UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

F O R M 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, ~~2020~~2021

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-35081

KINDER MORGAN, INC.

(Exact name of registrant as specified in its charter)


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

1001 Louisiana Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

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

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


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class P Common Stock	KMI	New York Stock Exchange
1.500% Senior Notes due 2022	KMI 22	New York Stock Exchange
2.250% Senior Notes due 2027	KMI 27 A	New York Stock Exchange

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

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

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

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

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

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

As of October ~~22, 2020,~~21, 2021, the registrant had ~~2,263,793,923~~2,267,425,507 Class P shares outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

Page
Number

Glossary

Information Regarding Forward-Looking Statements

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements (Unaudited)

Consolidated Statements of Operations - Three and Nine Months Ended September 30, ~~2020~~2021 and ~~2019~~2020

Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, ~~2020~~2021 and ~~2019~~2020

Consolidated Balance Sheets - as of ~~September~~Septem ber 30, ~~2020~~2021 and December 31, ~~2019~~2020

Consolidated Statements of Cash Flows - Nine Months Ended September 30, ~~2020~~2021 and ~~2019~~2020

Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 30, ~~2020~~2021 and ~~2019~~2020

Notes to Consolidated Financial Statements

Note 1 .

General

Note 2 .

~~Impairments~~Acquisitions

Note 3 .

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

~~Income Taxes~~Litigation and Environmental

~~Note 9~~

~~Litigation and Environmental~~Note 1 1 .

~~Note 10~~

Recent Accounting Pronouncements

3432

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

General and Basis of Presentation

3534

Results of Operations

3635

Overview

3635

Consolidated Earnings Results (GAAP)

3937

Non-GAAP Financial Measures

4240

Segment Earnings Results

4543

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

5351

Income Taxes

5452

Liquidity and Capital Resources

5452

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

5956

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

6057

Item 4.

Controls and Procedures

6057

PART II. OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

6057

Item 3.

Defaults Upon Senior Securities

6057

Item 4.

Mine Safety Disclosures

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

~~CIG~~

~~Colorado Interstate Gas Company, L.L.C.~~

~~KMP~~

~~Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries~~

~~ELC~~

~~Elba Liquefaction Company, L.L.C.~~

EPNG

El Paso Natural Gas Company, L.L.C.

~~SFPP~~Ruby

~~SFPP, L.P.~~Ruby Pipeline Holding Company, L.L.C.

KMBT

Kinder Morgan Bulk Terminals, Inc.

~~SNG~~SFPP

~~Southern Natural Gas Company, L.L.C.~~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.

~~TMPL~~

~~Trans Mountain Pipeline System~~

~~KML~~

~~Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries~~

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

per day

EPA

U.S. Environmental Protection Agency

~~BBtu~~Bbl

~~billion British Thermal Units~~barrel

FASB

Financial Accounting Standards Board

~~Bcf~~BBtu

billion ~~cubic feet~~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

~~GAAP~~

~~U.S. Generally Accepted Accounting Principles~~

LLC

limited liability company

LIBOR

London Interbank Offered Rate

CO₂

carbon dioxide or our CO₂ business segment

~~LIBOR~~MBbl

~~London Interbank Offered Rate~~thousand barrels

COVID-19

Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturn

~~MBbl~~

~~thousand barrels~~

MMBbl

million barrels

MMtons

million tons

DCF

distributable cash flow

~~MMtons~~NGL

~~million tons~~natural gas liquids

DD&A

depreciation, depletion and amortization

~~NGL~~NYMEX

~~natural gas liquids~~New York Mercantile Exchange

EBDA

earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments

~~NYMEX~~

~~New York Mercantile Exchange~~

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

~~ROU~~

~~Right-of-Use~~

U.S.

United States of America

WTI

West Texas Intermediate

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,” ~~“position,~~“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 to pay dividends, are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict.

~~Forward-looking statements~~ in this report include, ~~statements,~~among others, express or implied ~~concerning, without limitation:~~statements pertaining to: the long-term demand for our assets and services, ~~the future impact on~~ our ~~business~~anticipated dividends, our proposed acquisition of Kinetrex Energy and our capital projects, including expected completion timing and benefits of the ~~global economic consequences~~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 ~~our expected 2020 outlook, including our expected DCF, Adjusted EBITDA,~~the pace and ~~Net Debt-to-Adjusted EBITDA ratio.~~

~~The impacts~~extent of ~~COVID-19~~economic recovery; the timing and ~~decreases~~extent of changes in ~~commodity prices resulting from oversupply~~the supply of and demand ~~weakness are discussed~~for the products we transport and handle; commodity prices; and the other risks and uncertainties described in ~~further detail in Part I, Item 1. “Financial Statements (Unaudited)—Note 1 General—COVID-19~~;” Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition of ~~Operations—General and Basis of Presentation—COVID-19~~Operations” and “~~—2020 Outlook~~;” Part I, Item 3. “Quantitative and Qualitative Disclosures About Market ~~Risk;”~~ ~~and Part II, Item 1A. “~~Risk ~~Factors,~~” ~~and~~ in ~~Part II, Item 1A. “Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. In addition to the preceding factors,~~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, ~~2019 (2019 Form 10-K),contain a more detailed description of other factors that may affect the forward-looking statements and should be referenced, except~~2020 (except to the extent such ~~other factors are~~information is modified or superseded by ~~the descriptions~~information in subsequent ~~reports.~~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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts, unaudited)


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Revenues	Revenues									Revenues
Services	Services	$	1,881	$	2,014	$	5,664	$	6,060	Services	$	1,928	$	1,881	$	5,734	$	5,664
Commodity sales	Commodity sales	982		1,154		2,772		3,659		Commodity sales	1,868		982		6,343		2,772
Other	Other	56		46		149		138		Other	28		56		108		149
Total Revenues	Total Revenues	2,919		3,214		8,585		9,857		Total Revenues	3,824		2,919		12,185		8,585

Operating Costs, Expenses and Other	Operating Costs, Expenses and Other									Operating Costs, Expenses and Other
Costs of sales	Costs of sales	655		762		1,759		2,487		Costs of sales	1,559		655		4,504		1,759
Operations and maintenance	Operations and maintenance	643		668		1,869		1,912		Operations and maintenance	614		643		1,710		1,869
Depreciation, depletion and amortization	Depreciation, depletion and amortization	539		578		1,636		1,750		Depreciation, depletion and amortization	526		539		1,595		1,636
General and administrative	General and administrative	153		154		461		456		General and administrative	174		153		490		461
Taxes, other than income taxes	Taxes, other than income taxes	100		103		295		324		Taxes, other than income taxes	106		100		324		295

Loss (gain) on impairments and divestitures, net (Note 2)		11		(3)		1,987		(13)
Other (income) expense, net		(1)		1		(2)		(1)
Loss on impairments and divestitures, net (Note 3)										Loss on impairments and divestitures, net (Note 3)	4		11		1,602		1,987
Other income, net										Other income, net	(3)		(1)		(6)		(2)
Total Operating Costs, Expenses and Other	Total Operating Costs, Expenses and Other	2,100		2,263		8,005		6,915		Total Operating Costs, Expenses and Other	2,980		2,100		10,219		8,005

Operating Income	Operating Income	819		951		580		2,942		Operating Income	844		819		1,966		580

Other Income (Expense)	Other Income (Expense)									Other Income (Expense)
Earnings from equity investments	Earnings from equity investments	194		173		562		526		Earnings from equity investments	169		194		392		562

Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(32)		(21)		(99)		(61)		Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)
Interest, net	Interest, net	(383)		(447)		(1,214)		(1,359)		Interest, net	(368)		(383)		(1,122)		(1,214)
Other, net		14		12		32		35
Other, net (Note 3)										Other, net (Note 3)	21		14		264		32
Total Other Expense	Total Other Expense	(207)		(283)		(719)		(859)		Total Other Expense	(199)		(207)		(522)		(719)

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	612		668		(139)		2,083		Income (Loss) Before Income Taxes	645		612		1,444		(139)

Income Tax Expense	Income Tax Expense	(140)		(151)		(304)		(471)		Income Tax Expense	(134)		(140)		(248)		(304)

Net Income (Loss)	Net Income (Loss)	472		517		(443)		1,612		Net Income (Loss)	511		472		1,196		(443)

Net Income Attributable to Noncontrolling Interests	Net Income Attributable to Noncontrolling Interests	(17)		(11)		(45)		(32)		Net Income Attributable to Noncontrolling Interests	(16)		(17)		(49)		(45)

Net Income (Loss) Attributable to Kinder Morgan, Inc.	Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	455	$	506	$	(488)	$	1,580	Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	495	$	455	$	1,147	$	(488)

Class P Shares	Class P Shares									Class P Shares
Basic and Diluted Earnings (Loss) Per Common Share		$	0.20	$	0.22	$	(0.22)	$	0.69
Basic and Diluted Earnings (Loss) Per Share										Basic and Diluted Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)

Basic and Diluted Weighted Average Common Shares Outstanding		2,263		2,264		2,263		2,263
Basic and Diluted Weighted Average Shares Outstanding										Basic and Diluted Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In millions, unaudited)


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Net income (loss)	Net income (loss)	$	472	$	517	$	(443)	$	1,612	Net income (loss)	$	511	$	472	$	1,196	$	(443)
Other comprehensive (loss) income, net of tax	Other comprehensive (loss) income, net of tax									Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $17, $(6), $5, and $39, respectively)		(56)		20		(16)		(132)
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $1, $(13), $(22), and $(11), respectively)		(5)		40		72		35
Foreign currency translation adjustments (net of tax benefit (expense) of $0, $2, $0, and $(5), respectively)		0		(7)		1		16
Benefit plan adjustments (net of tax expense of $2, $3, $7 and $8, respectively)		5		8		21		23
Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively)										Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively)	(131)		(56)		(444)		(16)
Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively)										Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively)	92		(5)		181		72
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)										Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)	—		—		—		1
Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively)										Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively)	6		5		28		21
Total other comprehensive (loss) income	Total other comprehensive (loss) income	(56)		61		78		(58)		Total other comprehensive (loss) income	(33)		(56)		(235)		78

Comprehensive income (loss)	Comprehensive income (loss)	416		578		(365)		1,554		Comprehensive income (loss)	478		416		961		(365)
Comprehensive income attributable to noncontrolling interests	Comprehensive income attributable to noncontrolling interests	(17)		(8)		(45)		(28)		Comprehensive income attributable to noncontrolling interests	(16)		(17)		(49)		(45)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.	Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$	399	$	570	$	(410)	$	1,526	Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$	462	$	399	$	912	$	(410)

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except per share amounts, unaudited)


		September 30, 2020		December 31, 2019			September 30, 2021		December 31, 2020
ASSETS	ASSETS					ASSETS
Current Assets	Current Assets					Current Assets
Cash and cash equivalents	Cash and cash equivalents	$	632	$	185	Cash and cash equivalents	$	102	$	1,184
Restricted deposits	Restricted deposits	67		24		Restricted deposits	177		25
Marketable securities at fair value		0		925
Accounts receivable	Accounts receivable	1,142		1,379		Accounts receivable	1,433		1,293
Fair value of derivative contracts	Fair value of derivative contracts	257		84		Fair value of derivative contracts	199		185
Inventories	Inventories	317		371		Inventories	457		348

Other current assets	Other current assets	257		270		Other current assets	318		168
Total current assets	Total current assets	2,672		3,238		Total current assets	2,686		3,203

Property, plant and equipment, net	Property, plant and equipment, net	35,958		36,419		Property, plant and equipment, net	35,576		35,836
Investments	Investments	8,014		7,759		Investments	7,620		7,917
Goodwill	Goodwill	19,851		21,451		Goodwill	20,033		19,851
Other intangibles, net	Other intangibles, net	2,510		2,676		Other intangibles, net	1,744		2,453
Deferred income taxes	Deferred income taxes	671		857		Deferred income taxes	303		536

Deferred charges and other assets	Deferred charges and other assets	2,145		1,757		Deferred charges and other assets	1,678		2,177
Total Assets	Total Assets	$	71,821	$	74,157	Total Assets	$	69,640	$	71,973

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY	LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY					LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities	Current Liabilities					Current Liabilities
Current portion of debt	Current portion of debt	$	2,057	$	2,477	Current portion of debt	$	2,822	$	2,558
Accounts payable	Accounts payable	774		914		Accounts payable	1,189		837

Accrued interest	Accrued interest	351		548		Accrued interest	332		525
Accrued taxes	Accrued taxes	335		364		Accrued taxes	284		267
Accrued contingencies	Accrued contingencies	315		89		Accrued contingencies	246		307

Other current liabilities	Other current liabilities	544		708		Other current liabilities	952		580
Total current liabilities	Total current liabilities	4,376		5,100		Total current liabilities	5,825		5,074

Long-term liabilities and deferred credits	Long-term liabilities and deferred credits					Long-term liabilities and deferred credits
Long-term debt	Long-term debt					Long-term debt
Outstanding	Outstanding	31,281		30,883		Outstanding	28,988		30,838

Debt fair value adjustments	Debt fair value adjustments	1,379		1,032		Debt fair value adjustments	1,014		1,293
Total long-term debt	Total long-term debt	32,660		31,915		Total long-term debt	30,002		32,131

Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits	2,093		2,253		Other long-term liabilities and deferred credits	2,160		2,202

Total long-term liabilities and deferred credits	Total long-term liabilities and deferred credits	34,753		34,168		Total long-term liabilities and deferred credits	32,162		34,333
Total Liabilities	Total Liabilities	39,129		39,268		Total Liabilities	37,987		39,407

Commitments and contingencies (Notes 3 and 9)
Commitments and contingencies (Notes 4 and 10)						Commitments and contingencies (Notes 4 and 10)	0		0
Redeemable Noncontrolling Interest	Redeemable Noncontrolling Interest	747		803		Redeemable Noncontrolling Interest	661		728
Stockholders’ Equity	Stockholders’ Equity					Stockholders’ Equity

Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,263,749,898 and 2,264,936,054 shares, respectively, issued and outstanding		23		23
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding						Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding	23		23
Additional paid-in capital	Additional paid-in capital	41,736		41,745		Additional paid-in capital	41,788		41,756
Accumulated deficit	Accumulated deficit	(9,945)		(7,693)		Accumulated deficit	(10,617)		(9,936)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(255)		(333)		Accumulated other comprehensive loss	(642)		(407)
Total Kinder Morgan, Inc.’s stockholders’ equity	Total Kinder Morgan, Inc.’s stockholders’ equity	31,559		33,742		Total Kinder Morgan, Inc.’s stockholders’ equity	30,552		31,436
Noncontrolling interests	Noncontrolling interests	386		344		Noncontrolling interests	440		402
Total Stockholders’ Equity	Total Stockholders’ Equity	31,945		34,086		Total Stockholders’ Equity	30,992		31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	71,821	$	74,157	Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	69,640	$	71,973

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


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

		Nine Months Ended September 30,							Nine Months Ended September 30,
		2020		2019			2021		2020
Cash Flows From Operating Activities	Cash Flows From Operating Activities					Cash Flows From Operating Activities
Net (loss) income		$	(443)	$	1,612
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Net income (loss)						Net income (loss)	$	1,196	$	(443)
Adjustments to reconcile net income (loss) to net cash provided by operating activities						Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	Depreciation, depletion and amortization	1,636		1,750		Depreciation, depletion and amortization	1,595		1,636
Deferred income taxes	Deferred income taxes	164		254		Deferred income taxes	236		164
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	99		61		Amortization of excess cost of equity investments	56		99

Loss (gain) on impairments and divestitures, net (Note 2)		1,987		(13)

Loss on impairments and divestitures, net (Note 3)						Loss on impairments and divestitures, net (Note 3)	1,602		1,987
Gain on sale of interest in equity investment (Note 3)						Gain on sale of interest in equity investment (Note 3)	(206)		—
Earnings from equity investments	Earnings from equity investments	(562)		(526)		Earnings from equity investments	(392)		(562)
Distributions from equity investment earnings	Distributions from equity investment earnings	487		412		Distributions from equity investment earnings	535		487
Changes in components of working capital	Changes in components of working capital					Changes in components of working capital
Accounts receivable	Accounts receivable	238		224		Accounts receivable	(119)		238
Inventories	Inventories	41		(28)		Inventories	(89)		41
Other current assets	Other current assets	14		97		Other current assets	(90)		14
Accounts payable	Accounts payable	(107)		(266)		Accounts payable	362		(107)
Accrued interest, net of interest rate swaps	Accrued interest, net of interest rate swaps	(208)		(218)		Accrued interest, net of interest rate swaps	(177)		(208)
Accrued taxes	Accrued taxes	(25)		(107)		Accrued taxes	15		(25)
Other current liabilities	Other current liabilities	(111)		(136)		Other current liabilities	71		(93)

Rate reparations, refunds and other litigation reserve adjustments						Rate reparations, refunds and other litigation reserve adjustments	(97)		48
Other, net	Other, net	72		5		Other, net	(58)		6
Net Cash Provided by Operating Activities	Net Cash Provided by Operating Activities	3,282		3,121		Net Cash Provided by Operating Activities	4,440		3,282
Cash Flows From Investing Activities	Cash Flows From Investing Activities					Cash Flows From Investing Activities

Acquisitions of assets and investments, net of cash acquired						Acquisitions of assets and investments, net of cash acquired	(1,518)		(16)
Capital expenditures	Capital expenditures	(1,351)		(1,719)		Capital expenditures	(894)		(1,351)
Proceeds from sales of assets and investments, net of working capital adjustments		907		80
Proceeds from sales of investments						Proceeds from sales of investments	417		907
Contributions to investments	Contributions to investments	(365)		(1,148)		Contributions to investments	(36)		(365)
Distributions from equity investments in excess of cumulative earnings	Distributions from equity investments in excess of cumulative earnings	105		207		Distributions from equity investments in excess of cumulative earnings	121		105

Other, net	Other, net	(72)		(30)		Other, net	(1)		(56)
Net Cash Used in Investing Activities	Net Cash Used in Investing Activities	(776)		(2,610)		Net Cash Used in Investing Activities	(1,911)		(776)
Cash Flows From Financing Activities	Cash Flows From Financing Activities					Cash Flows From Financing Activities
Issuances of debt	Issuances of debt	3,888		5,118		Issuances of debt	4,950		3,888
Payments of debt	Payments of debt	(3,991)		(6,303)		Payments of debt	(6,459)		(3,991)
Debt issue costs	Debt issue costs	(23)		(9)		Debt issue costs	(20)		(23)
Common stock dividends		(1,764)		(1,593)
Dividends						Dividends	(1,828)		(1,764)

Repurchases of common shares		(50)		(2)
Repurchases of shares						Repurchases of shares	—		(50)

Contributions from investment partner and noncontrolling interests	Contributions from investment partner and noncontrolling interests	11		138		Contributions from investment partner and noncontrolling interests	4		11
Distributions to investment partner	Distributions to investment partner	(60)		0		Distributions to investment partner	(67)		(60)
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds		0		(879)
Distributions to noncontrolling interests - other		(11)		(42)

Distributions to noncontrolling interests						Distributions to noncontrolling interests	(14)		(11)
Other, net	Other, net	(13)		(28)		Other, net	(25)		(13)
Net Cash Used in Financing Activities	Net Cash Used in Financing Activities	(2,013)		(3,600)		Net Cash Used in Financing Activities	(3,459)		(2,013)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(3)		26		Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	—		(3)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits		490		(3,063)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits						Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(930)		490
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	Cash, Cash Equivalents, and Restricted Deposits, beginning of period	209		3,331		Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209
Cash, Cash Equivalents, and Restricted Deposits, end of period	Cash, Cash Equivalents, and Restricted Deposits, end of period	$	699	$	268	Cash, Cash Equivalents, and Restricted Deposits, end of period	$	279	$	699


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

		Nine Months Ended September 30,							Nine Months Ended September 30,
		2020		2019			2021		2020
Cash and Cash Equivalents, beginning of period	Cash and Cash Equivalents, beginning of period	$	185	$	3,280	Cash and Cash Equivalents, beginning of period	$	1,184	$	185
Restricted Deposits, beginning of period	Restricted Deposits, beginning of period	24		51		Restricted Deposits, beginning of period	25		24
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	Cash, Cash Equivalents, and Restricted Deposits, beginning of period	209		3,331		Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209
Cash and Cash Equivalents, end of period	Cash and Cash Equivalents, end of period	632		241		Cash and Cash Equivalents, end of period	102		632
Restricted Deposits, end of period	Restricted Deposits, end of period	67		27		Restricted Deposits, end of period	177		67
Cash, Cash Equivalents, and Restricted Deposits, end of period	Cash, Cash Equivalents, and Restricted Deposits, end of period	699		268		Cash, Cash Equivalents, and Restricted Deposits, end of period	279		699
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits		$	490	$	(3,063)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits						Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(930)	$	490

Non-cash Investing and Financing Activities	Non-cash Investing and Financing Activities					Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	ROU assets and operating lease obligations recognized	$	15	$	764	ROU assets and operating lease obligations recognized	$	35	$	15

Increase in property, plant and equipment from both accruals and contractor retainage						Increase in property, plant and equipment from both accruals and contractor retainage	4		0
Supplemental Disclosures of Cash Flow Information	Supplemental Disclosures of Cash Flow Information					Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	Cash paid during the period for interest (net of capitalized interest)	1,440		1,584		Cash paid during the period for interest (net of capitalized interest)	1,313		1,440
Cash paid during the period for income taxes, net	Cash paid during the period for income taxes, net	202		364		Cash paid during the period for income taxes, net	8		202

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions, unaudited)


		Common stock																	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			Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at June 30, 2020		2,261	$	23	$	41,731	$	(9,802)	$	(199)	$	31,753	$	371	$	32,124
Balance at June 30, 2021																	Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)	$	30,711	$	429	$	31,140

Restricted shares	Restricted shares	3			5						5				5		Restricted shares	2			(5)						(5)				(5)
Net income	Net income						455				455		17		472		Net income						495				495		16		511
Distributions	Distributions										0		(4)		(4)		Distributions										—		(6)		(6)
Contributions	Contributions										0		2		2		Contributions										—		1		1

Common stock dividends							(598)				(598)				(598)
Dividends																	Dividends						(616)				(616)				(616)

Other comprehensive loss	Other comprehensive loss								(56)		(56)				(56)		Other comprehensive loss								(33)		(33)				(33)
Balance at September 30, 2020		2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945
Balance at September 30, 2021																	Balance at September 30, 2021	2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992

Common stock
Issued shares Par value Additional
paid-in
capital Accumulated
deficit Accumulated
other
comprehensive
loss Stockholders’
equity
attributable
to KMI Non-controlling
interests Total
Balance at June 30, 2019 2,262 $ 23 $ 41,734 $ (7,670) $ (448) $ 33,639 $ 846 $ 34,485
Restricted shares 3 (7) (7) (7)
Net income 506 506 11 517
Distributions 0 (14) (14)
Contributions 0 2 2
Common stock dividends (569) (569) (569)
Other 0 (1) (1)
Other comprehensive income (loss) 64 64 (3) 61
Balance at September 30, 2019 2,265 $ 23 $ 41,727 $ (7,733) $ (384) $ 33,633 $ 841 $ 34,474


	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at June 30, 2020	2,261	$	23	$	41,731	$	(9,802)	$	(199)	$	31,753	$	371	$	32,124





Restricted shares	3			5						5				5
Net income						455				455		17		472


Distributions										—		(4)		(4)
Contributions										—		2		2
Dividends						(598)				(598)				(598)



Other comprehensive loss								(56)		(56)				(56)
Balance at September 30, 2020	2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945

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

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, 2019 2,265 $ 23 $ 41,745 $ (7,693) $ (333) $ 33,742 $ 344 $ 34,086
Repurchases of common shares (4) (50) (50) (50)
Restricted shares 3 41 41 41
Net (loss) income (488) (488) 45 (443)
Distributions 0 (11) (11)
Contributions 0 8 8
Common stock dividends (1,764) (1,764) (1,764)
Other comprehensive income 78 78 78
Balance at September 30, 2020 2,264 $ 23 $ 41,736 $ (9,945) $ (255) $ 31,559 $ 386 $ 31,945


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




Restricted shares	3			32						32				32
Net income						1,147				1,147		49		1,196
Distributions										—		(14)		(14)
Contributions										—		4		4
Dividends						(1,828)				(1,828)				(1,828)
Other										—		(1)		(1)
Other comprehensive loss								(235)		(235)				(235)
Balance at September 30, 2021	2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992

Common stock
Issued shares Par value Additional
paid-in
capital Accumulated
deficit Accumulated
other
comprehensive
loss Stockholders’
equity
attributable
to KMI Non-controlling
interests Total
Balance at December 31, 2018 2,262 $ 23 $ 41,701 $ (7,716) $ (330) $ 33,678 $ 853 $ 34,531
Impact of adoption of ASU 2017-12 (4) (4) (4)
Balance at January 1, 2019 2,262 23 41,701 (7,720) (330) 33,674 853 34,527
Repurchases of common shares (2) (2) (2)
Restricted shares 3 28 28 28
Net income 1,580 1,580 32 1,612
Distributions 0 (42) (42)
Contributions 0 3 3
Common stock dividends (1,593) (1,593) (1,593)
Other 0 (1) (1)
Other comprehensive loss (54) (54) (4) (58)
Balance at September 30, 2019 2,265 $ 23 $ 41,727 $ (7,733) $ (384) $ 33,633 $ 841 $ 34,474


	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at December 31, 2019	2,265	$	23	$	41,745	$	(7,693)	$	(333)	$	33,742	$	344	$	34,086




Repurchases of shares	(4)			(50)						(50)				(50)
Restricted shares	3			41						41				41
Net (loss) income						(488)				(488)		45		(443)


Distributions										—		(11)		(11)
Contributions										—		8		8
Dividends						(1,764)				(1,764)				(1,764)



Other comprehensive income								78		78				78
Balance at September 30, 2020	2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945

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

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines, 144 terminals, and ~~147 terminals.~~700 billion cubic feet of working natural gas storage capacity. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO₂ and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our ~~2019~~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.

~~COVID-19~~

The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began to impact us in the first quarter of 2020 has continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic also affected our business in the second quarter and continues to do so. Further, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities.

~~These events, among other factors, resulted in certain non-cash impairments charges during 2020 as further discussed in Note 2.~~

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, ~~as discussed above,~~ we evaluate goodwill for impairment on May 31 of each year. For ~~this purpose,~~our May 31, 2021 evaluation, we ~~have~~grouped our businesses into 6 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 23 for results of our May 31, ~~2020~~2021 goodwill impairment test.

~~The goodwill impairment tests for our reporting units reflected our adoption of the Accounting Standards Updates (ASU) No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” on January 1, 2020.This new accounting method simplifies the goodwill impairment test by removing Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation.~~

Earnings per Share

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

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

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except per share amounts)
Net Income (Loss) Available to Common Stockholders $ 455 $ 506 $ (488) $ 1,580
Participating securities:
Less: Net Income allocated to restricted stock awards(a) (3) (3) (9) (9)
Net Income (Loss) Allocated to Class P Stockholders $ 452 $ 503 $ (497) $ 1,571
Basic Weighted Average Common Shares Outstanding 2,263 2,264 2,263 2,263
Basic Earnings (Loss) Per Common Share $ 0.20 $ 0.22 $ (0.22) $ 0.69

~~________~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders	$	495	$	455	$	1,147	$	(488)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(4)		(3)		(10)		(9)
Net Income (Loss) Allocated to Class P Stockholders	$	491	$	452	$	1,137	$	(497)

Basic Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263
Basic Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)

(a)As of September 30, ~~2020,~~2021, there were approximately 13 million restricted stock awards outstanding.

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


		Three Months Ended September 30,			Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
		2020	2019	2020	2019		2021	2020	2021	2020
		(In millions on a weighted average basis)								(In millions on a weighted average basis)
Unvested restricted stock awards	Unvested restricted stock awards	13	13	13	13	Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	Convertible trust preferred securities	3	3	3	3	Convertible trust preferred securities	3	3	3	3

2. Acquisitions

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


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

Pro Forma Information

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

(1) Kinetrex Energy Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on 3 additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.

(2) Stagecoach Acquisition

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

Goodwill

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

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


	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		Products Pipelines		Products Pipelines Terminals		Terminals		Energy Transition Ventures		Total
	(In millions)


Goodwill as of December 31, 2020	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	—	$	19,851
Acquisitions	118		—		—		—		—		—		64		182


Goodwill as of September 30, 2021	$	14,367	$	2,343	$	928	$	1,378	$	151	$	802	$	64	$	20,033

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	—	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		—		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Loss (gain) on divestitures of long-lived assets and other write-downs	—		11		(1)		11
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21

Terminals
Impairment of long-lived and intangible assets	14		—		14		5

CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Gain on divestitures of long-lived assets, net	(11)		—		(8)		—
Other loss (gain) on divestitures of long-lived assets, net	1		—		(3)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	4	$	11	$	1,513	$	1,987

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

Impairments

Long-lived Assets

During the second quarter 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. The long-lived asset impairment test involved two steps. Step one was an assessment as to whether the asset’s net book value was expected to be recovered from the estimated undiscounted future cash flows. To compute the estimated undiscounted future cash flows we included an unfavorable adjustment for upcoming contract expirations. With this inclusion, our South Texas gathering and processing assets failed step one. In step two, we utilized an income approach to estimate fair value and compared it to the carrying value. We applied an approximate 8.5% discount rate, a Level 3 input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the nine months ended September 30, 2021.

During the first ~~quarter~~half of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering ~~events~~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 CO₂business segment ~~and conducted interim tests of the recoverability of goodwill for our CO~~₂ ~~and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020,~~ which resulted in ~~impairments~~a non-cash impairment of long-lived assets ~~and goodwill~~ within our CO₂business segment ~~during the three months ended March 31, 2020.~~

Additionally, we performed our annual goodwill impairment testing as of May 31, 2020. For our Natural Gas Pipelines Non-Regulated reporting unit, while no goodwill impairment was required as of March 31, 2020, the additional market and economic indicators existing at May 31, 2020, as further described below, resultedshown in the ~~recognition of a goodwill impairment for that reporting unit during the three months ended June 30, 2020.~~

~~We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assets~~above table during the nine months ended September 30, ~~2020 and 2019:~~

Nine Months Ended September 30,
2020 2019
(In millions)
Natural Gas Pipelines
Impairment of goodwill $ 1,000 $ 0
Impairments of inventory 11 0
Gain on divestitures of long-lived assets 0 (10)
Products Pipelines
Impairment of long-lived and intangible assets 21 0
Terminals
Impairment of long-lived and intangible assets 5 0
Gain on divestitures of long-lived assets 0 (3)
CO₂
Impairment of goodwill 600 0
Impairment of long-lived assets 350 0
Kinder Morgan Canada
Loss on divestiture of long-lived assets 0 2
Other gain on divestitures of long-lived assets 0 (2)
Pre-tax loss (gain) on divestitures and impairments, net $ 1,987 $ (13)

~~Long-lived Assets~~

~~As of March 31, 2020, for our CO~~₂ ~~assets, the long lived asset impairment test involved an assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows.~~2020.

•To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer’s estimates of proved and risk adjusted probable reserves. These estimates of proved and probable reserves are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.

•~~To compute estimated future cash flows for our CO~~₂ ~~source and transportation assets, volume forecasts were developed based on projected demand for our CO~~₂ ~~services based upon management’s projections of the availability of CO~~₂ ~~supply and the future demand for CO~~₂ ~~for use in enhanced oil recovery projects. The CO~~₂ ~~pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO~~₂ ~~pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.~~

Certain oil and gas properties failed the first step. For these assets, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represented the estimated weighted average cost of capital of a theoretical market participant. Based on step two of our long lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.

Goodwill

~~Changes in the amounts of our goodwill for the nine months ended September 30, 2020 are summarized by reporting unit as follows:~~

Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated
CO₂
Products Pipelines Products Pipelines Terminals Terminals Total
(In millions)
Goodwill as of December 31, 2019 $ 14,249 $ 3,343 $ 1,528 $ 1,378 $ 151 $ 802 $ 21,451
Impairments 0 (1,000) (600) 0 0 0 (1,600)
Goodwill as of September 30, 2020 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 19,851

•~~Our May 31, 2020 goodwill impairment tests of the Products Pipelines, Products Pipelines Terminals, Natural Gas Pipelines Regulated and CO~~₂~~reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO~~₂ reporting units, determined that each of the three reporting unit’s fair value was in excess of carrying value by less than 10%. For the Products Pipelines and Terminals reporting units, we used the market approach with assumptions similar to those described below for the Natural Gas Pipelines Non-Regulated reporting unit. For our May 31, 2020 goodwill impairment test of the CO₂ ~~reporting unit we used the income approach with assumptions similar to those used for its March 31, 2020 goodwill impairment test.~~

•In regards to our Natural Gas Pipelines Non-Regulated reporting unit, it experienced a sharp decline in customer demand for its services during the second quarter of 2020. This represented a timing lag from the initial economic decline impacts resulting from the severe downturn in the upstream energy industry, including our CO₂business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter.

Our May 31, 2020 goodwill impairment test for the Natural Gas Pipelines Non-Regulated reporting unit utilized a weighted average of a market approach (25%) and income approach (75%) to estimate its fair value. We gave higher weighting to the income approach as we believe it was more representative of the value that would be received from a market participant.

The market approach was based on enterprise value (EV) to estimated 2020 EBITDA multiples for a selected number of peer group midstream companies with comparable operations and economic characteristics. We estimated the median EV to EBITDA multiple to be approximately 10x without consideration of any control premium. The income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6.5 years of projections and application of an exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. We applied an approximate 8% discount rate to the undiscounted cash flow amounts which represents our estimate of the weighted average cost of capital of a theoretical market participant. The discounted cash flows included various assumptions on commodity volumes and prices for each underlying asset within the reporting unit, and as applicable applied to our existing contracts and expected future customer demand for such commodities. The fair value based on a weighting of the market and income approaches resulted in an implied EV to 2020 EBITDA multiple valuation of approximately 11x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium at the reporting unit level.

The results of our May 31, 2021 annual impairment test indicated that for each of our reporting units, the ~~Natural Gas Pipelines Non-Regulated~~ reporting unit ~~goodwill impairment analysis was a partial impairment of goodwill of approximately $1,000 million as of May 31, 2020.~~

•~~For our March 31, 2020 interim~~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 CO₂~~reporting unit, we applied an~~fair value hierarchy. The inputs include valuation estimates using market and income approach ~~to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertainty~~valuation methodologies, which include assumptions primarily involving management’s significant judgments and ~~volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.~~estimates with respect

~~In determining~~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 ~~for~~of our CO₂ ~~reporting unit, we applied a 9.25%~~assets. We use discount ~~rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents~~rates representing our estimate of the ~~weighted average cost of capital of a theoretical~~risk-adjusted discount rates that would be used by market ~~participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO~~₂participants specific to the particular reporting ~~unit of approximately $600 million as of March 31, 2020.~~unit.

~~The fair value estimates used~~During the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 and Natural Gas Pipelines business segments during the nine months ended September 30, 2020 as shown in the ~~long-lived asset and goodwill test were primarily based on Level 3 inputs of the fair value hierarchy.~~

Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.table above.

As conditions warrant, we routinely evaluate our assets for potential triggering events ~~such as those described above~~ 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. Although we did not identify additional triggering events during the third quarter of 2020, in the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.

Sale of an Interest in NGPL Holdings

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the nine months ended September 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

Other Write-downs

During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, driven by the recent impairment by Ruby of its assets, which is included within “Earnings from equity investments” in our accompanying consolidated statement of operations for the nine months ended September 30, 2021. The impairment at Ruby was the result of upcoming contract expirations and additional uncertainty identified in late February 2021 regarding the proposed development of a third party liquefied natural gas exporting facility that could significantly increase the demand for its services.

3.4. Debt

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

September 30, 2020 December 31, 2019
(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023 $ 0 $ 0
Commercial paper notes(a) 0 37
Current portion of senior notes
6.85%, due February 2020(b) 0 700
6.50%, due April 2020(c) 0 535
5.30%, due September 2020(d) 0 600
6.50%, due September 2020(d) 0 349
5.00%, due February 2021 750 0
3.50%, due March 2021 750 0
5.80%, due March 2021 400 0
Trust I preferred securities, 4.75%, due March 2028 111 111
Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e) 0 100
Current portion of other debt 46 45
Total current portion of debt 2,057 2,477
Long-term debt (excluding current portion)
Senior notes 30,578 30,164
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035 369 381
Trust I preferred securities, 4.75%, due March 2028 110 110
Other 224 228
Total long-term debt 31,281 30,883
Total debt(f) $ 33,338 $ 33,360

~~_______~~


	September 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt

$3.5 billion credit facility due August 20, 2026(a)	$	—	$	—
$500 million credit facility due November 16, 2023(a)	—		—
Commercial paper notes	160		—
Current portion of senior notes
5.00%, due February 2021(b)	—		750
3.50%, due March 2021(b)	—		750
5.80%, due March 2021(b)	—		400
5.00%, due October 2021(c)	—		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(d)	869		—
3.95% due September 2022	1,000		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,822		2,558

Long-term debt (excluding current portion)
Senior notes	28,306		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	353		364

Trust I preferred securities, 4.75%, due March 2028	110		110
Other	219		223
Total long-term debt	28,988		30,838
Total debt(e)	$	31,810	$	33,396

(a)~~Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.~~On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.

(b)~~On January 9, 2020, we sold~~We repaid the ~~approximate 25 million shares~~principal amounts on these senior notes during the first quarter of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to partially repay debt that matured in February 2020. The fair value of the Pembina common equity of $925 million as of December 31, 2019 was reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet.2021.

(c)~~In April 2020, we~~These notes were repaid ~~$535 million of maturing senior notes.~~on July 1, 2021.

(d)~~In September 2020, we repaid a combined $949 million~~Consists of ~~maturing~~ senior notes ~~using proceeds from~~denominated in Euros that have been converted to U.S. dollars. The September 30, 2021 balance is reported above at the exchange rate of 1.1580 U.S. dollars per Euro. As of September 30, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our ~~newly issued senior~~debt balance of $54 million related to these notes.

~~(e)In December 2019, we notified~~ The cumulative increase in debt due to the ~~holder~~changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of ~~our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as~~cross-currency swaps reflected in “Other current inassets” and “Other current liabilities” on our accompanying consolidated balance ~~sheet as~~sheets. At the time of ~~December 31, 2019. We redeemed~~issuance, we entered into foreign currency contracts associated with these ~~securities, including accrued dividends, on January 15, 2020.~~senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 6 “Risk Management—Foreign Currency Risk Management”).

~~(f)~~(e)Excludes our “Debt fair value adjustments” which, as of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, increased our total debt balances by ~~$1,379~~$1,014 million and ~~$1,032~~$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 ~~August 5, 2020,~~February 11, 2021, we issued in a registered offering ~~two series of senior notes consisting of~~ $750 million aggregate principal amount of ~~2.00%~~3.60% senior notes due ~~2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million.~~

~~On February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030~~2051 and received net proceeds of ~~$991~~$741 million.

~~The senior~~ These notes ~~issued in August 2020 and February 2020~~ are guaranteed through the cross guarantee agreement discussed above.

Credit Facilities and Restrictive Covenants

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

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

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

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

As of September 30, ~~2020,~~2021, we had 0no borrowings outstanding under our ~~$4.0 billion~~ credit ~~facility, 0~~facilities, $160 million in borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit ~~facility~~facilities as of September 30, ~~2020~~2021 was ~~$3,919~~$3,759 million. As of September 30, ~~2020,~~2021, we were in compliance with all required covenants.

Fair Value of Financial Instruments

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

September 30, 2020 December 31, 2019
Carrying
value Estimated
fair value Carrying
value Estimated
fair value
(In millions)
Total debt $ 34,717 $ 38,253 $ 34,392 $ 38,016


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

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, ~~2020~~2021 and December 31, ~~2019.~~2020.

4.5. Stockholders’ Equity

Class P ~~Common~~ Stock

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. ~~In March 2020, we repurchased approximately 3.6 million of our Class P shares for approximately $50 million at an average price of approximately $13.94 per share.~~ 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.

~~Common Stock~~ Dividends

~~Holders of our common stock participate in common stock dividends declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock.~~ The following table provides information about our per share dividends:

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Per common share cash dividend declared for the period $ 0.2625 $ 0.25 $ 0.7875 $ 0.75
Per common share cash dividend paid in the period 0.2625 0.25 0.775 0.70

On October 21, 2020, our board of directors declared a cash dividend of $0.2625 per common share for the quarterly period ended September 30, 2020, which is payable on November 16, 2020 to common shareholders of record as of the close of business on November 2, 2020.


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

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

Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

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

Net unrealized
gains/(losses)
on cash flow
hedge derivatives Foreign
currency
translation
adjustments Pension and
other
postretirement
liability adjustments Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019 $ (7) $ 0 $ (326) $ (333)
Other comprehensive (loss) gain before reclassifications (16) 1 21 6
Loss reclassified from accumulated other comprehensive loss 72 0 0 72
Net current-period change in accumulated other comprehensive (loss) income 56 1 21 78
Balance as of September 30, 2020 $ 49 $ 1 $ (305) $ (255)


	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2020	$	(13)	$	—	$	(394)	$	(407)
Other comprehensive (loss) gain before reclassifications	(444)		—		28		(416)
Loss reclassified from accumulated other comprehensive loss	181		—		—		181
Net current-period change in accumulated other comprehensive loss	(263)		—		28		(235)
Balance as of September 30, 2021	$	(276)	$	—	$	(366)	$	(642)

Net unrealized
gains/(losses)
on cash flow
hedge derivatives Foreign
currency
translation
adjustments Pension and
other
postretirement
liability adjustments Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2018 $ 164 $ (91) $ (403) $ (330)
Other comprehensive (loss) gain before reclassifications (132) 20 23 (89)
Loss reclassified from accumulated other comprehensive loss 35 0 0 35
Net current-period change in accumulated other comprehensive income (loss) (97) 20 23 (54)
Balance as of September 30, 2019 $ 67 $ (71) $ (380) $ (384)


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

5.6. Risk Management

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

During the three months ended March 31, 2020, we entered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $2,500 million. During the three months ended September 30, 2020, we entered into an additional floating-to-fixed interest rate swap agreement with a notional principal amount of $1,000 million. These agreements were not designated as accounting hedges and effectively fixed our LIBOR exposure for a portion of our fixed to floating rate interest rate swaps through 2021.

Energy Commodity Price Risk Management

As of September 30, ~~2020,~~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

~~(20.2)~~(15.9)

MMBbl

Crude oil basis

~~(2.6)~~(6.4)

MMBbl

Natural gas fixed price

~~(34.8)~~(29.5)

Bcf

Natural gas basis

~~(34.8)~~(27.1)

Bcf

NGL fixed price

~~(1.2)~~(1.0)

MMBbl

Derivatives not designated as hedging contracts

Crude oil fixed price

~~(2.4)~~(1.4)

MMBbl

Crude oil basis

~~(0.9)~~(8.7)

MMBbl

Natural gas fixed price

~~(9.7)~~(8.7)

Bcf

Natural gas basis

~~2.2~~ (22.8)

Bcf

NGL fixed price

~~(1.4)~~(1.9)

MMBbl

As of September 30, ~~2020,~~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 ~~2024.~~2025.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, ~~2020:~~2021:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

Fixed-to-variable interest rate contracts(a)

~~7,625~~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

~~3,500~~6,250

Mark-to-Market

December ~~2021~~2022

~~_______~~

(a)The principal amount of hedged senior notes consisted of ~~$900~~$750 million included in “Current portion of debt” and ~~$6,725~~$6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

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

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, ~~2020:~~2021:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

EUR-to-USD cross currency swap contracts(a)

1,358

Cash flow hedge

March 2027

~~_______~~

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

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

Fair Value of Derivative Contracts
Derivatives Asset Derivatives Liability
September 30,
2020 December 31,
2019 September 30,
2020 December 31,
2019
Location Fair value Fair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 103 $ 31 $ (25) $ (43)
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 59 17 (4) (8)
Subtotal 162 48 (29) (51)
Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 134 45 (3) 0
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 634 313 (8) (1)
Subtotal 768 358 (11) (1)
Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) 0 0 (14) (6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 70 46 0 0
Subtotal 70 46 (14) (6)
Total 1,000 452 (54) (58)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 19 8 (10) (7)
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 6 0 (1) 0
Subtotal 25 8 (11) (7)
Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 0 0 (3) 0
Subtotal 0 0 (3) 0
Total 25 8 (14) (7)
Total derivatives $ 1,025 $ 460 $ (68) $ (65)


Fair Value of Derivative Contracts
		Derivatives Asset				Derivatives Liability
		September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	13	$	42	$	(256)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		33		(96)		(8)
Subtotal		14		75		(352)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	127		119		(4)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	350		575		(14)		(7)
Subtotal		477		694		(18)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	49		—		(6)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		138		—		—
Subtotal		69		138		(6)		(6)
Total		560		907		(376)		(57)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	10		24		(63)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		—		(3)		—
Subtotal		14		24		(66)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		—		—
Subtotal		1		—		(1)		—



Total		15		24		(67)		(21)
Total derivatives		$	575	$	931	$	(443)	$	(78)

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


		Balance sheet asset fair value measurements by level																							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			Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
		(In millions)																											(In millions)
As of September 30, 2020
As of September 30, 2021																As of September 30, 2021
Energy commodity derivative contracts(a)	Energy commodity derivative contracts(a)	$	3	$	184	$	0	$	187	$	(28)	$	0	$	159	Energy commodity derivative contracts(a)	$	15	$	13	$	—	$	28	$	(26)	$	—	$	2
Interest rate contracts	Interest rate contracts	0		768		0		768		(2)		0		766		Interest rate contracts	—		478		—		478		(9)		—		469
Foreign currency contracts	Foreign currency contracts	0		70		0		70		(14)		0		56		Foreign currency contracts	—		69		—		69		(6)		—		63
As of December 31, 2019
As of December 31, 2020																As of December 31, 2020
Energy commodity derivative contracts(a)	Energy commodity derivative contracts(a)	$	19	$	37	$	0	$	56	$	(19)	$	(21)	$	16	Energy commodity derivative contracts(a)	$	6	$	93	$	—	$	99	$	(35)	$	—	$	64
Interest rate contracts	Interest rate contracts	0		358		0		358		0		0		358		Interest rate contracts	—		694		—		694		(2)		—		692
Foreign currency contracts	Foreign currency contracts	0		46		0		46		(6)		0		40		Foreign currency contracts	—		138		—		138		(6)		—		132

Balance sheet liability
fair value measurements by level
Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(b) Net amount
(In millions)
As of September 30, 2020
Energy commodity derivative contracts(a) $ (29) $ (11) $ 0 $ (40) $ 28 $ 8 $ (4)
Interest rate contracts 0 (14) 0 (14) 2 0 (12)
Foreign currency contracts 0 (14) 0 (14) 14 0 0
As of December 31, 2019
Energy commodity derivative contracts(a) $ (3) $ (55) $ 0 $ (58) $ 19 $ 0 $ (39)
Interest rate contracts 0 (1) 0 (1) 0 0 (1)
Foreign currency contracts 0 (6) 0 (6) 6 0 0

~~_______~~


	Balance sheet liability fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral posted(b)		Net amount
	(In millions)
As of September 30, 2021
Energy commodity derivative contracts(a)	$	(111)	$	(307)	$	—	$	(418)	$	26	$	135	$	(257)
Interest rate contracts	—		(19)		—		(19)		9		—		(10)
Foreign currency contracts	—		(6)		—		(6)		6		—		—
As of December 31, 2020
Energy commodity derivative contracts(a)	$	(7)	$	(56)	$	—	$	(63)	$	35	$	(8)	$	(36)
Interest rate contracts	—		(10)		—		(10)		2		—		(8)
Foreign currency contracts	—		(6)		—		(6)		6		—		—

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

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

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

Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income
on derivative and related hedged item
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Interest rate contracts Interest, net $ (50) $ 117 $ 409 $ 453
Hedged fixed rate debt(a) Interest, net $ 50 $ (119) $ (418) $ (468)

~~_______~~


Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item
		Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	(39)	$	(50)	$	(228)	$	409

Hedged fixed rate debt(a)	Interest, net	$	39	$	50	$	229	$	(418)

(a)As of September 30, ~~2020,~~2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of ~~$777~~$473 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


Derivatives in cash flow hedging relationships	Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)					Location		Gain/(loss) reclassified from Accumulated OCI into income(b)						Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)			Location		Gain/(loss) reclassified from Accumulated OCI into income(b)
		Three Months Ended September 30,							Three Months Ended September 30,							Three Months Ended September 30,					Three Months Ended September 30,
		2020		2019			2020		2019			2021		2020			2021		2020
		(In millions)							(In millions)							(In millions)					(In millions)
Energy commodity derivative contracts	Energy commodity derivative contracts	$	(143)	$	96	Revenues—Commodity sales	$	(47)	$	9	Energy commodity derivative contracts	$	(140)	$	(143)	Revenues—Commodity sales	$	(94)	$	(47)

																Costs of sales	8		(7)
						Costs of sales	(7)		(3)
Interest rate contracts	Interest rate contracts	0		(1)		Earnings from equity investments(c)	(1)		0		Interest rate contracts	1		—		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	Foreign currency contracts	70		(69)		Other, net	61		(59)		Foreign currency contracts	(33)		70		Other, net	(34)		61
Total	Total	$	(73)	$	26	Total	$	6	$	(53)	Total	$	(172)	$	(73)	Total	$	(120)	$	6

Derivatives in cash flow hedging relationships Gain/(loss)
recognized in OCI on derivative(a) Location Gain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions) (In millions)
Energy commodity derivative contracts $ (29) $ (74) Revenues—Commodity sales $ (145) $ 15
Costs of sales (12) 8
Interest rate contracts (9) (2) Earnings from equity investments(c) (1) 2
Foreign currency contracts 17 (95) Other, net 64 (71)
Total $ (21) $ (171) Total $ (94) $ (46)

~~_______~~


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(514)	$	(29)	Revenues—Commodity sales	$	(167)	$	(145)

					Costs of sales	10		(12)
Interest rate contracts	3		(9)		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(68)		17		Other, net	(79)		64
Total	$	(579)	$	(21)	Total	$	(236)	$	(94)

(a)We expect to reclassify ~~an approximate $68~~approximately $181 million ~~gain~~of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, ~~2020~~2021 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

(b)During the nine months ended September 30, ~~2019,~~2021, we recognized ~~a $12~~gains of $6 million ~~gain~~ 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 in net investment hedging relationships Gain/(loss)
recognized in OCI on derivative
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Foreign currency contracts $ 0 $ 0 $ 0 $ (8)
Total $ 0 $ 0 $ 0 $ (8)

Derivatives not designated as hedging instruments Location Gain/(loss) recognized in income on derivatives
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Energy commodity derivative contracts Revenues—Commodity sales $ 87 $ 12 $ 353 $ 36
Costs of sales 12 0 18 (3)
Earnings from equity investments(b) 0 0 0 2
Total(a) $ 99 $ 12 $ 371 $ 35

~~_______~~


Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(40)	$	87	$	(703)	$	353
	Costs of sales	(7)		12		154		18
	Earnings from equity investments	(2)		—		(4)		—
Total(a)		$	(49)	$	99	$	(553)	$	371

(a)The three and nine months ended September 30, ~~2020~~2021 amounts include approximate ~~gains~~losses of ~~$96~~$24 million and ~~$349~~$480 million, respectively, and the three and nine months ended September 30, ~~2019~~2020 amounts include an approximate ~~loss~~gains of $4$96 million and $2$349 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

~~(b)~~

~~Amounts represent our share of an equity investee’s income (loss).~~

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, we had 0no outstanding letters of credit supporting our commodity price risk management program. As of September 30, ~~2020,~~2021, we had cash margins of ~~$32~~$165 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance ~~sheets.~~sheet. As of December 31, ~~2019,~~2020, we had cash margins of ~~$15~~$3 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance ~~sheets.~~sheet. The balance at September 30, ~~2020~~2021 represents the net of our initial margin requirements of ~~$24~~$30 million and counterparty variation margin requirements of $8$135 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of September 30, ~~2020,~~2021, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one ~~or two notches~~notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $177 million of additional collateral.

6.7. Revenue Recognition

Disaggregation of Revenues

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


		Three Months Ended September 30, 2020																							Three Months Ended September 30, 2021
		Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations		Total			Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
		(In millions)																							(In millions)
Revenues from contracts with customers(a)	Revenues from contracts with customers(a)													Revenues from contracts with customers(a)
Services	Services													Services
Firm services(b)	Firm services(b)	$	818	$	69	$	185	$	1	$	(2)	$	1,071	Firm services(b)	$	836	$	66	$	181	$	1	$	(2)	$	1,082
Fee-based services	Fee-based services	173		228		91		8		3		503		Fee-based services	190		244		93		10		—		537
Total services	Total services	991		297		276		9		1		1,574		Total services	1,026		310		274		11		(2)		1,619
Commodity sales	Commodity sales													Commodity sales
Natural gas sales	Natural gas sales	507		0		0		1		(2)		506		Natural gas sales	1,097		—		—		7		(3)		1,101
Product sales	Product sales	158		97		5		180		(5)		435		Product sales	372		247		8		279		(11)		895

Total commodity sales	Total commodity sales	665		97		5		181		(7)		941		Total commodity sales	1,469		247		8		286		(14)		1,996
Total revenues from contracts with customers	Total revenues from contracts with customers	1,656		394		281		190		(6)		2,515		Total revenues from contracts with customers	2,495		557		282		297		(16)		3,615
Other revenues(c)	Other revenues(c)													Other revenues(c)
Leasing services(d)	Leasing services(d)	119		42		143		13		0		317		Leasing services(d)	119		42		140		15		—		316
Derivatives adjustments on commodity sales	Derivatives adjustments on commodity sales	(6)		0		0		46		0		40		Derivatives adjustments on commodity sales	(71)		—		—		(63)		—		(134)
Other	Other	40		6		0		2		(1)		47		Other	12		6		—		8		1		27
Total Other revenues		153		48		143		61		(1)		404
Total other revenues														Total other revenues	60		48		140		(40)		1		209
Total revenues	Total revenues	$	1,809	$	442	$	424	$	251	$	(7)	$	2,919	Total revenues	$	2,555	$	605	$	422	$	257	$	(15)	$	3,824


	Three Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	818	$	69	$	185	$	1	$	(2)	$	1,071
Fee-based services	173		228		91		8		3		503
Total services	991		297		276		9		1		1,574
Commodity sales
Natural gas sales	507		—		—		1		(2)		506
Product sales	158		97		5		180		(5)		435

Total commodity sales	665		97		5		181		(7)		941
Total revenues from contracts with customers	1,656		394		281		190		(6)		2,515
Other revenues(c)
Leasing services(d)	119		42		143		13		—		317
Derivatives adjustments on commodity sales	(6)		—		—		46		—		40
Other	40		6		—		2		(1)		47
Total other revenues	153		48		143		61		(1)		404
Total revenues	$	1,809	$	442	$	424	$	251	$	(7)	$	2,919


	Nine Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,501	$	191	$	570	$	1	$	(2)	$	3,261
Fee-based services	544		709		258		35		—		1,546
Total services	3,045		900		828		36		(2)		4,807
Commodity sales
Natural gas sales	5,090		—		—		9		(11)		5,088
Product sales	840		529		20		766		(34)		2,121

Total commodity sales	5,930		529		20		775		(45)		7,209
Total revenues from contracts with customers	8,975		1,429		848		811		(47)		12,016
Other revenues(c)
Leasing services(d)	356		128		427		42		—		953
Derivatives adjustments on commodity sales	(726)		(1)		—		(143)		—		(870)
Other	51		16		—		19		—		86
Total other revenues	(319)		143		427		(82)		—		169
Total revenues	$	8,656	$	1,572	$	1,275	$	729	$	(47)	$	12,185


		Three Months Ended September 30, 2019																							Nine Months Ended September 30, 2020
		Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations		Total			Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
		(In millions)																							(In millions)
Revenues from contracts with customers(a)	Revenues from contracts with customers(a)													Revenues from contracts with customers(a)
Services	Services													Services
Firm services(b)	Firm services(b)	$	882	$	89	$	256	$	1	$	(1)	$	1,227	Firm services(b)	$	2,479	$	215	$	563	$	1	$	(2)	$	3,256
Fee-based services	Fee-based services	182		265		132		14		0		593		Fee-based services	523		670		307		31		1		1,532
Total services	Total services	1,064		354		388		15		(1)		1,820		Total services	3,002		885��		870		32		(1)		4,788
Commodity sales	Commodity sales													Commodity sales
Natural gas sales	Natural gas sales	618		0		0		0		(1)		617		Natural gas sales	1,385		—		—		1		(5)		1,381
Product sales	Product sales	162		84		9		268		(7)		516		Product sales	396		255		11		546		(22)		1,186

Total commodity sales	Total commodity sales	780		84		9		268		(8)		1,133		Total commodity sales	1,781		255		11		547		(27)		2,567
Total revenues from contracts with customers	Total revenues from contracts with customers	1,844		438		397		283		(9)		2,953		Total revenues from contracts with customers	4,783		1,140		881		579		(28)		7,355
Other revenues(c)	Other revenues(c)													Other revenues(c)
Leasing services(d)	Leasing services(d)	57		45		111		13		0		226		Leasing services(d)	346		126		404		34		—		910
Derivatives adjustments on commodity sales	Derivatives adjustments on commodity sales	23		0		0		(1)		(1)		21		Derivatives adjustments on commodity sales	35		—		—		173		—		208
Other	Other	10		1		0		3		0		14		Other	91		16		—		6		(1)		112
Total Other revenues		90		46		111		15		(1)		261
Total other revenues														Total other revenues	472		142		404		213		(1)		1,230
Total revenues	Total revenues	$	1,934	$	484	$	508	$	298	$	(10)	$	3,214	Total revenues	$	5,255	$	1,282	$	1,285	$	792	$	(29)	$	8,585

Nine Months Ended September 30, 2020
Natural Gas Pipelines Products Pipelines Terminals
CO₂
Corporate and Eliminations Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b) $ 2,479 $ 215 $ 563 $ 1 $ (2) $ 3,256
Fee-based services 523 670 307 31 1 1,532
Total services 3,002 885 870 32 (1) 4,788
Commodity sales
Natural gas sales 1,385 0 0 1 (5) 1,381
Product sales 396 255 11 546 (22) 1,186
Total commodity sales 1,781 255 11 547 (27) 2,567
Total revenues from contracts with customers 4,783 1,140 881 579 (28) 7,355
Other revenues(c)
Leasing services 346 126 404 34 0 910
Derivatives adjustments on commodity sales 35 0 0 173 0 208
Other 91 16 0 6 (1) 112
Total Other revenues 472 142 404 213 (1) 1,230
Total revenues $ 5,255 $ 1,282 $ 1,285 $ 792 $ (29) $ 8,585

Nine Months Ended September 30, 2019
Natural Gas Pipelines Products Pipelines Terminals
CO₂
Corporate and Eliminations Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b) $ 2,701 $ 253 $ 785 $ 1 $ (3) $ 3,737
Fee-based services 561 752 398 45 0 1,756
Total services 3,262 1,005 1,183 46 (3) 5,493
Commodity sales
Natural gas sales 1,979 0 0 1 (7) 1,973
Product sales 599 211 16 827 (23) 1,630
Total commodity sales 2,578 211 16 828 (30) 3,603
Total revenues from contracts with customers 5,840 1,216 1,199 874 (33) 9,096
Other revenues(c)
Leasing services 167 129 325 39 0 660
Derivatives adjustments on commodity sales 61 0 0 (10) 0 51
Other 35 5 0 10 0 50
Total Other revenues 263 134 325 39 0 761
Total revenues $ 6,103 $ 1,350 $ 1,524 $ 913 $ (33) $ 9,857

~~_______~~

(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)~~For the three and nine months ended September 30, 2020 and 2019, amounts~~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 56 for additional information related to our derivative contracts.

(d)

~~Contract Balances~~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 ~~assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections.~~Balances

As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, our contract asset balances were ~~$44~~$62 million and ~~$27~~$20 million, respectively. Of the contract asset balance at December 31, ~~2019, $21~~2020, $14 million was transferred to accounts receivable during the nine months ended September 30, ~~2020.~~2021. As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, our contract liability balances were ~~$237~~$217 million and ~~$232~~$239 million, respectively. Of the contract liability balance at December 31, ~~2019, $57~~2020, $63 million was recognized as revenue during the nine months ended September 30, ~~2020.~~2021.

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Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, ~~2020~~2021 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Year	Estimated Revenue		Year	Estimated Revenue
		(In millions)			(In millions)
Three months ended December 31, 2020		$	1,152
2021		4,102
Three months ended December 31, 2021				Three months ended December 31, 2021	$	1,178
2022	2022	3,344		2022	4,022
2023	2023	2,715		2023	3,186
2024	2024	2,361		2024	2,711
2025				2025	2,277
Thereafter	Thereafter	14,722		Thereafter	14,018
Total	Total	$	28,396	Total	$	27,392

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

7.8. Reportable Segments

Financial information by segment follows:


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019			2021		2020		2021		2020
		(In millions)															(In millions)
Revenues	Revenues									Revenues
Natural Gas Pipelines	Natural Gas Pipelines									Natural Gas Pipelines
Revenues from external customers	Revenues from external customers	$	1,803	$	1,925	$	5,229	$	6,073	Revenues from external customers	$	2,541	$	1,803	$	8,611	$	5,229
Intersegment revenues	Intersegment revenues	6		9		26		30		Intersegment revenues	14		6		45		26

Products Pipelines	Products Pipelines	442		484		1,282		1,350		Products Pipelines	605		442		1,572		1,282

Terminals	Terminals									Terminals
Revenues from external customers	Revenues from external customers	423		507		1,282		1,521		Revenues from external customers	421		423		1,273		1,282
Intersegment revenues	Intersegment revenues	1		1		3		3		Intersegment revenues	1		1		2		3
CO₂	CO₂	251		298		792		913		CO2	257		251		729		792

Corporate and intersegment eliminations	Corporate and intersegment eliminations	(7)		(10)		(29)		(33)		Corporate and intersegment eliminations	(15)		(7)		(47)		(29)
Total consolidated revenues	Total consolidated revenues	$	2,919	$	3,214	$	8,585	$	9,857	Total consolidated revenues	$	3,824	$	2,919	$	12,185	$	8,585

2726


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019			2021		2020		2021		2020
		(In millions)															(In millions)
Segment EBDA(a)	Segment EBDA(a)									Segment EBDA(a)
Natural Gas Pipelines	Natural Gas Pipelines	$	1,091	$	1,092	$	2,284	$	3,383	Natural Gas Pipelines	$	1,069	$	1,091	$	2,602	$	2,284
Products Pipelines	Products Pipelines	223		325		719		908		Products Pipelines	279		223		792		719
Terminals	Terminals	246		295		732		884		Terminals	216		246		689		732
CO₂	CO₂	156		164		(453)		558		CO2	163		156		599		(453)
Kinder Morgan Canada		0		0		0		(2)

Total Segment EBDA	Total Segment EBDA	1,716		1,876		3,282		5,731		Total Segment EBDA	1,727		1,716		4,682		3,282
DD&A	DD&A	(539)		(578)		(1,636)		(1,750)		DD&A	(526)		(539)		(1,595)		(1,636)
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(32)		(21)		(99)		(61)		Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)

General and administrative and corporate charges	General and administrative and corporate charges	(150)		(162)		(472)		(478)		General and administrative and corporate charges	(167)		(150)		(465)		(472)
Interest, net	Interest, net	(383)		(447)		(1,214)		(1,359)		Interest, net	(368)		(383)		(1,122)		(1,214)

Income tax expense	Income tax expense	(140)		(151)		(304)		(471)		Income tax expense	(134)		(140)		(248)		(304)

Total consolidated net income (loss)	Total consolidated net income (loss)	$	472	$	517	$	(443)	$	1,612	Total consolidated net income (loss)	$	511	$	472	$	1,196	$	(443)

September 30, 2020 December 31, 2019
(In millions)
Assets
Natural Gas Pipelines $ 48,522 $ 50,310
Products Pipelines 9,216 9,468
Terminals 8,808 8,890
CO₂
2,589 3,523
Corporate assets(b) 2,686 1,966
Total consolidated assets $ 71,821 $ 74,157

~~_______~~


	September 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	47,576	$	48,597
Products Pipelines	9,118		9,182
Terminals	8,507		8,639
CO2	2,808		2,478



Corporate assets(b)	1,631		3,077

Total consolidated assets	$	69,640	$	71,973

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

8.9. Income Taxes

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


		Three Months Ended September 30,									Nine Months Ended September 30,										Three Months Ended September 30,						Nine Months Ended September 30,
		2020			2019			2020			2019				2021			2020			2021			2020
		(In millions, except percentages)																						(In millions, except percentages)
Income tax expense	Income tax expense	$	140		$	151		$	304		$	471		Income tax expense	$	134		$	140		$	248		$	304
Effective tax rate	Effective tax rate	22.9		%	22.6		%	(218.7)		%	22.6		%	Effective tax rate	20.8		%	22.9		%	17.2		%	(218.7)		%

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

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

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

The effective tax rate for the nine months ended September 30, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to the $1,600 million CO₂ ~~and Natural Gas Pipelines Non-Regulated reporting units’~~ impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit.This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus and PPL.

While we would normally expect a federal income tax benefit from our loss before income taxes for the nine months ended September 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for ~~the period, partially offset by the refund of alternative minimum tax~~

~~sequestration credits and dividend-received deductions from our investments in Citrus Corporation (Citrus) and Plantation Pipe Line Company (Plantation).~~

The effective tax rate for the three and nine months ended September 30, 2019 is higher than the statutory federal rate of 21% primarily due to state and foreign taxes, partially offset by dividend-received deductions from our investments in Citrus, NGPL Holdings LLC and Plantation.these periods.

9.10. Litigation and Environmental

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

SFPP FERC ~~Inquiry Regarding the Commission’s Policy for Determining Return on Equity~~Proceedings

~~On March 21, 2019,~~The FERC approved the ~~FERC issued a notice of inquiry (NOI) seeking comments regarding whether~~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 ~~FERC should revise its policies for determining~~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 ~~base return~~EL Settlement were fully accrued on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI sought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC. On May 21, 2020, the FERC issued its Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines (Policy Statement). As it applies to natural gas and oil pipelines, the Policy Statement requires averaging the results of the discounted cash flow model and capital asset pricing model, giving equal weight to each model, retains its existing two-thirds/one-third weighting of short and long-term growth projections in the discounted cash flow model, and excludes the risk premium or expected earnings models. On other matters raised in this proceeding, the FERC declined to adopt rigid policy changes, and will address issues, such as the appropriate sources for data sets and the specific companies to use for a given proxy group, as those issues arise in future rate proceedings on a pipeline-by-pipeline, case-by-case basis. The Policy Statement does not result in any immediate changes to any existing rates or ROEs for any of our pipelines, and any future changes to rates or ROEs for a pipeline will depend on a variety of factors that remain to be determined when they are raised and argued in connection with future or existing rate proceedings, including the ~~OR16-6~~ ~~proceeding referenced in “SFPP FERC Proceedings”~~ ~~below.~~

~~SFPP FERC Proceedings~~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. These include IS08-390, filed in June 2008, in which various shippers are challenging SFPP’s West Line rates (pending before the D.C. Circuit Court on rehearing following an order that upheld the FERC’s underlying decision); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (pending before the FERC on rehearing); OR11-13/16/18, filed in June 2011, in which various shippers are seeking to challenge SFPP’s North Line, Oregon Line, and West Line rates (pending before the FERC for an order on the complaint); OR14-35/36, filed in June 2014, in which various shippers are challenging SFPP’s index increases in 2012 and 2013 (dismissed by the FERC, but remanded back to the FERC from the D.C. Circuit for further consideration); OR16-6, filed in December 2015, in which various shippers are challenging SFPP’s East line rates (the FERC issued Order 571 which largely confirmed the initial decision, but granted SFPP’s motion to reopen the record and allowed the parties to file written submissions addressing the FERC’s Policy Statement on ROE for purposes of establishing SFPP’s ROE in this matter); and OR19-21/33/37, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 (pending before the FERC for an order on the complaints). 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~~two-year period preceding the filing date of their complaints ~~(OR cases)~~ and/or prospective refunds in protest cases from the

date of protest, ~~(IS cases),~~ 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.

SFPP paid refunds to shippers in May 2019, in the IS08-390 proceeding as ordered by the FERC based on its denial of an income tax allowance. With respect to the various SFPP related complaints and protest proceedings at the FERC (including IS08-390), we estimate that the shippers are seeking approximately $50 million in annual rate reductions and approximately $425 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. ~~However, to~~We do not believe the ~~extent the shippers are successful in one or more~~ultimate resolution of the shipper complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, as well as the compliance filing methodology recently approved by the FERC to pending SFPP cases would result inand protests seeking rate reductions ~~and~~or refunds ~~substantially lower than those sought by the shippers.~~

~~EPNG FERC Proceedings~~

The tariffs and rates charged by EPNG are subject to 2 ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it would apply its findings in Opinion 517-A to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A)ongoing proceedings will have a material adverse impact on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC the refund calculations, and that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. EPNG’s appeals in the 2008 and 2010 rate cases as well as the intervenors’ appeal in the 2010 rate case were consolidated. The U.S. Court of Appeals for the D.C. Circuit denied all petitions for review on July 24, 2020.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 ~~panel~~tribunal delivered ~~its~~an Award ~~and the panel's ruling~~that called for the termination of the agreement and Eni ~~USA's~~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 ~~September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. 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~~Eni USA’s second ~~Notice of Arbitration, Eni USA seeks~~arbitration sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response, ~~to the second Notice of Arbitration,~~ GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the second arbitration. On ~~January 10, 2020, the Court of Chancery entered~~cross-appeals from an Order and Final Judgment ~~granting GLNG’s motion to enjoin arbitration~~ of the ~~negligent misrepresentation claim, but denying~~Court of Chancery, the ~~motion to enjoin~~Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from pursuing the second arbitration, ofincluding the breach of contract ~~claims. The parties filed cross appeals of~~and negligent misrepresentation claims therein. On October 4, 2021, the ~~Final Judgment. The Delaware cross appeals were argued to the Delaware~~U.S. Supreme Court ~~on September 9, 2020. The~~denied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration ~~proceeding remains pending, but has been stayed by agreement pending~~and the ~~Delaware Supreme Court’s decision.~~

claims asserted therein.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A., filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also ~~seeks~~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 ~~have given~~gave rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also ~~seeks~~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. ~~A final decision in this~~On July 15, 2021, the arbitration ~~is expected by~~tribunal delivered a Final Award on the ~~end~~merits of all claims submitted to the ~~second quarter of 2021.~~

~~GLNG intends to continue to vigorously prosecute~~tribunal and ~~defend~~denied all of ~~the foregoing proceedings.~~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~~$276 million. Hiland Partners denies and will vigorously defend against these claims.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed suit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $98 million, plus attorney fees and interest. We believe that our declaration of force majeure is valid and appropriate and intend to vigorously defend against Freeport’s claims.

Pipeline Integrity and Releases

From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with

these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

General

As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, our total reserve for legal matters was ~~$280~~$192 million and ~~$203~~$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 ~~federal,~~local, state and ~~local~~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, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act.~~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 ~~state~~ remediation programs. We have established a reserve to address the costs associated with the ~~remediation.~~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 ~~approximately $1.1~~more than $3 billion and active cleanup is expected to take ~~as long as 13~~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 2 ~~facilities acquired from GATX Terminals Corporation)~~facilities) and KMBT (in connection with its ownership or operation of 2 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,~~(collectively EPEC) are ~~involved~~identified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic ~~River. It has been alleged that~~River in New Jersey. 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~~EPEC is 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~~a Record of Decision (ROD) for the lower 8 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 8 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, are~~ engaged in an allocation process for the implementation of the remedy for the lower 8 miles of the Site. ~~We anticipate that~~That process ~~will be~~was completed by December ~~31, 2020.~~28, 2020 and certain PRPs, including EPEC, are engaged in discussions with the EPA as a result thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper 9 miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There ~~is also~~remains significant uncertainty as to the ~~impact~~implementation and associated costs 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~~set forth in the upper nine ~~miles of the Site.~~mile ROD. Until the ~~allocation process and FS are completed, and~~ongoing discussions with the ~~RI/FS is finalized,~~EPA conclude, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the Site, will have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, 1 of which is against TGP and 1 of which is against SNG, both described further below.

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the U.S. District Court ordered the case ~~was~~to be 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.~~The defendants appealed that decision. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for ~~rehearing which~~rehearing. On August 5, 2021, the Fifth Circuit remanded the case to the U.S. District Court to

determine whether there is ~~pending.~~federal officer jurisdiction. The case remains effectively stayed pending a ~~final~~ ruling by the U.S. District Court ~~of Appeals.~~on the federal officer issue. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

Louisiana Landowner Coastal Erosion Litigation

Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including 24 cases against TGP, 23 cases against SNG, and ~~2 cases~~1 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~~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~~Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. One of these cases filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana. On May 4, 2018, the U.S. District Court entered a judgment ruling in favor of the plaintiffs on certain of their contract claims. The Court stayed the judgment pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. In October 2018, the Court of Appeals dismissed the appeals for lack of subject matter jurisdiction. In April 2019, the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. On October 2, 2020, the case was settled for an amount which is not material to our business. We will continue to vigorously defend the remaining cases.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, we have accrued a total reserve for environmental liabilities in the amount of ~~$253~~$242 million and ~~$259~~$250 million, respectively. In addition, as of both September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, we ~~have recorded~~had a receivable of $12 million ~~and $15 million, respectively,~~recorded for expected cost recoveries that have been deemed probable.

~~10.~~11. Recent Accounting Pronouncements

~~ASU No. 2018-14~~

~~On August 28, 2018, the FASB issued ASU No. 2018-14, “Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans~~.” This ASU amends existing annual disclosure requirements applicable to all employers that sponsor defined benefit pension and other postretirement plans by adding, removing, and clarifying certain disclosures. ASU No. 2018-14 will be effective for us for the fiscal year ending December 31, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

~~ASU No. 2020-04~~Reference Rate Reform (Topic 848)

On March 12, 2020, the FASB issued ~~ASU~~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 ~~this~~ 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 ~~this ASU~~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,~~features; (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted ~~method~~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 ~~ending December 31,~~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 ~~and~~in our 2020 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our ~~2019~~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.

~~Sale~~Long-lived Asset Impairment

During the second quarter 2021 we recognized a non-cash, long-lived asset impairment of ~~U.S. Portion~~$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 ~~Cochin Pipeline and KML~~contracts expiring through 2024.

Stagecoach Acquisition

On ~~December 16, 2019,~~July 9, 2021, we ~~closed on two cross-conditional transactions resulting~~completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,228 million, including a preliminary purchase price adjustment for working capital. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the ~~sale~~northeast region of the U.S. ~~portion of the Cochin Pipeline and all the outstanding equity of KML,~~, including ~~our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”). We received approximately 25 million shares of Pembina common equity for our interest~~TGP. The acquired assets are included in ~~KML. On January 9, 2020, we sold our Pembina shares and received proceeds of approximately $907 million ($764 million after tax) which were used to repay maturing debt. The assets sold were part of~~ our Natural Gas Pipelines ~~and Terminals~~ business ~~segments.~~segment.

~~COVID-19~~

The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began to impact us in the first quarter of 2020 continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic also affected our business in the second quarter and continues to do so. Further, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities.Kinetrex Energy Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The ~~events~~acquired assets are included as described above resulted in decreases of current and estimated long-term crude oil and NGL sale prices and volumes we expect to realize and in significant reductions to the market capitalization of many midstream and oil and gas producing companies. These events triggered us to review the carrying valuepart of our long-lived assets and recoverability of goodwill as of March 31, 2020 and impacted our annual goodwill testing performed as of May 31, 2020. Our evaluations resulted in the recognition during the first six months of 2020 of a $350 million impairment for long-lived assets innew Energy Transition Ventures group within our CO₂ business ~~segment and goodwill impairments of $1,000 million and $600 million to our Natural Gas Pipelines Non-Regulated and CO~~₂ ~~reporting units, respectively. For a further discussion of these impairments and our risk for future impairments, see Note 2, “Impairments.~~”segment.

~~We have placed~~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 priority on protecting our employees during this pandemic while continuing to provide essential services to our customers. We continue to follow the Centers for Disease Control guidelines for those employees that perform essential taskscombined 25% interest in our ~~operations and have taken~~joint venture, NGPL Holdings LLC (NGPL Holdings), to a ~~cautious enterprise-wide approach with a phased return to workplace process~~fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our ~~employees who are currently working remotely. During~~proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the nine months ended September 30, 2020, our incremental employee safety costs associated with COVID-19 mitigation have been approximately $11 million, primarily for personal protective equipment, enhanced cleaning protocols, temperature screening2021. We and ~~other measures we adopted to protect our employees. We continue to operate our assets safely and efficiently during this challenging period.~~Brookfield now each hold a 37.5% interest in NGPL Holdings.

~~2020 Outlook~~February 2021 Winter Storm

~~As previously announced, for 2020~~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 ~~original budget contemplated DCF of approximately $5.1 billion ($2.24 per common share)~~future earnings, cash flows and Adjusted EBITDA of approximately $7.6 billion. We now expect DCF to be below plan by slightly more than 10% and Adjusted EBITDA to be below plan by slightly more than 8%. As a result, we now expect to end 2020 with a Net Debt-to-Adjusted EBITDA ratio of approximately 4.6 times.financial condition.

~~Market conditions also negatively impacted~~2021 Dividends and Discretionary Capital

We expect to declare dividends of $1.08 per share for 2021, a ~~number~~3% increase from the 2020 declared dividends of ~~planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. We therefore~~$1.05 per share. Excluding the recent acquisitions, we expect ~~the budgeted $2.4~~to invest $0.8 billion in expansion projects and contributions to joint ventures for 2020 to be lower by approximately $680 million. With this reduction, DCF less expansion capital expenditures is improved by approximately $135 million compared to budget, helping to keep our balance sheet strong. In addition, to help preserve flexibility and maintain balance sheet strength, our board of directors has maintained the dividend level and declared a dividend of $0.2625 per share, or $1.05 per share annualized, for the third quarter of 2020. This represents a 5% increase over the dividend declared for the third quarter of 2019 rather than the previously budgeted dividend of $0.3125,during 2021.

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~~which would have been a 25% increase. We expect that our 2020 dividend payments as well as our 2020 discretionary spending will be fully funded with internally generated cash flow.~~

We do not provide budgeted net income attributable to Kinder Morgan, Inc. or budgeted net income, the GAAP financial measures most directly comparable to the non-GAAP financial measures of DCF and Adjusted EBITDA, respectively, due to the impracticality of quantifying certain components required by GAAP such as: unrealized gains and losses on derivatives marked-to-market and potential changes in estimates for certain contingent liabilities. See “~~—Results of Operations—Overview—Non-GAAP Financial Measures~~”~~below.~~

~~Considerable uncertainty exists with respect to the future pace and extent of a global economic recovery from the effects of the COVID-19 pandemic. Our updated~~The expectations for ~~2020~~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 ~~statements. Please read Part II, Item 1A. “Risk Factors~~”~~below and “Information Regarding Forward-Looking Statements~~”at the beginning of this report for more information. Furthermore, 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.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 7,8, “Reportable Segments”)~~, net income (loss)~~ and ~~net~~Net income (loss) attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA ~~Net Debt~~ and Net ~~Debt to Adjusted EBITDA.~~Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the three and nine months ended September 30, ~~2020~~2021 and ~~2019~~2020 present Segment EBDA ~~net income (loss)~~ and ~~net~~Net income (loss) attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures

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

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in ~~net~~Net income (loss) attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below). In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

Adjusted Earnings

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

DCF

DCF is calculated by adjusting ~~net~~Net income (loss) attributable to Kinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as ~~common stock~~ 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~~Net income (loss) attributable to Kinder Morgan, Inc. DCF per ~~common~~ share is DCF divided by average outstanding ~~common~~ shares, including restricted stock awards that participate in ~~common share~~ dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” and “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate ~~segment~~ 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~~Net income (loss). attributable to Kinder Morgan, Inc. In prior periods Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries. (See “—Non-GAAP Financial Measures—Supplemental Information” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures. ~~DCF and Adjusted EBITDA are further adjusted for certain KML activities attributable to our noncontrolling interests in KML for the periods presented through KML’s sale on December 16, 2019 (See~~ ~~“—Non-GAAP Financial Measures—Supplemental Information, KML Activities Prior to December 16, 2019”~~ ~~below.)~~

Net Debt

Net Debt is calculated, based on amounts as of September 30, 2021, by subtracting the following amounts from our debt balance of $32,824 million: (i) cash and cash ~~equivalents;~~equivalents of $102 million; (ii) ~~the preferred interest in the general partner of KMP (which was redeemed in January 2020); (iii)~~ debt fair value ~~adjustments;~~adjustments of $1,014 million; and ~~(iv)~~(iii) the foreign exchange impact on Euro-denominated bonds of $90 million for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents. ~~Our Net Debt-to-Adjusted EBITDA ratio was 4.6 as of September 30, 2020.~~

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Consolidated Earnings Results (GAAP)

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


		Three Months Ended September 30,													Three Months Ended September 30,
		2020		2019		Earnings increase/(decrease)							2021		2020		Earnings increase/(decrease)
		(In millions, except percentages)															(In millions, except percentages)
Segment EBDA(a)	Segment EBDA(a)									Segment EBDA(a)
Natural Gas Pipelines	Natural Gas Pipelines	$	1,091	$	1,092	$	(1)	—	%	Natural Gas Pipelines	$	1,069	$	1,091	$	(22)	(2)	%
Products Pipelines	Products Pipelines	223		325		(102)		(31)	%	Products Pipelines	279		223		56		25	%
Terminals	Terminals	246		295		(49)		(17)	%	Terminals	216		246		(30)		(12)	%
CO₂	CO₂	156		164		(8)		(5)	%	CO2	163		156		7		4	%

Total Segment EBDA	Total Segment EBDA	1,716		1,876		(160)		(9)	%	Total Segment EBDA	1,727		1,716		11		1	%
DD&A	DD&A	(539)		(578)		39		7	%	DD&A	(526)		(539)		13		2	%
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(32)		(21)		(11)		(52)	%	Amortization of excess cost of equity investments	(21)		(32)		11		34	%

General and administrative and corporate charges	General and administrative and corporate charges	(150)		(162)		12		7	%	General and administrative and corporate charges	(167)		(150)		(17)		(11)	%

Interest, net	Interest, net	(383)		(447)		64		14	%	Interest, net	(368)		(383)		15		4	%
Income before income taxes	Income before income taxes	612		668		(56)		(8)	%	Income before income taxes	645		612		33		5	%
Income tax expense	Income tax expense	(140)		(151)		11		7	%	Income tax expense	(134)		(140)		6		4	%

Net income	Net income	472		517		(45)		(9)	%	Net income	511		472		39		8	%
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	(17)		(11)		(6)		(55)	%	Net income attributable to noncontrolling interests	(16)		(17)		1		6	%
Net income attributable to Kinder Morgan, Inc.	Net income attributable to Kinder Morgan, Inc.	$	455	$	506	$	(51)	(10)	%	Net income attributable to Kinder Morgan, Inc.	$	495	$	455	$	40	9	%

Nine Months Ended September 30,
2020 2019 Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines $ 2,284 $ 3,383 $ (1,099) (32) %
Products Pipelines 719 908 (189) (21) %
Terminals 732 884 (152) (17) %
CO₂
(453) 558 (1,011) (181) %
Kinder Morgan Canada — (2) 2 100 %
Total Segment EBDA 3,282 5,731 (2,449) (43) %
DD&A (1,636) (1,750) 114 7 %
Amortization of excess cost of equity investments (99) (61) (38) (62) %
General and administrative and corporate charges (472) (478) 6 1 %
Interest, net (1,214) (1,359) 145 11 %
(Loss) income before income taxes (139) 2,083 (2,222) (107) %
Income tax expense (304) (471) 167 35 %
Net (loss) income (443) 1,612 (2,055) (127) %
Net income attributable to noncontrolling interests (45) (32) (13) (41) %
Net (loss) income attributable to Kinder Morgan, Inc. $ (488) $ 1,580 $ (2,068) (131) %

~~_______~~


	Nine Months Ended September 30,
	2021		2020		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	2,602	$	2,284	$	318	14	%
Products Pipelines	792		719		73		10	%
Terminals	689		732		(43)		(6)	%
CO2	599		(453)		1,052		232	%


Total Segment EBDA	4,682		3,282		1,400		43	%
DD&A	(1,595)		(1,636)		41		3	%
Amortization of excess cost of equity investments	(56)		(99)		43		43	%

General and administrative and corporate charges	(465)		(472)		7		1	%

Interest, net	(1,122)		(1,214)		92		8	%
Income (loss) before income taxes	1,444		(139)		1,583		1,139	%
Income tax expense	(248)		(304)		56		18	%


Net income (loss)	1,196		(443)		1,639		370	%
Net income attributable to noncontrolling interests	(49)		(45)		(4)		(9)	%
Net income (loss) attributable to Kinder Morgan, Inc.	$	1,147	$	(488)	$	1,635	335	%

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

~~Income (loss) before~~Net income ~~taxes decreased $56~~attributable to Kinder Morgan, Inc. increased $40 million and ~~$2,222~~$1,635 million for the three and nine months ended September 30, ~~2020,~~2021, respectively, as compared to the respective prior year periods. The ~~decreases~~third quarter increase in results were impacted by ~~lower~~higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals ~~in the comparative three-month periods~~ and ~~from all of our~~Natural Gas Pipelines business segments ~~in the comparative nine-month periods~~and higher general and administrative and corporate charges expense. The year-to-date increase was primarily ~~attributable to COVID-19-related reduced energy demand and commodity price impacts and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 on~~impacted by higher earnings from our Natural Gas Pipelines and ~~Terminals~~CO2 business segments ~~partially offset by~~primarily related to the ~~benefit~~February 2021 winter storm and therefore largely nonrecurring, and a decrease of ~~completed expansion projects~~$362 million of impairments in 2021 as compared to 2020 primarily reflecting the $1,600 million pre-tax non-cash asset impairment loss related to South Texas gathering and processing assets within our Natural Gas ~~Pipelines business~~Pipeline segment ~~and by lower interest expense and DD&A expense. The year-to-date decrease also included a~~in 2021 compared to the combined ~~$1.95 billion~~$1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO₂ reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO₂ business segment. The impacts of the long-lived asset impairments for both periods were partially offset by associated tax benefits. The year-to-date increase was also impacted by higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals business segment.

Certain Items Affecting Consolidated Earnings Results


		Three Months Ended September 30,																									Three Months Ended September 30,
		2020										2019													2021						2020
		GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings			GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
		(In millions)																											(In millions)
Segment EBDA	Segment EBDA															Segment EBDA
Natural Gas Pipelines	Natural Gas Pipelines	$	1,091	$	(9)	$	1,082	$	1,092	$	(2)	$	1,090	$	(8)	Natural Gas Pipelines	$	1,069	$	21	$	1,090	$	1,091	$	(9)	$	1,082	$	8
Products Pipelines	Products Pipelines	223		46		269		325		11		336		(67)		Products Pipelines	279		1		280		223		46		269		11
Terminals	Terminals	246		—		246		295		—		295		(49)		Terminals	216		17		233		246		—		246		(13)
CO₂	CO₂	156		(2)		154		164		(15)		149		5		CO2	163		(9)		154		156		(2)		154		—

Total Segment EBDA(a)	Total Segment EBDA(a)	1,716		35		1,751		1,876		(6)		1,870		(119)		Total Segment EBDA(a)	1,727		30		1,757		1,716		35		1,751		6
DD&A and amortization of excess cost of equity investments	DD&A and amortization of excess cost of equity investments	(571)		—		(571)		(599)		—		(599)		28		DD&A and amortization of excess cost of equity investments	(547)		—		(547)		(571)		—		(571)		24
General and administrative and corporate charges(a)	General and administrative and corporate charges(a)	(150)		11		(139)		(162)		5		(157)		18		General and administrative and corporate charges(a)	(167)		—		(167)		(150)		11		(139)		(28)
Interest, net(a)	Interest, net(a)	(383)		(8)		(391)		(447)		(5)		(452)		61		Interest, net(a)	(368)		(8)		(376)		(383)		(8)		(391)		15
Income before income taxes	Income before income taxes	612		38		650		668		(6)		662		(12)		Income before income taxes	645		22		667		612		38		650		17
Income tax expense(b)	Income tax expense(b)	(140)		(8)		(148)		(151)		8		(143)		(5)		Income tax expense(b)	(134)		(12)		(146)		(140)		(8)		(148)		2
Net income	Net income	472		30		502		517		2		519		(17)		Net income	511		10		521		472		30		502		19
Net income attributable to noncontrolling interests(a)	Net income attributable to noncontrolling interests(a)	(17)		—		(17)		(11)		—		(11)		(6)		Net income attributable to noncontrolling interests(a)	(16)		—		(16)		(17)		—		(17)		1

Net income attributable to Kinder Morgan, Inc.	Net income attributable to Kinder Morgan, Inc.	$	455	$	30	$	485	$	506	$	2	$	508	$	(23)	Net income attributable to Kinder Morgan, Inc.	$	495	$	10	$	505	$	455	$	30	$	485	$	20

4038

Nine Months Ended September 30,
2020 2019
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts
increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines $ 2,284 $ 993 $ 3,277 $ 3,383 $ (21) $ 3,362 $ (85)
Products Pipelines 719 50 769 908 28 936 (167)
Terminals 732 — 732 884 — 884 (152)
CO₂
(453) 938 485 558 (36) 522 (37)
Kinder Morgan Canada — — — (2) 2 — —
Total Segment EBDA(a) 3,282 1,981 5,263 5,731 (27) 5,704 (441)
DD&A and amortization of excess cost of equity investments (1,735) — (1,735) (1,811) — (1,811) 76
General and administrative and corporate charges(a) (472) 36 (436) (478) 11 (467) 31
Interest, net(a) (1,214) (8) (1,222) (1,359) (6) (1,365) 143
(Loss) income before income taxes (139) 2,009 1,870 2,083 (22) 2,061 (191)
Income tax expense(b) (304) (114) (418) (471) 15 (456) 38
Net (loss) income (443) 1,895 1,452 1,612 (7) 1,605 (153)
Net income attributable to noncontrolling interests(a) (45) — (45) (32) (1) (33) (12)
Net (loss) income attributable to Kinder Morgan, Inc. $ (488) $ 1,895 $ 1,407 $ 1,580 $ (8) $ 1,572 $ (165)

~~_______~~


	Nine Months Ended September 30,
	2021						2020
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	2,602	$	1,646	$	4,248	$	2,284	$	993	$	3,277	$	971
Products Pipelines	792		44		836		719		50		769		67
Terminals	689		17		706		732		—		732		(26)
CO2	599		(3)		596		(453)		938		485		111

Total Segment EBDA(a)	4,682		1,704		6,386		3,282		1,981		5,263		1,123
DD&A and amortization of excess cost of equity investments	(1,651)		—		(1,651)		(1,735)		—		(1,735)		84
General and administrative and corporate charges(a)	(465)		—		(465)		(472)		36		(436)		(29)
Interest, net(a)	(1,122)		(17)		(1,139)		(1,214)		(8)		(1,222)		83
Income (loss) before income taxes	1,444		1,687		3,131		(139)		2,009		1,870		1,261
Income tax expense(b)	(248)		(439)		(687)		(304)		(114)		(418)		(269)
Net income (loss)	1,196		1,248		2,444		(443)		1,895		1,452		992
Net income attributable to noncontrolling interests(a)	(49)		—		(49)		(45)		—		(45)		(4)

Net income (loss) attributable to Kinder Morgan, Inc.	$	1,147	$	1,248	$	2,395	$	(488)	$	1,895	$	1,407	$	988

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

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

Net income ~~(loss)~~ attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) ~~decreased~~increased by ~~$23~~$20 million and ~~$165~~$988 million for the three and nine months ended September 30, ~~2020,~~2021, respectively, as compared to the respective prior year periods. ~~Decreases in Adjusted Segment EBDA from the prior~~The third quarter ~~and year-to-date periods were~~increase was primarily due to ~~lower~~higher earnings from our Products Pipelines ~~Terminals~~ and Natural Gas Pipelines business segments ~~primarily attributable to COVID-19-related reduced energy demand~~ and ~~commodity price impacts discussed above~~lower DD&A expense (including amortization of excess cost of equity investments) and ~~the impact of the KML~~interest expense partially offset by higher general and ~~U.S. Cochin Sale in the fourth quarter of 2019 on~~administrative and corporate charges expense and lower earnings from our Terminals business segment. The year-to-date increase was impacted by higher earnings from our Natural Gas Pipelines and ~~Terminals~~CO2 business segments primarily related to the February 2021 winter storm, and therefore largely nonrecurring, higher earnings from our Products Pipelines business segment and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by ~~the benefit of completed expansion projects in~~higher general and administrative and corporate charges expense and lower earnings from our ~~Natural Gas Pipelines~~Terminals business segment.

4139

Non-GAAP Financial Measures

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


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019			2021		2020		2021		2020
		(In millions)															(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	455	$	506	$	(488)	$	1,580	Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	495	$	455	$	1,147	$	(488)
Total Certain Items	Total Certain Items	30		2		1,895		(8)		Total Certain Items	10		30		1,248		1,895
Adjusted Earnings(a)	Adjusted Earnings(a)	485		508		1,407		1,572		Adjusted Earnings(a)	505		485		2,395		1,407
DD&A and amortization of excess cost of equity investments for DCF(b)	DD&A and amortization of excess cost of equity investments for DCF(b)	662		694		2,012		2,093		DD&A and amortization of excess cost of equity investments for DCF(b)	612		662		1,854		2,012
Income tax expense for DCF(a)(b)	Income tax expense for DCF(a)(b)	171		164		484		521		Income tax expense for DCF(a)(b)	165		171		754		484
Cash taxes~~(c)~~(b)	Cash taxes~~(c)~~(b)	(49)		(12)		(57)		(76)		Cash taxes~~(c)~~(b)	(12)		(49)		(56)		(57)
Sustaining capital expenditures~~(c)~~(b)	Sustaining capital expenditures~~(c)~~(b)	(177)		(173)		(477)		(477)		Sustaining capital expenditures~~(c)~~(b)	(241)		(177)		(558)		(477)
Other items~~(d)~~(c)	Other items~~(d)~~(c)	(7)		(41)		(22)		6		Other items~~(d)~~(c)	(16)		(7)		(22)		(22)
DCF	DCF	$	1,085	$	1,140	$	3,347	$	3,639	DCF	$	1,013	$	1,085	$	4,367	$	3,347

Adjusted Segment EBDA to Adjusted EBITDA to DCF

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except per share amounts)
Natural Gas Pipelines $ 1,082 $ 1,090 $ 3,277 $ 3,362
Products Pipelines 269 336 769 936
Terminals 246 295 732 884
CO₂
154 149 485 522
Adjusted Segment EBDA(a) 1,751 1,870 5,263 5,704
General and administrative and corporate charges(a) (139) (157) (436) (467)
Joint venture DD&A and income tax expense(a)(e) 114 123 343 368
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a) (17) (2) (45) (7)
Adjusted EBITDA 1,709 1,834 5,125 5,598
Interest, net(a) (391) (452) (1,222) (1,365)
Cash taxes(c) (49) (12) (57) (76)
Sustaining capital expenditures(c) (177) (173) (477) (477)
KML noncontrolling interests DCF adjustments(f) — (16) — (47)
Other items(d) (7) (41) (22) 6
DCF $ 1,085 $ 1,140 $ 3,347 $ 3,639
Adjusted Earnings per common share $ 0.21 $ 0.22 $ 0.62 $ 0.69
Weighted average common shares outstanding for dividends(g) 2,276 2,277 2,276 2,276
DCF per common share $ 0.48 $ 0.50 $ 1.47 $ 1.60
Declared dividends per common share $ 0.2625 $ 0.25 $ 0.7875 $ 0.75

~~_______~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Natural Gas Pipelines	$	1,090	$	1,082	$	4,248	$	3,277
Products Pipelines	280		269		836		769
Terminals	233		246		706		732
CO2	154		154		596		485

Adjusted Segment EBDA(a)	1,757		1,751		6,386		5,263
General and administrative and corporate charges(a)	(167)		(139)		(465)		(436)
Joint venture DD&A and income tax expense(a)(b)	84		114		270		343
Net income attributable to noncontrolling interests(a)	(16)		(17)		(49)		(45)
Adjusted EBITDA	1,658		1,709		6,142		5,125
Interest, net(a)	(376)		(391)		(1,139)		(1,222)
Cash taxes(b)	(12)		(49)		(56)		(57)
Sustaining capital expenditures(b)	(241)		(177)		(558)		(477)


Other items(c)	(16)		(7)		(22)		(22)
DCF	$	1,013	$	1,085	$	4,367	$	3,347

Adjusted Earnings per share	$	0.22	$	0.21	$	1.05	$	0.62
Weighted average shares outstanding for dividends(d)	2,279		2,276		2,278		2,276
DCF per share	$	0.44	$	0.48	$	1.92	$	1.47
Declared dividends per share	$	0.27	$	0.2625	$	0.81	$	0.7875

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

(b)Includes or represents DD&A, or income tax expense, ascash taxes and/or sustaining capital expenditures (as applicable for each item) from ~~unconsolidated~~ joint ~~ventures, reduced by consolidated joint venture partners’ DD&A. 2019 amounts are also net of DD&A or income tax expense attributable to KML noncontrolling interests.~~ventures. See tables included in “—Supplemental Information” below.

(c)Includes cash taxes or sustaining capital expenditures, as applicable, from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in ~~“—Supplemental Information”~~ ~~below.~~

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

~~(e)Represents unconsolidated joint venture DD&A and income tax expense, reduced by consolidated joint venture partners’ DD&A. See tables included in~~ ~~“—Supplemental Information”~~ ~~below.~~

~~(f)2019 amounts represent the combined net income, DD&A and income tax expense adjusted for Certain Items, as applicable, attributable to KML noncontrolling interests. See table included in~~ ~~“—Supplemental Information”~~ ~~below.~~

~~(g)~~(d)Includes restricted stock awards that participate in ~~common share~~ dividends.

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

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Net income (loss) (GAAP) $ 472 $ 517 $ (443) $ 1,612
Certain Items:
Fair value amortization (5) (7) (17) (22)
Legal, environmental and taxes other than income tax reserves 46 11 38 28
Change in fair value of derivative contracts(a) (6) (14) (10) (22)
Loss (gain) on impairments and divestitures, net(b) 11 — 382 (5)
Loss on impairment of goodwill(c) — — 1,600 —
COVID-19 costs 11 — 11 —
Income tax Certain Items (8) 8 (114) 15
Noncontrolling interests associated with Certain Items — — — (1)
Other (19) 4 5 (1)
Total Certain Items(d) 30 2 1,895 (8)
DD&A and amortization of excess cost of equity investments 571 599 1,735 1,811
Income tax expense(e) 148 143 418 456
Joint venture DD&A and income tax expense(e)(f) 114 123 343 368
Interest, net(e) 391 452 1,222 1,365
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(e)) (17) (2) (45) (6)
Adjusted EBITDA $ 1,709 $ 1,834 $ 5,125 $ 5,598

~~______~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)(a)	$	495	$	455	$	1,147	$	(488)
Certain Items:
Fair value amortization	(7)		(5)		(15)		(17)
Legal, environmental and taxes other than income tax reserves	—		46		112		38
Change in fair value of derivative contracts(b)	22		(6)		64		(10)
Loss on impairments, divestitures and other write-downs, net(c)	4		11		1,515		382
Loss on impairments of goodwill(d)	—		—		—		1,600

COVID-19 costs	—		11		—		11
Income tax Certain Items	(12)		(8)		(439)		(114)


Other	3		(19)		11		5
Total Certain Items(e)	10		30		1,248		1,895
DD&A and amortization of excess cost of equity investments	547		571		1,651		1,735
Income tax expense(f)	146		148		687		418
Joint venture DD&A and income tax expense(f)(g)	84		114		270		343
Interest, net(f)	376		391		1,139		1,222

Adjusted EBITDA	$	1,658	$	1,709	$	6,142	$	5,125

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

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

~~(b)~~(c)Three and nine months ended September 30, 2021 amounts include a non-cash impairment of $14 million related to the reclassification of an asset to held for sale within our Terminals business segment, offset partially by a gain of $10 million on the sale of assets within our CO2 business segment. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from lower expectations regarding the volumes and rates associated with re-contracting and a write-down of $117 million, reported within “Earnings from equity investments” on the accompanying consolidated statement of operations, on a long-term subordinated note receivable from an equity investee, Ruby, offset partially by a pre-tax gain of $206 million, reported within “Other, net” on the accompanying consolidated statement of operations, associated with the sale of a partial interest in our equity investment in NGPL Holdings. Nine months ended September 30, 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO₂ business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business ~~segment which~~segment. Except as otherwise noted above, these amounts are reported within “Loss ~~(gain)~~ on impairments and divestitures, net” on ~~our Consolidated Earnings Results (GAAP) table above.~~the accompanying consolidated statement of operations.

~~(c)~~(d)Nine months ended September 30, 2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO₂reporting units, respectively.

~~(d)~~(e)Three months ended September 30, ~~2020~~2021 and ~~2019~~2020 amounts include ~~$(4)~~$2 million and ~~$(2)~~$(4) million, respectively, and nine months ended September 30, ~~2020~~2021 and ~~2019~~2020 amounts include ~~$(4)~~$129 million and ~~$(15)~~$(4) million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.

~~(e)~~(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.

~~(f)~~(g)Represents ~~unconsolidated~~ joint venture DD&A and income tax ~~expense, reduced by consolidated joint venture partners’ DD&A.~~expense. See ~~table~~tables included in “—Supplemental Information” below.

4341

Supplemental Information

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
DD&A (GAAP) $ 539 $ 578 $ 1,636 $ 1,750
Amortization of excess cost of equity investments (GAAP) 32 21 99 61
DD&A and amortization of excess cost of equity investments 571 599 1,735 1,811
Joint venture DD&A 91 100 277 297
DD&A attributable to KML noncontrolling interests — (5) — (15)
DD&A and amortization of excess cost of equity investments for DCF $ 662 $ 694 $ 2,012 $ 2,093
Income tax expense (GAAP) $ 140 $ 151 $ 304 $ 471
Certain Items 8 (8) 114 (15)
Income tax expense(a) 148 143 418 456
Unconsolidated joint venture income tax expense(a) 23 23 66 71
Income tax expense attributable to KML noncontrolling interests(a) — (2) — (6)
Income tax expense for DCF(a) $ 171 $ 164 $ 484 $ 521
KML activities prior to December 16, 2019
Net income attributable to KML noncontrolling interests $ — $ 9 $ — $ 25
KML noncontrolling interests associated with Certain Items — — — 1
KML noncontrolling interests(a) — 9 — 26
DD&A attributable to KML noncontrolling interests — 5 — 15
Income tax expense attributable to KML noncontrolling interests(a) — 2 — 6
KML noncontrolling interests DCF adjustments(a) $ — $ 16 $ — $ 47
Net income attributable to noncontrolling interests (GAAP) $ 17 $ 11 $ 45 $ 32
Less: KML noncontrolling interests(a) — 9 — 26
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a)) 17 2 45 6
Noncontrolling interests associated with Certain Items — — — 1
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items) $ 17 $ 2 $ 45 $ 7

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Additional joint venture information
Unconsolidated joint venture DD&A $ 101 $ 104 $ 306 $ 308
Consolidated joint venture partners’ DD&A (10) (4) (29) (11)
Joint venture DD&A 91 100 277 297
Unconsolidated joint venture income tax expense(a) 23 23 66 71
Joint venture DD&A and income tax expense(a) $ 114 $ 123 $ 343 $ 368
Unconsolidated joint venture cash taxes(b) $ (41) $ (16) $ (51) $ (50)
Unconsolidated joint venture sustaining capital expenditures $ (32) $ (35) $ (84) $ (85)
Consolidated joint venture partners’ sustaining capital expenditures 2 2 4 5
Joint venture sustaining capital expenditures $ (30) $ (33) $ (80) $ (80)

~~______~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
DD&A (GAAP)	$	526	$	539	$	1,595	$	1,636
Amortization of excess cost of equity investments (GAAP)	21		32		56		99
DD&A and amortization of excess cost of equity investments	547		571		1,651		1,735
Joint venture DD&A	65		91		203		277

DD&A and amortization of excess cost of equity investments for DCF	$	612	$	662	$	1,854	$	2,012

Income tax expense (GAAP)	$	134	$	140	$	248	$	304
Certain Items	12		8		439		114
Income tax expense(a)	146		148		687		418
Unconsolidated joint venture income tax expense(a)(b)	19		23		67		66

Income tax expense for DCF(a)	$	165	$	171	$	754	$	484

Additional joint venture information
Unconsolidated joint venture DD&A	$	76	$	101	$	236	$	306
Less: Consolidated joint venture partners’ DD&A	11		10		33		29
Joint venture DD&A	65		91		203		277
Unconsolidated joint venture income tax expense(a)(b)	19		23		67		66
Joint venture DD&A and income tax expense(a)	$	84	$	114	$	270	$	343

Unconsolidated joint venture cash taxes(b)	$	(13)	$	(41)	$	(47)	$	(51)

Unconsolidated joint venture sustaining capital expenditures	$	(29)	$	(32)	$	(81)	$	(84)
Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(2)		(5)		(4)
Joint venture sustaining capital expenditures	$	(27)	$	(30)	$	(76)	$	(80)

(a)Amounts are adjusted for Certain Items.

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

Segment Earnings Results

Natural Gas Pipelines

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except operating statistics)
Revenues $ 1,809 $ 1,934 $ 5,255 $ 6,103
Operating expenses (878) (993) (2,455) (3,190)
(Loss) gain on impairments and divestitures, net (11) — (1,011) 10
Other income — — 1 2
Earnings from equity investments 169 141 484 431
Other, net 2 10 10 27
Segment EBDA 1,091 1,092 2,284 3,383
Certain Items(a)(b) (9) (2) 993 (21)
Adjusted Segment EBDA $ 1,082 $ 1,090 $ 3,277 $ 3,362
Change from prior period Increase/(Decrease)
Adjusted revenues $ (128) (7) % $ (852) (14) %
Adjusted Segment EBDA (8) (1) % (85) (3) %
Volumetric data(c)
Transport volumes (BBtu/d) 36,453 37,028 37,091 35,958
Sales volumes (BBtu/d) 2,382 2,647 2,330 2,435
Gathering volumes (BBtu/d) 2,925 3,380 3,109 3,335
NGLs (MBbl/d) 22 33 27 32

~~_______~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	2,555	$	1,809	$	8,656	$	5,255
Operating expenses	(1,634)		(878)		(4,981)		(2,455)
Loss on impairments and divestitures, net	—		(11)		(1,599)		(1,011)
Other income	—		—		2		1
Earnings from equity investments	144		169		311		484

Other, net	4		2		213		10
Segment EBDA	1,069		1,091		2,602		2,284
Certain Items(a)	21		(9)		1,646		993
Adjusted Segment EBDA	$	1,090	$	1,082	$	4,248	$	3,277

Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	8			$	971

Volumetric data(b)
Transport volumes (BBtu/d)	38,527		37,475		38,593		37,887
Sales volumes (BBtu/d)	2,616		2,382		2,480		2,330
Gathering volumes (BBtu/d)	2,808		2,925		2,662		3,109
NGLs (MBbl/d)	29		22		30		27

Certain Items affecting Segment EBDA

(a)Includes ~~revenue~~ Certain Item amounts of ~~$(4)~~$21 million and ~~$(5)~~$1,646 million for the three and nine months ended September 30, 2021, respectively, and $(9) million and $993 million for the three and nine months ended September 30, 2020, ~~respectively, and $(1) million for both three~~respectively. Three and nine months ended September 30, ~~2019 which includes $(14)~~2021 amounts include decreases in revenues of $14 million ~~of amortization of~~

~~regulatory liabilities (three~~ and ~~nine months 2020), partially offset by~~$36 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL ~~sales (all periods).~~

~~(b)Includes non-revenue Certain Item amounts~~sales. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash asset impairment loss of ~~$(5)~~$1,600 million resulting from lower expectations regarding the volumes and ~~$998~~rates associated with re-contracting related to our South Texas gathering and processing assets, a write-down of $117 million ~~for~~on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a litigation reserve partially offset by a pre-tax gain of $206 million associated with the ~~three~~sale of a partial interest in our equity investment in NGPL Holdings. Three and nine months ended September 30, 2020 ~~respectively, and $(1)~~amounts both include an increase in revenues of $(14) million ~~and $(20) million for the three and nine~~of amortization of regulatory liabilities, largely offset by non-cash amounts related to mark-to-market derivative contracts. Nine months ended September 30, ~~2019, respectively. Nine-month~~ 2020 amount ~~primarily resulted from~~also includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit. ~~Nine-month 2019 amounts are primarily related to an increase in earnings from certain equity investees’ amortization of regulatory liabilities.~~

Other

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

Below are the changes in ~~both~~ Adjusted Segment EBDA ~~and adjusted revenues~~ in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019:~~2020:

Three Months Ended September 30, ~~2020~~2021 versus Three Months Ended September 30, ~~2019~~2020


		Adjusted Segment EBDA increase/(decrease)						Adjusted revenues increase/(decrease)							Adjusted Segment EBDA increase/(decrease)
		(In millions, except percentages)														(In millions, except percentages)
Midstream	Midstream	$	(68)	(21)	%	$	(208)	(19)	%	Midstream	$	29	11%
East Region										East Region	8		1%
West Region	West Region	(5)		(2)	%	1		—	%	West Region	(29)		(11)%
East Region		65		13	%	77		15	%

Intrasegment eliminations		—		—	%	2		40	%

Total Natural Gas Pipelines	Total Natural Gas Pipelines	$	(8)	(1)	%	$	(128)	(7)	%	Total Natural Gas Pipelines	$	8	1	%

Nine Months Ended September 30, ~~2020~~2021 versus Nine Months Ended September 30, ~~2019~~2020


		Adjusted Segment EBDA increase/(decrease)						Adjusted revenues increase/(decrease)							Adjusted Segment EBDA increase/(decrease)
		(In millions, except percentages)														(In millions, except percentages)
Midstream	Midstream	$	(183)	(18)	%	$	(1,033)	(29)	%	Midstream	$	998	123%
East Region										East Region	25		1%
West Region	West Region	(19)		(2)	%	4		—	%	West Region	(52)		(7)%
East Region		117		7	%	173		11	%

Intrasegment eliminations		—		—	%	4		33	%

Total Natural Gas Pipelines	Total Natural Gas Pipelines	$	(85)	(3)	%	$	(852)	(14)	%	Total Natural Gas Pipelines	$	971	30	%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019:~~2020:

•~~Midstream’s decreases of $68~~$29 million ~~(21%~~(11%) and ~~$183~~$998 million ~~(18%~~(123%), increases, respectively, in Midstream were primarily due to (i) ~~decreases of $40 million and $112 million, respectively, related to the sale of the Cochin Pipeline on December 16, 2019 to Pembina; (ii) lower prices~~ and quarter-to-date volumes on South Texas assets; (iii) lower volumes on KinderHawk; (iv) lower contract rates on our North Texas assets; and (v) lower sales margins partially offset by higher transportation revenues driven by new customer contracts on Texas intrastate natural gas pipeline operations. T~~hese decreases were partially offset by~~ higher equity earnings due to the ~~Gulf Coast Express~~Permian Highway Pipeline ~~(Gulf Coast)~~ being placed in service in ~~September 2019.~~ January 2021; (ii) higher sales margins driven by higher commodity prices on our Texas intrastate natural gas pipeline operations; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets. The year-to-date increase was also impacted by higher commodity prices as a result of the February 2021 winter storm on our South Texas assets and Texas intrastate natural gas pipeline operations partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations on our Oklahoma assets. Overall Midstream’s revenues ~~decreased in both the three and nine-month periods~~increased primarily due to ~~lower~~higher commodity prices ~~and volumes~~ which was ~~largely~~partially offset by corresponding ~~decreases~~increases in costs of sales;

•~~West Region’s decreases of $5~~$8 million ~~(2%~~(1%) and ~~$19~~$25 million ~~(2%~~(1%), increases, respectively, in the East Region were primarily due to decreases in earnings from (i) Ruby Pipeline Company, L.L.C. primarily due to lower transportation revenues and an increase in operating expenses due to the recognition of a credit loss reserve associated with a shipper; (ii) Cheyenne Plains Gas Pipeline Company, L.L.C. as a resultour July 2021 acquisition of the ~~expiration of one shipper’s contract; and (iii) EPNG driven by higher operating expenses,~~Stagecoach assets partially offset by lower earnings on Fayetteville Express Pipeline LLC driven by lower revenues resulting from contract expirations. The year-to-date increase was also impacted by higher earnings from TGP due to weather-driven increases in reservation and park and loan revenues mostly during the first quarter of 2021 and increased earnings from ~~CIG resulting from an expansion project in the Denver Julesburg basin; and~~

•~~East Region’s increases of $65 million (13%) and $117 million (7%), respectively, were primarily due to increases in earnings from ELC and Southern LNG~~Elba Liquefaction Company, L.L.C. resulting from the liquefaction units of the Elba Liquefaction project being ~~placed into service~~fully operational as of August 2020; and

•$29 million (11%) and $52 million (7%) decreases, respectively, in the ~~later part of 2019~~West Region were primarily due to lower earnings from Wyoming Interstate Company, LLC, Colorado Interstate Gas Company, L.L.C. and ~~through the first eight months of 2020~~Cheyenne Plains Gas Pipeline Company, L.L.C. driven by lower revenues due to contract expirations and ~~increased~~lower equity earnings from Ruby. The third quarter decrease was also impacted by lower earnings from EPNG driven by lower park and loan revenues.

4644

earnings from Citrus Corporation (Citrus) as a result of lower operating expenses and interest expense and higher transportation revenues. The year-to-date increase was also impacted by reduced contributions from TGP due to mild weather in the Northeast and the impact of the FERC 501-G rate settlement.

Products Pipelines

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except operating statistics)
Revenues $ 442 $ 484 $ 1,282 $ 1,350
Operating expenses (233) (177) (585) (500)
Loss on impairments and divestitures, net — — (21) —
Earnings from equity investments 14 17 42 52
Other, net — 1 1 6
Segment EBDA 223 325 719 908
Certain Items(a) 46 11 50 28
Adjusted Segment EBDA $ 269 $ 336 $ 769 $ 936
Change from prior period Increase/(Decrease)
Adjusted revenues $ (42) (9) % $ (68) (5) %
Adjusted Segment EBDA (67) (20) % (167) (18) %
Volumetric data(b)
Gasoline(c) 941 1,066 888 1,045
Diesel fuel 383 393 371 370
Jet fuel 160 318 184 305
Total refined product volumes 1,484 1,777 1,443 1,720
Crude and condensate 530 639 570 644
Total delivery volumes (MBbl/d) 2,014 2,416 2,013 2,364

~~_______~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	605	$	442	$	1,572	$	1,282
Operating expenses	(341)		(233)		(828)		(585)
Loss on impairments and divestitures, net	—		—		—		(21)

Earnings from equity investments	15		14		48		42

Other, net	—		—		—		1
Segment EBDA	279		223		792		719
Certain Items(a)	1		46		44		50
Adjusted Segment EBDA	$	280	$	269	$	836	$	769

Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	11			$	67

Volumetric data(b)
Gasoline(c)	1,023		941		987		888
Diesel fuel	389		383		395		371
Jet fuel	250		160		217		184
Total refined product volumes	1,662		1,484		1,599		1,443
Crude and condensate	491		530		503		570
Total delivery volumes (MBbl/d)	2,153		2,014		2,102		2,013

Certain Items affecting Segment EBDA

(a)Includes ~~non-revenue~~ Certain Item amounts of $1 million and $44 million for the three and nine months ended September 30, 2021, respectively, and $46 million and $50 million for the three and nine months ended September 30, 2020, ~~respectively, and $11~~respectively. Nine month 2021 amount includes increases in expense of $28 million and ~~$28~~$15 million ~~for the three~~related to a litigation reserve and ~~nine months ended September 30, 2019,~~an environmental reserve adjustment, respectively. Three and ~~nine-month~~nine month 2020 amounts both include a $46 million unfavorable rate case reserve adjustment. ~~Nine-month~~Nine month 2020 amount also includes a non-cash loss on impairment of our Belton Terminal of $21 million ~~and~~partially offset by a $17 million favorable adjustment for tax reserves, other than income taxes. Three and nine-month 2019 amounts include an unfavorable environmental reserve adjustment. Nine-month 2019 amount also includes a $17 million unfavorable adjustment of tax reserves, other than income taxes.

Other

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

(c)Volumes include ethanol pipeline volumes.

4745

Below are the changes in ~~both~~ Adjusted Segment EBDA ~~and adjusted revenues,~~ in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~2020:

Three Months Ended September 30, ~~2020~~2021 versus Three Months Ended September 30, ~~2019~~2020


		Adjusted Segment EBDA increase/(decrease)						Adjusted revenues increase/(decrease)							Adjusted Segment EBDA increase/(decrease)
		(In millions, except percentages)														(In millions, except percentages)
West Coast Refined Products	West Coast Refined Products	$	(31)	(21)	%	$	(19)	(10)	%	West Coast Refined Products	$	17	15	%
Southeast Refined Products										Southeast Refined Products	6		10	%
Crude and Condensate	Crude and Condensate	(27)		(22)	%	1		1	%	Crude and Condensate	(12)		(12)	%
Southeast Refined Products		(9)		(13)	%	(24)		(22)	%

Total Products Pipelines	Total Products Pipelines	$	(67)	(20)	%	$	(42)	(9)	%	Total Products Pipelines	$	11	4	%

Nine Months Ended September 30, ~~2020~~2021 versus Nine Months Ended September 30, ~~2019~~2020


		Adjusted Segment EBDA increase/(decrease)						Adjusted revenues increase/(decrease)							Adjusted Segment EBDA increase/(decrease)
		(In millions, except percentages)														(In millions, except percentages)
West Coast Refined Products	West Coast Refined Products	$	(51)	(13)	%	$	(45)	(8)	%	West Coast Refined Products	$	38	11	%
Southeast Refined Products										Southeast Refined Products	39		25	%
Crude and Condensate	Crude and Condensate	(76)		(21)	%	2		—	%	Crude and Condensate	(10)		(4)	%
Southeast Refined Products		(40)		(20)	%	(25)		(8)	%

Total Products Pipelines	Total Products Pipelines	$	(167)	(18)	%	$	(68)	(5)	%	Total Products Pipelines	$	67	9	%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019:~~2020:

•$17 million (15%) and $38 million (11%) increases, respectively, in West Coast Refined ~~Products’ decreases of $31 million (21%) and $51 million (13%), respectively,~~Products were primarily due to ~~decreased~~increased earnings on Pacific (SFPP) ~~operations,~~, and to a lesser extent, on Calnev Pipe Line LLC and West Coast terminals driven by ~~lower services~~higher revenues from the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expense primarily as a result of ~~a reduction in volumes due to COVID-19;~~higher integrity management spending on SFPP;

•~~Crude and Condensate’s decreases of $27~~$6 million ~~(22%~~(10%) and ~~$76~~$39 million ~~(21%~~(25%), increases, respectively, in Southeast Refined Products were primarily due to South East Terminals resulting from increased revenues from higher volumes driven by continued recovery of volumes from 2020. The year-to-date increase was also driven by higher 2021 earnings at our Transmix processing operations primarily due to higher prices and first quarter 2020 unfavorable inventory adjustments, and an increase in equity earnings from Products (SE) Pipe Line primarily due to product net gains resulting from higher prices; and

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

•Southeast Refined Products’ decreases of $9 million (13%) and $40 million (20%), respectively, were primarily due to decreased earnings from our South East Terminals and Central Florida Pipeline and a decrease in equity earnings from Plantation Pipe Line as a result of decreased transportation revenues driven by lower volumes and prices due to COVID-19. The year-to-date decrease was also impacted by lower earnings from our Transmix processing operations driven by unfavorable inventory adjustments resulting from commodity price declines during the first quarter 2020.

4846

Terminals


		Three Months Ended September 30,									Nine Months Ended September 30,										Three Months Ended September 30,							Nine Months Ended September 30,
		2020			2019			2020			2019				2021			2020			2021				2020
		(In millions, except operating statistics)																							(In millions, except operating statistics)
Revenues	Revenues	$	424		$	508		$	1,285		$	1,524		Revenues	$	422		$	424		$	1,275			$	1,285
Operating expenses	Operating expenses	(185)			(223)			(570)			(660)			Operating expenses	(200)			(185)			(588)				(570)
Gain (loss) on divestitures and impairments, net		—			3			(5)			3

Loss on impairments and divestitures, net														Loss on impairments and divestitures, net	(14)			—			(14)				(5)
Other income														Other income	4			—			4				—
Earnings from equity investments	Earnings from equity investments	7			6			19			15			Earnings from equity investments	3			7			10				19
Other, net	Other, net	—			1			3			2			Other, net	1			—			2				3
Segment EBDA	Segment EBDA	246			295			732			884			Segment EBDA	216			246			689				732
Certain Items(a)	Certain Items(a)	—			—			—			—			Certain Items(a)	17			—			17				—
Adjusted Segment EBDA	Adjusted Segment EBDA	$	246		$	295		$	732		$	884		Adjusted Segment EBDA	$	233		$	246		$	706			$	732

Change from prior period	Change from prior period	Increase/(Decrease)																						Change from prior period	Increase/(Decrease)
Adjusted revenues		$	(84)		(17)		%	$	(239)		(16)		%
Adjusted Segment EBDA	Adjusted Segment EBDA	(49)			(17)		%	(152)			(17)		%	Adjusted Segment EBDA	$	(13)					$	(26)

Volumetric data(a)
Volumetric data(b)														Volumetric data(b)
Liquids leasable capacity (MMBbl)	Liquids leasable capacity (MMBbl)	79.4			79.5			79.4			79.5			Liquids leasable capacity (MMBbl)	79.9			79.6			79.9				79.6
Liquids utilization %(b)		96.2		%	94.4		%	96.2		%	94.4		%
Liquids utilization %(c)														Liquids utilization %(c)	94.2		%	96.3		%	94.2		%		96.3		%
Bulk transload tonnage (MMtons)	Bulk transload tonnage (MMtons)	11.3			14.1			35.4			42.0			Bulk transload tonnage (MMtons)	13.5			11.3			38.1				35.4

Certain Items affecting Segment EBDA

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

Other

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

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

Below are the changes in ~~both~~ Adjusted Segment EBDA ~~and adjusted revenues,~~ in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~2020:

Three Months Ended September 30, ~~2020~~2021 versus Three Months Ended September 30, ~~2019~~2020

Adjusted Segment EBDA
increase/(decrease) Adjusted revenues increase/(decrease)
(In millions, except percentages)
Alberta Canada $ (31) (100) % $ (47) (100) %
Gulf Liquids (5) (6) % (4) (4) %
West Coast (5) (100) % (18) (100) %
Gulf Bulk (4) (27) % (3) (10) %
Mid Atlantic (3) (23) % (4) (14) %
All others (including intrasegment eliminations) (1) (1) % (8) (3) %
Total Terminals $ (49) (17) % $ (84) (17) %


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

Nine Months Ended September 30, ~~2020~~2021 versus Nine Months Ended September 30, ~~2019~~2020

Adjusted Segment EBDA
increase/(decrease) Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Alberta Canada $ (96) (100) % $ (144) (100) %
Gulf Liquids (21) (9) % (10) (3) %
West Coast (17) (100) % (51) (100) %
Gulf Bulk (4) (8) % (3) (3) %
Mid Atlantic (12) (24) % (16) (17) %
All others (including intrasegment eliminations) (2) — % (15) (2) %
Total Terminals $ (152) (17) % $ (239) (16) %


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

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019:~~2020:

•~~combined decreases of $36~~$15 million ~~and $113 million, respectively, associated with our Alberta Canada terminals and our West Coast terminals due to the sale of KML assets to Pembina on December 16, 2019;~~

•~~decreases of $5 million (6%~~(29%) and ~~$21~~$39 million ~~(9%~~(25%), decreases, respectively, from our Gulf Liquids terminals primarily driven by lower volumes and associated ancillary fees related to demand reduction attributable to COVID-19. Year-to-date decrease was also impacted by tanks being temporarily off-lease as they are transitioned to new customers following the termination of a major customer contract;

•~~decreases of $4 million (27%) and $4 million (8%), respectively, from our Gulf Bulk terminals~~in Marine operations were primarily due to lower ~~revenues driven by lower refinery petroleum coke production~~fleet utilization and ~~the expiration of a customer contract in January 2020; and~~average charter rates;

•~~decreases of $3~~$5 million ~~(23%~~(19%) increase and $7 million (8%) decrease, respectively, in the Gulf Central terminals. The third quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol, petroleum coke, and coal volumes. The year-to-date decrease in earnings was primarily driven by unfavorable petroleum coke volumes due to refinery outages associated with the February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC;

•$4 million (40%) and ~~$12~~$8 million ~~(24%~~(21%), increases, respectively, ~~from our~~in the Mid Atlantic terminals were primarily due to ~~lower~~higher coal volumes at our Pier IX ~~facility~~facility; and

•$2 million (7%) decrease and $9 million (13%) increase, respectively, in the Northeast terminals. The year-to-date increase was primarily driven by ~~coal market weakness largely attributable to demand reduction~~increased revenues associated with ~~COVID-19.~~

higher throughput levels and new contracts.

5048

CO2

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except operating statistics)
Revenues $ 251 $ 298 $ 792 $ 913
Operating expenses (99) (143) (312) (383)
Loss on impairments and divestitures, net — — (950) —
Earnings from equity investments 4 9 17 28
Segment EBDA 156 164 (453) 558
Certain Items(a)(b) (2) (15) 938 (36)
Adjusted Segment EBDA $ 154 $ 149 $ 485 $ 522
Change from prior period Increase/(Decrease)
Adjusted revenues $ (34) (12) % $ (97) (11) %
Adjusted Segment EBDA 5 3 % (37) (7) %
Volumetric data
SACROC oil production 21.2 23.2 22.1 24.0
Yates oil production 6.4 6.8 6.7 7.1
Katz and Goldsmith oil production 2.6 3.6 2.8 3.8
Tall Cotton oil production 1.4 2.1 1.9 2.4
Total oil production, net (MBbl/d)(c) 31.6 35.7 33.5 37.3
NGL sales volumes, net (MBbl/d)(c) 9.1 10.2 9.4 10.2
CO₂ sales volumes, net (Bcf/d)
0.4 0.6 0.5 0.6
Realized weighted average oil price per Bbl $ 54.83 $ 49.45 $ 53.28 $ 49.36
Realized weighted average NGL price per Bbl $ 17.65 $ 21.12 $ 17.77 $ 23.54

~~_______~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except operating statistics)
Revenues	$	257	$	251	$	729	$	792
Operating expenses	(112)		(99)		(161)		(312)
Gain (loss) on impairments and divestitures, net	11		—		8		(950)

Earnings from equity investments	7		4		23		17

Segment EBDA	163		156		599		(453)
Certain Items(a)	(9)		(2)		(3)		938
Adjusted Segment EBDA	$	154	$	154	$	596	$	485

Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	$	—			$	111

Volumetric data
SACROC oil production	20.1		21.2		19.9		22.1
Yates oil production	6.5		6.4		6.5		6.7
Katz and Goldsmith oil production	2.1		2.6		2.3		2.8
Tall Cotton oil production	1.1		1.4		1.0		1.9
Total oil production, net (MBbl/d)(b)	29.8		31.6		29.7		33.5
NGL sales volumes, net (MBbl/d)(b)	9.7		9.1		9.3		9.4

CO2 sales volumes, net (Bcf/d)	0.4		0.4		0.4		0.5
Realized weighted average oil price ($ per Bbl)	$	53.03	$	54.83	$	52.21	$	53.28
Realized weighted average NGL price ($ per Bbl)	$	28.01	$	17.65	$	23.73	$	17.77

Certain Items affecting Segment EBDA

(a)Includes ~~revenue~~ Certain Item amounts of $(9) million and $(3) million for the three and nine months ended September 30, 2021, respectively, and $(2) million and ~~$(12)~~$938 million for the three and nine months ended September 30, 2020, respectively, and $(15) million and $(36) million for the three and nine months ended September 30, 2019, respectively, related to mark-to-market gains associated with derivative contracts used to hedge forecasted commodity sales.

~~(b)Includes non-revenue Certain Item~~respectively. Nine month 2020 amount ~~of $950 million for the nine months ended September 30, 2020 resulting~~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

~~(c)~~(b)Net of royalties and outside working interests.

Below are the changes in ~~both~~ Adjusted Segment EBDA ~~and adjusted revenues,~~ in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019.~~2020:

Three Months Ended September 30, ~~2020~~2021 versus Three Months Ended September 30, ~~2019~~2020


		Adjusted Segment EBDA increase/(decrease)						Adjusted revenues increase/(decrease)							Adjusted Segment EBDA increase/(decrease)
		(In millions, except percentages)														(In millions, except percentages)
Oil and Gas Producing activities	Oil and Gas Producing activities	$	27	35	%	$	(10)	(5)	%	Oil and Gas Producing activities	$	(42)	(40)	%
Source and Transportation activities	Source and Transportation activities	(22)		(31)	%	(28)		(29)	%	Source and Transportation activities	40		82	%
Intrasegment eliminations		—		—	%	4		80	%

Subtotal										Subtotal	(2)		(1)	%
Energy Transition Ventures										Energy Transition Ventures	2		n/a
Total CO₂	Total CO₂	$	5	3	%	$	(34)	(12)	%	Total CO2	$	—	—	%

5149

Nine Months Ended September 30, ~~2020~~2021 versus Nine Months Ended September 30, ~~2019~~2020


		Adjusted Segment EBDA increase/(decrease)						Adjusted revenues increase/(decrease)							Adjusted Segment EBDA increase/(decrease)
		(In millions, except percentages)														(In millions, except percentages)
Oil and Gas Producing activities	Oil and Gas Producing activities	$	23	8	%	$	(37)	(6)	%	Oil and Gas Producing activities	$	73	23	%
Source and Transportation activities	Source and Transportation activities	(60)		(27)	%	(73)		(25)	%	Source and Transportation activities	36		22	%
Intrasegment eliminations		—		—	%	13		72	%

Subtotal										Subtotal	109		22	%
Energy Transition Ventures										Energy Transition Ventures	2		n/a
Total CO₂	Total CO₂	$	(37)	(7)	%	$	(97)	(11)	%	Total CO2	$	111	23	%

n/a - not applicable

The changes in Segment EBDA for our CO₂ business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, ~~2020~~2021 and ~~2019:~~2020:

•~~increases of $27~~$42 million ~~(35%~~(40%) decrease and ~~$23~~$73 million ~~(8%~~(23%), increase, respectively, ~~from our~~in Oil and Gas Producing ~~activities~~activities. The third quarter decrease was primarily due to ~~(i)~~a settlement for a terminated affiliate purchase contract with Source and Transportation activities which increased operating expenses by $38 million and lower crude oil sales revenues of $14 million due to lower volumes and realized prices partially offset by higher realized NGL prices which increased revenues by $12 million. The year-to-date increase was primarily due to lower operating expenses of ~~$32~~$118 million driven by a benefit in the 2021 period realized from returning power to the grid by curtailing oil production during the February 2021 winter storm, net of the impact of the terminated affiliate contract noted above, and ~~$50~~higher realized NGL prices which increased revenues by $27 million, ~~respectively;~~partially offset by lower crude oil volumes which decreased revenues by $45 million, driven in part, by the curtailed oil production and ~~(ii) higher~~by lower realized crude oil prices which ~~increased revenues by $18 million and $42 million, respectively, offset by (i) lower volumes which~~ decreased revenues by ~~$25 million and $61 million, respectively; and (ii) lower NGL prices which decreased revenues by $3 million and $19 million, respectively;~~$22 million; and

•~~decreases of $22~~$40 million ~~(31%~~(82%) and ~~$60~~$36 million ~~(27%~~(22%), increases, respectively, ~~from our~~in Source and Transportation activities primarily due to ~~decreases~~a settlement for a terminated affiliate sales contract with Oil and Gas Producing activities which resulted in an increase in revenues of ~~$28~~$38 million. The year-to-date increase was also impacted by a decrease in revenues of $19 million ~~and $77 million, respectively,~~ related to lower CO₂ sales volumes partially offset by an increase in equity earnings of $6 million and lower operating expenses of ~~$9 million and $22 million, respectively.~~$5 million.

We believe that our existing hedge contracts in place within our CO₂ business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO₂business segment hedges outstanding as of September 30, ~~2020.~~2021.

Remaining 2020 2021 2022 2023 2024
Crude Oil(a)
Price ($/barrel) $ 56.07 $ 52.00 $ 53.05 $ 50.14 $ 43.40
Volume (barrels per day) 30,684 20,300 8,600 5,150 950
NGLs
Price ($/barrel) $ 28.17 $ 26.61
Volume (barrels per day) 6,315 2,474
Midland-to-Cushing Basis Spread
Price ($/barrel) $ 0.14 $ 0.40
Volume (barrels per day) 31,100 1,500

~~_______~~


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

(a)Includes West Texas Intermediate hedges.

5250

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


		Three Months Ended September 30,						Earnings increase/(decrease)											Three Months Ended September 30,								Earnings increase/(decrease)
		2020		2019											2021				2020				Earnings increase/(decrease)
		(In millions, except percentages)																							(In millions, except percentages)
DD&A (GAAP)										DD&A (GAAP)	$	(526)			$	(539)			$	13			2	%

General and administrative (GAAP)	General and administrative (GAAP)	$	(153)	$	(154)	$	1			1	%	General and administrative (GAAP)	$	(174)			$	(153)			$	(21)			(14)	%
Corporate benefit (charges)		3		(8)		11		138	%
Corporate benefit										Corporate benefit	7				3				4				133	%
Certain Items(a)	Certain Items(a)	11		5		6		120	%	Certain Items(a)	—				11				(11)				(100)	%
General and administrative and corporate charges(b)	General and administrative and corporate charges(b)	$	(139)	$	(157)	$	18	11	%	General and administrative and corporate charges(b)	$	(167)			$	(139)			$	(28)			(20)	%

Interest, net (GAAP)	Interest, net (GAAP)	$	(383)	$	(447)	$	64	14	%	Interest, net (GAAP)	$	(368)			$	(383)			$	15			4	%
Certain Items(c)	Certain Items(c)	(8)		(5)		(3)		(60)	%	Certain Items(c)	(8)				(8)				—				—	%
Interest, net(b)	Interest, net(b)	$	(391)	$	(452)	$	61	13	%	Interest, net(b)	$	(376)			$	(391)			$	15			4	%

Net income attributable to noncontrolling interests (GAAP)	Net income attributable to noncontrolling interests (GAAP)	$	(17)	$	(11)	$	(6)	(55)	%	Net income attributable to noncontrolling interests (GAAP)	$	(16)			$	(17)			$	1			6	%
Certain Items		—		—		—		—	%
Certain Items(d)										Certain Items(d)	—				—				—				—	%
Net income attributable to noncontrolling interests(b)	Net income attributable to noncontrolling interests(b)	$	(17)	$	(11)	$	(6)	(55)	%	Net income attributable to noncontrolling interests(b)	$	(16)			$	(17)			$	1			6	%


		Nine Months Ended September 30,						Earnings increase/(decrease)											Nine Months Ended September 30,								Earnings increase/(decrease)
		2020		2019											2021				2020				Earnings increase/(decrease)
		(In millions, except percentages)																							(In millions, except percentages)
DD&A (GAAP)										DD&A (GAAP)	$	(1,595)			$	(1,636)			$	41			3	%

General and administrative (GAAP)	General and administrative (GAAP)	$	(461)	$	(456)	$	(5)			(1)	%	General and administrative (GAAP)	$	(490)			$	(461)			$	(29)			(6)	%
Corporate charges		(11)		(22)		11		50	%
Corporate benefit (charges)										Corporate benefit (charges)	25				(11)				36				327	%
Certain Items(a)	Certain Items(a)	36		11		25		227	%	Certain Items(a)	—				36				(36)				(100)	%
General and administrative and corporate charges(b)	General and administrative and corporate charges(b)	$	(436)	$	(467)	$	31	7	%	General and administrative and corporate charges(b)	$	(465)			$	(436)			$	(29)			(7)	%

Interest, net (GAAP)	Interest, net (GAAP)	$	(1,214)	$	(1,359)	$	145	11	%	Interest, net (GAAP)	$	(1,122)			$	(1,214)			$	92			8	%
Certain Items(c)	Certain Items(c)	(8)		(6)		(2)		(33)	%	Certain Items(c)	(17)				(8)				(9)				(113)	%
Interest, net(b)	Interest, net(b)	$	(1,222)	$	(1,365)	$	143	10	%	Interest, net(b)	$	(1,139)			$	(1,222)			$	83			7	%

Net income attributable to noncontrolling interests (GAAP)	Net income attributable to noncontrolling interests (GAAP)	$	(45)	$	(32)	$	(13)	(41)	%	Net income attributable to noncontrolling interests (GAAP)	$	(49)			$	(45)			$	(4)			(9)	%
Certain Items		—		(1)		1		100	%
Certain Items(d)										Certain Items(d)	—				—				—				—	%
Net income attributable to noncontrolling interests(b)	Net income attributable to noncontrolling interests(b)	$	(45)	$	(33)	$	(12)	(36)	%	Net income attributable to noncontrolling interests(b)	$	(49)			$	(45)			$	(4)			(9)	%

Certain items

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

(b)Amounts are adjusted for Certain Items.

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

(d)Three and ~~nine-month 2019~~nine months ended September 30, 2021 and 2020 amounts each include ~~(i) decreases in interest expense~~less than $1 million of ~~$7 million and $22 million, respectively, related to non-cash debt fair value adjustments~~noncontrolling interests associated with acquisitions and (ii) increases in expense of $2 million and $15 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.Certain Items.

General and administrative expenses and corporate charges adjusted for Certain Items ~~decreased $18 million and $31 million~~ for the three and nine months ended September 30, ~~2020, respectively,~~2021 when compared with the respective prior year periods increased $28 million and $29 million, respectively, primarily due to lower ~~non-cash pension expenses~~capitalized costs of ~~$11~~$18 million and ~~$34~~$41 million, respectively, ~~lower expenses~~reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment, non-recurring cost savings realized in the 2020 period as a result of $6the global pandemic of $10 million and ~~$27~~$17 million, respectively, ~~due to the KML~~ and ~~U.S. Cochin Sale, $7~~higher benefit-related costs of $10 million and $16 million, respectively, partially offset by $12 million and $36 million, respectively, of cost

savings in the 2021 period associated with ~~reduced business activity during the pandemic, partially offset by~~organizational efficiency efforts, and lower ~~capitalized~~pension costs of $4 million and ~~$43~~$14 million, ~~respectively, reflecting the COVID-19-related cutback on capital projects primarily by our CO~~₂and Natural Gas Pipelines business segments and our Gulf Coast project being placed in service in September 2019. The year-to-date decrease was also impacted by $8 million for a reduction in other benefit-related costs and a 2019 project write-off in our Terminals segment.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 ~~of interest income~~ adjusted for Certain Items for the three and nine months ended September 30, ~~2020~~2021 when compared with the respective prior year periods decreased ~~$61~~$15 million and ~~$143~~$83 million, respectively, primarily due to lower ~~weighted average~~ long-term debt balances, lower LIBOR rates, and lower ~~LIBOR~~long-term interest rates, partially offset by lower capitalized interest.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, approximately ~~16%~~15% and ~~27%~~16%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The percentage at September 30, 2021 includes our variable-to-fixed interest rate derivative contracts not designated as hedging instruments which hedge our exposure through 2021. For more information on our interest rate swaps, see Note 56 “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. Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2020 when compared with the respective prior year periods increased $6 million and $12 million, respectively.

Income Taxes

Our tax expense for the three months ended September 30, ~~2020~~2021 was approximately ~~$140~~$134 million as compared with ~~$151~~$140 million of expense for the same period of ~~2019.~~2020. The ~~$11~~$6 million decrease in tax expense was due ~~primarily due~~ to a slightly lower ~~pre-tax book income in the 2020 period.~~2021 effective tax rate caused by multiple factors.

Our tax expense for the nine months ended September 30, ~~2020~~2021 was approximately ~~$304~~$248 million as compared with ~~$471~~$304 million of expense for the same period of ~~2019.~~2020. The ~~$167~~$56 million decrease in tax expense was due primarily to (i) ~~lower~~the prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment, (ii) higher dividend-received deductions in 2021, and (iii) the current year release of the valuation allowance on our investment in NGPL Holdings, partially offset by federal and state taxes on higher pre-tax book income in ~~the 2020 period; (ii) lower foreign income taxes as a result of the KML~~2021 and ~~U.S. Cochin Sale in 2019; and (iii)~~ the refund of alternative minimum tax sequestration credits in 2020.

Liquidity and Capital Resources

General

As of September 30, ~~2020,~~2021, we had ~~$632~~$102 million of “Cash and cash equivalents,” ~~an increase~~a decrease of ~~$447~~$1,082 million from December 31, ~~2019.~~2020. We used $1.2 billion of cash on hand to complete the acquisition on July 9, 2021 of subsidiaries of Stagecoach. Additionally, as of September 30, ~~2020,~~2021, we had borrowing capacity of approximately ~~$3.9~~$3.8 billion under our ~~$4 billion revolving~~ credit ~~facility~~facilities (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit ~~facility~~facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash ~~flow~~flows from operations, providing a source of funds of ~~$3,282~~$4,440 million and ~~$3,121~~$3,282 million in the first nine months of ~~2020~~2021 and ~~2019,~~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 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;expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.

Our board of directors declared a quarterly dividend of ~~$0.2625~~$0.27 per share for the third quarter of ~~2020, unchanged from the previous quarter. This represents a 5% increase over~~2021, consistent with the dividend declared for the third quarter of 2019. As previously announced, market conditions have negatively impacted a number of our current year and future planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. As a result, our estimated capital expenditures for expansion projects and contributions to joint ventures will be almost 30% below our 2020 budget.previous quarter. We

~~continue to~~ expect to fully fund our dividend payments as well as our discretionary spending for ~~2020~~2021 without funding from the capital markets.

To refinance construction costs of its recent expansions, on February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 20302051 and received net proceeds of ~~$991 million. We~~$741 million which were used ~~the proceeds~~ to repay maturing ~~debt.~~senior notes.

~~During March 2020,~~On August 20, 2021, we ~~opportunistically repurchased approximately 3.6~~entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 and amended our existing facility (the “Existing Facility”) to reduce the borrowing capacity to $500 million and terminate the letter of ~~our Class P shares for approximately $50 million at an average price including commissions of $13.94 per share.~~credit commitments and the swing line capacity thereunder (together, the “Credit Facilities”).

Short-term Liquidity

As of September 30, ~~2020,~~2021, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion ~~revolving credit facility~~of Credit Facilities and associated commercial paper program. The loan commitments under our ~~revolving credit facility~~Credit Facilities 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~~Commercial paper borrowings reduce borrowings allowed under our Credit Facilities and letters of credit ~~facility.~~reduce borrowings allowed under our New Credit Facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our ~~credit facility~~Credit Facilities and, as previously discussed, have consistently generated strong cash flows from operations. We do not anticipate any significant limitations from the impacts of COVID-19 with respect to our ability to access funding through our ~~credit facility.~~Credit Facilities.

As of September 30, ~~2020,~~2021, our ~~$2,057~~$2,822 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. ~~Although we used the proceeds from the sale of the Pembina common equity that we received for the sale of KML to reduce debt during 2020, we generally~~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, ~~2019~~2020 was ~~$2,477~~$2,558 million.

We had working capital (defined as current assets less current liabilities) deficits of ~~$1,704~~$3,139 million and ~~$1,862~~$1,871 million as of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. ~~Our~~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 ~~$158~~$1,268 million ~~favorable~~unfavorable change from year-end ~~2019~~2020 was primarily due to (i) ~~an increase~~a $1,082 million decrease in cash and cash equivalents primarily resulting from utilizing cash on hand to acquire subsidiaries of ~~$447 million;~~Stagecoach; (ii) a ~~decrease~~net unfavorable short-term fair value adjustment of ~~approximately $284~~$253 million on derivative contract assets and liabilities in 2021; (iii) an increase in accounts payable, net of change in accounts receivable, of $212 million; (iv) a $160 million increase in commercial paper borrowings; and (iv) an increase of $104 million in senior notes that mature in the next twelve ~~months; (iii) a favorable asset fair value adjustment of $173 million on derivative contracts in 2020; and (iv) the $100 million repayment of the preferred interest in Kinder Morgan G.P. Inc.;~~months, partially offset by (i) a $193 million decrease in accrued interest; (ii) an increase of ~~$925~~$152 million in restricted deposits primarily related to ~~the sale of Pembina common equity~~margin calls in ~~January 2020.~~our derivative activities; (iii) a $109 million increase in inventories, primarily storage gas and product inventories; and (iv) a $61 million decrease in accrued contingencies. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

Counterparty Creditworthiness

Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices, or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. The balance of our allowance for credit losses as of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, was ~~$25~~$2 million and $9$26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets ~~which includes reserves for counterparty bankruptcies recorded during the nine months ended September 30, 2020. Our outlook as discussed under “~~—.~~2020 Outlook~~” takes into account the estimated impact attributable to counterparty bankruptcy filings to date. See also our “Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, Part II, Item 1A. Risk Factors —Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.”

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 nine months ended September 30, ~~2020,~~2021, and the amount we expect to spend for the remainder of ~~2020~~2021 to sustain and grow our businesses are as follows:

Nine Months Ended September 30, 2020 2020 Remaining Total 2020(a)
(In millions)
Sustaining capital expenditures(b)(c) $ 477 $ 181 $ 658
Discretionary capital investments(c)(d)(e) 1,397 321 1,718

~~_______~~


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

(a)~~Amounts include reductions due to revised outlook, as discussed above in “—General~~.”

~~(b)~~Nine months ended September 30, ~~2020, 2020~~2021, 2021 Remaining, and Total ~~2020~~2021 amounts include ~~$80~~$76 million, ~~$35~~$31 million, and ~~$115~~$107 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “Non-GAAP Financial Measures—Supplemental Information.”

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

(c)Nine months ended September 30, ~~2020~~2021 amount includes ~~$1 million of net changes from accrued capital expenditures, contractor retainage, and other.~~

~~(d)Nine months ended September 30, 2020 amount includes $442~~$135 million of our contributions to certain unconsolidated joint ventures for capital investments. Both Nine months ended September 30, 2021 and Total 2021 amounts also include $1,508 million for our acquisitions of Stagecoach and Kinetrex.

~~(e)~~(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, ~~2019~~2020 in our ~~2019~~2020 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, ~~2020~~2021 and December 31, ~~2019~~2020 were ~~$192~~$201 million and ~~$439~~$141 million, respectively. The ~~decrease~~increase of ~~$247~~$60 million was primarily driven by capital commitments related to our ~~Natural Gas Pipelines~~Terminals business segment.

Cash Flows

Operating Activities

Cash provided by operating activities increased ~~$161~~$1,158 million in the nine months ended September 30, ~~2020~~2021 compared to the respective ~~2019~~2020 period primarily due to:

•a ~~$161~~$1,206 million increase in cash ~~primarily resulting from $202~~after adjusting the $1,639 million ofincrease in net income ~~tax~~by $433 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) loss from impairments and divestitures, net (see discussion above in “—Results of Operations”); (ii) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “—General and Basis of Presentation”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred

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

•a $48 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by payments for litigation matters in the ~~2020~~2021 period which was partially offset by a net increase in working capital items and higher distributions from equity investment earnings in the 2021 period compared to $364 million of net income tax payments in the 2019 period, which in both periods were primarily for foreign income taxes associated with the sale of certain Canadian assets. The income tax payments for the 2020 ~~period are net of a $20 million refund related to alternative minimum tax sequestration credits.~~period.

Investing Activities

Cash used in investing activities ~~decreased $1,834~~increased $1,135 million for the nine months ended September 30, ~~2020~~2021 compared to the respective ~~2019~~2020 period primarily attributable to:

•~~an $827~~a $1,502 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,197 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 2 “Acquisitions” to our consolidated financial statements for further information regarding these transactions; and

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

•a ~~$783~~$457 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and

•a $329 million decrease in cash used for contributions to equity ~~investments~~investees driven primarily by lower contributions to ~~Gulf Coast Express~~Permian Highway Pipeline LLC ~~Midcontinent Express Pipeline LLC, Citrus,~~ and ~~Fayetteville Express Pipeline LLC~~SNG in the ~~2020~~2021 period compared with the ~~2019 period, partially offset by contributions made to SNG in the~~ 2020 ~~period; and~~

•a $368 million decrease in capital expenditures in the 2020 period over the comparative 2019 period primarily due to lower expenditures on the Elba Liquefaction expansion and also reflecting our reduction of expansion capital projects in the wake of COVID-19; partially offset by,

•a $102 million decrease in distributions received from equity investments in excess of cumulative earnings primarily from Ruby Pipeline Holding Company L.L.C. and Fayetteville Express Pipeline LLC in the 2020 period over the comparative 2019 period.

Financing Activities

Cash used in financing activities ~~decreased $1,587~~increased $1,446 million for the nine months ended September 30, ~~2020~~2021 compared to the respective ~~2019~~2020 period primarily attributable to:

•a ~~$1,068~~$1,403 million net ~~decrease~~increase in cash used related to debt activity as a result of ~~lower~~higher net debt payments in the ~~2020~~2021 period compared to the ~~2019 period; and~~

•~~an $879 million increase in cash reflecting the distribution of the TMPL sale proceeds to the owners of KML restricted voting shares in the 2019 period; partially offset by,~~

•~~a $171 million increase in dividend payments to our common shareholders; and~~

•~~a $127 million decrease in contributions received from investment partner and noncontrolling interests primarily driven by lower contributions received from EIG Global Energy Partners in the~~ 2020 ~~period compared to the 2019~~ period.

~~Common Stock~~ Dividends

We expect to declare ~~common stock~~ dividends of ~~$1.05~~$1.08 per share on our ~~common~~ stock for ~~2020.~~2021. The table below reflects our ~~2020 common stock~~2021 dividends declared:

Three months ended

Total quarterly dividend per share for the period

Date of declaration

Date of record

Date of dividend

~~December~~March 31, ~~2019~~2021

~~0.25~~

~~January 22, 2020~~

~~February 3, 2020~~

~~February 18, 2020~~

~~March 31, 2020~~

~~0.2625~~0.27

April ~~22, 2020~~21, 2021

April 30, 2021

May ~~4, 2020~~

~~May 15, 2020~~17, 2021

June 30, ~~2020~~2021

~~0.2625~~0.27

July ~~22, 2020~~21, 2021

August ~~3, 2020~~2, 2021

August ~~17, 2020~~16, 2021

September 30, ~~2020~~2021

~~0.2625~~0.27

October ~~21, 2020~~20, 2021

November ~~2, 2020~~1, 2021

November ~~16, 2020~~15, 2021

The actual amount of ~~common stock~~ 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 ~~2019~~2020 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.

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

5855

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 that we early adopted effective January 1, 2020.~~S-X. Also, see Exhibit 10.1 to this report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of September 30, ~~2020.~~2021.”

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

Excluding fair value adjustments, as of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the Obligated Group had ~~$32,502~~$30,994 million and ~~$32,409~~$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	Summarized Combined Balance Sheet Information	September 30, 2020		December 31, 2019		Summarized Combined Balance Sheet Information	September 30, 2021		December 31, 2020
		(In millions)							(In millions)

Current assets	Current assets	$	2,418	$	1,918	Current assets	$	2,412	$	2,957
Current assets - affiliates	Current assets - affiliates	1,073		1,146		Current assets - affiliates	1,118		1,151
Noncurrent assets	Noncurrent assets	62,131		63,298		Noncurrent assets	62,129		61,783
Noncurrent assets - affiliates	Noncurrent assets - affiliates	615		441		Noncurrent assets - affiliates	507		616
Total Assets	Total Assets	$	66,237	$	66,803	Total Assets	$	66,166	$	66,507

Current liabilities	Current liabilities	$	3,810	$	4,569	Current liabilities	$	5,390	$	4,528
Current liabilities - affiliates	Current liabilities - affiliates	1,118		1,139		Current liabilities - affiliates	1,269		1,209
Noncurrent liabilities	Noncurrent liabilities	34,320		33,612		Noncurrent liabilities	31,803		33,907
Noncurrent liabilities - affiliates	Noncurrent liabilities - affiliates	1,057		1,325		Noncurrent liabilities - affiliates	1,006		1,078
Total Liabilities	Total Liabilities	40,305		40,645		Total Liabilities	39,468		40,722
Redeemable noncontrolling interest	Redeemable noncontrolling interest	747		803		Redeemable noncontrolling interest	661		728
Kinder Morgan, Inc.’s stockholders’ equity	Kinder Morgan, Inc.’s stockholders’ equity	25,185		25,355		Kinder Morgan, Inc.’s stockholders’ equity	26,037		25,057
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	66,237	$	66,803	Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	66,166	$	66,507


Summarized Combined Income Statement Information	Summarized Combined Income Statement Information	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020		Summarized Combined Income Statement Information	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
		(In millions)							(In millions)
Revenues	Revenues	$	2,653	$	7,840	Revenues	$	3,472	$	11,211
Operating income	Operating income	788		1,032		Operating income	699		1,697
Net income	Net income	463		113		Net income	373		937

5956

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

~~For a discussion of~~There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, ~~2019,~~2020, in Item 7A in our ~~2019~~2020 Form ~~10-K, see Item 2,~~ ~~“Management's Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook”and~~10-K. For more information on our risk management activities, refer to Item 1, Note 56 “Risk Management” to our consolidated financial ~~statements for more information on our risk management activities, both of which are incorporated in this item by reference.~~statements.

Item 4. Controls and Procedures.

As of September 30, ~~2020,~~2021, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, ~~2020~~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 910 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 ~~2019~~2020 Form ~~10-K and in Part II,~~10-K. For more information on our risk management activities, refer to Item ~~1A.~~1, Note 6 “Risk ~~Factors~~Management” ofto our ~~Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.~~consolidated financial statements.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

The Company does not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. The Company has not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended September 30, ~~2020.~~2021.

Item 5. Other Information.

~~None.~~Effective October 20, 2021, our board of directors approved the Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (the “Amended Director Plan”), which amends and restates the previous Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors dated January 1, 2015, as

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

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

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

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

•the total cash compensation awarded to such director and

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

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

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

6058

Item 6. Exhibits.

Exhibit

Number Description


~~4.1~~		~~Certificate of the Vice President and Chief Financial Officer, and Vice President, Investor Relations and Treasurer of Kinder Morgan~~, ~~Inc. establishing the terms of the 2.00% Notes due February 15, 2031 and the 3.25% Notes due August 1, 2050.~~

10.1		Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of September 30, ~~2020.~~2021.

10.2	*	Revolving Credit Agreement, dated August 20, 2021 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed August 25, 2021 (File No. 001-35081)).

10.3	*	First Amendment to Revolving Credit Agreement, dated August 20, 2021 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to KMI's Current Report on Form 8-K filed August 25, 2021 (File 001-35081)).

10.4		Second Amended and Restated Stock Compensation Plan for Non-Employee Directors.

10.5		2021 Form of Non-Employee Director Stock Compensation Agreement.

22.1		Subsidiary guarantors and issuers of guaranteed securities.

31.1		Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification by Chief Executive Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification by Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101		Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Operations for the three and nine months ended September 30, ~~2020~~2021 and ~~2019;~~2020; (ii) our Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, ~~2020~~2021 and ~~2019;~~2020; (iii) our Consolidated Balance Sheets as of September 30, ~~2020~~2021 and December 31, ~~2019;~~2020; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, ~~2020~~2021 and ~~2019;~~2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, ~~2020~~2021 and ~~2019;~~2020; and (vi) the notes to our Consolidated Financial Statements.

104		Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.

_______

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

6159

SIGNATURE

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


			KINDER MORGAN, INC.
						Registrant

Date:

October ~~23, 2020~~22, 2021

By:

/s/ David P. Michels

David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)

6260


	Nine Months Ended September 30, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,701	$	253	$	785	$	1	$	(3)	$	3,737
Fee-based services	561		752		398		45		0		1,756
Total services	3,262		1,005		1,183		46		(3)		5,493
Commodity sales
Natural gas sales	1,979		0		0		1		(7)		1,973
Product sales	599		211		16		827		(23)		1,630

Total commodity sales	2,578		211		16		828		(30)		3,603
Total revenues from contracts with customers	5,840		1,216		1,199		874		(33)		9,096
Other revenues(c)
Leasing services	167		129		325		39		0		660
Derivatives adjustments on commodity sales	61		0		0		(10)		0		51
Other	35		5		0		10		0		50
Total Other revenues	263		134		325		39		0		761
Total revenues	$	6,103	$	1,350	$	1,524	$	913	$	(33)	$	9,857


	Remaining 2020		2021		2022		2023		2024
Crude Oil(a)
Price ($/barrel)	$	56.07	$	52.00	$	53.05	$	50.14	$	43.40
Volume (barrels per day)	30,684		20,300		8,600		5,150		950
NGLs
Price ($/barrel)	$	28.17	$	26.61
Volume (barrels per day)	6,315		2,474
Midland-to-Cushing Basis Spread
Price ($/barrel)	$	0.14	$	0.40
Volume (barrels per day)	31,100		1,500


	Nine Months Ended September 30, 2020		2020 Remaining		Total 2020(a)
	(In millions)
Sustaining capital expenditures(b)(c)	$	477	$	181	$	658
Discretionary capital investments(c)(d)(e)	1,397		321		1,718