KINDER MORGAN, INC. - Quarter Report: 2020 September (Form 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

☐ 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

Information Regarding Forward-Looking Statements

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements (Unaudited)

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

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

Consolidated Balance Sheets - as of September 30, 2020 and December 31, 2019

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

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

Notes to Consolidated Financial Statements

Note 1

Note 2

Note 3

Note 4

Note 5

Note 6

Note 7

Note 8

Note 9

Litigation and Environmental

Note 10

Recent Accounting Pronouncements

Item 2.

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

General and Basis of Presentation

Results of Operations

Overview

Consolidated Earnings Results (GAAP)

Non-GAAP Financial Measures

Segment Earnings Results

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

Income Taxes

Liquidity and Capital Resources

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Item 4.

Controls and Procedures

PART II. OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.

Defaults Upon Senior Securities

Item 4.

Mine Safety Disclosures

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

CIG

Colorado Interstate Gas Company, L.L.C.

KMP

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

ELC

Elba Liquefaction Company, L.L.C.

EPNG

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

SFPP

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

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

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.

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.

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.

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.


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


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.

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.

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.

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.

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 CO₂business 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 CO₂business segment during the three months ended March 31, 2020.

Additionally, we performed our annual goodwill impairment testing as of May 31, 2020. For our Natural Gas Pipelines Non-Regulated reporting unit, while no goodwill impairment was required as of March 31, 2020, the additional market and economic indicators existing at May 31, 2020, as further described below, 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 CO₂reporting 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 CO₂business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter.

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

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

The results of 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 CO₂reporting 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.

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.

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)

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.

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.

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.

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.

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.

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.

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,

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.

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.)

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.

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.

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 CO₂business 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)


	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.

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.

(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 CO₂reporting 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.

Supplemental Information


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
DD&A (GAAP)	$	539	$	578	$	1,636	$	1,750
Amortization of excess cost of equity investments (GAAP)	32		21		99		61
DD&A and amortization of excess cost of equity investments	571		599		1,735		1,811
Joint venture DD&A	91		100		277		297
DD&A attributable to KML noncontrolling interests	—		(5)		—		(15)
DD&A and amortization of excess cost of equity investments for DCF	$	662	$	694	$	2,012	$	2,093

Income tax expense (GAAP)	$	140	$	151	$	304	$	471
Certain Items	8		(8)		114		(15)
Income tax expense(a)	148		143		418		456
Unconsolidated joint venture income tax expense(a)	23		23		66		71
Income tax expense attributable to KML noncontrolling interests(a)	—		(2)		—		(6)
Income tax expense for DCF(a)	$	171	$	164	$	484	$	521

KML activities prior to December 16, 2019
Net income attributable to KML noncontrolling interests	$	—	$	9	$	—	$	25
KML noncontrolling interests associated with Certain Items	—		—		—		1
KML noncontrolling interests(a)	—		9		—		26
DD&A attributable to KML noncontrolling interests	—		5		—		15
Income tax expense attributable to KML noncontrolling interests(a)	—		2		—		6
KML noncontrolling interests DCF adjustments(a)	$	—	$	16	$	—	$	47

Net income attributable to noncontrolling interests (GAAP)	$	17	$	11	$	45	$	32
Less: KML noncontrolling interests(a)	—		9		—		26
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))	17		2		45		6
Noncontrolling interests associated with Certain Items	—		—		—		1
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)	$	17	$	2	$	45	$	7


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions)
Additional joint venture information
Unconsolidated joint venture DD&A	$	101	$	104	$	306	$	308
Consolidated joint venture partners’ DD&A	(10)		(4)		(29)		(11)
Joint venture DD&A	91		100		277		297
Unconsolidated joint venture income tax expense(a)	23		23		66		71
Joint venture DD&A and income tax expense(a)	$	114	$	123	$	343	$	368

Unconsolidated joint venture cash taxes(b)	$	(41)	$	(16)	$	(51)	$	(50)

Unconsolidated joint venture sustaining capital expenditures	$	(32)	$	(35)	$	(84)	$	(85)
Consolidated joint venture partners’ sustaining capital expenditures	2		2		4		5
Joint venture sustaining capital expenditures	$	(30)	$	(33)	$	(80)	$	(80)

______

(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

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

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.

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.

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)	%

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.

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)	%

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 CO₂business 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.

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

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 CO₂and 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

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

To refinance construction costs of its recent expansions, on February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 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.”

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.

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

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.

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

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.

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.

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)