted Stock Units Vesting

Each Restricted Stock Unit that vests under the terms of this Agreement becomes a “Vested Unit.” Except as otherwise provided herein, if the Employee’s employment with the Employer terminates for any reason at any time before the Vesting Date, [or if the Performance Goals set forth in Exhibit I are not achieved prior to the end of the Performance Period,] Employee’s unvested Restricted Stock Units shall be automatically forfeited upon such termination of employment [or the end of such Performance Period, as applicable], and neither the Company nor any Affiliate shall have any further obligations to the Employee under this Agreement. Upon settlement or forfeiture of any Restricted Stock Units, such Restricted Stock Units shall immediately be canceled.

[The Performance Period shall be the period beginning on the Date of Grant and ending on the Vesting Date.]

(b)    Death. Notwithstanding the vesting schedule [and Performance Goals] provided in paragraph (a), if the Employee’s employment with the Employer terminates as a result of the Employee’s death [prior to the end of the Performance Period], 100% of the unvested Restricted Stock Units shall vest as of the date of the Employee’s death.

(c)    Disability. Notwithstanding the vesting schedule [and Performance Goals] provided in paragraph (a), upon the earlier of (i) the termination of the Employee’s employment with the Employer [prior to the end of the Performance Period] by reason of disability that results in the Employer determining that the Employee cannot perform the essential functions of his or her job, with or without a reasonable accommodation, or (ii) the Employee becoming disabled for purposes of receiving benefits under the Employer’s long-term disability plan [prior to the end of the Performance Period] (provided the

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Employee has remained continuously employed by the Employer until such time), 100% of the unvested Restricted Stock Units shall vest. Notwithstanding the foregoing, if the Employee is a 409A Person (as defined below), for purposes of clause (ii) above, the Employee will be disabled only if the Employee is considered disabled within the meaning of Treasury Regulation 1.409A-3(i)(4)(i).

(d)    Change in Control. The applicable provisions of Section 12 of the Plan will govern the impact of a Change in Control (if any) on the vesting and forfeiture restrictions applicable to this grant of Restricted Stock Units.

(e)    Involuntary Termination. Notwithstanding the vesting schedule [and Performance Goals] provided in paragraph (a), upon the involuntary termination of the Employee’s employment with the Employer [prior to the end of the Performance Period], other than for Cause (as defined below) and due to (i) a reorganization or reduction in force for which the Employee would be eligible for pay under the Kinder Morgan, Inc. Severance Plan, or (ii) a termination where the Employer agrees to vest the unvested Restricted Stock Units as full or partial consideration for the Employee’s satisfaction of the requirements under Section 2(g), or (iii) a sale, transfer or discontinuation of any part of the operations or any business unit of the Employer, 100% of the unvested Restricted Stock Units shall vest as of the date of such termination of the Employee’s employment, provided that the Employee satisfies the requirements of Section 2(g). For purposes of this Agreement, “Cause” is defined as the Employee’s (i) grand jury indictment or prosecutorial information charging the Employee with illegal or fraudulent acts; (ii) conviction of a crime which, in the opinion of the Employer, would adversely affect the Employer’s reputation or business; (iii) willful refusal, without proper legal or medical cause, to perform the Employee’s duties and responsibilities; (iv) willfully engaging in conduct that the Employee has reason to know is injurious to the Employer; or (v) willful and material violation of any of the Employer’s written policies and procedures.

(f)    Retirement. For purposes of this Agreement, “Retirement” is defined as a voluntary termination by the Employee of the Employee’s employment with the Employer on or after attaining age 62, provided that the Employee has delivered to the Company written notice of the Employee’s intent to retire at least 15 days prior to the date of termination. Notwithstanding the vesting schedule [and Performance Goals] provided in paragraph (a), a pro-rata portion of the unvested Restricted Stock Units based on the number of full years from the Date of Grant to the date of Retirement (the “Retirement Vesting Portion”) will vest upon a termination of the Employee’s employment with the Employer by reason of Retirement, provided that the Employee satisfies the requirements of Section 2(g). On the date of such Employee’s Retirement, the Employee’s unvested Restricted Stock Units other than the Retirement Vesting Portion shall be automatically forfeited, and neither the Company nor any Affiliate shall have any further obligations to the Employee under this Agreement in respect of such forfeited Restricted Stock Units. As an example solely for purposes of clarity, if the terms of the grant provide that 100% of the Restricted Stock Units will vest on the third anniversary of the Date of Grant, and the Employee’s date of Retirement is more than

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one full year, but less than two full years, after the Date of Grant, then 33-1/3% of the Employee’s Restricted Stock Units constitute the Employee’s Retirement Vesting Portion and will vest, and the remaining 66-2/3% of the Employee’s Restricted Stock Units will be automatically forfeited.

(g)    Release. Unless waived in writing by the Company, the requirements of this Section 2(g) shall be satisfied only if, prior to the sixtieth (60th) day following the date of termination of the Employee’s employment under Section 2(e) or 2(f), (i) the Employee executes a release (“Release”) by the Employee of all claims, known or unknown, arising on or before the date of the Release against the Company and its officers, directors and employees in the form and manner prescribed by the Company and provided to the Employee (which Release may include cooperation, nondisclosure and confidentiality covenants), and (ii) any applicable period during which the Employee can revoke his or her execution of the Release expires without the Employee revoking such execution. Notwithstanding anything herein to the contrary, the requirements of this Section 2(g) (if not waived in writing by the Company) shall be satisfied only if the Employee executes the Release within any time period required under the terms of the Release.

3.    Restrictions.Subject to any exceptions set forth in this Agreement or the Plan, during the Restricted Period and until such time as the Restricted Stock Units are settled in accordance with Section 5, the Restricted Stock Units or the rights relating thereto may not be sold, assigned, alienated, attached, exchanged, pledged, hypothecated or otherwise transferred or encumbered by the Employee, and any attempt to sell, assign, alienate, attach, exchange, pledge, hypothecate or otherwise transfer or encumber, whether made or created by voluntary act of the Employee or any agent of the Employee or by operation of law, shall be wholly ineffective and shall not be recognized by, or be binding upon, and shall not in any manner affect the rights of, the Company or any agent, and if any such attempt is made, the Restricted Stock Units will be forfeited by the Employee and all of the Employee’s rights to such units shall immediately terminate without any payment or consideration by the Company.

4.    No Rights as Stockholder; Dividend Equivalents.

(a)    The Employee shall not have any rights of a stockholder with respect to the shares of Stock underlying the Restricted Stock Units unless and until the Restricted Stock Units vest and are settled by the issuance of such shares of Stock. Upon and following the settlement of any Restricted Stock Units, such Restricted Stock Units shall expire and the Employee shall be the record owner of the shares of Stock underlying such Restricted Stock Units unless and until such shares are sold or otherwise disposed of, and as record owner shall be entitled to all rights of a stockholder of the Company (including voting rights).

(b)    If, prior to the settlement date, the Company declares a cash or stock dividend on the shares of Stock, and the record date for such dividend occurs prior to the settlement of the Restricted Stock Units, then, within 30 days following the date the dividend is paid to holders of Stock, the Company shall pay the Employee, in cash, Dividend

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Equivalents in an amount equal to the dividends that would have been paid to the Employee if one share of Stock had been issued on the Date of Grant for each Restricted Stock Unit held by the Employee. Notwithstanding the foregoing, if the Restricted Stock Units are forfeited prior to payment of such Dividend Equivalents, the unpaid Dividend Equivalents shall also be forfeited, and neither the Company nor any Affiliate shall have any further obligations to the Employee under this Agreement. Dividend Equivalents and any amounts that may become payable in respect thereof shall be treated separately from the Restricted Stock Units and the rights arising in connection therewith for purposes of the designation of time and form of payments required by Section 409A of the Code.

5.    Settlement of Restricted Stock Units.

(a)    Subject to Section 6 hereof, in the event that any portion of the Restricted Stock Units become Vested Units pursuant to Section 2(a), settlement of such portion of this Award shall occur by the Company issuing and delivering to the Employee the number of shares of Stock equal to the number of Vested Units immediately (and in no event later than 30 days) following the Vesting Date. Notwithstanding the foregoing, if the Employee is a 409A Person, settlement shall occur on the Vesting Date; provided, that settlement shall be deemed to have occurred on the Vesting Date if settlement occurs on the Vesting Date or a later date within the same calendar year or, if later, by the 15th day of the third calendar month following the Vesting Date.

(b)    Subject to Section 6 hereof, in the event that the Restricted Stock Units become Vested Units pursuant to Section 2(b), settlement of this Award shall occur by the Company issuing and delivering to the Employee the number of shares of Stock equal to the number of Vested Units immediately (and in no event later than 30 days) following the date of the Employee’s death.

(c)    Subject to Section 6 hereof, in the event that the Restricted Stock Units become Vested Units pursuant to Section 2(c) (clause (ii)), settlement of this Award shall occur by the Company issuing and delivering to the Employee the number of shares of Stock equal to the number of Vested Units immediately (and in no event later than 30 days) following the date on which the Employee becomes disabled.

(d)    Upon termination of the Employee’s employment with the Employer under circumstances contemplated by Section 2(c) (clause (i)), Section 2(d), Section 2(e) or Section 2(f), subject to Section 6 hereof and conditioned on the Employee’s satisfaction of the requirements of Section 2(g) (to the extent applicable), settlement of this Award shall occur by the Company issuing and delivering to the Employee the number of shares of Stock equal to the number of Restricted Stock Units, if any, that become Vested Units as a result of such termination of employment. Settlement shall occur within sixty (60) days after the date of the Employee’s termination of employment.

(e)    For purpose of this Agreement, the Employee shall be a “409A Person” if the Employee has attained age 62 or will attain age 62 on or prior to December 31 of the calendar

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year immediately preceding the year of the Vesting Date set forth in Section 2(a). Notwithstanding anything herein to the contrary, if the Employee is a 409A Person, the following shall apply:

(i)    Any termination of the Employee’s employment that triggers a settlement of the Award must constitute a “separation from service” under Section 409A of the Code. In the event that a termination of the Employee’s employment does not constitute a separation from service, any Restricted Stock Units that become Vested Units as a result of such termination of employment will be settled upon the earliest to occur of: (A) the Vesting Date (in accordance with paragraph (a) above), (B) the Employee’s death (in accordance with paragraph (b) above), (C) the Employee becoming disabled within the meaning of Treasury Regulation 1.409A-3(i)(4)(i) (in accordance with paragraph (c) above), or (D) the employee’s separation from service (in accordance with paragraph (d) above).

(ii)    If the Employee is a “specified employee” within the meaning of Section 409A of the Code, as determined by the Committee, as of the date of the Employee’s separation from service, settlement in connection with a separation from service will be delayed until the earlier of: (a) the first payroll date after the six-month anniversary of the Employee’s separation from service or (b) the Employee’s death to the extent necessary to comply with Code Section 409A.

(iii)    In no event may the Employee, directly or indirectly, designate the calendar year of settlement of this Award.

(iv)    If settlement of this Award is subject to the satisfaction of the requirements of Section 2(g), and if the sixty (60) day period described in Section 2(g) spans two calendar years, settlement shall be made in the later calendar year.

(f)    Notwithstanding any other provisions of this Agreement, except to the extent that a violation of Code Section 409A would occur, the issuance or delivery of any Stock 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 Stock. The Company shall not be obligated to issue or deliver any 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.

(g)    Except to the extent that a violation of Code Section 409A would occur, if the employment of the Employee with the Employer terminates prior to the vesting date, and there exists a dispute between the Employee and the Employer or the Committee as to the satisfaction of the conditions to the vesting of some or all of the Restricted Stock Units or the terms and conditions of the grant, the Restricted Stock Units shall remain unvested until the resolution of such dispute, except that any Dividend Equivalents relating to dividends that may be payable to the holders of record of Stock

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as of a date during the period from termination of the Employee’s employment to the resolution of such dispute shall:

(1)     to the extent to which such Dividend Equivalents would have been payable to the Employee under the terms hereof, be held by the Company as part of its general funds, and shall be paid to or for the account of the Employee only upon, and in the event of, a resolution of such dispute in a manner favorable to the Employee, and then only with respect to such of the Restricted Stock Units as to which such resolution shall be so favorable, and

(2)     be retained by the Company in the event of a resolution of such dispute in a manner unfavorable to the Employee only with respect to such of the Restricted Stock Units as to which such resolution shall be so unfavorable.

6.    Withholding of Tax. To the extent that the Restricted Stock Units or vesting thereof, or the payment of Dividend Equivalents, results in income to the Employee for federal, state, provincial or local income tax purposes, the Company shall have the right to take all such action as the Committee deems necessary to satisfy all obligations for the payment of such withholding taxes, including, but not limited to, withholding shares of Stock out of Stock otherwise issuable or deliverable to the Employee as a result of the vesting of the Restricted Stock Units (provided, however, that no shares of Stock are withheld with a value exceeding the maximum statutory tax rates in the jurisdiction(s) applicable to the Employee). The Company shall, to the extent permitted by law, have the right to deduct any such taxes from any payment of any kind otherwise due to the Employee. Notwithstanding any action the Company takes with respect to any or all income tax, social insurance, payroll tax, or other tax-related withholding (“Tax-Related Items”), the ultimate liability for all Tax-Related Items is and remains the Employee’s responsibility and the Company (a) makes no representation or undertakings regarding the treatment of any Tax-Related Items in connection with the grant, vesting or settlement of the Restricted Stock Units or the subsequent sale of any shares; and (b) does not commit to structure the Restricted Stock Units to reduce or eliminate the Employee’s liability for Tax-Related Items.

7.    Status of Shares. The Employee agrees that,notwithstanding anything to the contrary herein, any shares of Stock issued to the Employee in settlement of the Restricted Stock Units may not be sold or otherwise disposed of in any manner that would constitute a violation of any applicable federal or state securities laws.

8.    Changes in Capital Structure. In the event that the outstanding shares of Stock shall be changed in number or class or the capital structure of the Company shall be changed by reason of stock splits, reverse stock splits, split-ups, spin-offs, combinations, mergers, consolidations or recapitalizations, or by reason of Stock dividends or other relevant changes in capitalization, the number or class of securities underlying the Restricted Stock Units, and any performance goal affected by such change, shall be adjusted to reflect such change to the extent necessary to preserve the economic intent of this Award, as determined by the Committee in accordance with the terms of the Plan.

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9.    Employment Relationship. For purposes of this Agreement, the Employee shall be considered to be in the employment of the Employer as long as the Employee remains an employee of the Employer, or any successor, whether a corporation or other Entity; provided that, for purposes of this Agreement, the Employee shall be deemed terminated on the later of the date on which the Employee delivers or receives notice of termination or the last date on which the Employee provides services to the Employer as an employee (excluding where the Employee is not providing services to the Employer because the Employee is on a leave of absence permitted by law or has been granted a leave of absence by the Employer under the Employer’s policies respecting leaves of absence). Any question as to whether and when there has been a termination of such employment, and the nature or cause of such termination, shall be determined by the Committee in its sole discretion, and its determination shall be final, conclusive and binding. Notwithstanding the foregoing, to the extent necessary to comply with Section 409A of the Code, the Employee’s employment with the Employer shall be terminated for purposes of this Agreement on the date the Employee incurs a “separation from service” as defined under Section 409A of the Code. Nothing contained herein shall be construed as conferring upon the Employee the right to continue in the employ of the Employer, nor shall anything contained herein be construed or interpreted to limit the “employment at will” relationship between the Employee and the Employer. A period of noticeawarded by a court or other competent tribunal, if any, or payment in lieu of actual or reasonable notice upon termination of employment, wrongful or otherwise, shall not be considered as extending the period of employment for purposes of this Agreement.

10.    Non-Disclosure of Confidential Matters. Pursuant to this Agreement and through the Employee’s continued employment with the Employer, the Employer agrees to provide the Employee with access to certain confidential information, intellectual property, and/or other trade secret information that belongs to the Employer (hereinafter “Confidential Information”). The Employee expressly acknowledges that the Employee will receive access to certain Confidential Information belonging to the Employer pursuant to this Agreement and through the Employee’s continued employment with the Employer. In consideration for the Employer’s agreement to provide the Employee with access to certain Confidential Information, the Employer’s agreements as it relates to the Restricted Stock Units as provided herein, and other good and valuable consideration, the Employee agrees not to make, at any time hereafter, including after the termination of employment for any reason, any unauthorized use, publication, or disclosure, during or subsequent to his/her employment by the Employer, of any Confidential Information generated or acquired by him/her during the course of his/her employment, except to the extent that the disclosure of Confidential Information is necessary to fulfill his/her responsibilities as an employee of the Employer. The Employee understands that Confidential Information includes information not generally known by or available to the public about or belonging to the Employer, or belonging to other companies to whom the Employer may have an obligation to maintain information in confidence, and that authorization for public disclosure may only be obtained through the Employer’s written consent. The Employee also understands and agrees that the information protected by this provision includes, but is not limited to, information of a technical and a business nature such as ideas, discoveries, designs, inventions, improvements, trade secrets, know-how, manufacturing processes, product formulae, design specifications, writings and other works of authorship, computer programs, financial figures, marketing plans, customer lists and data, business plans

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or methods and the like, which relate in any manner to the actual or anticipated business of the Employer, or related to its actual or anticipated areas of research and development. The Employee further agrees not to disclose to the Employer, nor induce any personnel of the Employer to use, any confidential information, trade secret, or confidential material belonging to others. Should the Employee be required to testify pursuant to subpoena under oath or as otherwise required by law and such testimony could result in disclosure of Confidential Information, the Employee agrees to promptly notify Employer that his or her testimony is being sought in sufficient time so as to permit Employer to seek to prevent or limit such testimony or otherwise seek to obtain a protective order. No restriction on disclosure contained within this paragraph shall be construed to restrict your ability to provide information to the Securities and Exchange Commission (“SEC”) in connection with its enforcement activities.

11.    Resolution of Disputes. As a condition of the granting of the Restricted Stock Units hereby, the Employee and the Employee’s heirs, personal representatives and successors agree that any dispute or disagreement that may arise hereunder shall be determined by the Committee in its sole discretion and judgment, and that any such determination and any interpretation by the Committee of this Agreement shall be final and shall be binding and conclusive, for all purposes, upon the Company, the Employee, the Employee’s heirs, personal representatives and successors or any Person claiming through any of them.

12.    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 the Employee, including, without limitation, the Employee’s estate and the executors, administrators, or trustees thereof, heirs and legatees, and any receiver, trustee in bankruptcy, or representative of creditors of the Employee. This Agreement shall be binding upon and inure to the benefit of any successors to the Company.

13.     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.

14.      Non-Solicitation. The Employee agrees that during his/her employment with the Employer and for a period of one (1) year after the termination of the Employee’s employment relationship with the Employer, the Employee will not directly or indirectly solicit, induce, recruit, encourage, or persuade any employee of the Employer to leave the Employer.

15.       Non-Disparagement. The Employee agrees not to engage in any act or make any comments (written, electronic, or oral), that are intended, or reasonably may be expected, to harm the business, prospects, or operations of the Employer, or to disparage the reputation of the Employer; provided, however, that the Employee shall not be held in breach of this provision should the Employee be required to testify pursuant to subpoena under oath or as otherwise required by law, provided additionally that the Employee testifies truthfully and that, prior to providing such testimony, the Employee promptly notifies Employer that his or her testimony

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is being sought in sufficient time so as to permit Employer to seek to prevent or limit such testimony or otherwise seek to obtain a protective order. “Disparage” for purposes of this Agreement shall mean any statements that a reasonable person would interpret as intending to be derogatory, harmful or create a negative impression about the business of the Employer.

16.    Irreparable Harm. The Employee acknowledges that a breach of the obligations set forth in Sections 10, 14 and 15 of this Agreement shall cause irreparable harm to the Employer and that monetary damages would be an inadequate remedy for such a breach. The Employee agrees that the Employer shall be entitled to equitable relief by way of injunction or otherwise, as well as any other remedy available at law, if the Employee breaches or threatens to breach the provisions of this Agreement. Further, in the event that the Employer determines in good faith that the Employee has breached any of said provisions of this Agreement, the Employer shall, to the extent the Restricted Stock Units have not vested, be entitled, at its election, to immediately stop making any payments hereunder and/or to terminate the vesting of, or otherwise cancel, terminate or require to be relinquished to the Company the Restricted Stock Units awarded to the Employee and/or to enforce the specific performance of this Agreement by the Employee and/or to enjoin the Employee from activities in breach of said provisions of this Agreement without having to show that there are no other adequate remedies available.

17.    Notices. Every notice hereunder shall be in writing and shall be given by registered or certified mail or by any other method accepted by the Company or the Company’s designee. All notices to the Company shall be directed to Kinder Morgan, Inc., 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, Attention: Secretary, or to the Company’s designee. Any notice given by the Company to the Employee directed to the Employee at the address on file with the Company shall be effective to bind the Employee and any other Person who shall acquire rights hereunder. The Company shall be under no obligation whatsoever to advise the Employee of the existence, maturity or termination of any of the Employee’s rights hereunder, and the Employee shall be deemed to have familiarized himself or herself with all matters contained herein and in the Plan that may affect any of the Employee’s rights or privileges hereunder.

18.    Modification and Severability. If a court of competent jurisdiction declares that any provision of this Agreement is illegal, invalid or unenforceable, then such provision shall be modified automatically to the extent necessary to make such provision fully enforceable. If such court does not modify any such provision as contemplated herein, but instead declares it to be wholly illegal, invalid or unenforceable, then such provision shall be severed from this Agreement, as applicable, and such declaration shall in no way affect the legality, validity and enforceability of the other provisions of this Agreement to which such declaration does not relate. In this event, this Agreement shall be construed as if it did not contain the particular provision held to be illegal, invalid or unenforceable, the rights and obligations of the parties hereto shall be construed and enforced accordingly, and this Agreement otherwise shall remain in full force and effect. If any provision of this Agreement is capable of two constructions, one of which would render the provision void and the other would render the provision valid, then the provision shall have the construction that renders it valid.

19.    No Derogation of Obligations. Nothing in this Agreement is intended to limit or otherwise affect the duties and obligations of the Employee to the Company or an Employer existing at

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law, statutory or otherwise, or under any other written agreement between the Employee and the Company or Employer, whether during or after the termination of the Employee’s employment by the Company or Employer.

20.    Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas and applicable federal law.

21.    Section 409A. This Agreement is intended to comply with Section 409A of the Code or an exemption thereunder and shall be construed and interpreted in a manner that is consistent with the requirements for avoiding additional taxes or penalties under Section 409A of the Code. Each payment made under this Agreement shall be treated as a separate payment for purposes of Section 409A of the Code. Any provision in the Plan or this Agreement that is determined to violate the requirements of Section 409A of the Code shall be void and without effect until amended to comply with Section 409A of the Code (which amendment may be retroactive to the extent permitted by Section 409A of the Code and may be made by the Company without the consent of the Employee). Any provision that is required by Section 409A of the Code to appear in the Agreement that is not expressly set forth herein shall be deemed to be set forth herein, and the Agreement shall be administered in all respects as if such provision was expressly set forth herein. Notwithstanding the foregoing, the Company makes no representations that the payments and benefits provided under this Agreement comply with Section 409A of the Code and in no event shall the Company be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by the Employee on account of non-compliance with Section 409A of the Code.

22.    Entire Agreement; Amendment. This Agreement and any other agreements and instruments contemplated by this Agreement contain the entire agreement of the parties, and, except as provided in Section 18, this Agreement may be amended only in writing signed by both parties.

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

KINDER MORGAN, INC.

By:

Name:

Title:

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[Exhibit I

Performance Goals]

EX-22.1

Exhibit 22.1

List of Guarantor Subsidiaries

The Cross Guarantee Agreement furnished as Exhibit 10.1 to this Quarterly Report on Form 10-Q sets forth, as of June 30, 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:	July 23, 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:	July 23, 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 June 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:	July 23, 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 June 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:	July 23, 2021	/s/ David P. Michels
		David P. Michels
		Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2021	Jul. 22, 2021
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 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		2,266,520,797
Entity Central Index Key	0001506307
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2
Amendment Flag	false
Class P Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class P Common Stock
Trading Symbol	KMI
Security Exchange Name	NYSE
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

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Revenues
Revenues	$ 3,150	$ 2,560	$ 8,361	$ 5,666
Operating Costs, Expenses and Other
Costs of sales	936	441	2,945	1,104
Operations and maintenance	582	606	1,096	1,226
Depreciation, depletion and amortization	528	532	1,069	1,097
General and administrative	160	155	316	308
Taxes, other than income taxes	108	103	218	195
Loss on impairments and divestitures, net (Note 2)	1,602	1,005	1,598	1,976
Other income, net	(2)	0	(3)	(1)
Total Operating Costs, Expenses and Other	3,914	2,842	7,239	5,905
Operating (Loss) Income	(764)	(282)	1,122	(239)
Other Income (Expense)
Earnings from equity investments	157	176	223	368
Amortization of excess cost of equity investments	(13)	(35)	(35)	(67)
Interest, net	(377)	(395)	(754)	(831)
Other, net (Note 2)	20	16	243	18
Total Other Expense	(213)	(238)	(323)	(512)
(Loss) Income Before Income Taxes	(977)	(520)	799	(751)
Income Tax Benefit (Expense)	237	(104)	(114)	(164)
Net (Loss) Income	(740)	(624)	685	(915)
Net Income Attributable to Noncontrolling Interests	(17)	(13)	(33)	(28)
Net (Loss) Income Attributable to Kinder Morgan, Inc.	$ (757)	$ (637)	$ 652	$ (943)
Class P Shares
Basic (Loss) Earnings Per Share	$ (0.34)	$ (0.28)	$ 0.29	$ (0.42)
Diluted (Loss) Earnings Per Share	$ (0.34)	$ (0.28)	$ 0.29	$ (0.42)
Basic Weighted Average Shares Outstanding	2,265	2,261	2,264	2,263
Diluted Weighted Average Shares Outstanding	2,265	2,261	2,264	2,263
Services
Revenues
Revenues	$ 1,889	$ 1,791	$ 3,806	$ 3,783
Commodity sales
Revenues
Revenues	1,246	723	4,475	1,790
Other
Revenues
Revenues	$ 15	$ 46	$ 80	$ 93

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement of Comprehensive Income [Abstract]
Net (loss) income	$ (740)	$ (624)	$ 685	$ (915)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $47, $57, $94 and $(12), respectively)	(157)	(189)	(313)	40
Reclassification of change in fair value of derivatives to net (loss) income (net of tax expense of $9, $14, $27 and $23, respectively)	30	47	89	77
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)	0	0	0	1
Benefit plan adjustments (net of tax expense of $1, $2, $5 and $5, respectively)	5	5	22	16
Total other comprehensive (loss) income	(122)	(137)	(202)	134
Comprehensive (loss) income	(862)	(761)	483	(781)
Comprehensive income attributable to noncontrolling interests	(17)	(13)	(33)	(28)
Comprehensive (loss) income attributable to Kinder Morgan, Inc.	$ (879)	$ (774)	$ 450	$ (809)

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement of Comprehensive Income [Abstract]
Change in fair value of hedge derivatives, tax benefit (expense)	$ 47	$ 57	$ 94	$ (12)
Reclassification of change in fair value of derivatives to net (loss) income, tax expense	9	14	27	23
Foreign currency translation adjustments, tax expense	0	0	0	0
Benefit plan adjustments, tax expense	$ 1	$ 2	$ 5	$ 5

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 1,365	$ 1,184
Restricted deposits	604	25
Accounts receivable	1,416	1,293
Fair value of derivative contracts	221	185
Inventories	396	348
Other current assets	281	168
Total current assets	4,283	3,203
Property, plant and equipment, net	34,570	35,836
Investments	7,650	7,917
Goodwill	19,851	19,851
Other intangibles, net	1,585	2,453
Deferred income taxes	492	536
Deferred charges and other assets	1,744	2,177
Total Assets	70,175	71,973
Current Liabilities
Current portion of debt	2,183	2,558
Accounts payable	949	837
Accrued interest	479	525
Accrued taxes	217	267
Accrued contingencies	232	307
Other current liabilities	999	580
Total current liabilities	5,059	5,074
Long-term debt
Outstanding	30,008	30,838
Debt fair value adjustments	1,069	1,293
Total long-term debt	31,077	32,131
Other long-term liabilities and deferred credits	2,216	2,202
Total long-term liabilities and deferred credits	33,293	34,333
Total Liabilities	38,352	39,407
Commitments and contingencies (Notes 3 and 9)
Redeemable Noncontrolling Interest	683	728
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,604,747 and 2,264,257,336 shares, respectively, issued and outstanding	23	23
Additional paid-in capital	41,793	41,756
Accumulated deficit	(10,496)	(9,936)
Accumulated other comprehensive loss	(609)	(407)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,711	31,436
Noncontrolling interests	429	402
Total Stockholders’ Equity	31,140	31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$ 70,175	$ 71,973

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Jun. 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)	2,264,604,747	2,264,257,336
Common stock, shares outstanding (in shares)	2,264,604,747	2,264,257,336

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Cash Flows From Operating Activities
Net income (loss)	$ 685	$ (915)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	1,069	1,097
Deferred income taxes	105	28
Amortization of excess cost of equity investments	35	67
Loss on impairments and divestitures, net (Note 2)	1,598	1,976
Gain on sale of interest in equity investment (Note 2)	(206)	0
Earnings from equity investments	(223)	(368)
Distributions from equity investment earnings	346	317
Changes in components of working capital
Accounts receivable	(130)	335
Inventories	(51)	28
Other current assets	(31)	48
Accounts payable	145	(182)
Accrued interest, net of interest rate swaps	(42)	(65)
Accrued taxes	(51)	(23)
Other current liabilities	195	(96)
Rate reparations, refunds and other litigation reserve adjustments	(102)	(12)
Other, net	(31)	(3)
Net Cash Provided by Operating Activities	3,311	2,232
Cash Flows From Investing Activities
Capital expenditures	(545)	(963)
Proceeds from sales of investments	413	907
Contributions to investments	(26)	(225)
Distributions from equity investments in excess of cumulative earnings	48	86
Other, net	(1)	(46)
Net Cash Used in Investing Activities	(111)	(241)
Cash Flows From Financing Activities
Issuances of debt	3,110	2,652
Payments of debt	(4,273)	(3,037)
Debt issue costs	(12)	(11)
Dividends	(1,212)	(1,166)
Repurchases of shares	0	(50)
Contributions from investment partner and noncontrolling interests	3	9
Distributions to investment partner	(45)	(38)
Distributions to noncontrolling interests	(8)	(7)
Other, net	(3)	(1)
Net Cash Used in Financing Activities	(2,440)	(1,649)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	(5)
Net Increase in Cash, Cash Equivalents and Restricted Deposits	760	337
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	1,365	526
Restricted Deposits, end of period	604	20
Cash, Cash Equivalents, and Restricted Deposits, end of period	1,969	546
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	28	8
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	807	891
Cash paid during the period for income taxes, net	$ 8	$ 136

XML

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	36		36			36
Net income (loss)	(915)			(943)		(943)	28
Distributions	(7)					0	(7)
Contributions	6					0	6
Dividends	(1,166)			(1,166)		(1,166)
Other comprehensive income (loss)	134				134	134
Balance at Jun. 30, 2020	32,124	$ 23	41,731	(9,802)	(199)	31,753	371
Balance (shares) at Jun. 30, 2020		2,261
Balance at Mar. 31, 2020	33,464	$ 23	41,713	(8,568)	(62)	33,106	358
Balance (shares) at Mar. 31, 2020		2,261
Restricted shares	18		18			18
Net income (loss)	(624)			(637)		(637)	13
Distributions	(4)					0	(4)
Contributions	4					0	4
Dividends	(597)			(597)		(597)
Other comprehensive income (loss)	(137)				(137)	(137)
Balance at Jun. 30, 2020	32,124	$ 23	41,731	(9,802)	(199)	31,753	371
Balance (shares) at Jun. 30, 2020		2,261
Balance at Dec. 31, 2020	31,838	$ 23	41,756	(9,936)	(407)	31,436	402
Balance (shares) at Dec. 31, 2020		2,264
Restricted shares	37		37			37
Restricted shares (shares)		1
Net income (loss)	685			652		652	33
Distributions	(8)					0	(8)
Contributions	3					0	3
Dividends	(1,212)			(1,212)		(1,212)
Other	(1)					0	(1)
Other comprehensive income (loss)	(202)				(202)	(202)
Balance at Jun. 30, 2021	31,140	$ 23	41,793	(10,496)	(609)	30,711	429
Balance (shares) at Jun. 30, 2021		2,265
Balance at Mar. 31, 2021	32,603	$ 23	41,775	(9,124)	(487)	32,187	416
Balance (shares) at Mar. 31, 2021		2,264
Restricted shares	18		18			18
Restricted shares (shares)		1
Net income (loss)	(740)			(757)		(757)	17
Distributions	(5)					0	(5)
Contributions	1					0	1
Dividends	(615)			(615)		(615)
Other comprehensive income (loss)	(122)				(122)	(122)
Balance at Jun. 30, 2021	$ 31,140	$ 23	$ 41,793	$ (10,496)	$ (609)	$ 30,711	$ 429
Balance (shares) at Jun. 30, 2021		2,265

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General (Notes)

6 Months Ended

Jun. 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 and 144 terminals. 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.

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 billion, 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.

Kinetrex Energy Acquisition

On July 16, 2021, we announced an agreement to acquire Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $310 million. 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 as well as signed commercial agreements to begin construction on three additional landfill based RNG facilities. The transaction requires regulatory approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and is expected to close in the third quarter of 2021.

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 this purpose, we have 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 2 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 (loss) income available to shareholders of Class P shares and participating securities:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net (Loss) Income Available to Stockholders	$	(757)	$	(637)	$	652	$	(943)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(3)		(3)		(6)		(6)
Net (Loss) Income Allocated to Class P Stockholders	$	(760)	$	(640)	$	646	$	(949)
Basic Weighted Average Shares Outstanding	2,265		2,261		2,264		2,263
Basic (Loss) Earnings Per Share	$	(0.34)	$	(0.28)	$	0.29	$	(0.42)

(a)As of June 30, 2021, there were approximately 12 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 June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	12	12	12	12
Convertible trust preferred securities	3	3	3	3

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

6 Months Ended

Jun. 30, 2021

Impairments [Abstract]

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

2. 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 six months ended June 30, 2021 and 2020:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	1,600	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		1,000		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Gain on divestitures of long-lived assets	(1)		—		(1)		—
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21
Terminals
Impairment of long-lived and intangible assets	—		5		—		5
Loss on divestitures of long-lived assets	1		—		—		—
CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Loss on divestitures of long-lived assets	3		—		3		—
Other gain on divestitures of long-lived assets	(1)		—		(4)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	1,602	$	1,005	$	1,509	$	1,976

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

Impairments

Long-lived Assets

During the quarter ended June 30, 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. The long-lived asset impairment test involves two steps. Step one is an assessment as to whether the asset’s net book value is 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 the 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, which we believe represented the estimated weighted average cost of capital of a theoretical market participant.

During the six months ended June 30, 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 six months ended June 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 tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the three months ended June 30, 2020, we conducted our annual test of the recoverability of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 business segment during the six months ended June 30, 2020 and within our Natural Gas Pipelines business segment during the three and six months ended June 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 $413 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 six months ended June 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. 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)

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Debt

3. Debt

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

	June 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023	$	—	$	—
Commercial paper notes	—		—
Current portion of senior notes
5.00%, due February 2021(a)	—		750
3.50%, due March 2021(a)	—		750
5.80%, due March 2021(a)	—		400
5.00%, due October 2021(b)	500		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(c)	890		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,183		2,558
Long-term debt (excluding current portion)
Senior notes	29,320		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	357		364
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	221		223
Total long-term debt	30,008		30,838
Total debt(d)	$	32,191	$	33,396

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

(b)These notes were repaid on July 1, 2021. As of June 30, 2021, $506 million for the repayment of these maturing notes and associated accrued interest were held in escrow and included in the accompanying consolidated balance sheet within “Restricted deposits.”

(c)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The June 30, 2021 balance is reported above at the exchange rate of 1.1858 U.S. dollars per Euro. As of June 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 $75 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 5 “Risk Management—Foreign Currency Risk Management”).

(d)Excludes our “Debt fair value adjustments” which, as of June 30, 2021 and December 31, 2020, increased our total debt balances by $1,069 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 Facility

As of June 30, 2021, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of June 30, 2021 was $3,919 million. As of June 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: 

	June 30, 2021				December 31, 2020
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
	(In millions)
Total debt	$	33,260	$	38,498	$	34,689	$	39,622

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

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Stockholders' Equity (Notes)

6 Months Ended

Jun. 30, 2021

Stockholders' Equity Note [Abstract]

Stockholders' Equity

4. 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.54	$	0.525
Per share cash dividend paid in the period	0.27		0.2625		0.5325		0.5125

On July 21, 2021, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended June 30, 2021, which is payable on August 16, 2021 to shareholders of record as of the close of business on August 2, 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	(313)		—		22		(291)
Loss reclassified from accumulated other comprehensive loss	89		—		—		89
Net current-period change in accumulated other comprehensive loss	(224)		—		22		(202)
Balance as of June 30, 2021	$	(237)	$	—	$	(372)	$	(609)

	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 gain before reclassifications	40		1		16		57
Loss reclassified from accumulated other comprehensive loss	77		—		—		77
Net current-period change in accumulated other comprehensive (loss) income	117		1		16		134
Balance as of June 30, 2020	$	110	$	1	$	(310)	$	(199)

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Risk Management (Notes)

6 Months Ended

Jun. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management

5.  Risk Management

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

Energy Commodity Price Risk Management

As of June 30, 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	(7.9)	MMBbl
Natural gas fixed price	(31.7)	Bcf
Natural gas basis	(26.2)	Bcf
NGL fixed price	(1.0)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.2)	MMBbl
Crude oil basis	(9.8)	MMBbl
Natural gas fixed price	(3.4)	Bcf
Natural gas basis	(15.8)	Bcf
NGL fixed price	(2.1)	MMBbl

As of June 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 June 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	2,500		Mark-to-Market	December 2021

(a)The principal amount of hedged senior notes consisted of $250 million included in “Current portion of debt” and $6,850 million included in “Long-term debt” on our accompanying consolidated balance sheet.

During the three months ended March 31, 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 rate through February 2028.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of June 30, 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
		June 30, 2021		December 31, 2020		June 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)	$	18	$	42	$	(206)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	2		33		(87)		(8)
Subtotal		20		75		(293)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	118		119		(3)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	395		575		(12)		(7)
Subtotal		513		694		(15)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	67		—		(8)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	38		138		—		—
Subtotal		105		138		(8)		(6)
Total		638		907		(316)		(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	18		24		(46)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(5)		—
Subtotal		18		24		(51)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
Subtotal		—		—		(1)		—
Total		18		24		(52)		(21)
Total derivatives		$	656	$	931	$	(368)	$	(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 June 30, 2021
Energy commodity derivative contracts(a)	$	18	$	20	$	—	$	38	$	(35)	$	—	$	3
Interest rate contracts	—		513		—		513		(5)		—		508
Foreign currency contracts	—		105		—		105		(8)		—		97
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 June 30, 2021
Energy commodity derivative contracts(a)	$	(46)	$	(298)	$	—	$	(344)	$	35	$	55	$	(254)
Interest rate contracts	—		(16)		—		(16)		5		—		(11)
Foreign currency contracts	—		(8)		—		(8)		8		—		—
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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	28	$	26	$	(189)	$	459
Hedged fixed rate debt(a)	Interest, net	$	(28)	$	(28)	$	190	$	(468)

(a)As of June 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $512 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended June 30,					Three Months Ended June 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(215)	$	(273)	Revenues—Commodity sales	$	(53)	$	(84)
					Costs of sales	(2)		(2)
Interest rate contracts	1		(1)		Earnings from equity investments(c)	—		—
Foreign currency contracts	10		28		Other, net	16		25
Total	$	(204)	$	(246)	Total	$	(39)	$	(61)

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,					Six Months Ended June 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(374)	$	114	Revenues—Commodity sales	$	(73)	$	(98)
					Costs of sales	2		(5)
Interest rate contracts	2		(9)		Earnings from equity investments(c)	—		—
Foreign currency contracts	(35)		(53)		Other, net	(45)		3
Total	$	(407)	$	52	Total	$	(116)	$	(100)

(a)We expect to reclassify approximately $121 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 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 six months ended June 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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(33)	$	149	$	(663)	$	266
	Costs of sales	(2)		2		160		6
	Earnings from equity investments	(2)		—		(2)		—
Total(a)		$	(37)	$	151	$	(505)	$	272

(a)The three and six months ended June 30, 2021 amounts include approximate losses of $7 million and $455 million, respectively, and the three and six months ended June 30, 2020 amounts include approximate gains of $179 million and $253 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 June 30, 2021 and December 31, 2020, we had no

outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2021, we had cash margins of $77 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 June 30, 2021 represents the net of our initial margin requirements of $22 million and counterparty variation margin requirements of $55 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 June 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 $169 million of additional collateral.

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Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 2021

Revenue from Contract with Customer [Abstract]

Revenue Recognition

6. Revenue Recognition

Disaggregation of Revenues

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

	Three Months Ended June 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	799	$	66	$	198	$	—	$	—	$	1,063
Fee-based services	176		244		84		10		—		514
Total services	975		310		282		10		—		1,577
Commodity sales
Natural gas sales	674		—		—		1		(3)		672
Product sales	248		157		7		258		(13)		657
Total commodity sales	922		157		7		259		(16)		1,329
Total revenues from contracts with customers	1,897		467		289		269		(16)		2,906
Other revenues(c)
Leasing services(d)	118		43		144		15		1		321
Derivatives adjustments on commodity sales	(37)		(1)		—		(47)		—		(85)
Other	(2)		5		—		6		(1)		8
Total other revenues	79		47		144		(26)		—		244
Total revenues	$	1,976	$	514	$	433	$	243	$	(16)	$	3,150

	Three Months Ended June 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)	$	796	$	67	$	189	$	—	$	—	$	1,052
Fee-based services	157		182		95		10		(2)		442
Total services	953		249		284		10		(2)		1,494
Commodity sales
Natural gas sales	377		—		—		—		(1)		376
Product sales	102		49		3		134		(4)		284
Total commodity sales	479		49		3		134		(5)		660
Total revenues from contracts with customers	1,432		298		287		144		(7)		2,154
Other revenues(c)
Leasing services(d)	114		42		132		11		—		299
Derivatives adjustments on commodity sales	(11)		—		—		75		—		64
Other	36		5		—		2		—		43
Total other revenues	139		47		132		88		—		406
Total revenues	$	1,571	$	345	$	419	$	232	$	(7)	$	2,560

	Six Months Ended June 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)	$	1,665	$	125	$	389	$	—	$	—	$	2,179
Fee-based services	354		465		165		25		—		1,009
Total services	2,019		590		554		25		—		3,188
Commodity sales
Natural gas sales	3,993		—		—		2		(8)		3,987
Product sales	468		282		12		487		(23)		1,226
Total commodity sales	4,461		282		12		489		(31)		5,213
Total revenues from contracts with customers	6,480		872		566		514		(31)		8,401
Other revenues(c)
Leasing services(d)	237		86		287		27		—		637
Derivatives adjustments on commodity sales	(655)		(1)		—		(80)		—		(736)
Other	39		10		—		11		(1)		59
Total other revenues	(379)		95		287		(42)		(1)		(40)
Total revenues	$	6,101	$	967	$	853	$	472	$	(32)	$	8,361

	Six Months Ended June 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)	$	1,661	$	146	$	378	$	—	$	—	$	2,185
Fee-based services	350		442		216		23		(2)		1,029
Total services	2,011		588		594		23		(2)		3,214
Commodity sales
Natural gas sales	878		—		—		—		(3)		875
Product sales	238		158		6		366		(17)		751
Total commodity sales	1,116		158		6		366		(20)		1,626
Total revenues from contracts with customers	3,127		746		600		389		(22)		4,840
Other revenues(c)
Leasing services(d)	227		84		261		21		—		593
Derivatives adjustments on commodity sales	41		—		—		127		—		168
Other	51		10		—		4		—		65
Total other revenues	319		94		261		152		—		826
Total revenues	$	3,446	$	840	$	861	$	541	$	(22)	$	5,666

(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 5 for additional information related to our derivative contracts.

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

Contract Balances

As of June 30, 2021 and December 31, 2020, our contract asset balances were $48 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $12 million was transferred to accounts receivable during the six months ended June 30, 2021. As of June 30, 2021 and December 31, 2020, our contract liability balances were $232 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $45 million was recognized as revenue during the six months ended June 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 June 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Six months ended December 31, 2021	$	2,232
2022	3,766
2023	3,040
2024	2,590
2025	2,191
Thereafter	13,776
Total	$	27,595

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

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Reportable Segments (Notes)

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Reportable Segments

7.  Reportable Segments

Financial information by segment follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,960	$	1,565	$	6,070	$	3,426
Intersegment revenues	16		6		31		20
Products Pipelines	514		345		967		840
Terminals
Revenues from external customers	433		418		852		859
Intersegment revenues	—		1		1		2
CO2	243		232		472		541
Corporate and intersegment eliminations	(16)		(7)		(32)		(22)
Total consolidated revenues	$	3,150	$	2,560	$	8,361	$	5,666

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	(570)	$	(3)	$	1,533	$	1,193
Products Pipelines	265		227		513		496
Terminals	246		229		473		486
CO2	150		146		436		(609)
Total Segment EBDA	91		599		2,955		1,566
DD&A	(528)		(532)		(1,069)		(1,097)
Amortization of excess cost of equity investments	(13)		(35)		(35)		(67)
General and administrative and corporate charges	(150)		(157)		(298)		(322)
Interest, net	(377)		(395)		(754)		(831)
Income tax benefit (expense)	237		(104)		(114)		(164)
Total consolidated net (loss) income	$	(740)	$	(624)	$	685	$	(915)

	June 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	46,445	$	48,597
Products Pipelines	9,138		9,182
Terminals	8,555		8,639
CO2	2,433		2,478
Corporate assets(b)	3,604		3,077
Total consolidated assets	$	70,175	$	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)

6 Months Ended

Jun. 30, 2021

Income Tax Disclosure [Abstract]

Income Taxes

8.  Income Taxes

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
	(In millions, except percentages)
Income tax (benefit) expense	$	(237)		$	104		$	114		$	164
Effective tax rate	24.3		%	(20.0)		%	14.3		%	(21.8)		%

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

The effective tax rate for the six months ended June 30, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

The effective tax rate for the three months ended June 30, 2020 is “negative” and lower than the statutory federal rate of 21% due to the $1,000 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 dividend-received deductions from our investments in Citrus and PPL.

The effective tax rate for the six months ended June 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 three and six months ended June 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)

6 Months Ended

Jun. 30, 2021

Commitments and Contingencies Disclosure [Abstract]

Litigation and Environmental

9.   Litigation and Environmental

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose 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. By its second Notice of Arbitration, Eni USA 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 to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the 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 re-arbitrating both the breach of contract and negligent misrepresentation claims. On April 15, 2021, Eni USA filed a petition for writ of certiorari with the U.S. Supreme Court seeking review of the Delaware Supreme Court’s decision. This petition remains pending.

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 $225 million. Hiland Partners denies and will vigorously defend against these claims.

Pipeline Integrity and Releases

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

General

As of June 30, 2021 and December 31, 2020, our total reserve for legal matters was $185 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. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved 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. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.

On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins.

In addition, the EPA and numerous PRPs, including EPEC Polymers, 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 Polymers, 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 ROD as well as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the ongoing discussions with the EPA conclude, or the FS is completed and the RI/FS is finalized, 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, 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 case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August

10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Fifth Circuit. 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 June 30, 2021 and December 31, 2020, we have accrued a total reserve for environmental liabilities in the amount of $248 million and $250 million, respectively. In addition, as of both June 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)

6 Months Ended

Jun. 30, 2021

Accounting Standards Update and Change in Accounting Principle [Abstract]

Recent Accounting Pronouncements

10. 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)

6 Months Ended

Jun. 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 this purpose, we have 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 2 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)

6 Months Ended

Jun. 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 (loss) income available to shareholders of Class P shares and participating securities:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net (Loss) Income Available to Stockholders	$	(757)	$	(637)	$	652	$	(943)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(3)		(3)		(6)		(6)
Net (Loss) Income Allocated to Class P Stockholders	$	(760)	$	(640)	$	646	$	(949)
Basic Weighted Average Shares Outstanding	2,265		2,261		2,264		2,263
Basic (Loss) Earnings Per Share	$	(0.34)	$	(0.28)	$	0.29	$	(0.42)

(a)As of June 30, 2021, there were approximately 12 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 June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	12	12	12	12
Convertible trust preferred securities	3	3	3	3

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

6 Months Ended

Jun. 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 six months ended June 30, 2021 and 2020:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	1,600	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		1,000		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Gain on divestitures of long-lived assets	(1)		—		(1)		—
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21
Terminals
Impairment of long-lived and intangible assets	—		5		—		5
Loss on divestitures of long-lived assets	1		—		—		—
CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Loss on divestitures of long-lived assets	3		—		3		—
Other gain on divestitures of long-lived assets	(1)		—		(4)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	1,602	$	1,005	$	1,509	$	1,976

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

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Debt (Tables)

6 Months Ended

Jun. 30, 2021

Debt Instrument [Line Items]

Schedule of Debt

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

	June 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023	$	—	$	—
Commercial paper notes	—		—
Current portion of senior notes
5.00%, due February 2021(a)	—		750
3.50%, due March 2021(a)	—		750
5.80%, due March 2021(a)	—		400
5.00%, due October 2021(b)	500		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(c)	890		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,183		2,558
Long-term debt (excluding current portion)
Senior notes	29,320		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	357		364
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	221		223
Total long-term debt	30,008		30,838
Total debt(d)	$	32,191	$	33,396

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

(b)These notes were repaid on July 1, 2021. As of June 30, 2021, $506 million for the repayment of these maturing notes and associated accrued interest were held in escrow and included in the accompanying consolidated balance sheet within “Restricted deposits.”

(c)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The June 30, 2021 balance is reported above at the exchange rate of 1.1858 U.S. dollars per Euro. As of June 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 $75 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 5 “Risk Management—Foreign Currency Risk Management”).

(d)Excludes our “Debt fair value adjustments” which, as of June 30, 2021 and December 31, 2020, increased our total debt balances by $1,069 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: 

	June 30, 2021				December 31, 2020
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
	(In millions)
Total debt	$	33,260	$	38,498	$	34,689	$	39,622

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Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2021

Stockholders' Equity Note [Abstract]

Schedule of Dividends

The following table provides information about our per share dividends:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.54	$	0.525
Per share cash dividend paid in the period	0.27		0.2625		0.5325		0.5125

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	(313)		—		22		(291)
Loss reclassified from accumulated other comprehensive loss	89		—		—		89
Net current-period change in accumulated other comprehensive loss	(224)		—		22		(202)
Balance as of June 30, 2021	$	(237)	$	—	$	(372)	$	(609)

	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 gain before reclassifications	40		1		16		57
Loss reclassified from accumulated other comprehensive loss	77		—		—		77
Net current-period change in accumulated other comprehensive (loss) income	117		1		16		134
Balance as of June 30, 2020	$	110	$	1	$	(310)	$	(199)

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Risk Management (Tables)

6 Months Ended

Jun. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of June 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	(7.9)	MMBbl
Natural gas fixed price	(31.7)	Bcf
Natural gas basis	(26.2)	Bcf
NGL fixed price	(1.0)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.2)	MMBbl
Crude oil basis	(9.8)	MMBbl
Natural gas fixed price	(3.4)	Bcf
Natural gas basis	(15.8)	Bcf
NGL fixed price	(2.1)	MMBbl

Schedule of Interest Rate Derivatives

The following table summarizes our outstanding interest rate contracts as of June 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	2,500		Mark-to-Market	December 2021

(a)The principal amount of hedged senior notes consisted of $250 million included in “Current portion of debt” and $6,850 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 June 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
		June 30, 2021		December 31, 2020		June 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)	$	18	$	42	$	(206)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	2		33		(87)		(8)
Subtotal		20		75		(293)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	118		119		(3)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	395		575		(12)		(7)
Subtotal		513		694		(15)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	67		—		(8)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	38		138		—		—
Subtotal		105		138		(8)		(6)
Total		638		907		(316)		(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	18		24		(46)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(5)		—
Subtotal		18		24		(51)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
Subtotal		—		—		(1)		—
Total		18		24		(52)		(21)
Total derivatives		$	656	$	931	$	(368)	$	(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 June 30, 2021
Energy commodity derivative contracts(a)	$	18	$	20	$	—	$	38	$	(35)	$	—	$	3
Interest rate contracts	—		513		—		513		(5)		—		508
Foreign currency contracts	—		105		—		105		(8)		—		97
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 June 30, 2021
Energy commodity derivative contracts(a)	$	(46)	$	(298)	$	—	$	(344)	$	35	$	55	$	(254)
Interest rate contracts	—		(16)		—		(16)		5		—		(11)
Foreign currency contracts	—		(8)		—		(8)		8		—		—
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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	28	$	26	$	(189)	$	459
Hedged fixed rate debt(a)	Interest, net	$	(28)	$	(28)	$	190	$	(468)

(a)As of June 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $512 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended June 30,					Three Months Ended June 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(215)	$	(273)	Revenues—Commodity sales	$	(53)	$	(84)
					Costs of sales	(2)		(2)
Interest rate contracts	1		(1)		Earnings from equity investments(c)	—		—
Foreign currency contracts	10		28		Other, net	16		25
Total	$	(204)	$	(246)	Total	$	(39)	$	(61)

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,					Six Months Ended June 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(374)	$	114	Revenues—Commodity sales	$	(73)	$	(98)
					Costs of sales	2		(5)
Interest rate contracts	2		(9)		Earnings from equity investments(c)	—		—
Foreign currency contracts	(35)		(53)		Other, net	(45)		3
Total	$	(407)	$	52	Total	$	(116)	$	(100)

(a)We expect to reclassify approximately $121 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 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 six months ended June 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 June 30,				Six Months Ended June 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(33)	$	149	$	(663)	$	266
	Costs of sales	(2)		2		160		6
	Earnings from equity investments	(2)		—		(2)		—
Total(a)		$	(37)	$	151	$	(505)	$	272

(a)The three and six months ended June 30, 2021 amounts include approximate losses of $7 million and $455 million, respectively, and the three and six months ended June 30, 2020 amounts include approximate gains of $179 million and $253 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

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Revenue Recognition (Tables)

6 Months Ended

Jun. 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 June 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)	$	799	$	66	$	198	$	—	$	—	$	1,063
Fee-based services	176		244		84		10		—		514
Total services	975		310		282		10		—		1,577
Commodity sales
Natural gas sales	674		—		—		1		(3)		672
Product sales	248		157		7		258		(13)		657
Total commodity sales	922		157		7		259		(16)		1,329
Total revenues from contracts with customers	1,897		467		289		269		(16)		2,906
Other revenues(c)
Leasing services(d)	118		43		144		15		1		321
Derivatives adjustments on commodity sales	(37)		(1)		—		(47)		—		(85)
Other	(2)		5		—		6		(1)		8
Total other revenues	79		47		144		(26)		—		244
Total revenues	$	1,976	$	514	$	433	$	243	$	(16)	$	3,150

	Three Months Ended June 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)	$	796	$	67	$	189	$	—	$	—	$	1,052
Fee-based services	157		182		95		10		(2)		442
Total services	953		249		284		10		(2)		1,494
Commodity sales
Natural gas sales	377		—		—		—		(1)		376
Product sales	102		49		3		134		(4)		284
Total commodity sales	479		49		3		134		(5)		660
Total revenues from contracts with customers	1,432		298		287		144		(7)		2,154
Other revenues(c)
Leasing services(d)	114		42		132		11		—		299
Derivatives adjustments on commodity sales	(11)		—		—		75		—		64
Other	36		5		—		2		—		43
Total other revenues	139		47		132		88		—		406
Total revenues	$	1,571	$	345	$	419	$	232	$	(7)	$	2,560

	Six Months Ended June 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)	$	1,665	$	125	$	389	$	—	$	—	$	2,179
Fee-based services	354		465		165		25		—		1,009
Total services	2,019		590		554		25		—		3,188
Commodity sales
Natural gas sales	3,993		—		—		2		(8)		3,987
Product sales	468		282		12		487		(23)		1,226
Total commodity sales	4,461		282		12		489		(31)		5,213
Total revenues from contracts with customers	6,480		872		566		514		(31)		8,401
Other revenues(c)
Leasing services(d)	237		86		287		27		—		637
Derivatives adjustments on commodity sales	(655)		(1)		—		(80)		—		(736)
Other	39		10		—		11		(1)		59
Total other revenues	(379)		95		287		(42)		(1)		(40)
Total revenues	$	6,101	$	967	$	853	$	472	$	(32)	$	8,361

	Six Months Ended June 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)	$	1,661	$	146	$	378	$	—	$	—	$	2,185
Fee-based services	350		442		216		23		(2)		1,029
Total services	2,011		588		594		23		(2)		3,214
Commodity sales
Natural gas sales	878		—		—		—		(3)		875
Product sales	238		158		6		366		(17)		751
Total commodity sales	1,116		158		6		366		(20)		1,626
Total revenues from contracts with customers	3,127		746		600		389		(22)		4,840
Other revenues(c)
Leasing services(d)	227		84		261		21		—		593
Derivatives adjustments on commodity sales	41		—		—		127		—		168
Other	51		10		—		4		—		65
Total other revenues	319		94		261		152		—		826
Total revenues	$	3,446	$	840	$	861	$	541	$	(22)	$	5,666

(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 5 for additional information related to our derivative contracts.

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

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of June 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Six months ended December 31, 2021	$	2,232
2022	3,766
2023	3,040
2024	2,590
2025	2,191
Thereafter	13,776
Total	$	27,595

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Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

Financial information by segment follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,960	$	1,565	$	6,070	$	3,426
Intersegment revenues	16		6		31		20
Products Pipelines	514		345		967		840
Terminals
Revenues from external customers	433		418		852		859
Intersegment revenues	—		1		1		2
CO2	243		232		472		541
Corporate and intersegment eliminations	(16)		(7)		(32)		(22)
Total consolidated revenues	$	3,150	$	2,560	$	8,361	$	5,666

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	(570)	$	(3)	$	1,533	$	1,193
Products Pipelines	265		227		513		496
Terminals	246		229		473		486
CO2	150		146		436		(609)
Total Segment EBDA	91		599		2,955		1,566
DD&A	(528)		(532)		(1,069)		(1,097)
Amortization of excess cost of equity investments	(13)		(35)		(35)		(67)
General and administrative and corporate charges	(150)		(157)		(298)		(322)
Interest, net	(377)		(395)		(754)		(831)
Income tax benefit (expense)	237		(104)		(114)		(164)
Total consolidated net (loss) income	$	(740)	$	(624)	$	685	$	(915)

	June 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	46,445	$	48,597
Products Pipelines	9,138		9,182
Terminals	8,555		8,639
CO2	2,433		2,478
Corporate assets(b)	3,604		3,077
Total consolidated assets	$	70,175	$	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)

6 Months Ended

Jun. 30, 2021

Income Tax Disclosure [Abstract]

Schedule of Income Taxes

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
	(In millions, except percentages)
Income tax (benefit) expense	$	(237)		$	104		$	114		$	164
Effective tax rate	24.3		%	(20.0)		%	14.3		%	(21.8)		%

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General - Organization and Basis of Presentation (Details) mi in Thousands, $ in Millions			6 Months Ended
	Jul. 16, 2021 USD ($)	Jul. 09, 2021 USD ($) Bcf Terminals	Jun. 30, 2021 segment mi Terminals
General [Line Items]
Miles of pipeline | mi			83
Number of pipeline terminals owned interest in and/or operated | Terminals			144
Number of reporting units | segment			6
Stagecoach Gas Services LLC | Subsequent Event
General [Line Items]
Number of pipeline terminals owned interest in and/or operated | Terminals		4
Payments to acquire businesses | $		$ 1,228
Working capacity | Bcf		41
Kinetrex Energy | Subsequent Event
General [Line Items]
Payments to acquire businesses | $	$ 310
Kinetrex Energy | Subsequent Event | RNG Facility in Indiana
General [Line Items]
Ownership percentage	50.00%

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General - Schedule of Net Income Available to Shareholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Common Stockholders	$ (757)	$ (637)	$ 652	$ (943)
Less: Net Income allocated to restricted stock awards(a)	$ (3)	$ (3)	$ (6)	$ (6)
Basic Weighted Average Common Shares Outstanding	2,265	2,261	2,264	2,263
Basic Earnings (Loss) Per Common Share	$ (0.34)	$ (0.28)	$ 0.29	$ (0.42)
Class P Common Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Common Stockholders	$ (760)	$ (640)	$ 646	$ (949)
Unvested restricted stock awards | Class P Common Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Restricted stock awards outstanding	12		12

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General - Schedule of Antidilutive Securities (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Unvested restricted stock awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	12	12	12	12
Convertible trust preferred securities
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	3	3	3	3

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Losses and Gains on Divestitures, Impairments and Other Write-downs – Schedule of Pre-tax Loss (Gain) on Impairments and Divestitures (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Finite-Lived Intangible Assets [Line Items]
Gain on sale of interests in NGPL Holdings LLC				$ (206)	$ 0
(Gain) loss on divestitures of long-lived assets	$ 1,602		$ 1,005	1,598	1,976
Impairment of goodwill			1,000		1,600
Pre-tax loss on impairments, divestitures and other write-downs, net	1,602		1,005	1,509	1,976
Corporate and intersegment eliminations
Finite-Lived Intangible Assets [Line Items]
Other gain on divestitures of long-lived assets	(1)		0	(4)	0
Natural Gas Pipelines
Finite-Lived Intangible Assets [Line Items]
Impairments of long-lived and intangible assets	1,600		0	1,600	0
(Gain) loss on divestitures of long-lived assets	(1)		0	(1)	0
Impairment of goodwill	$ 0		1,000	$ 0	1,000
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]
Impairments of long-lived and intangible assets	0		5	0	5
(Gain) loss on divestitures of long-lived assets	1		0	0	0
CO2
Finite-Lived Intangible Assets [Line Items]
Impairments of long-lived and intangible assets				0	350
(Gain) loss on divestitures of long-lived assets	3		0	3	0
Impairment of goodwill	0		0	$ 0	$ 600
CO2 | Oil and Gas Properties
Finite-Lived Intangible Assets [Line Items]
Impairments of long-lived and intangible assets	$ 0		$ 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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments			$ 413	$ 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			413
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]
Equity Method Investment, Ownership Percentage					25.00%
Brookfield | NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage					37.50%
KMI | NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, 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			6 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 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

XML

Debt - Schedule of Debt Outstanding (Details) $ in Millions		6 Months Ended
	Feb. 11, 2021 USD ($)	Jun. 30, 2021 USD ($) $ / €	Jun. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Debt Instrument [Line Items]
Current portion of debt		$ 2,183		$ 2,558
Total long-term debt		30,008		30,838
Total debt(d)		32,191		33,396
Debt fair value adjustments		1,069		1,293
Proceeds from issuances of debt		$ 3,110	$ 2,652
Foreign Currency Exchange Rate, Translation | $ / €		1.1858
Restricted deposits held for repayment of maturing notes and associated accrued interest		$ 604	$ 20	25	$ 24
Commercial paper notes
Debt Instrument [Line Items]
Current portion of debt		0		0
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		$ 357		364
Interest rate		3.967%
Other
Debt Instrument [Line Items]
Total long-term debt		$ 221		223
$4 billion credit facility due November 16, 2023
Debt Instrument [Line Items]
Current portion of debt		0		0
Line of Credit Facility, Current Borrowing Capacity		4,000
Senior notes
Debt Instrument [Line Items]
Total long-term debt		29,320		30,141
Senior notes | 5.00%, due February 2021(a)
Debt Instrument [Line Items]
Current portion of debt		0		$ 750
Interest rate				5.00%
Senior notes | 3.50%, due March 2021(a)
Debt Instrument [Line Items]
Current portion of debt		0		$ 750
Interest rate				3.50%
Senior notes | 5.80%, due March 2021(a)
Debt Instrument [Line Items]
Current portion of debt		0		$ 400
Interest rate				5.80%
Senior notes | 5.00%, due October 2021(b)
Debt Instrument [Line Items]
Current portion of debt		$ 500		$ 500
Interest rate		5.00%
Restricted deposits held for repayment of maturing notes and associated accrued interest		$ 506
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 | 1.50%, due March 2022(c)
Debt Instrument [Line Items]
Current portion of debt		$ 890		$ 0
Interest rate		1.50%
Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax		$ 75
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) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Line of credit facility	$ 2,183	$ 2,558
$4 billion credit facility due November 16, 2023
Line of Credit Facility [Line Items]
Line of credit facility	0	0
Line of Credit Facility, Remaining Borrowing Capacity	3,919
Letters of Credit Outstanding, Amount	81
Line of Credit Facility, Current Borrowing Capacity	4,000
Commercial paper notes
Line of Credit Facility [Line Items]
Line of credit facility	$ 0	$ 0

XML

Debt - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 33,260	$ 34,689
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 38,498	$ 39,622

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Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		6 Months Ended		43 Months Ended
	Jul. 21, 2021	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Jun. 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	$ 0.54	$ 0.525
Per share cash dividend paid in the period		$ 0.27	$ 0.2625	$ 0.5325	$ 0.5125
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	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Accumulated Other Comprehensive Loss [Line Items]
Balance	$ 31,838	$ 34,086
Balance	31,140	32,124
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Loss [Line Items]
Balance	(13)	(7)
Other comprehensive (loss) gain before reclassifications	(313)	40
Loss reclassified from accumulated other comprehensive loss	89	77
Net current-period change in accumulated other comprehensive (loss) income	(224)	117
Balance	(237)	110
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	22	16
Loss reclassified from accumulated other comprehensive loss	0	0
Net current-period change in accumulated other comprehensive (loss) income	22	16
Balance	(372)	(310)
Total accumulated other comprehensive loss
Accumulated Other Comprehensive Loss [Line Items]
Balance	(407)	(333)
Other comprehensive (loss) gain before reclassifications	(291)	57
Loss reclassified from accumulated other comprehensive loss	89	77
Net current-period change in accumulated other comprehensive (loss) income	(202)	134
Balance	$ (609)	$ (199)

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Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts	6 Months Ended
	Jun. 30, 2021 MMBbls Bcf
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	(7.9)
Derivatives designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	(31.7)
Derivatives designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	(26.2)
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	(1.2)
Derivatives not designated as hedging instruments | Crude oil basis
Derivative [Line Items]
Net open position	(9.8)
Derivatives not designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	(3.4)
Derivatives not designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	(15.8)
Derivatives not designated as hedging instruments | NGL fixed price
Derivative [Line Items]
Net open position	(2.1)

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Risk Management - Interest Rate Risk Management (Details) $ in Millions	Jun. 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	2,500
Current Portion Of Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	250
Long-term Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	$ 6,850

XML

Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Jun. 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	Jun. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivatives Asset	$ 656	$ 931
Derivatives Liability	(368)	(78)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	38	99
Derivatives Liability	(344)	(63)
Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	513	694
Derivatives Liability	(16)	(10)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	105	138
Derivatives Liability	(8)	(6)
Derivatives designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives Asset	638	907
Derivatives Liability	(316)	(57)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	20	75
Derivatives Liability	(293)	(41)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	18	42
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(206)	(33)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	2	33
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(87)	(8)
Derivatives designated as hedging instruments | Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	513	694
Derivatives Liability	(15)	(10)
Derivatives designated as hedging instruments | Interest rate contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	118	119
Derivatives designated as hedging instruments | Interest rate contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(3)	(3)
Derivatives designated as hedging instruments | Interest rate contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	395	575
Derivatives designated as hedging instruments | Interest rate contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(12)	(7)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	105	138
Derivatives Liability	(8)	(6)
Derivatives designated as hedging instruments | Foreign currency contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	67	0
Derivatives designated as hedging instruments | Foreign currency contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(8)	(6)
Derivatives designated as hedging instruments | Foreign currency contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	38	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	18	24
Derivatives Liability	(52)	(21)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	18	24
Derivatives Liability	(51)	(21)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	18	24
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(46)	(21)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Asset	0	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	(5)	0
Derivatives not designated as hedging instruments | Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Asset	0	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

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Risk Management - Derivative Assets Input Level (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 656	$ 931
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	38	99
Contracts available for netting	(35)	(35)
Cash collateral held	0	0
Net amount	3	64
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	18	6
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	20	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	513	694
Contracts available for netting	(5)	(2)
Cash collateral held	0	0
Net amount	508	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	513	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	105	138
Contracts available for netting	(8)	(6)
Cash collateral held	0	0
Net amount	97	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	105	138
Foreign currency contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 0	$ 0

XML

Risk Management - Derivative Liabilities Input Level (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ (368)	$ (78)
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(344)	(63)
Contracts available for netting	35	35
Cash collateral posted	55	(8)
Net amount	(254)	(36)
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(46)	(7)
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(298)	(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	(16)	(10)
Contracts available for netting	5	2
Cash collateral posted	0	0
Net amount	(11)	(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	(16)	(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	(8)	(6)
Contracts available for netting	8	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	(8)	(6)
Foreign currency contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 0	$ 0

XML

Risk Management - Effect of Derivative Contracts on the Income Statement (Details) - Derivatives designated as hedging instruments - Derivatives in fair value hedging relationships - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Interest rate contracts | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives adjustments on commodity sales	$ 28	$ 26	$ (189)	$ 459
Hedged fixed rate debt
Derivative Instruments, Gain (Loss) [Line Items]
Cumulative amount of fair value hedging adjustments to hedged fixed rate debt	512		512
Hedged fixed rate debt | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives adjustments on commodity sales	$ (28)	$ (28)	$ 190	$ (468)

XML

Risk Management - Effect on Income Statement Locations (Details) - Derivatives in cash flow hedging relationships - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months			$ (121)
Derivatives designated as hedging instruments
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	$ (204)	$ (246)	(407)	$ 52
Gain/(loss) reclassified from Accumulated OCI into income	(39)	(61)	(116)	(100)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	(215)	(273)	(374)	114
Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	1	(1)	2	(9)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	10	28	(35)	(53)
Revenues—Commodity sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(53)	(84)	(73)	(98)
Cost of sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(2)	(2)	2	(5)
Earnings from Equity Investments | Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	0	0	0	0
Other, net | Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ 16	$ 25	(45)	$ 3
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

XML

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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (37)	$ 151	$ (505)	$ 272
Gain/(loss) on settlement of derivative contracts	(7)	179	(455)	253
Revenues—Commodity sales
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(33)	149	(663)	266
Cost of sales
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(2)	2	160	6
Earnings from Equity Investments
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (2)	$ 0	$ (2)	$ 0

XML

Risk Management - Credit Risks (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	$ 169
Energy commodity derivative contracts
Credit Derivatives [Line Items]
Letter of credits outstanding, amount	0	$ 0
Initial Margin Requirements	22
Variation Margin Requirements	55
Cash collateral posted	55	(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	$ 77

XML

Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 2,906	$ 2,154	$ 8,401	$ 4,840
Leasing services	321	299	637	593
Other	8	43	59	65
Total other revenues	244	406	(40)	826
Total revenues	3,150	2,560	8,361	5,666
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	1,960	1,565	6,070	3,426
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	514	345	967	840
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	433	418	852	859
CO2
Disaggregation of Revenue [Line Items]
Total revenues	243	232	472	541
Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,897	1,432	6,480	3,127
Leasing services	118	114	237	227
Other	(2)	36	39	51
Total other revenues	79	139	(379)	319
Total revenues	1,976	1,571	6,101	3,446
Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	467	298	872	746
Leasing services	43	42	86	84
Other	5	5	10	10
Total other revenues	47	47	95	94
Total revenues	514	345	967	840
Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	289	287	566	600
Leasing services	144	132	287	261
Other	0	0	0	0
Total other revenues	144	132	287	261
Total revenues	433	419	853	861
Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	269	144	514	389
Leasing services	15	11	27	21
Other	6	2	11	4
Total other revenues	(26)	88	(42)	152
Total revenues	243	232	472	541
Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(16)	(7)	(31)	(22)
Leasing services	1	0	0	0
Other	(1)	0	(1)	0
Total other revenues	0	0	(1)	0
Total revenues	(16)	(7)	(32)	(22)
Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,063	1,052	2,179	2,185
Firm services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	799	796	1,665	1,661
Firm services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	66	67	125	146
Firm services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	198	189	389	378
Firm services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
Firm services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	514	442	1,009	1,029
Fee-based services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	176	157	354	350
Fee-based services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	244	182	465	442
Fee-based services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	84	95	165	216
Fee-based services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10	10	25	23
Fee-based services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	(2)	0	(2)
Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,577	1,494	3,188	3,214
Total services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	975	953	2,019	2,011
Total services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	310	249	590	588
Total services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	282	284	554	594
Total services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10	10	25	23
Total services | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	(2)	0	(2)
Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	672	376	3,987	875
Natural Gas Sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	674	377	3,993	878
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	1	0	2	0
Natural Gas Sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(3)	(1)	(8)	(3)
Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	657	284	1,226	751
Product sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	248	102	468	238
Product sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	157	49	282	158
Product sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7	3	12	6
Product sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	258	134	487	366
Product sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(13)	(4)	(23)	(17)
Commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,329	660	5,213	1,626
Total revenues	1,246	723	4,475	1,790
Commodity sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	922	479	4,461	1,116
Commodity sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	157	49	282	158
Commodity sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7	3	12	6
Commodity sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	259	134	489	366
Commodity sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(16)	(5)	(31)	(20)
Sales
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(85)	64	(736)	168
Sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(37)	(11)	(655)	41
Sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(1)	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	(47)	75	(80)	127
Sales | Corporate and intersegment eliminations
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	$ 0	$ 0	$ 0	$ 0

XML

Revenue Recognition - Contract Balances (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Dec. 31, 2020
Contract Assets
Contract assets balances	$ 48	$ 20
Transfer to Accounts receivable	12
Contract Liabilities
Contract liabilities balances	232	$ 239
Transfer to Revenues	$ 45

XML

Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Jun. 30, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue allocated to remaining performance obligations for contracted revenue	$ 27,595
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	6 months
Revenue allocated to remaining performance obligations for contracted revenue	$ 2,232
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	$ 3,766
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	$ 3,040
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	$ 2,590
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	$ 2,191
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	$ 13,776

XML

Reportable Segments Reportable Segments Revenues (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Segment Reporting Information [Line Items]
Revenues	$ 3,150	$ 2,560	$ 8,361	$ 5,666
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(16)	(7)	(32)	(22)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	1,960	1,565	6,070	3,426
Natural Gas Pipelines | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(16)	(6)	(31)	(20)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	514	345	967	840
Terminals
Segment Reporting Information [Line Items]
Revenues	433	418	852	859
Terminals | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	0	(1)	(1)	(2)
CO2
Segment Reporting Information [Line Items]
Revenues	$ 243	$ 232	$ 472	$ 541

XML

Reportable Segments Reportable Segments EBDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Segment Reporting Information [Line Items]
DD&A	$ (528)	$ (532)	$ (1,069)	$ (1,097)
Amortization of excess cost of equity investments	(13)	(35)	(35)	(67)
General and administrative and corporate charges	(160)	(155)	(316)	(308)
Income Tax Benefit (Expense)	237	(104)	(114)	(164)
Net (Loss) Income	(740)	(624)	685	(915)
Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	91	599	2,955	1,566
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
DD&A	(528)	(532)	(1,069)	(1,097)
Amortization of excess cost of equity investments	(13)	(35)	(35)	(67)
General and administrative and corporate charges	(150)	(157)	(298)	(322)
Interest, net	(377)	(395)	(754)	(831)
Income Tax Benefit (Expense)	237	(104)	(114)	(164)
Natural Gas Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	(570)	(3)	1,533	1,193
Products Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	265	227	513	496
Terminals | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	246	229	473	486
CO2 | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	$ 150	$ 146	$ 436	$ (609)

XML

Reportable Segments Reportable Segments Assets (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Assets	$ 70,175	$ 71,973
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
Assets	3,604	3,077
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	46,445	48,597
Products Pipelines
Segment Reporting Information [Line Items]
Assets	9,138	9,182
Terminals
Segment Reporting Information [Line Items]
Assets	8,555	8,639
CO2
Segment Reporting Information [Line Items]
Assets	$ 2,433	$ 2,478

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Segment Reporting Information [Line Items]
Income tax (benefit) expense	$ (237)	$ 104	$ 114	$ 164
Effective tax rate	24.30%	(20.00%)	14.30%	(21.80%)
Statutory federal rate	21.00%	21.00%	21.00%	21.00%
Impairment of goodwill		$ 1,000		$ 1,600

XML

Litigation and Environmental - Federal Energy Regulatory Commission Proceedings (Details) - Pending Litigation $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($)	Jun. 01, 2018 projects
Hiland Partners Holdings, LLC [Member]
Loss Contingencies [Line Items]
Infrastructures to Build for Settlement | projects		10
Loss Contingency, Damages Sought, Value	$ 225
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

XML

Litigation and Environmental - General (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Estimated Litigation Liability	$ 185	$ 273

XML

Litigation and Environmental - Portland Harbor (Details) - Environmental Protection Agency - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Billions	6 Months Ended
	Jun. 30, 2021 USD ($) Terminals Parties
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

XML

Litigation and Environmental - Lower Passaic River (Details) - Pending Litigation $ in Millions	Oct. 05, 2016 USD ($) mi	Mar. 04, 2016 USD ($) mi	Jun. 30, 2021 mi Parties
Lower Passaic River Study Area
Site Contingency [Line Items]
Miles of river | mi			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 | AOC required engineering and design work
Site Contingency [Line Items]
Environmental Remediation Expense | $	$ 165
Lower Passaic River Study Area | Design
Site Contingency [Line Items]
Estimated Remedy Implementation Period	4 years
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 | mi	8	8	8

XML

Litigation and Environmental - Environmental Matters (Details)				240 Months Ended
	Apr. 16, 2019	Mar. 29, 2019 Parties	Nov. 08, 2013 Parties	Dec. 31, 1969	Jun. 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				20
Percentage of Response Costs	35.00%

XML

Litigation and Environmental - Environmental Matters General (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Accrual for Environmental Loss Contingencies	$ 248	$ 250
Recorded Third-Party Environmental Recoveries Receivable	$ 12	$ 12