10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

F O R M  10-Q  

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

or

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-35081

KINDER MORGAN, INC.

(Exact name of registrant as specified in its charter)

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

1001 Louisiana Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

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

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

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

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

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

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

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

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

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

As of October 22, 2020, the registrant had 2,263,793,923 Class P shares outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

			Page Number
	Glossary		2
	Information Regarding Forward-Looking Statements		3
	PART I.  FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Operations - Three and Nine Months Ended September 30, 2020 and 2019		4
	Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, 2020 and 2019		5
	Consolidated Balance Sheets - as of September 30, 2020 and December 31, 2019		6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2020 and 2019		7
	Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 30, 2020 and 2019		9
	Notes to Consolidated Financial Statements		11
	Note 1	General	11
	Note 2	Impairments	12
	Note 3	Debt	16
	Note 4	Stockholders’ Equity	17
	Note 5	Risk Management	18
	Note 6	Revenue Recognition	24
	Note 7	Reportable Segments	27
	Note 8	Income Taxes	28
	Note 9	Litigation and Environmental	29
	Note 10	Recent Accounting Pronouncements	34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		35
	Results of Operations		36
	Overview		36
	Consolidated Earnings Results (GAAP)		39
	Non-GAAP Financial Measures		42
	Segment Earnings Results		45
	General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		53
	Income Taxes		54
	Liquidity and Capital Resources		54
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		59
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		60
Item 4.	Controls and Procedures		60
	PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings		60
Item 1A.	Risk Factors		60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		60
Item 3.	Defaults Upon Senior Securities		60
Item 4.	Mine Safety Disclosures		60
Item 5.	Other Information		60
Item 6.	Exhibits		61
	Signature		62

1

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	=	SFPP, L.P.
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	SNG	=	Southern Natural Gas Company, L.L.C.
KMI	=	Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries	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
/d	=	per day	EPA	=	U.S. Environmental Protection Agency
BBtu	=	billion British Thermal Units	FASB	=	Financial Accounting Standards Board
Bcf	=	billion cubic feet	FERC	=	Federal Energy Regulatory Commission
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	GAAP	=	U.S. Generally Accepted Accounting Principles
			LLC	=	limited liability company
CO2	=	carbon dioxide or our CO2 business segment	LIBOR	=	London Interbank Offered Rate
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
DCF	=	distributable cash flow	MMtons	=	million tons
DD&A	=	depreciation, depletion and amortization	NGL	=	natural gas liquids
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
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

2

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “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 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, express or implied, concerning, without limitation: the long-term demand for our assets and services, the future impact on our business of the global economic consequences of the COVID-19 pandemic, and our expected 2020 outlook, including our expected DCF, Adjusted EBITDA, and Net Debt-to-Adjusted EBITDA ratio.

The impacts of COVID-19 and decreases in commodity prices resulting from oversupply and demand weakness are discussed 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” 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, “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 to the extent such other factors are modified or superseded by the descriptions in subsequent reports.

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

3

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts, unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues
Services	$	1,881	$	2,014	$	5,664	$	6,060
Commodity sales	982		1,154		2,772		3,659
Other	56		46		149		138
Total Revenues	2,919		3,214		8,585		9,857
Operating Costs, Expenses and Other
Costs of sales	655		762		1,759		2,487
Operations and maintenance	643		668		1,869		1,912
Depreciation, depletion and amortization	539		578		1,636		1,750
General and administrative	153		154		461		456
Taxes, other than income taxes	100		103		295		324
Loss (gain) on impairments and divestitures, net (Note 2)	11		(3)		1,987		(13)
Other (income) expense, net	(1)		1		(2)		(1)
Total Operating Costs, Expenses and Other	2,100		2,263		8,005		6,915
Operating Income	819		951		580		2,942
Other Income (Expense)
Earnings from equity investments	194		173		562		526
Amortization of excess cost of equity investments	(32)		(21)		(99)		(61)
Interest, net	(383)		(447)		(1,214)		(1,359)
Other, net	14		12		32		35
Total Other Expense	(207)		(283)		(719)		(859)
Income (Loss) Before Income Taxes	612		668		(139)		2,083
Income Tax Expense	(140)		(151)		(304)		(471)
Net Income (Loss)	472		517		(443)		1,612
Net Income Attributable to Noncontrolling Interests	(17)		(11)		(45)		(32)
Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	455	$	506	$	(488)	$	1,580
Class P Shares
Basic and Diluted Earnings (Loss) Per Common Share	$	0.20	$	0.22	$	(0.22)	$	0.69
Basic and Diluted Weighted Average Common Shares Outstanding	2,263		2,264		2,263		2,263

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

4

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In millions, unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Net income (loss)	$	472	$	517	$	(443)	$	1,612
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 $—, $2, $—, and $(5), respectively)	—		(7)		1		16
Benefit plan adjustments (net of tax expense of $2, $3, $7 and $8, respectively)	5		8		21		23
Total other comprehensive (loss) income	(56)		61		78		(58)
Comprehensive income (loss)	416		578		(365)		1,554
Comprehensive income attributable to noncontrolling interests	(17)		(8)		(45)		(28)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$	399	$	570	$	(410)	$	1,526

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

5

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except per share amounts, unaudited)

	September 30, 2020		December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	$	632	$	185
Restricted deposits	67		24
Marketable securities at fair value	—		925
Accounts receivable	1,142		1,379
Fair value of derivative contracts	257		84
Inventories	317		371
Other current assets	257		270
Total current assets	2,672		3,238
Property, plant and equipment, net	35,958		36,419
Investments	8,014		7,759
Goodwill	19,851		21,451
Other intangibles, net	2,510		2,676
Deferred income taxes	671		857
Deferred charges and other assets	2,145		1,757
Total Assets	$	71,821	$	74,157
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,057	$	2,477
Accounts payable	774		914
Accrued interest	351		548
Accrued taxes	335		364
Accrued contingencies	315		89
Other current liabilities	544		708
Total current liabilities	4,376		5,100
Long-term liabilities and deferred credits
Long-term debt
Outstanding	31,281		30,883
Debt fair value adjustments	1,379		1,032
Total long-term debt	32,660		31,915
Other long-term liabilities and deferred credits	2,093		2,253
Total long-term liabilities and deferred credits	34,753		34,168
Total Liabilities	39,129		39,268
Commitments and contingencies (Notes 3 and 9)
Redeemable Noncontrolling Interest	747		803
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
Additional paid-in capital	41,736		41,745
Accumulated deficit	(9,945)		(7,693)
Accumulated other comprehensive loss	(255)		(333)
Total Kinder Morgan, Inc.’s stockholders’ equity	31,559		33,742
Noncontrolling interests	386		344
Total Stockholders’ Equity	31,945		34,086
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	71,821	$	74,157

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

6

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
	Nine Months Ended September 30,
	2020		2019
Cash Flows From Operating Activities
Net (loss) income	$	(443)	$	1,612
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	1,636		1,750
Deferred income taxes	164		254
Amortization of excess cost of equity investments	99		61
Loss (gain) on impairments and divestitures, net (Note 2)	1,987		(13)
Earnings from equity investments	(562)		(526)
Distributions from equity investment earnings	487		412
Changes in components of working capital
Accounts receivable	238		224
Inventories	41		(28)
Other current assets	14		97
Accounts payable	(107)		(266)
Accrued interest, net of interest rate swaps	(208)		(218)
Accrued taxes	(25)		(107)
Other current liabilities	(111)		(136)
Other, net	72		5
Net Cash Provided by Operating Activities	3,282		3,121
Cash Flows From Investing Activities
Capital expenditures	(1,351)		(1,719)
Proceeds from sales of assets and investments, net of working capital adjustments	907		80
Contributions to investments	(365)		(1,148)
Distributions from equity investments in excess of cumulative earnings	105		207
Other, net	(72)		(30)
Net Cash Used in Investing Activities	(776)		(2,610)
Cash Flows From Financing Activities
Issuances of debt	3,888		5,118
Payments of debt	(3,991)		(6,303)
Debt issue costs	(23)		(9)
Common stock dividends	(1,764)		(1,593)
Repurchases of common shares	(50)		(2)
Contributions from investment partner and noncontrolling interests	11		138
Distributions to investment partner	(60)		—
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds	—		(879)
Distributions to noncontrolling interests - other	(11)		(42)
Other, net	(13)		(28)
Net Cash Used in Financing Activities	(2,013)		(3,600)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(3)		26
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits	490		(3,063)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	209		3,331
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	699	$	268

7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
	Nine Months Ended September 30,
	2020		2019
Cash and Cash Equivalents, beginning of period	$	185	$	3,280
Restricted Deposits, beginning of period	24		51
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	209		3,331
Cash and Cash Equivalents, end of period	632		241
Restricted Deposits, end of period	67		27
Cash, Cash Equivalents, and Restricted Deposits, end of period	699		268
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits	$	490	$	(3,063)
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	$	15	$	764
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,440		1,584
Cash paid during the period for income taxes, net	202		364

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

8

KINDER MORGAN, INC. AND SUBSIDIARIES

 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions, unaudited)

	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at June 30, 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
Common stock 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

	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										—		(14)		(14)
Contributions										—		2		2
Common stock dividends						(569)				(569)				(569)
Other										—		(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

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

9

KINDER MORGAN, INC. AND SUBSIDIARIES

 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)

(In millions, unaudited)

	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at December 31, 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										—		(11)		(11)
Contributions										—		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, 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										—		(42)		(42)
Contributions										—		3		3
Common stock dividends						(1,593)				(1,593)				(1,593)
Other										—		(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

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

10

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

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

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2019 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, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO₂; and (vi) Terminals. See Note 2 for results of our May 31, 2020 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.

11

Earnings per Share

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

The following table sets forth the allocation of net 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

________

(a)As of September 30, 2020, 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,
	2020	2019	2020	2019
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	3	3	3	3

2. Impairments

During the first quarter of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented triggering events that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO₂ business segment and conducted interim tests of the recoverability of goodwill for our CO₂ and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020, which resulted in impairments of long-lived assets and goodwill within our CO₂ business 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, resulted in the recognition of a goodwill impairment for that reporting unit during the three months ended June 30, 2020.

12

We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assets 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	$	—
Impairments of inventory	11		—
Gain on divestitures of long-lived assets	—		(10)
Products Pipelines
Impairment of long-lived and intangible assets	21		—
Terminals
Impairment of long-lived and intangible assets	5		—
Gain on divestitures of long-lived assets	—		(3)
CO2
Impairment of goodwill	600		—
Impairment of long-lived assets	350		—
Kinder Morgan Canada
Loss on divestiture of long-lived assets	—		2
Other gain on divestitures of long-lived assets	—		(2)
Pre-tax loss (gain) on divestitures and impairments, net	$	1,987	$	(13)

Long-lived Assets

As of March 31, 2020, for our CO₂ 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.

•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 CO₂ source and transportation assets, volume forecasts were developed based on projected demand for our CO₂ services based upon management’s projections of the availability of CO₂ supply and the future demand for CO₂ for use in enhanced oil recovery projects. The CO₂ 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 CO₂ 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.

13

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	—		(1,000)		(600)		—		—		—		(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 CO₂ reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO₂ 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 CO₂ business, 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 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 goodwill impairment test of the CO₂ reporting unit, we applied an 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 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.

14

In determining the fair value for our CO₂ reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO₂ reporting unit of approximately $600 million as of March 31, 2020.

The fair value estimates used 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.

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.

15

3. 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	$	—	$	—
Commercial paper notes(a)	—		37
Current portion of senior notes
6.85%, due February 2020(b)	—		700
6.50%, due April 2020(c)	—		535
5.30%, due September 2020(d)	—		600
6.50%, due September 2020(d)	—		349
5.00%, due February 2021	750		—
3.50%, due March 2021	750		—
5.80%, due March 2021	400		—
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)	—		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

_______

(a)Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.

(b)On January 9, 2020, we sold the approximate 25 million shares 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.

(c)In April 2020, we repaid $535 million of maturing senior notes.

(d)In September 2020, we repaid a combined $949 million of maturing senior notes using proceeds from our newly issued senior notes.

(e)In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020.

(f)Excludes our “Debt fair value adjustments” which, as of September 30, 2020 and December 31, 2019, increased our total debt balances by $1,379 million and $1,032 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, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% 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 and received net proceeds of $991 million.

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

16

Credit Facility

As of September 30, 2020, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of September 30, 2020 was $3,919 million. As of September 30, 2020, 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

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

4. 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.

17

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)	$	—	$	(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)

	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		—		—		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)

5.  Risk Management

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

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.

18

Energy Commodity Price Risk Management

As of September 30, 2020, 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)	MMBbl
Crude oil basis	(2.6)	MMBbl
Natural gas fixed price	(34.8)	Bcf
Natural gas basis	(34.8)	Bcf
NGL fixed price	(1.2)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(2.4)	MMBbl
Crude oil basis	(0.9)	MMBbl
Natural gas fixed price	(9.7)	Bcf
Natural gas basis	2.2	Bcf
NGL fixed price	(1.4)	MMBbl

As of September 30, 2020, 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.

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:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	7,625	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		Mark-to-Market	December 2021

_______

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

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:

	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.

19

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)		—
	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)	—		—		(14)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	70		46		—		—
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		—		(1)		—
Subtotal		25		8		(11)		(7)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(3)		—
Subtotal		—		—		(3)		—
Total		25		8		(14)		(7)
Total derivatives		$	1,025	$	460	$	(68)	$	(65)

20

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

	Balance sheet asset fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
	(In millions)
As of September 30, 2020
Energy commodity derivative contracts(a)	$	3	$	184	$	—	$	187	$	(28)	$	—	$	159
Interest rate contracts	—		768		—		768		(2)		—		766
Foreign currency contracts	—		70		—		70		(14)		—		56
As of December 31, 2019
Energy commodity derivative contracts(a)	$	19	$	37	$	—	$	56	$	(19)	$	(21)	$	16
Interest rate contracts	—		358		—		358		—		—		358
Foreign currency contracts	—		46		—		46		(6)		—		40

	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)	$	—	$	(40)	$	28	$	8	$	(4)
Interest rate contracts	—		(14)		—		(14)		2		—		(12)
Foreign currency contracts	—		(14)		—		(14)		14		—		—
As of December 31, 2019
Energy commodity derivative contracts(a)	$	(3)	$	(55)	$	—	$	(58)	$	19	$	—	$	(39)
Interest rate contracts	—		(1)		—		(1)		—		—		(1)
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)

_______

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

21

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,
	2020		2019			2020		2019
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(143)	$	96	Revenues—Commodity sales	$	(47)	$	9
					Costs of sales	(7)		(3)
Interest rate contracts	—		(1)		Earnings from equity investments(c)	(1)		—
Foreign currency contracts	70		(69)		Other, net	61		(59)
Total	$	(73)	$	26	Total	$	6	$	(53)

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)

_______

(a)We expect to reclassify an approximate $68 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2020 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, we recognized a $12 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	$	—	$	—	$	—	$	(8)
Total	$	—	$	—	$	—	$	(8)

22

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		—		18		(3)
	Earnings from equity investments(b)	—		—		—		2
Total(a)		$	99	$	12	$	371	$	35

_______

(a)The three and nine months ended September 30, 2020 include approximate gains of $96 million and $349 million, respectively, and the three and nine months ended September 30, 2019 include an approximate loss of $4 million and $2 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 and December 31, 2019, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2020, we had cash margins of $32 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. As of December 31, 2019, we had cash margins of $15 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at September 30, 2020 represents the net of our initial margin requirements of $24 million and counterparty variation margin requirements of $8 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, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post additional collateral.

23

6. Revenue Recognition

Disaggregation of Revenues

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

	Three Months Ended 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	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

24

	Three 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)	$	882	$	89	$	256	$	1	$	(1)	$	1,227
Fee-based services	182		265		132		14		—		593
Total services	1,064		354		388		15		(1)		1,820
Commodity sales
Natural gas sales	618		—		—		—		(1)		617
Product sales	162		84		9		268		(7)		516
Total commodity sales	780		84		9		268		(8)		1,133
Total revenues from contracts with customers	1,844		438		397		283		(9)		2,953
Other revenues(c)
Leasing services	57		45		111		13		—		226
Derivatives adjustments on commodity sales	23		—		—		(1)		(1)		21
Other	10		1		—		3		—		14
Total Other revenues	90		46		111		15		(1)		261
Total revenues	$	1,934	$	484	$	508	$	298	$	(10)	$	3,214

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

25

	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		—		1,756
Total services	3,262		1,005		1,183		46		(3)		5,493
Commodity sales
Natural gas sales	1,979		—		—		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		—		660
Derivatives adjustments on commodity sales	61		—		—		(10)		—		51
Other	35		5		—		10		—		50
Total Other revenues	263		134		325		39		—		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 recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.

Contract Balances

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

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

26

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 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2020	$	1,152
2021	4,102
2022	3,344
2023	2,715
2024	2,361
Thereafter	14,722
Total	$	28,396

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 that we elected to apply, remaining performance obligations for: (i) 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.

7.  Reportable Segments

Financial information by segment follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,803	$	1,925	$	5,229	$	6,073
Intersegment revenues	6		9		26		30
Products Pipelines	442		484		1,282		1,350
Terminals
Revenues from external customers	423		507		1,282		1,521
Intersegment revenues	1		1		3		3
CO2	251		298		792		913
Corporate and intersegment eliminations	(7)		(10)		(29)		(33)
Total consolidated revenues	$	2,919	$	3,214	$	8,585	$	9,857

27

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,091	$	1,092	$	2,284	$	3,383
Products Pipelines	223		325		719		908
Terminals	246		295		732		884
CO2	156		164		(453)		558
Kinder Morgan Canada	—		—		—		(2)
Total Segment EBDA	1,716		1,876		3,282		5,731
DD&A	(539)		(578)		(1,636)		(1,750)
Amortization of excess cost of equity investments	(32)		(21)		(99)		(61)
General and administrative and corporate charges	(150)		(162)		(472)		(478)
Interest, net	(383)		(447)		(1,214)		(1,359)
Income tax expense	(140)		(151)		(304)		(471)
Total consolidated net income (loss)	$	472	$	517	$	(443)	$	1,612

	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

_______

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

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

8.  Income Taxes

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

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

The effective tax rate 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, 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. While we would normally expect a federal income tax benefit from our loss before income taxes, 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

28

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.

9.   Litigation and Environmental

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

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

On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return 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

The tariffs and rates charged by SFPP 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 period preceding the filing date of their complaints (OR cases) and/or prospective refunds in protest cases from the

29

date of protest (IS cases), and SFPP may be required to reduce its rates going forward. 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 the extent the shippers are successful in one or more of the 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 in rate reductions and refunds substantially lower than those sought by the shippers.

EPNG FERC Proceedings

The tariffs and rates charged by EPNG are subject to two 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) 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.

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 delivered its Award, and the panel's ruling called for the termination of the agreement and Eni USA's payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On 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 Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending.

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seeks to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. The Delaware cross appeals were argued to the Delaware Supreme Court on September 9, 2020. The arbitration proceeding remains pending, but has been stayed by agreement pending the Delaware Supreme Court’s decision.

30

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), 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 a declaration 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 rise to a contractual right on the part of ALSS to terminate the agreement.  ALSS also seeks 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 arbitration is expected by the end of the second quarter of 2021.

GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.

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

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties).  CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies and will vigorously defend against these claims.

Pipeline Integrity and Releases

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

General

As of September 30, 2020 and December 31, 2019, our total reserve for legal matters was $280 million and $203 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, state and local 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 environmental and safety regulations, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act. 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, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater

31

and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the remediation.

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 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. 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. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.

Uranium Mines in Vicinity of Cameron, Arizona

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

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

EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.

32

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

In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. We anticipate that process will be completed by December 31, 2020. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the allocation process and FS are completed, and the RI/FS is finalized, we are unable to reasonably estimate the extent of our potential liability.

Louisiana Governmental Coastal Zone Erosion Litigation

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

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Court of Appeals. 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 two cases against TGP, two cases against SNG, and two cases against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees,

33

interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. 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 and December 31, 2019, we have accrued a total reserve for environmental liabilities in the amount of $253 million and $259 million, respectively. In addition, as of September 30, 2020 and December 31, 2019, we have recorded a receivable of $12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable.

10. 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

On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.”  This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate.  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. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2020-06

On August 5, 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year ending December 31, 2021, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

34

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 (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2019 Form 10-K.

Sale of U.S. Portion of Cochin Pipeline and KML

On December 16, 2019, we closed on two cross-conditional transactions resulting in the sale 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 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.

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.

The events 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 value 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 in our CO₂ business segment and goodwill impairments of $1,000 million and $600 million to our Natural Gas Pipelines Non-Regulated and CO₂ reporting units, respectively. For a further discussion of these impairments and our risk for future impairments, see Note 2, “Impairments.”

We have placed 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 tasks in our operations and have taken a cautious enterprise-wide approach with a phased return to workplace process for our employees who are currently working remotely. During 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 screening and other measures we adopted to protect our employees. We continue to operate our assets safely and efficiently during this challenging period.

2020 Outlook

As previously announced, for 2020 our original budget contemplated DCF of approximately $5.1 billion ($2.24 per common share) 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.

Market conditions also negatively impacted a number of planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. We therefore expect the budgeted $2.4 billion 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,

35

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 expectations for 2020 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.

Results of Operations

Overview

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

GAAP Financial Measures

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

Non-GAAP Financial Measures

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

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in net income (loss), 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) (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 “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

36

Adjusted Earnings

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

37

Net Debt

Net Debt is calculated by subtracting from debt (i) cash and cash equivalents; (ii) the preferred interest in the general partner of KMP (which was redeemed in January 2020); (iii) debt fair value adjustments; and (iv) the foreign exchange impact on Euro-denominated bonds 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.

38

Consolidated Earnings Results (GAAP)

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

	Three Months Ended September 30,
	2020		2019		Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,091	$	1,092	$	(1)	—	%
Products Pipelines	223		325		(102)		(31)	%
Terminals	246		295		(49)		(17)	%
CO2	156		164		(8)		(5)	%
Total Segment EBDA	1,716		1,876		(160)		(9)	%
DD&A	(539)		(578)		39		7	%
Amortization of excess cost of equity investments	(32)		(21)		(11)		(52)	%
General and administrative and corporate charges	(150)		(162)		12		7	%
Interest, net	(383)		(447)		64		14	%
Income before income taxes	612		668		(56)		(8)	%
Income tax expense	(140)		(151)		11		7	%
Net income	472		517		(45)		(9)	%
Net income attributable to noncontrolling interests	(17)		(11)		(6)		(55)	%
Net income attributable to Kinder Morgan, Inc.	$	455	$	506	$	(51)	(10)	%

	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)	%

_______

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

39

Income (loss) before income taxes decreased $56 million and $2,222 million for the three and nine months ended September 30, 2020, respectively, as compared to the respective prior year periods. The decreases in results were impacted by lower earnings from our Products Pipelines and Terminals in the comparative three-month periods and from all of our business segments in the comparative nine-month periods 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 our Natural Gas Pipelines and Terminals business segments, partially offset by the benefit of completed expansion projects in our Natural Gas Pipelines business segment and by lower interest expense and DD&A expense. The year-to-date decrease also included a combined $1.95 billion of non-cash impairments of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO₂ reporting units and non-cash impairments of certain oil and gas producing assets in our CO₂ business segment.

Certain Items Affecting Consolidated Earnings Results

	Three 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	$	1,091	$	(9)	$	1,082	$	1,092	$	(2)	$	1,090	$	(8)
Products Pipelines	223		46		269		325		11		336		(67)
Terminals	246		—		246		295		—		295		(49)
CO2	156		(2)		154		164		(15)		149		5
Total Segment EBDA(a)	1,716		35		1,751		1,876		(6)		1,870		(119)
DD&A and amortization of excess cost of equity investments	(571)		—		(571)		(599)		—		(599)		28
General and administrative and corporate charges(a)	(150)		11		(139)		(162)		5		(157)		18
Interest, net(a)	(383)		(8)		(391)		(447)		(5)		(452)		61
Income before income taxes	612		38		650		668		(6)		662		(12)
Income tax expense(b)	(140)		(8)		(148)		(151)		8		(143)		(5)
Net income	472		30		502		517		2		519		(17)
Net income attributable to noncontrolling interests(a)	(17)		—		(17)		(11)		—		(11)		(6)
Net income attributable to Kinder Morgan, Inc.	$	455	$	30	$	485	$	506	$	2	$	508	$	(23)

40

	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)

_______

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

(b)The combined net effect of the 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 by $23 million and $165 million for the three and nine months ended September 30, 2020, respectively, as compared to the respective prior year periods. Decreases in Adjusted Segment EBDA from the prior quarter and year-to-date periods were primarily due to lower 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 and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and Terminals business segments, partially offset by the benefit of completed expansion projects in our Natural Gas Pipelines business segment.

41

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,
	2020		2019		2020		2019
	(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	455	$	506	$	(488)	$	1,580
Total Certain Items	30		2		1,895		(8)
Adjusted Earnings(a)	485		508		1,407		1,572
DD&A and amortization of excess cost of equity investments for DCF(b)	662		694		2,012		2,093
Income tax expense for DCF(a)(b)	171		164		484		521
Cash taxes(c)	(49)		(12)		(57)		(76)
Sustaining capital expenditures(c)	(177)		(173)		(477)		(477)
Other items(d)	(7)		(41)		(22)		6
DCF	$	1,085	$	1,140	$	3,347	$	3,639

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

_______

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

(b)Includes DD&A or income tax expense, as applicable, 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. 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.

42

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

Reconciliation of Net Income (Loss) (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

______

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

(b)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 are reported within “Loss (gain) on impairments and divestitures, net” on our Consolidated Earnings Results (GAAP) table above.

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

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

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

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

43

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

44

	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)

______

(a)Amounts are adjusted for Certain Items.

(b)Amounts are associated with our Citrus, NGPL and Plantation 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

_______

Certain Items affecting Segment EBDA

(a)Includes revenue Certain Item amounts of $(4) million and $(5) million for the three and nine months ended September 30, 2020, respectively, and $(1) million for both three and nine months ended September 30, 2019 which includes $(14) million of amortization of

45

regulatory liabilities (three and nine months 2020), partially offset by 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 of $(5) million and $998 million for the three and nine months ended September 30, 2020, respectively, and $(1) million and $(20) million for the three and nine months ended September 30, 2019, respectively. Nine-month 2020 amount primarily resulted from 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)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.

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

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

	Adjusted Segment EBDA increase/(decrease)				Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Midstream	$	(68)	(21)	%	$	(208)	(19)	%
West Region	(5)		(2)	%	1		—	%
East Region	65		13	%	77		15	%
Intrasegment eliminations	—		—	%	2		40	%
Total Natural Gas Pipelines	$	(8)	(1)	%	$	(128)	(7)	%

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

	Adjusted Segment EBDA increase/(decrease)				Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Midstream	$	(183)	(18)	%	$	(1,033)	(29)	%
West Region	(19)		(2)	%	4		—	%
East Region	117		7	%	173		11	%
Intrasegment eliminations	—		—	%	4		33	%
Total Natural Gas Pipelines	$	(85)	(3)	%	$	(852)	(14)	%

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 and 2019:

•Midstream’s decreases of $68 million (21%) and $183 million (18%), respectively, 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. These decreases were partially offset by higher equity earnings due to the Gulf Coast Express Pipeline (Gulf Coast) being placed in service in September 2019. Overall Midstream’s revenues decreased in both the three and nine-month periods primarily due to lower commodity prices and volumes which was largely offset by corresponding decreases in costs of sales;

•West Region’s decreases of $5 million (2%) and $19 million (2%), respectively, 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 result of the expiration of one shipper’s contract; and (iii) EPNG driven by higher operating expenses, partially offset by 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 Company, L.L.C. resulting from the liquefaction units of the Elba Liquefaction project being placed into service in the later part of 2019 and through the first eight months of 2020 and increased equity

46

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

_______

Certain Items affecting Segment EBDA

(a)Includes non-revenue Certain Item amounts of $46 million and $50 million for the three and nine months ended September 30, 2020, respectively, and $11 million and $28 million for the three and nine months ended September 30, 2019, respectively. Three and nine-month 2020 amounts both include a $46 million unfavorable rate case reserve adjustment. Nine-month 2020 amount also includes a non-cash loss on impairment of our Belton Terminal of $21 million and 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.

47

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

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

	Adjusted Segment EBDA increase/(decrease)				Adjusted revenues increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	(31)	(21)	%	$	(19)	(10)	%
Crude and Condensate	(27)		(22)	%	1		1	%
Southeast Refined Products	(9)		(13)	%	(24)		(22)	%
Total Products Pipelines	$	(67)	(20)	%	$	(42)	(9)	%

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

	Adjusted Segment EBDA increase/(decrease)				Adjusted revenues increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	(51)	(13)	%	$	(45)	(8)	%
Crude and Condensate	(76)		(21)	%	2		—	%
Southeast Refined Products	(40)		(20)	%	(25)		(8)	%
Total Products Pipelines	$	(167)	(18)	%	$	(68)	(5)	%

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 and 2019:

•West Coast Refined Products’ decreases of $31 million (21%) and $51 million (13%), respectively, were due to decreased earnings on Pacific (SFPP) operations, Calnev Pipe Line LLC and West Coast terminals driven by lower services revenues as a result of a reduction in volumes due to COVID-19;

•Crude and Condensate’s decreases of $27 million (22%) and $76 million (21%), respectively, were primarily due to decreased 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 decreased earnings were primarily driven by lower volumes and reduced re-contracted rates. KMCC and Bakken Crude assets year-to-date decreases were also impacted by unfavorable inventory valuation adjustments driven by declines in commodity prices during the first quarter of 2020; and

•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.

48

Terminals

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(In millions, except operating statistics)
Revenues	$	424		$	508		$	1,285		$	1,524
Operating expenses	(185)			(223)			(570)			(660)
Gain (loss) on divestitures and impairments, net	—			3			(5)			3
Earnings from equity investments	7			6			19			15
Other, net	—			1			3			2
Segment EBDA	246			295			732			884
Certain Items	—			—			—			—
Adjusted Segment EBDA	$	246		$	295		$	732		$	884
Change from prior period	Increase/(Decrease)
Adjusted revenues	$	(84)		(17)		%	$	(239)		(16)		%
Adjusted Segment EBDA	(49)			(17)		%	(152)			(17)		%
Volumetric data(a)
Liquids leasable capacity (MMBbl)	79.4			79.5			79.4			79.5
Liquids utilization %(b)	96.2		%	94.4		%	96.2		%	94.4		%
Bulk transload tonnage (MMtons)	11.3			14.1			35.4			42.0

Other

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

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

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

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

	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)	%

49

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

	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)	%

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 and 2019:

•combined decreases of $36 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%) and $21 million (9%), 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 primarily due to lower revenues driven by lower refinery petroleum coke production and the expiration of a customer contract in January 2020; and

•decreases of $3 million (23%) and $12 million (24%), respectively, from our Mid Atlantic terminals primarily due to lower coal volumes at our Pier IX facility driven by coal market weakness largely attributable to demand reduction associated with COVID-19.

50

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

_______

Certain Items affecting Segment EBDA

(a)Includes revenue Certain Item amounts of $(2) million and $(12) 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 amount of $950 million for the nine months ended September 30, 2020 resulting 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)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 and 2019.

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

	Adjusted Segment EBDA increase/(decrease)				Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing activities	$	27	35	%	$	(10)	(5)	%
Source and Transportation activities	(22)		(31)	%	(28)		(29)	%
Intrasegment eliminations	—		—	%	4		80	%
Total CO2	$	5	3	%	$	(34)	(12)	%

51

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

	Adjusted Segment EBDA increase/(decrease)				Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing activities	$	23	8	%	$	(37)	(6)	%
Source and Transportation activities	(60)		(27)	%	(73)		(25)	%
Intrasegment eliminations	—		—	%	13		72	%
Total CO2	$	(37)	(7)	%	$	(97)	(11)	%

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 and 2019:

•increases of $27 million (35%) and $23 million (8%), respectively, from our Oil and Gas Producing activities primarily due to (i) lower operating expenses of $32 million and $50 million, respectively; and (ii) higher 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; and

•decreases of $22 million (31%) and $60 million (27%), respectively, from our Source and Transportation activities primarily due to decreases of $28 million and $77 million, respectively, related to lower CO₂ sales volumes partially offset by lower operating expenses of $9 million and $22 million, respectively.

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

	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

_______

(a)Includes West Texas Intermediate hedges.

52

General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests

	Three Months Ended September 30,				Earnings increase/(decrease)
	2020		2019
	(In millions, except percentages)
General and administrative (GAAP)	$	(153)	$	(154)	$	1	1	%
Corporate benefit (charges)	3		(8)		11		138	%
Certain Items(a)	11		5		6		120	%
General and administrative and corporate charges(b)	$	(139)	$	(157)	$	18	11	%
Interest, net (GAAP)	$	(383)	$	(447)	$	64	14	%
Certain Items(c)	(8)		(5)		(3)		(60)	%
Interest, net(b)	$	(391)	$	(452)	$	61	13	%
Net income attributable to noncontrolling interests (GAAP)	$	(17)	$	(11)	$	(6)	(55)	%
Certain Items	—		—		—		—	%
Net income attributable to noncontrolling interests(b)	$	(17)	$	(11)	$	(6)	(55)	%

	Nine Months Ended September 30,				Earnings increase/(decrease)
	2020		2019
	(In millions, except percentages)
General and administrative (GAAP)	$	(461)	$	(456)	$	(5)	(1)	%
Corporate charges	(11)		(22)		11		50	%
Certain Items(a)	36		11		25		227	%
General and administrative and corporate charges(b)	$	(436)	$	(467)	$	31	7	%
Interest, net (GAAP)	$	(1,214)	$	(1,359)	$	145	11	%
Certain Items(c)	(8)		(6)		(2)		(33)	%
Interest, net(b)	$	(1,222)	$	(1,365)	$	143	10	%
Net income attributable to noncontrolling interests (GAAP)	$	(45)	$	(32)	$	(13)	(41)	%
Certain Items	—		(1)		1		100	%
Net income attributable to noncontrolling interests(b)	$	(45)	$	(33)	$	(12)	(36)	%

Certain items

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

(b)Amounts are adjusted for Certain Items.

(c)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. Three and nine-month 2019 amounts include (i) decreases in interest expense of $7 million and $22 million, respectively, related to non-cash debt fair value adjustments 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.

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, when compared with the respective prior year periods primarily due to lower non-cash pension expenses of $11 million and $34 million, respectively, lower expenses of $6 million and $27 million, respectively, due to the KML and U.S. Cochin Sale, $7 million and $12 million, respectively, of cost

53

savings associated with reduced business activity during the pandemic, partially offset by lower capitalized costs of $4 million and $43 million, respectively, reflecting the COVID-19-related cutback on capital projects primarily by our CO₂ and 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.

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 when compared with the respective prior year periods decreased $61 million and $143 million, respectively, primarily due to lower weighted average long-term debt balances and lower LIBOR 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 and December 31, 2019, approximately 16% and 27%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. 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 was approximately $140 million as compared with $151 million for the same period of 2019. The $11 million decrease in tax expense was due primarily due to lower pre-tax book income in the 2020 period.

Our tax expense for the nine months ended September 30, 2020 was approximately $304 million as compared with $471 million for the same period of 2019. The $167 million decrease in tax expense was due primarily to (i) lower pre-tax book income in the 2020 period; (ii) lower foreign income taxes as a result of the KML 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, we had $632 million of “Cash and cash equivalents,” an increase of $447 million from December 31, 2019. Additionally, as of September 30, 2020, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flow from operations, providing a source of funds of $3,282 million and $3,121 million in the first nine months of 2020 and 2019, 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; 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 per share for the third quarter of 2020, unchanged from the previous quarter. This represents a 5% increase over 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. We

54

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

On August 5, 2020, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% 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. We used a portion of the proceeds to repay maturing debt.

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 2030 and received net proceeds of $991 million. We used the proceeds to repay maturing debt.

During March 2020, we opportunistically repurchased approximately 3.6 million of our Class P shares for approximately $50 million at an average price including commissions of $13.94 per share.

Short-term Liquidity

As of September 30, 2020, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $4.0 billion revolving credit facility and associated commercial paper program. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Letters of credit and commercial paper borrowings reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations. We do not anticipate any significant limitations from the impacts of COVID-19 with respect to our ability to access funding through our credit facility.

As of September 30, 2020, our $2,057 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 intend to fund our debt, as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2019 was $2,477 million.

We had working capital (defined as current assets less current liabilities) deficits of $1,704 million and $1,862 million as of September 30, 2020 and December 31, 2019, respectively.  Our current liabilities may include short-term borrowings, which we may periodically replace with long-term financing and/or pay down using cash from operations. The overall $158 million favorable change from year-end 2019 was primarily due to (i) an increase in cash and cash equivalents of $447 million; (ii) a decrease of approximately $284 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.; partially offset by a decrease of $925 million related to the sale of Pembina common equity in January 2020. 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 and December 31, 2019, was $25 million and $9 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.”

55

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, and the amount we expect to spend for the remainder of 2020 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

_______

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

(b)Nine months ended September 30, 2020, 2020 Remaining, and Total 2020 amounts include $80 million, $35 million, and $115 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.”

(c)Nine months ended September 30, 2020 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 million of our contributions to certain unconsolidated joint ventures for capital investments.

(e)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 in our 2019 Form 10-K.

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

56

Cash Flows

Operating Activities

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

•a $161 million increase in cash primarily resulting from $202 million of net income tax payments in the 2020 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.

Investing Activities

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

•an $827 million increase in cash primarily due to $907 million of proceeds received from the sale of the Pembina shares in the 2020 period;

•a $783 million decrease in cash used for contributions to equity investments driven by lower contributions to Gulf Coast Express Pipeline LLC, Midcontinent Express Pipeline LLC, Citrus, and Fayetteville Express Pipeline LLC in the 2020 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 million for the nine months ended September 30, 2020 compared to the respective 2019 period primarily attributable to:

•a $1,068 million net decrease in cash used related to debt activity as a result of lower net debt payments in the 2020 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 per share on our common stock for 2020. The table below reflects our 2020 common stock dividends declared:

Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
December 31, 2019	$	0.25	January 22, 2020	February 3, 2020	February 18, 2020
March 31, 2020	0.2625		April 22, 2020	May 4, 2020	May 15, 2020
June 30, 2020	0.2625		July 22, 2020	August 3, 2020	August 17, 2020
September 30, 2020	0.2625		October 21, 2020	November 2, 2020	November 16, 2020

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

57

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 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.

58

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.  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.”

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 and December 31, 2019, the Obligated Group had $32,502 million and $32,409 million, respectively, of Guaranteed Notes outstanding.  

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

Summarized Combined Balance Sheet Information	September 30, 2020		December 31, 2019
	(In millions)
Current assets	$	2,418	$	1,918
Current assets - affiliates	1,073		1,146
Noncurrent assets	62,131		63,298
Noncurrent assets - affiliates	615		441
Total Assets	$	66,237	$	66,803
Current liabilities	$	3,810	$	4,569
Current liabilities - affiliates	1,118		1,139
Noncurrent liabilities	34,320		33,612
Noncurrent liabilities - affiliates	1,057		1,325
Total Liabilities	40,305		40,645
Redeemable noncontrolling interest	747		803
Kinder Morgan, Inc.’s stockholders’ equity	25,185		25,355
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	66,237	$	66,803

Summarized Combined Income Statement Information	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
	(In millions)
Revenues	$	2,653	$	7,840
Operating income	788		1,032
Net income	463		113

59

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

For a discussion of changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2019, in Item 7A in our 2019 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 Item 1, Note 5 “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.

Item 4.  Controls and Procedures.

As of September 30, 2020, 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 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

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

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2019 Form 10-K and in Part II, Item 1A. “Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

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.

Item 5.  Other Information.

None.

60

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.
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 and 2019; (ii) our Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2020 and 2019; (iii) our Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2020 and 2019; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2020 and 2019; 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.

61

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

62

EX-4.1

Exhibit 4.1

KINDER MORGAN, INC.

OFFICERS’ CERTIFICATE

PURSUANT TO SECTION 301 OF INDENTURE

Each of the undersigned, Anthony Ashley and David Michels, the Vice President, Investor Relations and Treasurer and the Vice President and Chief Financial Officer, respectively, of Kinder Morgan, Inc., a Delaware corporation (the “Corporation”), does hereby establish the terms of two separate series of senior debt Securities of the Corporation under the Indenture relating to senior debt Securities, dated as of March 1, 2012 (the “Indenture”), between the Corporation and U.S. Bank National Association, as trustee (the “Trustee”), pursuant to resolutions adopted by the Board of Directors of the Corporation, or a committee thereof, on July 22, 2020 and July 27, 2020 and in accordance with Section 301 of the Indenture, as follows:

1.The titles of the Securities shall be “2.000% Senior Notes due 2031” (the “2031 Notes”) and “3.250% Senior Notes due 2050” (the “2050 Notes” and, together with the 2031 Notes, the “Notes”);

2.The aggregate principal amount of the 2031 Notes and the 2050 Notes that initially may be authenticated and delivered under the Indenture shall be limited to a maximum of $750,000,000 and $500,000,000, respectively, except for Notes authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Notes pursuant to the terms of the Indenture, and except that any additional principal amount of Notes of either series may be issued in the future without the consent of Holders of the Notes of either series so long as such additional principal amount of Notes are authenticated as required by the Indenture;

3.The Notes shall be issued on August 5, 2020; the principal of the 2031 Notes shall be payable on February 15, 2031 and the principal of the 2050 Notes shall be payable on August 1, 2050; and the Notes will not be entitled to the benefit of a sinking fund;

4.The 2031 Notes shall bear interest at the rate of 2.000% per annum and the 2050 Notes shall bear interest at the rate of 3.250% per annum; in each case, which interest shall accrue from August 5, 2020, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, which dates shall be February 15 and August 15 of each year for the 2031 Notes and February 1 and August 1 of each year for the 2050 Notes; such interest on the 2031 Notes shall be payable semiannually in arrears on February 15 and August 15 of each year, commencing February 15, 2021, to holders of record at the close of business on the February 1 or August 1, respectively, preceding each such Interest Payment Date; and such interest on the 2050 Notes shall be payable semiannually in arrears on February 1 and August 1 of each year, commencing February 1, 2021, to holders of record at the close of business on the January 15 or July 15, respectively, preceding each such Interest Payment Date;

5.The principal of, and premium, if any, and interest on, the Notes shall be payable at the office or agency of the Corporation maintained for that purpose in the Borough of Manhattan, New York, New York; provided, however, that at the option of the Corporation, payment of interest may be made from such office in the Borough of Manhattan, New York, New York by check mailed to the address of the person entitled thereto as such address shall appear in the

Exhibit 4.1

Security Register. If at any time there shall be no such office or agency in the Borough of Manhattan, New York, New York, where the Notes may be presented or surrendered for payment, the Corporation shall forthwith designate and maintain such an office or agency in the Borough of Manhattan, New York, New York, in order that the Notes shall at all times be payable in the Borough of Manhattan, New York, New York. The Corporation hereby initially designates the Corporate Trust Office of the Trustee in the Borough of Manhattan, New York, New York, as one such office or agency;

6.U.S. Bank National Association is appointed as the Trustee for the Notes, and U.S. Bank National Association, and any other banking institution hereafter selected by the officers of the Corporation, are appointed agents of the Corporation (a) where the Notes may be presented for registration of transfer or exchange, (b) where notices and demands to or upon the Corporation in respect of the Notes or the Indenture may be made or served and (c) where the Notes may be presented for payment of principal and interest;

7.At any time prior to November 15, 2030 in the case of the 2031 Notes and February 1, 2050 in the case of the 2050 Notes (in each case, the “Early Call Date”), the Notes of the applicable series will be redeemable, at the Corporation’s option, at any time in whole or from time to time in part, at a redemption price, as determined by the Corporation, equal to (a) the greater of: (1) 100% of the principal amount of the Notes to be redeemed; or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes being redeemed that would be due if such Notes matured on the applicable Early Call Date but for the redemption (exclusive of any portion of the payments of interest accrued to the date of redemption), discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Yield (as defined below) plus 25 basis points in the case of the 2031 Notes and 35 basis points in the case of the 2050 Notes, plus (b) accrued and unpaid interest thereon to, but not including, the redemption date.

At any time on or after the applicable Early Call Date, the Notes will be redeemable in whole or in part, at the Corporation’s option, at a redemption price equal to 100% of the principal amount of the Notes to be redeemed plus accrued and unpaid interest thereon, but not including, the redemption date.

“Treasury Yield” means, with respect to any redemption date, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the redemption date.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such Notes (assuming for this purpose, that the Notes mature on the applicable Early Call Date).

“Comparable Treasury Price” means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest

-2-

Exhibit 4.1

and lowest Reference Treasury Dealer Quotations, or (2) if the Independent Investment Banker obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means one of the Reference Treasury Dealers that the Corporation appoints to act as the Independent Investment Banker from time to time.

“Reference Treasury Dealer” means each of (1) BofA Securities, Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC and their respective successors, unless it ceases to be a primary U.S. Government securities dealer in New York City (a “Primary Treasury Dealer”), in which case the Corporation will substitute another Primary Treasury Dealer, (2) a Primary Treasury Dealer selected by MUFG Securities Americas Inc. and its successors and (3) any other Primary Treasury Dealer the Corporation selects.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the applicable Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

Notice of redemption will be mailed or electronically delivered at least 30 but not more than 60 days before the redemption date to each holder of record of the Notes to be redeemed at its registered address. The notice of redemption for the Notes will state, among other things, the amount of the Notes to be redeemed, the redemption date, the manner in which the redemption price will be calculated and the place or places that payment will be made upon presentation and surrender of the Notes to be redeemed. Unless the Corporation defaults in the payment of the redemption price, interest will cease to accrue on any of the Notes that have been called for redemption on the redemption date. If less than all of the Notes are to be redeemed, the Notes to be redeemed shall be selected according to the procedures of The Depository Trust Company, in the case of Notes represented by a global note, or by lot, in the case of Notes that are not represented by a global note.

8.Payment of principal of, and interest on, the Notes shall be without deduction for taxes, assessments or governmental charges paid by Holders of the Notes;

9.The Notes shall be issuable only in registered form without coupons in minimum denominations of U.S. $2,000 and integral multiples of U.S. $1,000 in excess thereof.

10.The Notes are approved in the forms attached hereto as Exhibit A and Exhibit B and shall be issued upon original issuance in whole in the form of one or more book-entry Global Securities, and the Depositary shall be The Depository Trust Company; and

11.The Notes shall be entitled to the benefits of the Indenture, including the covenants and agreements of the Corporation set forth therein, except to the extent expressly otherwise provided herein or in the Notes.

Any initially capitalized terms not otherwise defined herein shall have the meanings ascribed to such terms in the Indenture.

-3-

Exhibit 4.1

IN WITNESS WHEREOF, each of the undersigned has hereunto signed his name this 5^th day of August, 2020.

/s/ Anthony Ashley    

Anthony Ashley

Vice President, Investor Relations and Treasurer

/s/ David Michels    

David Michels

Vice President and Chief Financial Officer

[Signature Page to Officers’ Certificate Establishing Terms of the Notes]

Exhibit 4.1

EXHIBIT A

[FORM OF GLOBAL NOTE]

THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITARY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE TRANSFERRED TO, OR REGISTERED OR EXCHANGED FOR SECURITIES REGISTERED IN THE NAME OF, ANY PERSON OTHER THAN THE DEPOSITARY OR A NOMINEE THEREOF AND NO SUCH TRANSFER MAY BE REGISTERED, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE. EVERY SECURITY AUTHENTICATED AND DELIVERED UPON REGISTRATION OF TRANSFER OF, OR IN EXCHANGE FOR OR IN LIEU OF, THIS SECURITY SHALL BE A GLOBAL SECURITY SUBJECT TO THE FOREGOING, EXCEPT IN SUCH LIMITED CIRCUMSTANCES.

UNLESS THIS SECURITY IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION, TO THE CORPORATION OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY SECURITY ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR SUCH OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (AND ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL IN AS MUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.

KINDER MORGAN, INC.

NO. [__]	2.000% NOTE DUE 2031	U.S.$[________]
CUSIP No. [___________]

KINDER MORGAN, INC., a Delaware corporation (herein called the “Corporation,” which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO., or registered assigns, the principal sum of [________] United States Dollars (U.S.$ [________]) on [__________], 20[__], and to pay interest thereon from August 5, 2020, or from the most recent Interest Payment Date to which interest has been paid, semi-annually in arrears on February 15 and August 15 in each year, commencing February 15, 2021 at the rate of 2.000% per annum, until the principal hereof is paid. The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year. The amount of interest payable for any partial period shall be computed on the basis of a 360-day year of twelve 30-day months and the days elapsed in any partial month. In the event that any date on which interest is payable on this Security is not a Business Day, then a payment of the interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay) with the same force and effect as if made on the date the payment was originally

Exhibit 4.1

payable. A “Business Day” shall mean, when used with respect to any Place of Payment, each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banking institutions in that Place of Payment are authorized or obligated by law, executive order or regulation to close. The interest so payable, and punctually paid, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest, which shall be the February 1 or August 1 (regardless of whether or not a Business Day), as the case may be, next preceding such Interest Payment Date. Any such interest not so punctually paid shall forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice of which shall be given to Holders of Securities of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange or automated quotation system on which the Securities of this series may be listed or traded, and upon such notice as may be required by such exchange or automated quotation system, all as more fully provided in such Indenture.

The principal of (and premium, if any) and interest on, this Security shall be payable at the office or agency of the Corporation maintained for that purpose in the Borough of Manhattan, New York, New York; provided, however, that at the option of the Corporation, payment of interest may be made from such office in the Borough of Manhattan, New York, New York by check mailed to the address of the person entitled thereto as such address shall appear in the Security Register. If at any time there shall be no such office or agency in the Borough of Manhattan, New York, New York where this Security may be presented or surrendered for payment, the Corporation shall forthwith designate and maintain such an office or agency in the Borough of Manhattan, New York, New York, in order that this Security shall at all times be payable in the Borough of Manhattan, New York, New York. The Corporation hereby initially designates the Corporate Trust Office of the Trustee in the Borough of Manhattan, New York, New York, as one such office or agency.

Payment of the principal of (and premium, if any) and any such interest on this Security will be made by transfer of immediately available funds to a bank account designated by the Holder in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts.

Reference is hereby made to the further provisions of this Security set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place.

Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Security shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

Exhibit A - 2

Exhibit 4.1

IN WITNESS WHEREOF, the Corporation has caused this instrument to be duly executed.

Dated: August 5, 2020

KINDER MORGAN, INC.,

By:     _____________________________________

    Anthony Ashley

    Vice President, Investor Relations and Treasurer

This is one of the Securities designated therein referred to in the within-mentioned Indenture.

U.S. BANK NATIONAL ASSOCIATION,

As Trustee

By:     _____________________________________

Authorized Signatory

Exhibit 4.1

This Security is one of a duly authorized issue of securities of the Corporation (the “Securities”), issued and to be issued in one or more series under an Indenture dated as of March 1, 2012 relating to senior debt Securities (the “Indenture”), between the Corporation and U.S. Bank National Association, as trustee (the “Trustee”, which term includes any successor trustee under the Indenture), to which Indenture, all indentures supplemental thereto and the Officers’ Certificate pursuant to Section 301 of the Indenture, dated August 5, 2020, relating to the Securities reference is hereby made for a statement of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Corporation, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered. As provided in the Indenture, the Securities may be issued in one or more series, which different series may be issued in various aggregate principal amounts, may mature at different times, may bear interest, if any, at different rates, may be subject to different redemption provisions, if any, may be subject to different sinking, purchase or analogous funds, if any, may be subject to different covenants and Events of Default and may otherwise vary as in the Indenture provided or permitted. This Security is one of the series designated on the face hereof, originally issued in book-entry only form in the aggregate principal amount of $750,000,000. This series of Securities may be reopened for issuances of additional Securities without the consent of Holders.

At any time prior to November 15, 2030 (the “Early Call Date”), the Securities will be redeemable, at the Corporation’s option, at any time in whole or from time to time in part, at a redemption price, as determined by the Corporation, equal to (a) the greater of: (1) 100% of the principal amount of the Securities to be redeemed; or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the Securities being redeemed that would be due if such Securities matured on the Early Call Date but for the redemption (exclusive of any portion of the payments of interest accrued to the date of redemption), discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Yield (as defined below) plus 25 basis points, plus (b) accrued and unpaid interest thereon to, but not including, the redemption date.

At any time on or after the Early Call Date, the Securities will be redeemable in whole or in part, at the Corporation’s option, at a redemption price equal to 100% of the principal amount of the Securities to be redeemed plus accrued and unpaid interest thereon to, but not including, the redemption date.

“Treasury Yield” means, with respect to any redemption date, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the redemption date.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Securities to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such Securities (assuming for this purpose, that the Securities mature on the Early Call Date).

Exhibit 4.1

“Comparable Treasury Price” means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (2) if the Independent Investment Banker obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means one of the Reference Treasury Dealers that the Corporation appoints to act as the Independent Investment Banker from time to time.

“Reference Treasury Dealer” means each of (1) BofA Securities, Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC and their respective successors, unless it ceases to be a primary U.S. Government securities dealer in New York City (a “Primary Treasury Dealer”), in which case the Corporation will substitute another Primary Treasury Dealer, (2) a Primary Treasury Dealer selected by MUFG Securities Americas Inc. and its successors and (3) any other Primary Treasury Dealer the Corporation selects.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the applicable Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

Notice of redemption will be mailed or electronically delivered at least 30 but not more than 60 days before the redemption date to each holder of record of the Securities to be redeemed at its registered address. The notice of redemption for the Securities will state, among other things, the amount of the Securities to be redeemed, the redemption date, the manner in which the redemption price will be calculated and the place or places that payment will be made upon presentation and surrender of the Securities to be redeemed. Unless the Corporation defaults in the payment of the redemption price, interest will cease to accrue on any of the Securities that have been called for redemption on the redemption date. If less than all of the Securities are to be redeemed, the Securities to be redeemed shall be selected according to the procedures of The Depository Trust Company, in the case of Securities represented by a global note, or by lot, in the case of Securities that are not represented by a global note.

In the event of redemption of this Security in part only, a new Security or Securities of this series and of like tenor for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the cancellation hereof.

If an Event of Default with respect to Securities of this series shall occur and be continuing, the principal of, and any premium and accrued but unpaid interest on, the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture.

The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Corporation and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Corporation and the Trustee with the consent of not less than the Holders of a majority in aggregate principal

Exhibit A - 5

Exhibit 4.1

amount of the Outstanding Securities of all series to be affected (voting as one class). The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Outstanding Securities of all affected series (voting as one class), on behalf of the Holders of all Securities of such series, to waive compliance by the Corporation with certain provisions of the Indenture. The Indenture permits, with certain exceptions as therein provided, the Holders of a majority in principal amount of Securities of any series then Outstanding to waive past defaults under the Indenture with respect to such series and their consequences. Any such consent or waiver by the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Security.

As provided in and subject to the provisions of the Indenture, the Holder of this Security shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default with respect to the Securities of this series, the Holders of not less than 25% in principal amount of the Securities of this series at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity and the Trustee shall not have received from the Holders of a majority in principal amount of Securities of this series at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such proceeding, for 90 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Security for the enforcement of any payment of principal hereof or any premium or interest hereon on or after the respective due dates expressed herein.

No reference herein to the Indenture and no provision of this Security or of the Indenture shall, without the consent of the Holder, alter or impair the obligation of the Corporation, which is absolute and unconditional, to pay the principal of and any premium and interest on this Security at the times, place(s) and rate, and in the coin or currency, herein prescribed.

This Security shall be entitled to the benefits of the Indenture, including the covenants and agreements of the Corporation set forth therein, except to the extent expressly otherwise set forth herein.

This Global Security or portion hereof may not be exchanged for Definitive Securities of this series except in the limited circumstances provided in the Indenture.

The Holders of beneficial interests in this Global Security will not be entitled to receive physical delivery of Definitive Securities except as described in the Indenture and will not be considered the Holders thereof for any purpose under the Indenture.

The Securities of this series are issuable only in registered form without coupons in minimum denominations of U.S. $2,000 and integral multiples of U.S. $1,000 in excess thereof. As provided in the Indenture and subject to certain limitations therein set forth, Securities of this series are exchangeable for a like aggregate principal amount of Securities of this series and of like tenor of a different authorized denomination, as requested by the Holder surrendering the same.

Exhibit A - 6

Exhibit 4.1

No service charge shall be made for any such registration of transfer or exchange, but the Corporation may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

Prior to due presentment of this Security for registration of transfer, the Corporation, the Trustee and any agent of the Corporation or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security is overdue, and neither the Corporation, the Trustee nor any such agent shall be affected by notice to the contrary.

Obligations of the Corporation under the Indenture and the Securities thereunder, including this Security, are non-recourse to the Corporation’s Affiliates, and payable only out of cash flow and assets of the Corporation. The Trustee, and each Holder of a Security by its acceptance hereof, will be deemed to have agreed in the Indenture that (1) none of the Corporation’s Affiliates, nor their respective assets, shall be liable for any of the obligations of the Corporation under the Indenture or such Securities, including this Security, and (2) no director, officer, employee, agent or shareholder, as such, of the Corporation, the Trustee or any of their respective Affiliates shall have any personal liability in respect of the obligations of the Corporation under the Indenture or such Securities by reason of his, her or its status.

The Indenture contains provisions that relieve the Corporation from the obligation to comply with certain restrictive covenants in the Indenture and for satisfaction and discharge at any time of the entire indebtedness upon compliance by the Corporation with certain conditions set forth in the Indenture.

This Security shall be governed by and construed in accordance with the laws of the State of New York.

All terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.

Exhibit A - 7

Exhibit 4.1

EXHIBIT B

[FORM OF GLOBAL NOTE]

THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITARY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE TRANSFERRED TO, OR REGISTERED OR EXCHANGED FOR SECURITIES REGISTERED IN THE NAME OF, ANY PERSON OTHER THAN THE DEPOSITARY OR A NOMINEE THEREOF AND NO SUCH TRANSFER MAY BE REGISTERED, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE. EVERY SECURITY AUTHENTICATED AND DELIVERED UPON REGISTRATION OF TRANSFER OF, OR IN EXCHANGE FOR OR IN LIEU OF, THIS SECURITY SHALL BE A GLOBAL SECURITY SUBJECT TO THE FOREGOING, EXCEPT IN SUCH LIMITED CIRCUMSTANCES.

UNLESS THIS SECURITY IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION, TO THE CORPORATION OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY SECURITY ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR SUCH OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (AND ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL IN AS MUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.

KINDER MORGAN, INC.

NO. [__]	3.250% NOTE DUE 2050	U.S.$[________]
CUSIP No. [___________]

KINDER MORGAN, INC., a Delaware corporation (herein called the “Corporation,” which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO., or registered assigns, the principal sum of [________] United States Dollars (U.S.$ [________]) on [__________], 20[__], and to pay interest thereon from August 5, 2020, or from the most recent Interest Payment Date to which interest has been paid, semi-annually in arrears on February 1 and August 1 in each year, commencing February 1, 2021 at the rate of 3.250% per annum, until the principal hereof is paid. The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year. The amount of interest payable for any partial period shall be computed on the basis of a 360-day year of twelve 30-day months and the days elapsed in any partial month. In the event that any date on which interest is payable on this Security is not a Business Day, then a payment of the interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay) with the same force and effect as if made on the date the payment was originally

Exhibit 4.1

payable. A “Business Day” shall mean, when used with respect to any Place of Payment, each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banking institutions in that Place of Payment are authorized or obligated by law, executive order or regulation to close. The interest so payable, and punctually paid, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest, which shall be the January 15 or July 15 (regardless of whether or not a Business Day), as the case may be, next preceding such Interest Payment Date. Any such interest not so punctually paid shall forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice of which shall be given to Holders of Securities of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange or automated quotation system on which the Securities of this series may be listed or traded, and upon such notice as may be required by such exchange or automated quotation system, all as more fully provided in such Indenture.

The principal of (and premium, if any) and interest on, this Security shall be payable at the office or agency of the Corporation maintained for that purpose in the Borough of Manhattan, New York, New York; provided, however, that at the option of the Corporation, payment of interest may be made from such office in the Borough of Manhattan, New York, New York by check mailed to the address of the person entitled thereto as such address shall appear in the Security Register. If at any time there shall be no such office or agency in the Borough of Manhattan, New York, New York where this Security may be presented or surrendered for payment, the Corporation shall forthwith designate and maintain such an office or agency in the Borough of Manhattan, New York, New York, in order that this Security shall at all times be payable in the Borough of Manhattan, New York, New York. The Corporation hereby initially designates the Corporate Trust Office of the Trustee in the Borough of Manhattan, New York, New York, as one such office or agency.

Payment of the principal of (and premium, if any) and any such interest on this Security will be made by transfer of immediately available funds to a bank account designated by the Holder in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts.

Reference is hereby made to the further provisions of this Security set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place.

Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Security shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

Exhibit B - 2

Exhibit 4.1

IN WITNESS WHEREOF, the Corporation has caused this instrument to be duly executed.

Dated: August 5, 2020

KINDER MORGAN, INC.,

By:     _____________________________________

    Anthony Ashley

    Vice President, Investor Relations and Treasurer

This is one of the Securities designated therein referred to in the within-mentioned Indenture.

U.S. BANK NATIONAL ASSOCIATION,

As Trustee

By:     _____________________________________

Authorized Signatory

Exhibit 4.1

This Security is one of a duly authorized issue of securities of the Corporation (the “Securities”), issued and to be issued in one or more series under an Indenture dated as of March 1, 2012 relating to senior debt Securities (the “Indenture”), between the Corporation and U.S. Bank National Association, as trustee (the “Trustee”, which term includes any successor trustee under the Indenture), to which Indenture, all indentures supplemental thereto and the Officers’ Certificate pursuant to Section 301 of the Indenture, dated August 5, 2020, relating to the Securities reference is hereby made for a statement of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Corporation, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered. As provided in the Indenture, the Securities may be issued in one or more series, which different series may be issued in various aggregate principal amounts, may mature at different times, may bear interest, if any, at different rates, may be subject to different redemption provisions, if any, may be subject to different sinking, purchase or analogous funds, if any, may be subject to different covenants and Events of Default and may otherwise vary as in the Indenture provided or permitted. This Security is one of the series designated on the face hereof, originally issued in book-entry only form in the aggregate principal amount of $500,000,000. This series of Securities may be reopened for issuances of additional Securities without the consent of Holders.

At any time prior to February 1, 2050 (the “Early Call Date”), the Securities will be redeemable, at the Corporation’s option, at any time in whole or from time to time in part, at a redemption price, as determined by the Corporation, equal to (a) the greater of: (1) 100% of the principal amount of the Securities to be redeemed; or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the Securities being redeemed that would be due if such Securities matured on the Early Call Date but for the redemption (exclusive of any portion of the payments of interest accrued to the date of redemption), discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Yield (as defined below) plus 35 basis points, plus (b) accrued and unpaid interest thereon to, but not including, the redemption date.

At any time on or after the Early Call Date, the Securities will be redeemable in whole or in part, at the Corporation’s option, at a redemption price equal to 100% of the principal amount of the Securities to be redeemed plus accrued and unpaid interest thereon to, but not including, the redemption date.

“Treasury Yield” means, with respect to any redemption date, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the redemption date.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Securities to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such Securities (assuming for this purpose, that the Securities mature on the Early Call Date).

Exhibit 4.1

“Comparable Treasury Price” means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (2) if the Independent Investment Banker obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means one of the Reference Treasury Dealers that the Corporation appoints to act as the Independent Investment Banker from time to time.

“Reference Treasury Dealer” means each of (1) BofA Securities, Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC and their respective successors, unless it ceases to be a primary U.S. Government securities dealer in New York City (a “Primary Treasury Dealer”), in which case the Corporation will substitute another Primary Treasury Dealer, (2) a Primary Treasury Dealer selected by MUFG Securities Americas Inc. and its successors and (3) any other Primary Treasury Dealer the Corporation selects.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the applicable Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

Notice of redemption will be mailed or electronically delivered at least 30 but not more than 60 days before the redemption date to each holder of record of the Securities to be redeemed at its registered address. The notice of redemption for the Securities will state, among other things, the amount of the Securities to be redeemed, the redemption date, the manner in which the redemption price will be calculated and the place or places that payment will be made upon presentation and surrender of the Securities to be redeemed. Unless the Corporation defaults in the payment of the redemption price, interest will cease to accrue on any of the Securities that have been called for redemption on the redemption date. If less than all of the Securities are to be redeemed, the Securities to be redeemed shall be selected according to the procedures of The Depository Trust Company, in the case of Securities represented by a global note, or by lot, in the case of Securities that are not represented by a global note.

In the event of redemption of this Security in part only, a new Security or Securities of this series and of like tenor for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the cancellation hereof.

If an Event of Default with respect to Securities of this series shall occur and be continuing, the principal of, and any premium and accrued but unpaid interest on, the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture.

The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Corporation and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Corporation

Exhibit B - 5

Exhibit 4.1

and the Trustee with the consent of not less than the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series to be affected (voting as one class). The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Outstanding Securities of all affected series (voting as one class), on behalf of the Holders of all Securities of such series, to waive compliance by the Corporation with certain provisions of the Indenture. The Indenture permits, with certain exceptions as therein provided, the Holders of a majority in principal amount of Securities of any series then Outstanding to waive past defaults under the Indenture with respect to such series and their consequences. Any such consent or waiver by the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Security.

As provided in and subject to the provisions of the Indenture, the Holder of this Security shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default with respect to the Securities of this series, the Holders of not less than 25% in principal amount of the Securities of this series at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity and the Trustee shall not have received from the Holders of a majority in principal amount of Securities of this series at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such proceeding, for 90 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Security for the enforcement of any payment of principal hereof or any premium or interest hereon on or after the respective due dates expressed herein.

No reference herein to the Indenture and no provision of this Security or of the Indenture shall, without the consent of the Holder, alter or impair the obligation of the Corporation, which is absolute and unconditional, to pay the principal of and any premium and interest on this Security at the times, place(s) and rate, and in the coin or currency, herein prescribed.

This Security shall be entitled to the benefits of the Indenture, including the covenants and agreements of the Corporation set forth therein, except to the extent expressly otherwise set forth herein.

This Global Security or portion hereof may not be exchanged for Definitive Securities of this series except in the limited circumstances provided in the Indenture.

The Holders of beneficial interests in this Global Security will not be entitled to receive physical delivery of Definitive Securities except as described in the Indenture and will not be considered the Holders thereof for any purpose under the Indenture.

The Securities of this series are issuable only in registered form without coupons in minimum denominations of U.S. $2,000 and integral multiples of U.S. $1,000 in excess thereof. As provided in the Indenture and subject to certain limitations therein set forth, Securities of this

Exhibit B - 6

Exhibit 4.1

series are exchangeable for a like aggregate principal amount of Securities of this series and of like tenor of a different authorized denomination, as requested by the Holder surrendering the same.

No service charge shall be made for any such registration of transfer or exchange, but the Corporation may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

Prior to due presentment of this Security for registration of transfer, the Corporation, the Trustee and any agent of the Corporation or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security is overdue, and neither the Corporation, the Trustee nor any such agent shall be affected by notice to the contrary.

Obligations of the Corporation under the Indenture and the Securities thereunder, including this Security, are non-recourse to the Corporation’s Affiliates, and payable only out of cash flow and assets of the Corporation. The Trustee, and each Holder of a Security by its acceptance hereof, will be deemed to have agreed in the Indenture that (1) none of the Corporation’s Affiliates, nor their respective assets, shall be liable for any of the obligations of the Corporation under the Indenture or such Securities, including this Security, and (2) no director, officer, employee, agent or shareholder, as such, of the Corporation, the Trustee or any of their respective Affiliates shall have any personal liability in respect of the obligations of the Corporation under the Indenture or such Securities by reason of his, her or its status.

The Indenture contains provisions that relieve the Corporation from the obligation to comply with certain restrictive covenants in the Indenture and for satisfaction and discharge at any time of the entire indebtedness upon compliance by the Corporation with certain conditions set forth in the Indenture.

This Security shall be governed by and construed in accordance with the laws of the State of New York.

All terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.

Exhibit B - 7

EX-10.1

Exhibit 10.1

CROSS GUARANTEE AGREEMENT

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

W I T N E S S E T H:

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

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

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

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

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

1.Defined Terms.

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

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

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

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

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

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

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

Exhibit 10.1

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

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

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

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

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

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

“Guarantee” of or by any Person (the “guarantor”) means any obligation, contingent or otherwise, of the guarantor guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, and including any obligation of the guarantor, direct or indirect, (i) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to

2

Exhibit 10.1

purchase (or to advance or supply funds for the purchase of) any security for the payment thereof, (ii) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness

or other obligation of the payment thereof, (iii) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation or (iv) as an account party in respect of any letter of credit or letter of guaranty issued to support such Indebtedness or obligation; provided that the term Guarantee shall not include endorsements for collection or deposit in the ordinary course of business.

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

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

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

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

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

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

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

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

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

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

3

Exhibit 10.1

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

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

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

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

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

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

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

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

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

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

“Requirement of Law” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement (whether or not having the force of law), including environmental laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

4

Exhibit 10.1

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

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

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

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

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

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

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

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

(b)    The words “hereof”, “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this

5

Exhibit 10.1

Agreement, and Section references are to Sections of this Agreement unless otherwise specified. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”.

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

2.    Guarantee.

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

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

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

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

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

6

Exhibit 10.1

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

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

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

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

7

Exhibit 10.1

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

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

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

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

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

7.Guarantee Absolute and Unconditional.

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

8

Exhibit 10.1

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

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

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

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

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

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

9

Exhibit 10.1

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

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

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

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

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

12.Notices.

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

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

10

Exhibit 10.1

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

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

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

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

16.Amendments; No Waiver; Cumulative Remedies.

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

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

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

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

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

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

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

11

Exhibit 10.1

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

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

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

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

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

19.Additional Guarantors.

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

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

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

12

Exhibit 10.1

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

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

[Signature pages follow]

13

Exhibit 10.1

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

KINDER MORGAN, INC.

By:        /s/ Anthony B. Ashley                

Name: Anthony B. Ashley

Title: Treasurer

AGNES B CRANE, LLC

AMERICAN PETROLEUM TANKERS II LLC

AMERICAN PETROLEUM TANKERS III LLC

AMERICAN PETROLEUM TANKERS IV LLC

AMERICAN PETROLEUM TANKERS LLC

AMERICAN PETROLEUM TANKERS PARENT LLC

AMERICAN PETROLEUM TANKERS V LLC

AMERICAN PETROLEUM TANKERS VI LLC

AMERICAN PETROLEUM TANKERS VII LLC

APT FLORIDA LLC

APT INTERMEDIATE HOLDCO LLC

APT NEW INTERMEDIATE HOLDCO LLC

APT PENNSYLVANIA LLC

APT SUNSHINE STATE LLC

AUDREY TUG LLC

BEAR CREEK STORAGE COMPANY, L.L.C.

BETTY LOU LLC

CAMINO REAL GATHERING COMPANY, L.L.C.

CANTERA GAS COMPANY LLC

CDE PIPELINE LLC

CENTRAL FLORIDA PIPELINE LLC

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

CIG GAS STORAGE COMPANY LLC

CIG PIPELINE SERVICES COMPANY, L.L.C.

CIMMARRON GATHERING LLC

COLORADO INTERSTATE GAS COMPANY, L.L.C.

COLORADO INTERSTATE ISSUING CORPORATION

COPANO DOUBLE EAGLE LLC

COPANO ENERGY FINANCE CORPORATION

COPANO ENERGY, L.L.C.

COPANO ENERGY SERVICES/UPPER GULF COAST LLC

COPANO FIELD SERVICES GP, L.L.C.

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

COPANO FIELD SERVICES/SOUTH TEXAS LLC

COPANO FIELD SERVICES/UPPER GULF COAST LLC

COPANO LIBERTY, LLC

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

COPANO NGL SERVICES LLC

COPANO PIPELINES GROUP, L.L.C.

[Signature Page to Cross Guarantee]

Exhibit 10.1

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

COPANO PIPELINES/ROCKY MOUNTAINS, LLC

COPANO PIPELINES/SOUTH TEXAS LLC

COPANO PIPELINES/UPPER GULF COAST LLC

COPANO PROCESSING LLC

COPANO RISK MANAGEMENT LLC

COPANO/WEBB-DUVAL PIPELINE LLC

CPNO SERVICES LLC

DAKOTA BULK TERMINAL, INC.

DELTA TERMINAL SERVICES LLC

EAGLE FORD GATHERING LLC

EL PASO CHEYENNE HOLDINGS, L.L.C.

EL PASO CITRUS HOLDINGS, INC.

EL PASO CNG COMPANY, L.L.C.

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

EL PASO LLC

EL PASO MIDSTREAM GROUP LLC

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

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

EL PASO PIPELINE CORPORATION

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

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

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

EL PASO PIPELINE PARTNERS, L.P.

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

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

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

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

ELBA EXPRESS COMPANY, L.L.C.

ELIZABETH RIVER TERMINALS LLC

EMORY B CRANE, LLC

EPBGP CONTRACTING SERVICES LLC

EP ENERGY HOLDING COMPANY

EP RUBY LLC

EPTP ISSUING CORPORATION

FERNANDINA MARINE CONSTRUCTION MANAGEMENT LLC

FRANK L. CRANE, LLC

GENERAL STEVEDORES GP, LLC

GENERAL STEVEDORES HOLDINGS LLC

GLOBAL AMERICAN TERMINALS LLC

HAMPSHIRE LLC

HARRAH MIDSTREAM LLC

HBM ENVIRONMENTAL, INC.

ICPT, L.L.C

J.R. NICHOLLS LLC

JAVELINA TUG LLC

JEANNIE BREWER LLC

JV TANKER CHARTERER LLC

KINDER MORGAN (DELAWARE), INC.

KINDER MORGAN 2-MILE LLC

KINDER MORGAN ADMINISTRATIVE SERVICES TAMPA LLC

KINDER MORGAN ALTAMONT LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

KINDER MORGAN AMORY LLC

KINDER MORGAN ARROW TERMINALS HOLDINGS, INC.

KINDER MORGAN ARROW TERMINALS, L.P.

By Kinder Morgan River Terminals, LLC, its general partner

KINDER MORGAN BALTIMORE TRANSLOAD TERMINAL LLC

KINDER MORGAN BATTLEGROUND OIL LLC

KINDER MORGAN BORDER PIPELINE LLC

KINDER MORGAN BULK TERMINALS, INC.

KINDER MORGAN CARBON DIOXIDE TRANSPORTATION

COMPANY

KINDER MORGAN CO2 COMPANY, L.P.

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

KINDER MORGAN COCHIN LLC

KINDER MORGAN COLUMBUS LLC

KINDER MORGAN COMMERCIAL SERVICES LLC

KINDER MORGAN CRUDE & CONDENSATE LLC

KINDER MORGAN CRUDE OIL PIPELINES LLC

KINDER MORGAN CRUDE TO RAIL LLC

KINDER MORGAN CUSHING LLC

KINDER MORGAN DALLAS FORT WORTH RAIL TERMINAL LLC

KINDER MORGAN ENDEAVOR LLC

KINDER MORGAN ENERGY PARTNERS, L.P.

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

KINDER MORGAN EP MIDSTREAM LLC

KINDER MORGAN FINANCE COMPANY LLC

KINDER MORGAN FLEETING LLC

KINDER MORGAN FREEDOM PIPELINE LLC

KINDER MORGAN KEYSTONE GAS STORAGE LLC

KINDER MORGAN KMAP LLC

KINDER MORGAN LAS VEGAS LLC

KINDER MORGAN LINDEN TRANSLOAD TERMINAL LLC

KINDER MORGAN LIQUIDS TERMINALS LLC

KINDER MORGAN LIQUIDS TERMINALS ST. GABRIEL LLC

KINDER MORGAN MARINE SERVICES LLC

KINDER MORGAN MATERIALS SERVICES, LLC

KINDER MORGAN MID ATLANTIC MARINE SERVICES LLC

KINDER MORGAN NATGAS O&M LLC

KINDER MORGAN NORTH TEXAS PIPELINE LLC

KINDER MORGAN OPERATING L.P. “A”

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

KINDER MORGAN OPERATING L.P. “B”

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

KINDER MORGAN OPERATING L.P. “C”

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

KINDER MORGAN OPERATING L.P. “D”

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

KINDER MORGAN PECOS LLC

KINDER MORGAN PECOS VALLEY LLC

KINDER MORGAN PETCOKE GP LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

KINDER MORGAN PETCOKE, L.P.

By Kinder Morgan Petcoke GP LLC, its general partner

KINDER MORGAN PETCOKE LP LLC

KINDER MORGAN PETROLEUM TANKERS LLC

KINDER MORGAN PIPELINE LLC

KINDER MORGAN PIPELINES (USA) INC.

KINDER MORGAN PORT MANATEE TERMINAL LLC

KINDER MORGAN PORT SUTTON TERMINAL LLC

KINDER MORGAN PORT TERMINALS USA LLC

KINDER MORGAN PRODUCTION COMPANY LLC

KINDER MORGAN RAIL SERVICES LLC

KINDER MORGAN RESOURCES II LLC

KINDER MORGAN RESOURCES III LLC

KINDER MORGAN RESOURCES LLC

KINDER MORGAN RIVER TERMINALS LLC

KINDER MORGAN SERVICES LLC

KINDER MORGAN SEVEN OAKS LLC

KINDER MORGAN SOUTHEAST TERMINALS LLC

KINDER MORGAN TANK STORAGE TERMINALS LLC

KINDER MORGAN TEJAS PIPELINE LLC

KINDER MORGAN TERMINALS, INC.

KINDER MORGAN TEXAS PIPELINE LLC

KINDER MORGAN TEXAS TERMINALS, L.P.

By General Stevedores GP, LLC, its general partner

KINDER MORGAN TRANSMIX COMPANY, LLC

KINDER MORGAN TREATING LP

By KM Treating GP LLC, its general partner

KINDER MORGAN URBAN RENEWAL, L.L.C.

KINDER MORGAN UTICA LLC

KINDER MORGAN VIRGINIA LIQUIDS TERMINALS LLC

KINDER MORGAN WINK PIPELINE LLC

KINDERHAWK FIELD SERVICES LLC

KM CRANE LLC

KM DECATUR, INC.

KM EAGLE GATHERING LLC

KM GATHERING LLC

KM KASKASKIA DOCK LLC

KM LIQUIDS TERMINALS LLC

KM NORTH CAHOKIA LAND LLC

KM NORTH CAHOKIA SPECIAL PROJECT LLC

KM NORTH CAHOKIA TERMINAL PROJECT LLC

KM SHIP CHANNEL SERVICES LLC

KM TREATING GP LLC

KM TREATING PRODUCTION LLC

KMBT LLC

KMGP CONTRACTING SERVICES LLC

KMGP SERVICES COMPANY, INC.

KN TELECOMMUNICATIONS, INC.

KNIGHT POWER COMPANY LLC

LOMITA RAIL TERMINAL LLC

MILWAUKEE BULK TERMINALS LLC

MJR OPERATING LLC

MOJAVE PIPELINE COMPANY, L.L.C.

MOJAVE PIPELINE OPERATING COMPANY, L.L.C.

MR. BENNETT LLC

[Signature Page to Cross Guarantee]

Exhibit 10.1

MR. VANCE LLC

NASSAU TERMINALS LLC

NGPL HOLDCO INC.

NS 307 HOLDINGS INC.

PADDY RYAN CRANE, LLC

PALMETTO PRODUCTS PIPE LINE LLC

PI 2 PELICAN STATE LLC

PINNEY DOCK & TRANSPORT LLC

QUEEN CITY TERMINALS LLC

RAHWAY RIVER LAND LLC

RAZORBACK TUG LLC

RCI HOLDINGS, INC.

RIVER TERMINALS PROPERTIES GP LLC

RIVER TERMINAL PROPERTIES, L.P.

By River Terminals Properties GP LLC, its general partner

SCISSORTAIL ENERGY, LLC

SNG PIPELINE SERVICES COMPANY, L.L.C.

SOUTHERN GULF LNG COMPANY, L.L.C.

SOUTHERN LIQUEFACTION COMPANY LLC

SOUTHERN LNG COMPANY, L.L.C.

SOUTHERN NATURAL GAS COMPANY, L.L.C.

SOUTHERN NATURAL ISSUING CORPORATION

SOUTHTEX TREATERS LLC

SOUTHWEST FLORIDA PIPELINE LLC

SRT VESSELS LLC

STEVEDORE HOLDINGS, L.P.

By Kinder Morgan Petcoke GP LLC, its general partner

TAJON HOLDINGS, INC.

TEJAS GAS, LLC

TEJAS NATURAL GAS, LLC

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

TENNESSEE GAS PIPELINE ISSUING CORPORATION

TEXAN TUG LLC

TGP PIPELINE SERVICES COMPANY, L.L.C.

TRANS MOUNTAIN PIPELINE (PUGET SOUND) LLC

TRANSCOLORADO GAS TRANSMISSION COMPANY LLC

TRANSLOAD SERVICES, LLC

UTICA MARCELLUS TEXAS PIPELINE LLC

WESTERN PLANT SERVICES, INC.

WYOMING INTERSTATE COMPANY, L.L.C.

By:     /s/ Anthony B. Ashley                

Anthony Ashley

Vice President

[Signature Page to Cross Guarantee]

Exhibit 10.1

ANNEX A TO

THE CROSS GUARANTEE AGREEMENT

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

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

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

Accordingly, each New Guarantor agrees as follows:

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

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

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

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

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

Exhibit 10.1

SECTION 6.    Any provision of this Supplement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof and in the Agreement, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. The parties hereto shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.

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

[Signature Pages Follow]

Exhibit 10.1

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

_________________________________

as Guarantor

By:______________________________

Name:

Title:

Exhibit 10.1

ANNEX B TO

THE CROSS GUARANTEE AGREEMENT

FORM OF NOTATION OF GUARANTEE

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

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

[GUARANTORS],

as Guarantor

By:    ______________________________

    Name:

    Title:

Exhibit 10.1

SCHEDULE I

Guaranteed Obligations

Current as of: September 30, 2020

Issuer	Indebtedness	Maturity
Kinder Morgan, Inc.	5.00% notes	February 15, 2021
Kinder Morgan, Inc.	1.500% notes	March 16, 2022
Kinder Morgan, Inc.	3.150% bonds	January 15, 2023
Kinder Morgan, Inc.	Floating rate bonds	January 15, 2023
Kinder Morgan, Inc.	5.625% notes	November 15, 2023
Kinder Morgan, Inc.	4.30% notes	June 1, 2025
Kinder Morgan, Inc.	6.70% bonds (Coastal)	February 15, 2027
Kinder Morgan, Inc.	2.250% notes	March 16, 2027
Kinder Morgan, Inc.	6.67% debentures	November 1, 2027
Kinder Morgan, Inc.	7.25% debentures	March 1, 2028
Kinder Morgan, Inc.	4.30% notes	March 1, 2028
Kinder Morgan, Inc.	6.95% bonds (Coastal)	June 1, 2028
Kinder Morgan, Inc.	8.05% bonds	October 15, 2030
Kinder Morgan, Inc.	2.00% notes	February 15, 2031
Kinder Morgan, Inc.	7.80% bonds	August 1, 2031
Kinder Morgan, Inc.	7.75% bonds	January 15, 2032
Kinder Morgan, Inc.	5.30% notes	December 1, 2034
Kinder Morgan, Inc.	7.75% bonds (Coastal)	October 15, 2035
Kinder Morgan, Inc.	6.40% notes	January 5, 2036
Kinder Morgan, Inc.	7.42% bonds (Coastal)	February 15, 2037
Kinder Morgan, Inc.	5.55% notes	June 1, 2045
Kinder Morgan, Inc.	5.050% notes	February 15, 2046
Kinder Morgan, Inc.	5.20% notes	March 1, 2048
Kinder Morgan, Inc.	3.25% notes	August 1, 2050
Kinder Morgan, Inc.	7.45% debentures	March 1, 2098
Kinder Morgan, Inc.	$100 Million Letter of Credit Facility	November 30, 2020
Kinder Morgan Energy Partners, L.P.	5.80% bonds	March 1, 2021
Kinder Morgan Energy Partners, L.P.	3.50% bonds	March 1, 2021
Kinder Morgan Energy Partners, L.P.	4.15% bonds	March 1, 2022
Kinder Morgan Energy Partners, L.P.	3.95% bonds	September 1, 2022
Kinder Morgan Energy Partners, L.P.	3.45% bonds	February 15, 2023
Kinder Morgan Energy Partners, L.P.	3.50% bonds	September 1, 2023
Kinder Morgan Energy Partners, L.P.	4.15% bonds	February 1, 2024
Kinder Morgan Energy Partners, L.P.	4.25% bonds	September 1, 2024
Kinder Morgan Energy Partners, L.P.	7.40% bonds	March 15, 2031
Kinder Morgan Energy Partners, L.P.	7.75% bonds	March 15, 2032
Kinder Morgan Energy Partners, L.P.	7.30% bonds	August 15, 2033
Kinder Morgan Energy Partners, L.P.	5.80% bonds	March 15, 2035
Kinder Morgan Energy Partners, L.P.	6.50% bonds	February 1, 2037
Kinder Morgan Energy Partners, L.P.	6.95% bonds	January 15, 2038
Kinder Morgan Energy Partners, L.P.	6.50% bonds	September 1, 2039

Exhibit 10.1

	Schedule I
	(Guaranteed Obligations)
	Current as of: September 30, 2020
Issuer	Indebtedness	Maturity
Kinder Morgan Energy Partners, L.P.	6.55% bonds	September 15, 2040
Kinder Morgan Energy Partners, L.P.	6.375% bonds	March 1, 2041
Kinder Morgan Energy Partners, L.P.	5.625% bonds	September 1, 2041
Kinder Morgan Energy Partners, L.P.	5.00% bonds	August 15, 2042
Kinder Morgan Energy Partners, L.P.	5.00% bonds	March 1, 2043
Kinder Morgan Energy Partners, L.P.	5.50% bonds	March 1, 2044
Kinder Morgan Energy Partners, L.P.	5.40% bonds	September 1, 2044
Kinder Morgan Energy Partners, L.P.(1)	5.00% bonds	October 1, 2021
Kinder Morgan Energy Partners, L.P.(1)	4.30% bonds	May 1, 2024
Kinder Morgan Energy Partners, L.P.(1)	7.50% bonds	November 15, 2040
Kinder Morgan Energy Partners, L.P.(1)	4.70% bonds	November 1, 2042
Tennessee Gas Pipeline Company, L.L.C.	7.00% bonds	March 15, 2027
Tennessee Gas Pipeline Company, L.L.C.	7.00% bonds	October 15, 2028
Tennessee Gas Pipeline Company, L.L.C.	2.90% bonds	March 1, 2030
Tennessee Gas Pipeline Company, L.L.C.	8.375% bonds	June 15, 2032
Tennessee Gas Pipeline Company, L.L.C.	7.625% bonds	April 1, 2037
El Paso Natural Gas Company, L.L.C.	8.625% bonds	January 15, 2022
El Paso Natural Gas Company, L.L.C.	7.50% bonds	November 15, 2026
El Paso Natural Gas Company, L.L.C.	8.375% bonds	June 15, 2032
Colorado Interstate Gas Company, L.L.C.	4.15% notes	August 15, 2026
Colorado Interstate Gas Company, L.L.C.	6.85% bonds	June 15, 2037
El Paso Tennessee Pipeline Co. L.L.C.	7.25% bonds	December 15, 2025
Other	Cora industrial revenue bonds	April 1, 2024
_________________________________________________ (1) The original issuer, El Paso Pipeline Partners, L.P. merged with and into Kinder Morgan Energy      Partners, L.P. effective January 1, 2015.

2

Exhibit 10.1

Schedule I

(Guaranteed Obligations)

Current as of: September 30, 2020

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

3

Exhibit 10.1

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

4

Exhibit 10.1

SCHEDULE II Guarantors Current as of: September 30, 2020
Agnes B Crane, LLC	Copano Risk Management LLC
American Petroleum Tankers II LLC	Copano Terminals LLC
American Petroleum Tankers III LLC	Copano/Webb-Duval Pipeline LLC
American Petroleum Tankers IV LLC	CPNO Services LLC
American Petroleum Tankers LLC	Dakota Bulk Terminal LLC
American Petroleum Tankers Parent LLC	Delta Terminal Services LLC
American Petroleum Tankers V LLC	Eagle Ford Gathering LLC
American Petroleum Tankers VI LLC	El Paso Cheyenne Holdings, L.L.C.
American Petroleum Tankers VII LLC	El Paso Citrus Holdings, Inc.
American Petroleum Tankers VIII LLC	El Paso CNG Company, L.L.C.
American Petroleum Tankers IX LLC	El Paso Energy Service Company, L.L.C.
American Petroleum Tankers X LLC	El Paso LLC
American Petroleum Tankers XI LLC	El Paso Midstream Group LLC
APT Florida LLC	El Paso Natural Gas Company, L.L.C.
APT Intermediate Holdco LLC	El Paso Noric Investments III, L.L.C.
APT New Intermediate Holdco LLC	El Paso Ruby Holding Company, L.L.C.
APT Pennsylvania LLC	El Paso Tennessee Pipeline Co., L.L.C.
APT Sunshine State LLC	Elba Express Company, L.L.C.
Betty Lou LLC	Elizabeth River Terminals LLC
Camino Real Gas Gathering LLC	Emory B Crane, LLC
Camino Real Gathering Company, L.L.C.	EP Ruby LLC
Cantera Gas Company LLC	EPBGP Contracting Services LLC
CDE Pipeline LLC	EPTP Issuing Corporation
Central Florida Pipeline LLC	Frank L. Crane, LLC
Cheyenne Plains Gas Pipeline Company, L.L.C.	General Stevedores GP, LLC
CIG Gas Storage Company LLC	General Stevedores Holdings LLC
CIG Pipeline Services Company, L.L.C.	Harrah Midstream LLC
Colorado Interstate Gas Company, L.L.C.	HBM Environmental LLC
Colorado Interstate Issuing Corporation	Hiland Crude, LLC
Copano Double Eagle LLC	Hiland Partners Holdings LLC
Copano Energy Finance Corporation	HPH Oklahoma Gathering LLC
Copano Energy Services/Upper Gulf Coast LLC	ICPT, L.L.C
Copano Energy, L.L.C.	Independent Trading & Transportation
Copano Field Services GP, L.L.C.	Company I, L.L.C.
Copano Field Services/North Texas, L.L.C.	JV Tanker Charterer LLC
Copano Field Services/South Texas LLC	Kinder Morgan 2-Mile LLC
Copano Field Services/Upper Gulf Coast LLC	Kinder Morgan Administrative Services Tampa LLC
Copano Liberty, LLC	Kinder Morgan Altamont LLC
Copano Liquids Marketing LLC	Kinder Morgan Baltimore Transload Terminal
Copano NGL Services (Markham), L.L.C.	LLC
Copano NGL Services LLC	Kinder Morgan Battleground Oil LLC
Copano Pipelines Group, L.L.C.	Kinder Morgan Border Pipeline LLC
Copano Pipelines/North Texas, L.L.C.	Kinder Morgan Bulk Terminals LLC
Copano Pipelines/Rocky Mountains, LLC	Kinder Morgan Carbon Dioxide Transportation
Copano Pipelines/South Texas LLC	Company
Copano Pipelines/Upper Gulf Coast LLC	Kinder Morgan CO2 Company, L.P.
Copano Processing LLC	Kinder Morgan Commercial Services LLC

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: September 30, 2020
Kinder Morgan Contracting Services LLC	Kinder Morgan Resources III LLC
Kinder Morgan Crude & Condensate LLC	Kinder Morgan Resources LLC
Kinder Morgan Crude Marketing LLC	Kinder Morgan Seven Oaks LLC
Kinder Morgan Crude Oil Pipelines LLC	Kinder Morgan SNG Operator LLC
Kinder Morgan Crude to Rail LLC	Kinder Morgan Southeast Terminals LLC
Kinder Morgan Cushing LLC	Kinder Morgan Scurry Connector LLC
Kinder Morgan Dallas Fort Worth Rail Terminal	Kinder Morgan Tank Storage Terminals LLC
LLC	Kinder Morgan Tejas Pipeline LLC
Kinder Morgan Deeprock North Holdco LLC	Kinder Morgan Terminals, Inc.
Kinder Morgan Endeavor LLC	Kinder Morgan Terminals Wilmington LLC
Kinder Morgan Energy Partners, L.P.	Kinder Morgan Texas Pipeline LLC
Kinder Morgan EP Midstream LLC	Kinder Morgan Texas Terminals, L.P.
Kinder Morgan Finance Company LLC	Kinder Morgan Transmix Company, LLC
Kinder Morgan Freedom Pipeline LLC	Kinder Morgan Treating LP
Kinder Morgan Galena Park West LLC	Kinder Morgan Urban Renewal, L.L.C.
Kinder Morgan IMT Holdco LLC	Kinder Morgan Utica LLC
Kinder Morgan, Inc.	Kinder Morgan Vehicle Services LLC
Kinder Morgan Keystone Gas Storage LLC	Kinder Morgan Virginia Liquids Terminals LLC
Kinder Morgan KMAP LLC	Kinder Morgan Wink Pipeline LLC
Kinder Morgan Las Vegas LLC	KinderHawk Field Services LLC
Kinder Morgan Linden Transload Terminal LLC	KM Crane LLC
Kinder Morgan Liquids Terminals LLC	KM Decatur LLC
Kinder Morgan Liquids Terminals St. Gabriel LLC	KM Eagle Gathering LLC
Kinder Morgan Louisiana Pipeline Holding LLC	KM Gathering LLC
Kinder Morgan Louisiana Pipeline LLC	KM Kaskaskia Dock LLC
Kinder Morgan Marine Services LLC	KM Liquids Terminals LLC
Kinder Morgan Materials Services, LLC	KM North Cahokia Land LLC
Kinder Morgan Mid Atlantic Marine Services LLC	KM North Cahokia Special Project LLC
Kinder Morgan NatGas O&M LLC	KM North Cahokia Terminal Project LLC
Kinder Morgan NGPL Holdings LLC	KM Ship Channel Services LLC
Kinder Morgan North Texas Pipeline LLC	KM Treating GP LLC
Kinder Morgan Operating L.P. “A”	KM Treating Production LLC
Kinder Morgan Operating L.P. “B”	KM Utopia Operator LLC
Kinder Morgan Operating L.P. “C”	KMBT Legacy Holdings LLC
Kinder Morgan Operating L.P. “D”	KMBT LLC
Kinder Morgan Pecos LLC	KMGP Services Company, Inc.
Kinder Morgan Pecos Valley LLC	KN Telecommunications, Inc.
Kinder Morgan Petcoke GP LLC	Knight Power Company LLC
Kinder Morgan Petcoke LP LLC	Lomita Rail Terminal LLC
Kinder Morgan Petcoke, L.P.	Milwaukee Bulk Terminals LLC
Kinder Morgan Petroleum Tankers LLC	MJR Operating LLC
Kinder Morgan Pipeline LLC	Mojave Pipeline Company, L.L.C.
Kinder Morgan Port Manatee Terminal LLC	Mojave Pipeline Operating Company, L.L.C.
Kinder Morgan Port Sutton Terminal LLC	Paddy Ryan Crane, LLC
Kinder Morgan Port Terminals USA LLC	Palmetto Products Pipe Line LLC
Kinder Morgan Portland Jet Line LLC	PI 2 Pelican State LLC
Kinder Morgan Production Company LLC	Pinney Dock & Transport LLC
Kinder Morgan Products Terminals LLC	Queen City Terminals LLC
Kinder Morgan Rail Services LLC	Rahway River Land LLC
Kinder Morgan Resources II LLC	River Terminals Properties GP LLC

2

Exhibit 10.1

	Schedule II
	(Guarantors)
	Current as of: September 30, 2020
River Terminal Properties, L.P.
ScissorTail Energy, LLC
SNG Pipeline Services Company, L.L.C.
Southern Dome, LLC
Southern Gulf LNG Company, L.L.C.
Southern Liquefaction Company LLC
Southern LNG Company, L.L.C.
Southern Oklahoma Gathering LLC
SouthTex Treaters LLC
Southwest Florida Pipeline LLC
SRT Vessels LLC
Stevedore Holdings, L.P.
Tejas Gas, LLC
Tejas Natural Gas, LLC
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Issuing Corporation
Texan Tug LLC
TGP Pipeline Services Company, L.L.C.
TransColorado Gas Transmission Company LLC
Transload Services, LLC
Utica Marcellus Texas Pipeline LLC
Western Plant Services LLC
Wyoming Interstate Company, L.L.C.

3

Exhibit 10.1

SCHEDULE III

Excluded Subsidiaries

ANR Real Estate Corporation

Coastal Eagle Point Oil Company

Coastal Oil New England, Inc.

Colton Processing Facility

Coscol Petroleum Corporation

El Paso CGP Company, L.L.C.

El Paso Energy Capital Trust I

El Paso Energy E.S.T. Company

El Paso Energy International Company

El Paso Marketing Company, L.L.C.

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

El Paso Merchant Energy-Petroleum Company

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

El Paso Remediation Company

El Paso Services Holding Company

EPEC Corporation

EPEC Oil Company Liquidating Trust

EPEC Polymers, Inc.

EPED Holding Company

KN Capital Trust I

KN Capital Trust III

Mesquite Investors, L.L.C.

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

EX-31.1

Exhibit 31.1

KINDER MORGAN, INC. AND SUBSIDIARIES

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

OF THE SECURITIES EXCHANGE ACT OF 1934,

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

I, Steven J. Kean, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	October 23, 2020	/s/ Steven J. Kean
		Steven J. Kean
		Chief Executive Officer

EX-31.2

Exhibit 31.2

KINDER MORGAN, INC. AND SUBSIDIARIES

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

OF THE SECURITIES EXCHANGE ACT OF 1934,

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

I, David P. Michels, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	October 23, 2020	/s/ David P. Michels
		David P. Michels
		Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

KINDER MORGAN, INC. AND SUBSIDIARIES

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

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Kinder Morgan, Inc. (the “Company”) for the quarterly period ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

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

Date:	October 23, 2020	/s/ Steven J. Kean
		Steven J. Kean
		Chief Executive Officer

EX-32.2

Exhibit 32.2

KINDER MORGAN, INC. AND SUBSIDIARIES

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

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Kinder Morgan, Inc. (the “Company”) for the quarterly period ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

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

Date:	October 23, 2020	/s/ David P. Michels
		David P. Michels
		Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2020	Oct. 22, 2020
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2020
Document Transition Report	false
Entity File Number	001-35081
Entity Registrant Name	KINDER MORGAN, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	80-0682103
Entity Address, Address Line One	1001 Louisiana Street
Entity Address, Address Line Two	Suite 1000
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	369-9000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		2,263,793,923
Entity Central Index Key	0001506307
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Amendment Flag	false
Class P Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class P Common Stock
Trading Symbol	KMI
Security Exchange Name	NYSE
1.500% Senior Notes due 2022
Entity Information [Line Items]
Title of 12(b) Security	1.500% Senior Notes due 2022
Trading Symbol	KMI 22
Security Exchange Name	NYSE
2.250% Senior Notes due 2027
Entity Information [Line Items]
Title of 12(b) Security	2.250% Senior Notes due 2027
Trading Symbol	KMI 27 A
Security Exchange Name	NYSE

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Revenues
Revenues	$ 2,919	$ 3,214	$ 8,585	$ 9,857
Operating Costs, Expenses and Other
Costs of sales	655	762	1,759	2,487
Operations and maintenance	643	668	1,869	1,912
Depreciation, depletion and amortization	539	578	1,636	1,750
General and administrative	153	154	461	456
Taxes, other than income taxes	100	103	295	324
Loss (gain) on impairments and divestitures, net (Note 2)	11	(3)	1,987	(13)
Other (income) expense, net	(1)	1	(2)	(1)
Total Operating Costs, Expenses and Other	2,100	2,263	8,005	6,915
Operating Income	819	951	580	2,942
Other Income (Expense)
Earnings from equity investments	194	173	562	526
Amortization of excess cost of equity investments	(32)	(21)	(99)	(61)
Interest, net	(383)	(447)	(1,214)	(1,359)
Other, net	14	12	32	35
Total Other Expense	(207)	(283)	(719)	(859)
Income (Loss) Before Income Taxes	612	668	(139)	2,083
Income Tax Expense	(140)	(151)	(304)	(471)
Net Income (Loss)	472	517	(443)	1,612
Net Income Attributable to Noncontrolling Interests	(17)	(11)	(45)	(32)
Net Income (Loss) Attributable to Kinder Morgan, Inc.	$ 455	$ 506	$ (488)	$ 1,580
Class P Shares
Basic and Diluted Earnings (Loss) Per Common Share	$ 0.20	$ 0.22	$ (0.22)	$ 0.69
Basic and Diluted Weighted Average Common Shares Outstanding	2,263	2,264	2,263	2,263
Services
Revenues
Revenues	$ 1,881	$ 2,014	$ 5,664	$ 6,060
Commodity sales
Revenues
Revenues	982	1,154	2,772	3,659
Other
Revenues
Revenues	$ 56	$ 46	$ 149	$ 138

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 472	$ 517	$ (443)	$ 1,612
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 $—, $2, $—, 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
Total other comprehensive (loss) income	(56)	61	78	(58)
Comprehensive income (loss)	416	578	(365)	1,554
Comprehensive income attributable to noncontrolling interests	(17)	(8)	(45)	(28)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$ 399	$ 570	$ (410)	$ 1,526

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives, tax benefit (expense)	$ 17	$ (6)	$ 5	$ 39
Reclassification of change in fair value of derivatives to net income, tax benefit (expense)	1	(13)	(22)	(11)
Foreign currency translation adjustments, tax benefit (expense)	0	2	0	(5)
Benefit plan adjustments, tax expense	$ (2)	$ (3)	$ (7)	$ (8)

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 632	$ 185
Restricted deposits	67	24
Marketable securities at fair value	0	925
Accounts receivable	1,142	1,379
Fair value of derivative contracts	257	84
Inventories	317	371
Other current assets	257	270
Total current assets	2,672	3,238
Property, plant and equipment, net	35,958	36,419
Investments	8,014	7,759
Goodwill	19,851	21,451
Other intangibles, net	2,510	2,676
Deferred income taxes	671	857
Deferred charges and other assets	2,145	1,757
Total Assets	71,821	74,157
Current Liabilities
Current portion of debt	2,057	2,477
Accounts payable	774	914
Accrued interest	351	548
Accrued taxes	335	364
Accrued contingencies	315	89
Other current liabilities	544	708
Total current liabilities	4,376	5,100
Long-term debt
Outstanding	31,281	30,883
Debt fair value adjustments	1,379	1,032
Total long-term debt	32,660	31,915
Other long-term liabilities and deferred credits	2,093	2,253
Total long-term liabilities and deferred credits	34,753	34,168
Total Liabilities	39,129	39,268
Commitments and contingencies (Notes 3 and 9)
Redeemable Noncontrolling Interest	747	803
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
Additional paid-in capital	41,736	41,745
Accumulated deficit	(9,945)	(7,693)
Accumulated other comprehensive loss	(255)	(333)
Total Kinder Morgan, Inc.’s stockholders’ equity	31,559	33,742
Noncontrolling interests	386	344
Total Stockholders’ Equity	31,945	34,086
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$ 71,821	$ 74,157

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2020	Dec. 31, 2019
Stockholders’ Equity
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	4,000,000,000	4,000,000,000
Common stock, shares issued (in shares)	2,263,749,898	2,264,936,054
Common stock, shares outstanding (in shares)	2,263,749,898	2,264,936,054

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Cash Flows From Operating Activities
Net (loss) income	$ (443)	$ 1,612
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	1,636	1,750
Deferred income taxes	164	254
Amortization of excess cost of equity investments	99	61
Loss (gain) on impairments and divestitures, net (Note 2)	1,987	(13)
Earnings from equity investments	(562)	(526)
Distributions from equity investment earnings	487	412
Changes in components of working capital
Accounts receivable	238	224
Inventories	41	(28)
Other current assets	14	97
Accounts payable	(107)	(266)
Accrued interest, net of interest rate swaps	(208)	(218)
Accrued taxes	(25)	(107)
Other current liabilities	(111)	(136)
Other, net	72	5
Net Cash Provided by Operating Activities	3,282	3,121
Cash Flows From Investing Activities
Capital expenditures	(1,351)	(1,719)
Proceeds from sales of assets and investments, net of working capital adjustments	907
Proceeds from sales of assets and investments, net of working capital adjustments		80
Contributions to investments	(365)	(1,148)
Distributions from equity investments in excess of cumulative earnings	105	207
Other, net	(72)	(30)
Net Cash Used in Investing Activities	(776)	(2,610)
Cash Flows From Financing Activities
Issuances of debt	3,888	5,118
Payments of debt	(3,991)	(6,303)
Debt issue costs	(23)	(9)
Common stock dividends	(1,764)	(1,593)
Repurchases of common shares	(50)	(2)
Contributions from investment partner and noncontrolling interests	11	138
Distributions to investment partner	(60)	0
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds	0	(879)
Distributions to noncontrolling interests - other	(11)	(42)
Other, net	(13)	(28)
Net Cash Used in Financing Activities	(2,013)	(3,600)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(3)	26
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits	490	(3,063)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	209	3,331
Cash and Cash Equivalents, beginning of period	185	3,280
Restricted Deposits, beginning of period	24	51
Cash and Cash Equivalents, end of period	632	241
Restricted Deposits, end of period	67	27
Cash, Cash Equivalents, and Restricted Deposits, end of period	699	268
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	15	764
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,440	1,584
Cash paid during the period for income taxes, net	$ 202	$ 364

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Common stock	Additional paid-in capital	Accumulated deficit	Accumulated other comprehensive loss	Stockholders’ equity attributable to KMI	Non-controlling interests	Impact of adoption of ASU 2017-12	Impact of adoption of ASU 2017-12 Accumulated deficit	Impact of adoption of ASU 2017-12 Stockholders’ equity attributable to KMI	Adjusted balance	Adjusted balance Common stock	Adjusted balance Additional paid-in capital	Adjusted balance Accumulated deficit	Adjusted balance Accumulated other comprehensive loss	Adjusted balance Stockholders’ equity attributable to KMI	Adjusted balance Non-controlling interests
Balance at Dec. 31, 2018	$ 34,531	$ 23	$ 41,701	$ (7,716)	$ (330)	$ 33,678	$ 853	$ (4)	$ (4)	$ (4)	$ 34,527	$ 23	$ 41,701	$ (7,720)	$ (330)	$ 33,674	$ 853
Balance (shares) at Dec. 31, 2018		2,262										2,262
Accounting Standards Update [Extensible List]	us-gaap:AccountingStandardsUpdate201712Member
Repurchases of common shares	$ (2)		(2)			(2)
Restricted shares	28		28			28
Restricted shares (shares)		3
Net (loss) income	1,612			1,580		1,580	32
Distributions	(42)					0	(42)
Contributions	3					0	3
Common stock dividends	(1,593)			(1,593)		(1,593)
Other	(1)					0	(1)
Other comprehensive income (loss)	(58)				(54)	(54)	(4)
Balance at Sep. 30, 2019	34,474	$ 23	41,727	(7,733)	(384)	33,633	841
Balance (shares) at Sep. 30, 2019		2,265
Balance at Jun. 30, 2019	34,485	$ 23	41,734	(7,670)	(448)	33,639	846
Balance (shares) at Jun. 30, 2019		2,262
Restricted shares	(7)		(7)			(7)
Restricted shares (shares)		3
Net (loss) income	517			506		506	11
Distributions	(14)					0	(14)
Contributions	2					0	2
Common stock dividends	(569)			(569)		(569)
Other	(1)					0	(1)
Other comprehensive income (loss)	61				64	64	(3)
Balance at Sep. 30, 2019	34,474	$ 23	41,727	(7,733)	(384)	33,633	841
Balance (shares) at Sep. 30, 2019		2,265
Balance at Dec. 31, 2019	34,086	$ 23	41,745	(7,693)	(333)	33,742	344
Balance (shares) at Dec. 31, 2019		2,265
Repurchases of common shares	(50)		(50)			(50)
Repurchases of common shares (shares)		(4)
Restricted shares	41		41			41
Restricted shares (shares)		3
Net (loss) income	(443)			(488)		(488)	45
Distributions	(11)					0	(11)
Contributions	8					0	8
Common stock dividends	(1,764)			(1,764)		(1,764)
Other comprehensive income (loss)	78				78	78
Balance at Sep. 30, 2020	31,945	$ 23	41,736	(9,945)	(255)	31,559	386
Balance (shares) at Sep. 30, 2020		2,264
Balance at Jun. 30, 2020	32,124	$ 23	41,731	(9,802)	(199)	31,753	371
Balance (shares) at Jun. 30, 2020		2,261
Restricted shares	5		5			5
Restricted shares (shares)		3
Net (loss) income	472			455		455	17
Distributions	(4)					0	(4)
Contributions	2					0	2
Common stock dividends	(598)			(598)		(598)
Other comprehensive income (loss)	(56)				(56)	(56)
Balance at Sep. 30, 2020	$ 31,945	$ 23	$ 41,736	$ (9,945)	$ (255)	$ 31,559	$ 386
Balance (shares) at Sep. 30, 2020		2,264

XML

General (Notes)

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General

1. General

Organization

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

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2019 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, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO₂; and (vi) Terminals. See Note 2 for results of our May 31, 2020 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

________

(a)As of September 30, 2020, 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,
	2020	2019	2020	2019
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	3	3	3	3

XML

Impairments (Notes)

9 Months Ended

Sep. 30, 2020

Impairments [Abstract]

Impairments

2. Impairments

During the first quarter of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented triggering events that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO₂ business segment and conducted interim tests of the recoverability of goodwill for our CO₂ and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020, which resulted in impairments of long-lived assets and goodwill within our CO₂ business 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, resulted 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 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	$	—
Impairments of inventory	11		—
Gain on divestitures of long-lived assets	—		(10)
Products Pipelines
Impairment of long-lived and intangible assets	21		—
Terminals
Impairment of long-lived and intangible assets	5		—
Gain on divestitures of long-lived assets	—		(3)
CO2
Impairment of goodwill	600		—
Impairment of long-lived assets	350		—
Kinder Morgan Canada
Loss on divestiture of long-lived assets	—		2
Other gain on divestitures of long-lived assets	—		(2)
Pre-tax loss (gain) on divestitures and impairments, net	$	1,987	$	(13)

Long-lived Assets

As of March 31, 2020, for our CO₂ 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.

•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 CO₂ source and transportation assets, volume forecasts were developed based on projected demand for our CO₂ services based upon management’s projections of the availability of CO₂ supply and the future demand for CO₂ for use in enhanced oil recovery projects. The CO₂ 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 CO₂ 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	—		(1,000)		(600)		—		—		—		(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 CO₂ reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO₂ 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 CO₂ business, 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 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 goodwill impairment test of the CO₂ reporting unit, we applied an 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 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.

In determining the fair value for our CO₂ reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO₂ reporting unit of approximately $600 million as of March 31, 2020.

The fair value estimates used 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.

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.

XML

Debt (Notes)

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Debt

3. 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	$	—	$	—
Commercial paper notes(a)	—		37
Current portion of senior notes
6.85%, due February 2020(b)	—		700
6.50%, due April 2020(c)	—		535
5.30%, due September 2020(d)	—		600
6.50%, due September 2020(d)	—		349
5.00%, due February 2021	750		—
3.50%, due March 2021	750		—
5.80%, due March 2021	400		—
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)	—		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

_______

(a)Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.

(b)On January 9, 2020, we sold the approximate 25 million shares 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.

(c)In April 2020, we repaid $535 million of maturing senior notes.

(d)In September 2020, we repaid a combined $949 million of maturing senior notes using proceeds from our newly issued senior notes.

(e)In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020.

(f)Excludes our “Debt fair value adjustments” which, as of September 30, 2020 and December 31, 2019, increased our total debt balances by $1,379 million and $1,032 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, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% 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 and received net proceeds of $991 million.

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

Credit Facility

As of September 30, 2020, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of September 30, 2020 was $3,919 million. As of September 30, 2020, 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

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

XML

Stockholders' Equity (Notes)

9 Months Ended

Sep. 30, 2020

Stockholders' Equity Note [Abstract]

Stockholders' Equity

4. Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion 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.

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)	$	—	$	(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)

	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		—		—		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)

XML

Risk Management (Notes)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management

5.  Risk Management

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

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, 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)	MMBbl
Crude oil basis	(2.6)	MMBbl
Natural gas fixed price	(34.8)	Bcf
Natural gas basis	(34.8)	Bcf
NGL fixed price	(1.2)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(2.4)	MMBbl
Crude oil basis	(0.9)	MMBbl
Natural gas fixed price	(9.7)	Bcf
Natural gas basis	2.2	Bcf
NGL fixed price	(1.4)	MMBbl

As of September 30, 2020, 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.

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:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	7,625	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		Mark-to-Market	December 2021

_______

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

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:

	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)		—
	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)	—		—		(14)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	70		46		—		—
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		—		(1)		—
Subtotal		25		8		(11)		(7)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(3)		—
Subtotal		—		—		(3)		—
Total		25		8		(14)		(7)
Total derivatives		$	1,025	$	460	$	(68)	$	(65)

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

	Balance sheet asset fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
	(In millions)
As of September 30, 2020
Energy commodity derivative contracts(a)	$	3	$	184	$	—	$	187	$	(28)	$	—	$	159
Interest rate contracts	—		768		—		768		(2)		—		766
Foreign currency contracts	—		70		—		70		(14)		—		56
As of December 31, 2019
Energy commodity derivative contracts(a)	$	19	$	37	$	—	$	56	$	(19)	$	(21)	$	16
Interest rate contracts	—		358		—		358		—		—		358
Foreign currency contracts	—		46		—		46		(6)		—		40

	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)	$	—	$	(40)	$	28	$	8	$	(4)
Interest rate contracts	—		(14)		—		(14)		2		—		(12)
Foreign currency contracts	—		(14)		—		(14)		14		—		—
As of December 31, 2019
Energy commodity derivative contracts(a)	$	(3)	$	(55)	$	—	$	(58)	$	19	$	—	$	(39)
Interest rate contracts	—		(1)		—		(1)		—		—		(1)
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)

_______

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

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended September 30,					Three Months Ended September 30,
	2020		2019			2020		2019
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(143)	$	96	Revenues—Commodity sales	$	(47)	$	9
					Costs of sales	(7)		(3)
Interest rate contracts	—		(1)		Earnings from equity investments(c)	(1)		—
Foreign currency contracts	70		(69)		Other, net	61		(59)
Total	$	(73)	$	26	Total	$	6	$	(53)

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)

_______

(a)We expect to reclassify an approximate $68 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2020 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, we recognized a $12 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	$	—	$	—	$	—	$	(8)
Total	$	—	$	—	$	—	$	(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		—		18		(3)
	Earnings from equity investments(b)	—		—		—		2
Total(a)		$	99	$	12	$	371	$	35

_______

(a)The three and nine months ended September 30, 2020 include approximate gains of $96 million and $349 million, respectively, and the three and nine months ended September 30, 2019 include an approximate loss of $4 million and $2 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 and December 31, 2019, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2020, we had cash margins of $32 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. As of December 31, 2019, we had cash margins of $15 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at September 30, 2020 represents the net of our initial margin requirements of $24 million and counterparty variation margin requirements of $8 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, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post additional collateral.

XML

Revenue Recognition (Notes)

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

Revenue Recognition

6. Revenue Recognition

Disaggregation of Revenues

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

	Three Months Ended 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	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

	Three 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)	$	882	$	89	$	256	$	1	$	(1)	$	1,227
Fee-based services	182		265		132		14		—		593
Total services	1,064		354		388		15		(1)		1,820
Commodity sales
Natural gas sales	618		—		—		—		(1)		617
Product sales	162		84		9		268		(7)		516
Total commodity sales	780		84		9		268		(8)		1,133
Total revenues from contracts with customers	1,844		438		397		283		(9)		2,953
Other revenues(c)
Leasing services	57		45		111		13		—		226
Derivatives adjustments on commodity sales	23		—		—		(1)		(1)		21
Other	10		1		—		3		—		14
Total Other revenues	90		46		111		15		(1)		261
Total revenues	$	1,934	$	484	$	508	$	298	$	(10)	$	3,214

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

	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		—		1,756
Total services	3,262		1,005		1,183		46		(3)		5,493
Commodity sales
Natural gas sales	1,979		—		—		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		—		660
Derivatives adjustments on commodity sales	61		—		—		(10)		—		51
Other	35		5		—		10		—		50
Total Other revenues	263		134		325		39		—		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 recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.

Contract Balances

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

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

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 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2020	$	1,152
2021	4,102
2022	3,344
2023	2,715
2024	2,361
Thereafter	14,722
Total	$	28,396

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 that we elected to apply, remaining performance obligations for: (i) 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.

XML

Reportable Segments (Notes)

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Reportable Segments

7.  Reportable Segments

Financial information by segment follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,803	$	1,925	$	5,229	$	6,073
Intersegment revenues	6		9		26		30
Products Pipelines	442		484		1,282		1,350
Terminals
Revenues from external customers	423		507		1,282		1,521
Intersegment revenues	1		1		3		3
CO2	251		298		792		913
Corporate and intersegment eliminations	(7)		(10)		(29)		(33)
Total consolidated revenues	$	2,919	$	3,214	$	8,585	$	9,857

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,091	$	1,092	$	2,284	$	3,383
Products Pipelines	223		325		719		908
Terminals	246		295		732		884
CO2	156		164		(453)		558
Kinder Morgan Canada	—		—		—		(2)
Total Segment EBDA	1,716		1,876		3,282		5,731
DD&A	(539)		(578)		(1,636)		(1,750)
Amortization of excess cost of equity investments	(32)		(21)		(99)		(61)
General and administrative and corporate charges	(150)		(162)		(472)		(478)
Interest, net	(383)		(447)		(1,214)		(1,359)
Income tax expense	(140)		(151)		(304)		(471)
Total consolidated net income (loss)	$	472	$	517	$	(443)	$	1,612

	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

_______

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

(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.

XML

Income Taxes (Notes)

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Income Taxes

8.  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,
	2020			2019			2020			2019
	(In millions, except percentages)
Income tax expense	$	140		$	151		$	304		$	471
Effective tax rate	22.9		%	22.6		%	(218.7)		%	22.6		%

The effective tax rate 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, 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. While we would normally expect a federal income tax benefit from our loss before income taxes, 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.

XML

Litigation and Environmental (Notes)

9 Months Ended

Sep. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

Litigation and Environmental

9.   Litigation and Environmental

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

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

On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return 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

The tariffs and rates charged by SFPP 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 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. 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 the extent the shippers are successful in one or more of the 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 in rate reductions and refunds substantially lower than those sought by the shippers.

EPNG FERC Proceedings

The tariffs and rates charged by EPNG are subject to two 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) 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.

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 delivered its Award, and the panel's ruling called for the termination of the agreement and Eni USA's payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On 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 Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending.

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seeks to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. The Delaware cross appeals were argued to the Delaware Supreme Court on September 9, 2020. The arbitration proceeding remains pending, but has been stayed by agreement pending the Delaware Supreme Court’s decision.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), 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 a declaration 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 rise to a contractual right on the part of ALSS to terminate the agreement.  ALSS also seeks 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 arbitration is expected by the end of the second quarter of 2021.

GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.

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

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties).  CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies and will vigorously defend against these claims.

Pipeline Integrity and Releases

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

General

As of September 30, 2020 and December 31, 2019, our total reserve for legal matters was $280 million and $203 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, state and local 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 environmental and safety regulations, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act. 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, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater

and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the remediation.

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 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. 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. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.

Uranium Mines in Vicinity of Cameron, Arizona

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

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

EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.

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

In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. We anticipate that process will be completed by December 31, 2020. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the allocation process and FS are completed, and the RI/FS is finalized, we are unable to reasonably estimate the extent of our potential liability.

Louisiana Governmental Coastal Zone Erosion Litigation

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

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Court of Appeals. 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 two cases against TGP, two cases against SNG, and two cases against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees,

interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. 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 and December 31, 2019, we have accrued a total reserve for environmental liabilities in the amount of $253 million and $259 million, respectively. In addition, as of September 30, 2020 and December 31, 2019, we have recorded a receivable of $12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable.

XML

Recent Accounting Pronouncements (Notes)

9 Months Ended

Sep. 30, 2020

Accounting Standards Update and Change in Accounting Principle [Abstract]

Recent Accounting Pronouncements

10. 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

On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.”  This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate.  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. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2020-06

On August 5, 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year ending December 31, 2021, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

XML

General (Policies)

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

General

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

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

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, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO₂; and (vi) Terminals. See Note 2 for results of our May 31, 2020 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

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.

XML

General (Tables)

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Net Income for Shareholders and Participating Securities

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	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

________

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

Schedule of Antidilutive Securities

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

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

XML

Impairments (Tables)

9 Months Ended

Sep. 30, 2020

Impairments [Abstract]

Schedule of Impairments

We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assets 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	$	—
Impairments of inventory	11		—
Gain on divestitures of long-lived assets	—		(10)
Products Pipelines
Impairment of long-lived and intangible assets	21		—
Terminals
Impairment of long-lived and intangible assets	5		—
Gain on divestitures of long-lived assets	—		(3)
CO2
Impairment of goodwill	600		—
Impairment of long-lived assets	350		—
Kinder Morgan Canada
Loss on divestiture of long-lived assets	—		2
Other gain on divestitures of long-lived assets	—		(2)
Pre-tax loss (gain) on divestitures and impairments, net	$	1,987	$	(13)

Schedule of 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	—		(1,000)		(600)		—		—		—		(1,600)
Goodwill as of September 30, 2020	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	19,851

XML

Debt (Tables)

9 Months Ended

Sep. 30, 2020

Debt Instrument [Line Items]

Schedule of 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	$	—	$	—
Commercial paper notes(a)	—		37
Current portion of senior notes
6.85%, due February 2020(b)	—		700
6.50%, due April 2020(c)	—		535
5.30%, due September 2020(d)	—		600
6.50%, due September 2020(d)	—		349
5.00%, due February 2021	750		—
3.50%, due March 2021	750		—
5.80%, due March 2021	400		—
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)	—		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

_______

(a)Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.

(b)On January 9, 2020, we sold the approximate 25 million shares 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.

(c)In April 2020, we repaid $535 million of maturing senior notes.

(d)In September 2020, we repaid a combined $949 million of maturing senior notes using proceeds from our newly issued senior notes.

(e)In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020.

(f)Excludes our “Debt fair value adjustments” which, as of September 30, 2020 and December 31, 2019, increased our total debt balances by $1,379 million and $1,032 million, respectively.

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]

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

XML

Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2020

Stockholders' Equity Note [Abstract]

Schedule of Dividends

The following table provides information about our per share dividends:

	Three Months Ended September 30,				Nine Months Ended September 30,
	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

Schedule of Accumulated Other Comprehensive Income

Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:

	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 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)

	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		—		—		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)

XML

Risk Management (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

As of September 30, 2020, 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)	MMBbl
Crude oil basis	(2.6)	MMBbl
Natural gas fixed price	(34.8)	Bcf
Natural gas basis	(34.8)	Bcf
NGL fixed price	(1.2)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(2.4)	MMBbl
Crude oil basis	(0.9)	MMBbl
Natural gas fixed price	(9.7)	Bcf
Natural gas basis	2.2	Bcf
NGL fixed price	(1.4)	MMBbl

Schedule of Interest Rate Derivatives

The following table summarizes our outstanding interest rate contracts as of September 30, 2020:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	7,625	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		Mark-to-Market	December 2021

_______

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

Schedule of Foreign Exchange Contracts, Statement of Financial Position

The following table summarizes our outstanding foreign currency contracts as of September 30, 2020:

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

_______

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

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

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

Fair Value of Derivative Contracts
		Derivatives Asset				Derivatives Liability
		September 30, 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)		—
	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)	—		—		(14)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	70		46		—		—
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		—		(1)		—
Subtotal		25		8		(11)		(7)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(3)		—
Subtotal		—		—		(3)		—
Total		25		8		(14)		(7)
Total derivatives		$	1,025	$	460	$	(68)	$	(65)

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

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

	Balance sheet asset fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
	(In millions)
As of September 30, 2020
Energy commodity derivative contracts(a)	$	3	$	184	$	—	$	187	$	(28)	$	—	$	159
Interest rate contracts	—		768		—		768		(2)		—		766
Foreign currency contracts	—		70		—		70		(14)		—		56
As of December 31, 2019
Energy commodity derivative contracts(a)	$	19	$	37	$	—	$	56	$	(19)	$	(21)	$	16
Interest rate contracts	—		358		—		358		—		—		358
Foreign currency contracts	—		46		—		46		(6)		—		40

	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)	$	—	$	(40)	$	28	$	8	$	(4)
Interest rate contracts	—		(14)		—		(14)		2		—		(12)
Foreign currency contracts	—		(14)		—		(14)		14		—		—
As of December 31, 2019
Energy commodity derivative contracts(a)	$	(3)	$	(55)	$	—	$	(58)	$	19	$	—	$	(39)
Interest rate contracts	—		(1)		—		(1)		—		—		(1)
Foreign currency contracts	—		(6)		—		(6)		6		—		—

_______

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

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

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

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

Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item
		Three Months Ended September 30,				Nine Months Ended September 30,
		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)

_______

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

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended September 30,					Three Months Ended September 30,
	2020		2019			2020		2019
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(143)	$	96	Revenues—Commodity sales	$	(47)	$	9
					Costs of sales	(7)		(3)
Interest rate contracts	—		(1)		Earnings from equity investments(c)	(1)		—
Foreign currency contracts	70		(69)		Other, net	61		(59)
Total	$	(73)	$	26	Total	$	6	$	(53)

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)

_______

(a)We expect to reclassify an approximate $68 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2020 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, we recognized a $12 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	$	—	$	—	$	—	$	(8)
Total	$	—	$	—	$	—	$	(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		—		18		(3)
	Earnings from equity investments(b)	—		—		—		2
Total(a)		$	99	$	12	$	371	$	35

_______

(a)The three and nine months ended September 30, 2020 include approximate gains of $96 million and $349 million, respectively, and the three and nine months ended September 30, 2019 include an approximate loss of $4 million and $2 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).

XML

Revenue Recognition (Tables)

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended September 30, 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	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

	Three 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)	$	882	$	89	$	256	$	1	$	(1)	$	1,227
Fee-based services	182		265		132		14		—		593
Total services	1,064		354		388		15		(1)		1,820
Commodity sales
Natural gas sales	618		—		—		—		(1)		617
Product sales	162		84		9		268		(7)		516
Total commodity sales	780		84		9		268		(8)		1,133
Total revenues from contracts with customers	1,844		438		397		283		(9)		2,953
Other revenues(c)
Leasing services	57		45		111		13		—		226
Derivatives adjustments on commodity sales	23		—		—		(1)		(1)		21
Other	10		1		—		3		—		14
Total Other revenues	90		46		111		15		(1)		261
Total revenues	$	1,934	$	484	$	508	$	298	$	(10)	$	3,214

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

	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		—		1,756
Total services	3,262		1,005		1,183		46		(3)		5,493
Commodity sales
Natural gas sales	1,979		—		—		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		—		660
Derivatives adjustments on commodity sales	61		—		—		(10)		—		51
Other	35		5		—		10		—		50
Total Other revenues	263		134		325		39		—		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 recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

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

Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2020	$	1,152
2021	4,102
2022	3,344
2023	2,715
2024	2,361
Thereafter	14,722
Total	$	28,396

XML

Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

Financial information by segment follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,803	$	1,925	$	5,229	$	6,073
Intersegment revenues	6		9		26		30
Products Pipelines	442		484		1,282		1,350
Terminals
Revenues from external customers	423		507		1,282		1,521
Intersegment revenues	1		1		3		3
CO2	251		298		792		913
Corporate and intersegment eliminations	(7)		(10)		(29)		(33)
Total consolidated revenues	$	2,919	$	3,214	$	8,585	$	9,857

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,091	$	1,092	$	2,284	$	3,383
Products Pipelines	223		325		719		908
Terminals	246		295		732		884
CO2	156		164		(453)		558
Kinder Morgan Canada	—		—		—		(2)
Total Segment EBDA	1,716		1,876		3,282		5,731
DD&A	(539)		(578)		(1,636)		(1,750)
Amortization of excess cost of equity investments	(32)		(21)		(99)		(61)
General and administrative and corporate charges	(150)		(162)		(472)		(478)
Interest, net	(383)		(447)		(1,214)		(1,359)
Income tax expense	(140)		(151)		(304)		(471)
Total consolidated net income (loss)	$	472	$	517	$	(443)	$	1,612

	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

_______

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

(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.

XML

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Schedule of Income Taxes

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

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

XML

General - Organization and Basis of Presentation (Details)	9 Months Ended
	Sep. 30, 2020 segment Terminals mi
General [Line Items]
Miles of pipeline | mi	83,000
Number of pipeline terminals owned interest in and/or operated | Terminals	147
Number of reporting units | segment	6

XML

General - Schedule of Net Income Available to Shareholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Common Stockholders	$ 455	$ 506	$ (488)	$ 1,580
Less: Net Income allocated to restricted stock awards(a)	$ (3)	$ (3)	$ (9)	$ (9)
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
Class P Common Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Available to Common Stockholders	$ 452	$ 503	$ (497)	$ 1,571
Unvested restricted stock awards | Class P Common Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Restricted stock awards outstanding	13		13

XML

General - Schedule of Antidilutive Securities (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Unvested restricted stock awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	13	13	13	13
Convertible trust preferred securities
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities	3	3	3	3

XML

Impairments – Schedule of Pre-tax Loss (Gain) on Impairments and Divestitures (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Finite-Lived Intangible Assets [Line Items]
Impairment of goodwill				$ 1,600
Loss (gain) on divestitures of long-lived assets	$ (11)		$ 3	(1,987)	$ 13
Pre-tax loss (gain) on divestitures and impairments, net				1,987	(13)
Natural Gas Pipelines
Finite-Lived Intangible Assets [Line Items]
Impairment of goodwill				1,000	0
Impairments of inventory				11	0
Loss (gain) on divestitures of long-lived assets				0	(10)
Products Pipelines
Finite-Lived Intangible Assets [Line Items]
Loss (gain) on impairments of long-lived assets				21	0
Terminals
Finite-Lived Intangible Assets [Line Items]
Loss (gain) on divestitures of long-lived assets				0	(3)
Loss (gain) on impairments of long-lived assets				5	0
CO2
Finite-Lived Intangible Assets [Line Items]
Impairment of goodwill				600	0
Loss (gain) on impairments of long-lived assets				350	0
Kinder Morgan Canada
Finite-Lived Intangible Assets [Line Items]
Loss (gain) on divestitures of long-lived assets					(2)
Corporate and intersegment eliminations
Finite-Lived Intangible Assets [Line Items]
Loss (gain) on divestitures of long-lived assets				0
Trans Mountain and Trans Mountain Expansion Project | Kinder Morgan Canada
Finite-Lived Intangible Assets [Line Items]
Loss (gain) on divestitures of long-lived assets				$ 0	$ 2
Oil and Gas Properties | CO2
Finite-Lived Intangible Assets [Line Items]
Loss (gain) on impairments of long-lived assets		$ 350

XML

Impairments Long-lived Assets (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2020	Sep. 30, 2020	Sep. 30, 2019
CO2
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges		$ 350	$ 0
Oil and Gas Properties | CO2
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges	$ 350
Valuation Technique, Discounted Cash Flow | CO2
Finite-Lived Intangible Assets [Line Items]
Estimated Weighted Average Cost Of Capital	9.25%
Valuation Technique, Discounted Cash Flow | Oil and Gas Properties | CO2
Finite-Lived Intangible Assets [Line Items]
Estimated Weighted Average Cost Of Capital	10.50%

XML

Impairments Goodwill Impairments (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended	9 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2020	Sep. 30, 2020	Sep. 30, 2019
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Goodwill, Balance		$ 21,451		$ 21,451	$ 21,451
Impairment					(1,600)
Goodwill, Balance	$ 19,851				19,851
Loss (gain) on divestitures of long-lived assets	(11)		$ 3		(1,987)	$ 13
Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Goodwill, Balance		14,249		14,249	14,249
Impairment					0
Goodwill, Balance	14,249				14,249
Natural Gas Pipelines Non-Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Goodwill, Balance		3,343		3,343	3,343
Impairment				(1,000)	(1,000)
Goodwill, Balance	2,343				2,343
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Goodwill, Balance		1,528		1,528	1,528
Impairment		(600)			(600)
Goodwill, Balance	$ 928				$ 928
CO2 | Maximum
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	10.00%				10.00%
Products Pipelines Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Goodwill, Balance		151		151	$ 151
Impairment					0
Goodwill, Balance	$ 151				151
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Goodwill, Balance		802		802	802
Impairment					0
Goodwill, Balance	$ 802				$ 802
Terminals | Maximum
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	10.00%				10.00%
Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Goodwill, Balance		$ 1,378		$ 1,378	$ 1,378
Impairment					0
Goodwill, Balance	$ 1,378				$ 1,378
Products Pipelines | Maximum
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	10.00%				10.00%
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment					$ (600)	0
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on divestitures of long-lived assets					0	(3)
Kinder Morgan Canada
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on divestitures of long-lived assets						(2)
Kinder Morgan Canada | Trans Mountain and Trans Mountain Expansion Project
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on divestitures of long-lived assets					$ 0	$ 2
Valuation Technique, Discounted Cash Flow | Natural Gas Pipelines Non-Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Number of Years of Projection to Determine Fair Value					6 years 6 months
Estimated Weighted Average Cost Of Capital	8.00%				8.00%
Valuation Technique, Discounted Cash Flow | CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Estimated Weighted Average Cost Of Capital		9.25%
Valuation Technique, Discounted Cash Flow | Oil and Gas Properties | CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Estimated Weighted Average Cost Of Capital		10.50%
Valuation, Market Approach | Natural Gas Pipelines Non-Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach	0.25				0.25
Enterprise Value to EBITDA Multiple Valuation	10				10
Valuation, Income Approach | Natural Gas Pipelines Non-Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach	0.75				0.75
Weighted Market Approach and Income Approach | Natural Gas Pipelines Non-Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Enterprise Value to EBITDA Multiple Valuation	11				11

XML

Debt Debt Outstanding (Details) - USD ($) shares in Millions				1 Months Ended		9 Months Ended
	Aug. 05, 2020	Feb. 24, 2020	Jan. 09, 2020	Sep. 30, 2020	Apr. 30, 2020	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Debt Instrument [Line Items]
Current portion of debt				$ 2,057,000,000		$ 2,057,000,000		$ 2,477,000,000
Total long-term debt				31,281,000,000		31,281,000,000		30,883,000,000
Total debt(f)				33,338,000,000		33,338,000,000		33,360,000,000
Debt fair value adjustments				1,379,000,000		1,379,000,000		1,032,000,000
Proceeds from issuances of debt						3,888,000,000	$ 5,118,000,000
Proceeds from Sale and Maturity of Marketable Securities			$ 907,000,000
Proceeds From Sale And Maturity Of Marketable Securities After Taxes			$ 764,000,000
Marketable securities at fair value				0		0		925,000,000
Repayments of debt						3,991,000,000	$ 6,303,000,000
Commercial paper notes(a)
Debt Instrument [Line Items]
Current portion of debt				0		0		$ 37,000,000
Debt, Weighted Average Interest Rate								1.90%
Current portion of other debt
Debt Instrument [Line Items]
Current portion of debt				46,000,000		46,000,000		$ 45,000,000
6.85%, due February 2020
Debt Instrument [Line Items]
Current portion of debt				0		0		$ 700,000,000
Debt Instrument, Interest Rate, Stated Percentage								6.85%
6.50%, due April 2020
Debt Instrument [Line Items]
Current portion of debt				0		0		$ 535,000,000
Debt Instrument, Interest Rate, Stated Percentage								6.50%
Repayments of debt					$ 535,000,000
5.30%, due September 2020
Debt Instrument [Line Items]
Current portion of debt				0		0		$ 600,000,000
Debt Instrument, Interest Rate, Stated Percentage								5.30%
6.50%, due September 2020
Debt Instrument [Line Items]
Current portion of debt				0		0		$ 349,000,000
Debt Instrument, Interest Rate, Stated Percentage								6.50%
5.00%, due February 2021
Debt Instrument [Line Items]
Current portion of debt				$ 750,000,000		$ 750,000,000		$ 0
Debt Instrument, Interest Rate, Stated Percentage				5.00%		5.00%
3.50%, due March 2021
Debt Instrument [Line Items]
Current portion of debt				$ 750,000,000		$ 750,000,000		0
Debt Instrument, Interest Rate, Stated Percentage				3.50%		3.50%
5.80%, due March 2021
Debt Instrument [Line Items]
Current portion of debt				$ 400,000,000		$ 400,000,000		0
Debt Instrument, Interest Rate, Stated Percentage				5.80%		5.80%
Other
Debt Instrument [Line Items]
Total long-term debt				$ 224,000,000		$ 224,000,000		228,000,000
$4 billion credit facility due November 16, 2023
Debt Instrument [Line Items]
Current portion of debt				0		0		0
Line of Credit Facility, Current Borrowing Capacity				4,000,000,000.0		4,000,000,000.0
Senior notes
Debt Instrument [Line Items]
Total long-term debt				30,578,000,000		30,578,000,000		30,164,000,000
Proceeds from issuances of debt	$ 1,226,000,000
Repayments of debt				949,000,000
Senior notes | 2.00%, due February 2031
Debt Instrument [Line Items]
Total long-term debt	$ 750,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.00%
Senior notes | 3.25%, due August 2050
Debt Instrument [Line Items]
Total long-term debt	$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Capital Trust I | Trust I preferred securities, 4.75%, due March 2028
Debt Instrument [Line Items]
Current portion of debt				111,000,000		111,000,000		111,000,000
Total long-term debt				$ 110,000,000		$ 110,000,000		$ 110,000,000
Debt Instrument, Interest Rate, Stated Percentage				4.75%		4.75%		4.75%
Kinder Morgan G.P., Inc. | KMI $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock
Debt Instrument [Line Items]
Current portion of debt				$ 0		$ 0		$ 100,000,000
Preferred Stock, Liquidation Preference, Value								1,000
EPC Building LLC | EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035
Debt Instrument [Line Items]
Total long-term debt				$ 369,000,000		$ 369,000,000		$ 381,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.967%		3.967%		3.967%
TGP | Senior notes
Debt Instrument [Line Items]
Total long-term debt		$ 1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage		2.90%
Proceeds from issuances of debt		$ 991,000,000
Kinder Morgan Canada Limited
Debt Instrument [Line Items]
Disposal Group, Including Discontinued Operation, Aggregate Shares			25

XML

Debt Credit Facilities (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Line of Credit Facility [Line Items]
Line of credit facility	$ 2,057	$ 2,477
$4 billion credit facility due November 16, 2023
Line of Credit Facility [Line Items]
Line of credit facility	0	0
Line of Credit Facility, Current Borrowing Capacity	4,000
5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member]
Line of Credit Facility [Line Items]
Line of credit facility	0
Line of Credit Facility, Remaining Borrowing Capacity	3,919
Letters of Credit Outstanding, Amount	81
Commercial paper notes(a)
Line of Credit Facility [Line Items]
Line of credit facility	$ 0	$ 37

XML

Debt FV Financial Instrument (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Reported Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	$ 34,717	$ 34,392
Estimate of Fair Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	$ 38,253	$ 38,016

XML

Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended		34 Months Ended
	Oct. 21, 2020	Mar. 31, 2020	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Jul. 19, 2017
Class of Stock [Line Items]
Common share buy-back program, amount								$ 2,000
Common share buy-back program, average price per share		$ 13.94					$ 17.71
Value of shares repurchased		$ 50			$ 50	$ 2	$ 575
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
Subsequent Event
Class of Stock [Line Items]
Per common share cash dividend declared for the period	$ 0.2625
Common stock
Class of Stock [Line Items]
Shares repurchased		3.6			4.0		32.0

XML

Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	$ 34,086	$ 34,531
Balance	31,945	34,474
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(7)	164
Other comprehensive (loss) gain before reclassifications	(16)	(132)
Loss reclassified from accumulated other comprehensive loss	72	35
Net current-period change in accumulated other comprehensive (loss) income	56	(97)
Balance	49	67
Foreign currency translation adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	0	(91)
Other comprehensive (loss) gain before reclassifications	1	20
Loss reclassified from accumulated other comprehensive loss	0	0
Net current-period change in accumulated other comprehensive (loss) income	1	20
Balance	1	(71)
Pension and other postretirement liability adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(326)	(403)
Other comprehensive (loss) gain before reclassifications	21	23
Loss reclassified from accumulated other comprehensive loss	0	0
Net current-period change in accumulated other comprehensive (loss) income	21	23
Balance	(305)	(380)
Total accumulated other comprehensive loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(333)	(330)
Other comprehensive (loss) gain before reclassifications	6	(89)
Loss reclassified from accumulated other comprehensive loss	72	35
Net current-period change in accumulated other comprehensive (loss) income	78	(54)
Balance	$ (255)	$ (384)

XML

Risk Management - Energy Commodity Price Risk Management (Details) - Energy commodity derivative contracts	9 Months Ended
	Sep. 30, 2020 MMBbls Bcf
Short | Derivatives designated as hedging instruments | Crude oil fixed price
Derivative [Line Items]
Net open position	20.2
Short | Derivatives designated as hedging instruments | Crude oil basis
Derivative [Line Items]
Net open position	2.6
Short | Derivatives designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	34.8
Short | Derivatives designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	34.8
Short | Derivatives designated as hedging instruments | NGL fixed price
Derivative [Line Items]
Net open position	1.2
Short | Derivatives not designated as hedging instruments | Crude oil fixed price
Derivative [Line Items]
Net open position	2.4
Short | Derivatives not designated as hedging instruments | Crude oil basis
Derivative [Line Items]
Net open position	0.9
Short | Derivatives not designated as hedging instruments | Natural gas fixed price
Derivative [Line Items]
Net open position | Bcf	9.7
Short | Derivatives not designated as hedging instruments | NGL fixed price
Derivative [Line Items]
Net open position	1.4
Long | Derivatives not designated as hedging instruments | Natural gas basis
Derivative [Line Items]
Net open position | Bcf	2.2

XML

Risk Management - Interest Rate Risk Management (Details) - USD ($) $ in Millions	3 Months Ended
	Sep. 30, 2020	Mar. 31, 2020
Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument | Fair Value Hedging
Derivative [Line Items]
Notional amount	$ 7,625
Floating-to-Fixed Interest Rate Contracts | Designated as Hedging Instrument | Derivatives in cash flow hedging relationships
Derivative [Line Items]
Notional amount	250
Floating-to-Fixed Interest Rate Contracts | Derivatives not designated as hedging instruments | Fair Value Hedging
Derivative [Line Items]
Notional amount	3,500
Notional Amount	1,000	$ 2,500
Current Portion Of Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	900
Long-term Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Amount of Hedged Item	$ 6,725

XML

Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Sep. 30, 2020 USD ($)
Derivatives in cash flow hedging relationships | Cross-currency contracts
Derivative [Line Items]
Notional amount	$ 1,358

XML

Risk Management - Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Derivatives Assets	$ 1,025	$ 460
Derivatives Liability	(68)	(65)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	187	56
Derivatives Liability	(40)	(58)
Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	768	358
Derivatives Liability	(14)	(1)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	70	46
Derivatives Liability	(14)	(6)
Derivatives designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives Assets	1,000	452
Derivatives Liability	(54)	(58)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	162	48
Derivatives Liability	(29)	(51)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	103	31
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(25)	(43)
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Assets	59	17
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(4)	(8)
Derivatives designated as hedging instruments | Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	768	358
Derivatives Liability	(11)	(1)
Derivatives designated as hedging instruments | Interest rate contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	134	45
Derivatives designated as hedging instruments | Interest rate contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(3)	0
Derivatives designated as hedging instruments | Interest rate contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Assets	634	313
Derivatives designated as hedging instruments | Interest rate contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(8)	(1)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	70	46
Derivatives Liability	(14)	(6)
Derivatives designated as hedging instruments | Foreign currency contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	0	0
Derivatives designated as hedging instruments | Foreign currency contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(14)	(6)
Derivatives designated as hedging instruments | Foreign currency contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Assets	70	46
Derivatives designated as hedging instruments | Foreign currency contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	0	0
Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives Assets	25	8
Derivatives Liability	(14)	(7)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	25	8
Derivatives Liability	(11)	(7)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	19	8
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	(10)	(7)
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets
Derivatives, Fair Value [Line Items]
Derivatives Assets	6	0
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits
Derivatives, Fair Value [Line Items]
Derivatives Liability	(1)	0
Derivatives not designated as hedging instruments | Interest rate contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	0	0
Derivatives Liability	(3)	0
Derivatives not designated as hedging instruments | Interest rate contracts | Fair value of derivatives contracts
Derivatives, Fair Value [Line Items]
Derivatives Assets	0	0
Derivatives not designated as hedging instruments | Interest rate contracts | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives Liability	$ (3)	$ 0

XML

Risk Management - Derivative Assets Input Level (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 1,025	$ 460
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	187	56
Contracts available for netting	(28)	(19)
Cash collateral held	0	(21)
Net amount	159	16
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	3	19
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	184	37
Energy commodity derivative contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	768	358
Contracts available for netting	(2)	0
Cash collateral held	0	0
Net amount	766	358
Interest rate contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	768	358
Interest rate contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Foreign currency contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	70	46
Contracts available for netting	(14)	(6)
Cash collateral held	0	0
Net amount	56	40
Foreign currency contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Foreign currency contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	70	46
Foreign currency contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 0	$ 0

XML

Risk Management - Derivative Liabilities Input Level (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ (68)	$ (65)
Energy commodity derivative contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(40)	(58)
Contracts available for netting	28	19
Cash collateral posted	8	0
Net amount	(4)	(39)
Energy commodity derivative contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(29)	(3)
Energy commodity derivative contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(11)	(55)
Energy commodity derivative contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(14)	(1)
Contracts available for netting	2	0
Cash collateral posted	0	0
Net amount	(12)	(1)
Interest rate contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Interest rate contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(14)	(1)
Interest rate contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Foreign currency contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(14)	(6)
Contracts available for netting	14	6
Cash collateral posted	0	0
Net amount	0	0
Foreign currency contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	0	0
Foreign currency contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	(14)	(6)
Foreign currency contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross amount	$ 0	$ 0

XML

Risk Management - Effect of Derivative Contracts on the Income Statement (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in income on derivative and related hedged item	$ 40	$ 21	$ 208	$ 51
Derivatives designated as hedging instruments | Derivatives in fair value hedging relationships | Interest rate contracts | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in income on derivative and related hedged item	(50)	117	409	453
Derivatives designated as hedging instruments | Derivatives in fair value hedging relationships | Hedged fixed rate debt
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Liability, Fair Value Hedge, Cumulative Increase (Decrease)	777		777
Derivatives designated as hedging instruments | Derivatives in fair value hedging relationships | Hedged fixed rate debt | Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in income on derivative and related hedged item	$ 50	$ (119)	$ (418)	$ (468)

XML

Risk Management - Effect on Income Statement Locations (Details) - Derivatives in cash flow hedging relationships - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income				$ 12
Cash flow hedge gain (loss) to be reclassified within twelve months			$ 68
Derivatives designated as hedging instruments
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	$ (73)	$ 26	(21)	(171)
Gain/(loss) reclassified from Accumulated OCI into income	6	(53)	(94)	(46)
Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	(143)	96	(29)	(74)
Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	0	(1)	(9)	(2)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	70	(69)	17	(95)
Revenues-Commodity sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(47)	9	(145)	15
Cost of sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(7)	(3)	(12)	8
Earnings from equity investments | Derivatives designated as hedging instruments | Interest rate contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(1)	0	(1)	2
Other, net | Derivatives designated as hedging instruments | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ 61	$ (59)	$ 64	$ (71)

XML

Risk Management - Derivatives in Net Investment Hedging Relationships (Details) - Derivatives in net investment hedging relationships - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	$ 0	$ 0	$ 0	$ (8)
Foreign currency contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	$ 0	$ 0	$ 0	$ (8)

XML

Risk Management - Effect on Income Statement Not Designated (Details) - Energy commodity derivative contracts - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ 99	$ 12	$ 371	$ 35
Revenues-Commodity sales
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	87	12	353	36
Cost of sales
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	12	0	18	(3)
Earnings from equity investments
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	0	0	0	2
Derivatives not designated as hedging instruments
Derivative [Line Items]
Gain/(loss) on settlement of derivative contracts	$ 96	$ (4)	$ 349	$ (2)

XML

Risk Management - Credit Risks (Details) - Energy commodity derivative contracts - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Credit Derivatives [Line Items]
Letter of credits outstanding, amount	$ 0	$ 0
Initial Margin Requirements	24
Variation Margin Requirements	8
Cash collateral posted	8	0
Other current liabilities | Cash collateral held
Credit Derivatives [Line Items]
Collateral posted		$ 15
Restricted Cash | Cash collateral held
Credit Derivatives [Line Items]
Cash collateral posted	$ 32

XML

Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 2,515	$ 2,953	$ 7,355	$ 9,096
Leasing services	317	226	910	660
Derivatives adjustments on commodity sales	40	21	208	51
Other	47	14	112	50
Total other revenues	404	261	1,230	761
Total revenues	2,919	3,214	8,585	9,857
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	1,803	1,925	5,229	6,073
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	442	484	1,282	1,350
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	423	507	1,282	1,521
CO2
Disaggregation of Revenue [Line Items]
Total revenues	251	298	792	913
Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,656	1,844	4,783	5,840
Leasing services	119	57	346	167
Derivatives adjustments on commodity sales	(6)	23	35	61
Other	40	10	91	35
Total other revenues	153	90	472	263
Total revenues	1,809	1,934	5,255	6,103
Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	394	438	1,140	1,216
Leasing services	42	45	126	129
Derivatives adjustments on commodity sales	0	0	0	0
Other	6	1	16	5
Total other revenues	48	46	142	134
Total revenues	442	484	1,282	1,350
Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	281	397	881	1,199
Leasing services	143	111	404	325
Derivatives adjustments on commodity sales	0	0	0	0
Other	0	0	0	0
Total other revenues	143	111	404	325
Total revenues	424	508	1,285	1,524
Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	190	283	579	874
Leasing services	13	13	34	39
Derivatives adjustments on commodity sales	46	(1)	173	(10)
Other	2	3	6	10
Total other revenues	61	15	213	39
Total revenues	251	298	792	913
Corporate and eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(6)	(9)	(28)	(33)
Leasing services	0	0	0	0
Derivatives adjustments on commodity sales	0	(1)	0	0
Other	(1)	0	(1)	0
Total other revenues	(1)	(1)	(1)	0
Total revenues	(7)	(10)	(29)	(33)
Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,071	1,227	3,256	3,737
Firm services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	818	882	2,479	2,701
Firm services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	69	89	215	253
Firm services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	185	256	563	785
Firm services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	1	1	1
Firm services | Corporate and eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(2)	(1)	(2)	(3)
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	503	593	1,532	1,756
Fee-based services | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	173	182	523	561
Fee-based services | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	228	265	670	752
Fee-based services | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	91	132	307	398
Fee-based services | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8	14	31	45
Fee-based services | Corporate and eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3	0	1	0
Total services revenues
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,574	1,820	4,788	5,493
Total services revenues | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	991	1,064	3,002	3,262
Total services revenues | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	297	354	885	1,005
Total services revenues | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	276	388	870	1,183
Total services revenues | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9	15	32	46
Total services revenues | Corporate and eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	(1)	(1)	(3)
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	506	617	1,381	1,973
Natural gas sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	507	618	1,385	1,979
Natural gas sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
Natural gas sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
Natural gas sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	0	1	1
Natural gas sales | Corporate and eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(2)	(1)	(5)	(7)
Product other than natural gas
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	435	516	1,186	1,630
Product other than natural gas | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	158	162	396	599
Product other than natural gas | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	97	84	255	211
Product other than natural gas | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5	9	11	16
Product other than natural gas | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	180	268	546	827
Product other than natural gas | Corporate and eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(5)	(7)	(22)	(23)
Commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	941	1,133	2,567	3,603
Total revenues	982	1,154	2,772	3,659
Commodity sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	665	780	1,781	2,578
Commodity sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	97	84	255	211
Commodity sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5	9	11	16
Commodity sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	181	268	547	828
Commodity sales | Corporate and eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ (7)	$ (8)	$ (27)	$ (30)

XML

Revenue Recognition Contract Balances (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Contract Assets
Contract assets balances	$ 44	$ 27
Transfer to Accounts receivable	21
Contract Liabilities
Contract liabilities balances	237	$ 232
Transfer to Revenues	$ 57

XML

Revenue Recognition Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Sep. 30, 2020 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue allocated to remaining performance obligations for contracted revenue	$ 28,396
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2020-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	3 months
Revenue allocated to remaining performance obligations for contracted revenue	$ 1,152
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 4,102
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 3,344
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 2,715
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 2,361
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition
Revenue allocated to remaining performance obligations for contracted revenue	$ 14,722

XML

Reportable Segments Reportable Segments Revenues (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Segment Reporting Information [Line Items]
Revenues	$ 2,919	$ 3,214	$ 8,585	$ 9,857
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(7)	(10)	(29)	(33)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	1,803	1,925	5,229	6,073
Natural Gas Pipelines | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(6)	(9)	(26)	(30)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	442	484	1,282	1,350
Terminals
Segment Reporting Information [Line Items]
Revenues	423	507	1,282	1,521
Terminals | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(1)	(1)	(3)	(3)
CO2
Segment Reporting Information [Line Items]
Revenues	$ 251	$ 298	$ 792	$ 913

XML

Reportable Segments Reportable Segments EBDA (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Segment Reporting Information [Line Items]
DD&A	$ (539)	$ (578)	$ (1,636)	$ (1,750)
Amortization of excess cost of equity investments	(32)	(21)	(99)	(61)
General and administrative and corporate charges	(153)	(154)	(461)	(456)
Income Tax Expense	(140)	(151)	(304)	(471)
Net Income (Loss)	472	517	(443)	1,612
Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	1,716	1,876	3,282	5,731
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
DD&A	(539)	(578)	(1,636)	(1,750)
Amortization of excess cost of equity investments	(32)	(21)	(99)	(61)
General and administrative and corporate charges	(150)	(162)	(472)	(478)
Interest, net	(383)	(447)	(1,214)	(1,359)
Income Tax Expense	(140)	(151)	(304)	(471)
Natural Gas Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	1,091	1,092	2,284	3,383
Products Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	223	325	719	908
Terminals | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	246	295	732	884
CO2 | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	156	164	(453)	558
Kinder Morgan Canada | Operating Segments
Segment Reporting Information [Line Items]
Total Segment EBDA	$ 0	$ 0	$ 0	$ (2)

XML

Reportable Segments Reportable Segments Assets (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Assets	$ 71,821	$ 74,157
Corporate and intersegment eliminations
Segment Reporting Information [Line Items]
Assets	2,686	1,966
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	48,522	50,310
Products Pipelines
Segment Reporting Information [Line Items]
Assets	9,216	9,468
Terminals
Segment Reporting Information [Line Items]
Assets	8,808	8,890
CO2
Segment Reporting Information [Line Items]
Assets	$ 2,589	$ 3,523

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Segment Reporting Information [Line Items]
Income tax expense	$ 140	$ 151	$ 304	$ 471
Effective tax rate	22.90%	22.60%	(218.70%)	22.60%
Statutory federal rate	21.00%	21.00%	21.00%	21.00%
Impairment of goodwill			$ 1,600

XML

Litigation and Environmental - Federal Energy Regulatory Commission Proceedings (Details) - Pending Litigation $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($) claims	Jun. 01, 2018 projects
Hiland Partners Holdings, LLC [Member]
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 225
EPNG [Abstract]
Infrastructures to Build for Settlement | projects		10
Federal Energy Regulatory Commission [Member] | Unfavorable Regulatory Action | EPNG
EPNG [Abstract]
Loss Contingency, Pending Claims, Number | claims	2
Federal Energy Regulatory Commission [Member] | Annual Rate Reductions | Unfavorable Regulatory Action | SFPP
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 50
Federal Energy Regulatory Commission [Member] | Revenue Subject to Refund | Unfavorable Regulatory Action | SFPP
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 425

XML

Litigation and Environmental - General (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Estimated Litigation Liability	$ 280	$ 203

XML

Litigation and Environmental - Portland Harbor (Details) - Environmental Protection Agency - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Billions	Jan. 06, 2017 USD ($) Parties Terminals
GATX Terminals Corporation (n/k/a KMLT)
Site Contingency [Line Items]
Estimated Remedy Implementation Period	13 years
Number of Parties Involved In Site Cleanup Allocation Negotiations | Parties	90
Number of Liquid Terminals	2
Environmental Remediation Expense | $	$ 1.1
KMBT
Site Contingency [Line Items]
Number of Liquid Terminals	2

XML

Litigation and Environmental - Lower Passaic River (Details) - Pending Litigation $ in Millions		9 Months Ended
	Oct. 05, 2016 USD ($)	Sep. 30, 2020 USD ($) Parties mi
Lower Passaic River Study Area
Site Contingency [Line Items]
Miles of river | mi		17
Number of Parties at a Joint Defense Group | Parties		44
Lower Passaic River Study Area | EPA preferred alternative estimate
Site Contingency [Line Items]
Environmental Remediation Expense | $		$ 1,700
Lower Passaic River Study Area | AOC required engineering and design work
Site Contingency [Line Items]
Environmental Remediation Expense | $	$ 165
Lower Passaic River Study Area | Design
Site Contingency [Line Items]
Estimated Remedy Implementation Period	4 years
Lower Passaic River Study Area | Clean Up Implementation
Site Contingency [Line Items]
Estimated Remedy Implementation Period	6 years
Lower Passaic River Study Area, Lower Portion
Site Contingency [Line Items]
Miles of river | mi		8

XML

Litigation and Environmental - Environmental Matters (Details)				240 Months Ended
	Apr. 16, 2019	Mar. 29, 2019 Parties	Nov. 08, 2013 Parties	Dec. 31, 1969	Jan. 31, 2015 cases
Loss Contingencies [Line Items]
Percentage of Response Costs	35.00%
Rare Metals Inc.
Loss Contingencies [Line Items]
Number of Uranium Mines				20
Parish of Plaquemines, Louisiana | Coastal Zone | TGP
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants | Parties			17
Parish Orleans, Louisiana | Coastal Zone | SNG
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants | Parties		10
Judicial District of Louisiana | Coastal Zone
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					40
Judicial District of Louisiana | Coastal Zone | TGP
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					1
Judicial District of Louisiana | Coastal Zone | SNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					1
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | TGP and SNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					2
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | TGP
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					2
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | SNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					2

XML

Litigation and Environmental - Other Contingencies (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Other contingencies
Accrual for Environmental Loss Contingencies	$ 253	$ 259
Recorded Third-Party Environmental Recoveries Receivable	$ 12	$ 15