KINDER MORGAN, INC. - Quarter Report: 2019 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, 2019

☐ 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 o

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 o

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 o Non-accelerated filer o 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. o

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 17, 2019, the registrant had 2,264,965,437 Class P shares outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS



		Page Number
	Glossary	2
	Information Regarding Forward-Looking Statements	3

	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2019 and 2018	4
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2019 and 2018	5
	Consolidated Balance Sheets - September 30, 2019 and December 31, 2018	6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2019 and 2018	7
	Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 30, 2019 and 2018	9
	Notes to Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation	44
	Results of Operations	45
	Overview	45
	Consolidated Earnings Results (GAAP)	47
	Non-GAAP Performance Measures	50
	Segment Earnings Results	53
	General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests	60
	Income Taxes	62
	Liquidity and Capital Resources	62

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	65

Item 4.	Controls and Procedures	66

	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	66

Item 1A.	Risk Factors	66

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66

Item 3.	Defaults Upon Senior Securities	66

Item 4.	Mine Safety Disclosures	66

Item 5.	Other Information	66

Item 6.	Exhibits	67

	Signature	68

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
EIG	=	EIG Global Energy Partners	KMP	=
ELC	=	Elba Liquefaction Company, L.L.C.	SFPP	=	SFPP, L.P.
EPNG	=	El Paso Natural Gas Company, L.L.C.	SNG	=	Southern Natural Gas Company, L.L.C.
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KMI	=	Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries	TMEP	=	Trans Mountain Expansion Project
KMI	=		TMPL	=	Trans Mountain Pipeline System
KML	=	Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries	Trans Mountain	=	Trans Mountain Pipeline ULC
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
2017 Tax Reform	=	The Tax Cuts & Jobs Act of 2017	EPA	=	U.S. Environmental Protection Agency
2017 Tax Reform	=	The Tax Cuts & Jobs Act of 2017	FASB	=	Financial Accounting Standards Board
/d	=	per day	FERC	=	Federal Energy Regulatory Commission
BBtu	=	billion British Thermal Units	GAAP	=	U.S. Generally Accepted Accounting Principles
Bcf	=	billion cubic feet	LLC	=	limited liability company
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	MBbl	=	thousand barrels
CERCLA	=		MMBbl	=	million barrels
C$	=	Canadian dollars	MMtons	=	million tons
CO₂	=	carbon dioxide or our CO₂ business segment	NGL	=	natural gas liquids
DCF	=	distributable cash flow	NYMEX	=	New York Mercantile Exchange
DD&A	=	depreciation, depletion and amortization	OTC	=	over-the-counter
EBDA	=	earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments	ROU	=	right of use
EBDA	=		U.S.	=	United States of America
EBITDA	=	earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments	WTI	=	West Texas Intermediate
EBITDA	=

When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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.

See “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, 2018 (2018 Form 10-K) for a more detailed description of factors that may affect the forward-looking statements. 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 plan to provide updates to projections included in this report when we believe previously disclosed projections no longer have a reasonable basis.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts, Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
Services	$	2,008		$	1,959		$	6,055		$	5,910
Natural gas sales	629			799			2,012			2,353
Product sales and other	577			759			1,790			2,100
Total Revenues	3,214			3,517			9,857			10,363
Operating Costs, Expenses and Other
Costs of sales	762			1,135			2,487			3,222
Operations and maintenance	668			646			1,912			1,882
Depreciation, depletion and amortization	578			569			1,750			1,710
General and administrative	154			154			456			491
Taxes, other than income taxes	103			86			324			259
(Gain) loss on divestitures and impairments, net	(3		)	(588		)	(13		)	65
Other expense (income), net	1			—			(1		)	(2		)
Total Operating Costs, Expenses and Other	2,263			2,002			6,915			7,627
Operating Income	951			1,515			2,942			2,736
Other Income (Expense)
Earnings from equity investments	173			160			526			438
Amortization of excess cost of equity investments	(21		)	(21		)	(61		)	(77		)
Interest, net	(447		)	(473		)	(1,359		)	(1,456		)
Other, net	12			20			35			90
Total Other Expense	(283		)	(314		)	(859		)	(1,005		)
Income Before Income Taxes	668			1,201			2,083			1,731
Income Tax Expense	(151		)	(196		)	(471		)	(314		)
Net Income	517			1,005			1,612			1,417
Net Income Attributable to Noncontrolling Interests	(11		)	(273		)	(32		)	(302		)
Net Income Attributable to Kinder Morgan, Inc.	506			732			1,580			1,115
Preferred Stock Dividends	—			(39		)	—			(117		)
Net Income Available to Common Stockholders	$	506		$	693		$	1,580		$	998
Class P Shares
Basic and Diluted Earnings Per Common Share	$	0.22		$	0.31		$	0.69		$	0.45
Basic and Diluted Weighted Average Common Shares Outstanding	2,264			2,205			2,263			2,205

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Millions, Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net income	$	517		$	1,005		$	1,612		$	1,417
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(6), $26, $39 and $39, respectively)	20			(87		)	(132		)	(133		)
Reclassification of change in fair value of derivatives to net income (net of tax expense of $13, $4, $11 and $23, respectively)	40			11			35			78
Foreign currency translation adjustments (net of tax benefit (expense) of $2, $(49), $(5) and $(28), respectively)	(7		)	300			16			187
Benefit plan adjustments (net of tax expense of $3, $21, $8 and $25, respectively)	8			37			23			49
Total other comprehensive income (loss)	61			261			(58		)	181
Comprehensive income	578			1,266			1,554			1,598
Comprehensive income attributable to noncontrolling interests	(8		)	(339		)	(28		)	(328		)
Comprehensive income attributable to Kinder Morgan, Inc.	$	570		$	927		$	1,526		$	1,270

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

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts, Unaudited)

	September 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	241		$	3,280
Restricted deposits	27			51
Accounts receivable, net	1,273			1,498
Fair value of derivative contracts	144			260
Inventories	405			385
Other current assets	275			248
Total current assets	2,365			5,722
Property, plant and equipment, net	37,934			37,897
Investments	8,387			7,481
Goodwill	21,964			21,965
Other intangibles, net	2,729			2,880
Deferred income taxes	1,324			1,566
Deferred charges and other assets	2,228			1,355
Total Assets	$	76,931		$	78,866
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	4,406		$	3,388
Accounts payable	916			1,337
Distributions payable to KML noncontrolling interests	—			876
Accrued interest	360			579
Accrued taxes	384			483
Other current liabilities	760			894
Total current liabilities	6,826			7,557
Long-term liabilities and deferred credits
Long-term debt
Outstanding	30,849			33,105
Preferred interest in general partner of KMP	100			100
Debt fair value adjustments	1,162			731
Total long-term debt	32,111			33,936
Other long-term liabilities and deferred credits	2,719			2,176
Total long-term liabilities and deferred credits	34,830			36,112
Total Liabilities	41,656			43,669
Commitments and contingencies (Notes 3, 10 and 11)
Redeemable Noncontrolling Interest	801			666
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,908,090 and 2,262,165,783 shares, respectively, issued and outstanding	23			23
Additional paid-in capital	41,727			41,701
Retained deficit	(7,733		)	(7,716		)
Accumulated other comprehensive loss	(384		)	(330		)
Total Kinder Morgan, Inc.’s stockholders’ equity	33,633			33,678
Noncontrolling interests	841			853
Total Stockholders’ Equity	34,474			34,531
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	76,931		$	78,866

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,
	2019			2018
Cash Flows From Operating Activities
Net income	$	1,612		$	1,417
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,750			1,710
Deferred income taxes	254			144
Amortization of excess cost of equity investments	61			77
Change in fair market value of derivative contracts	(20		)	188
(Gain) loss on divestitures and impairments, net	(13		)	65
Earnings from equity investments	(526		)	(438		)
Distributions from equity investment earnings	412			351
Changes in components of working capital
Accounts receivable, net	226			67
Inventories	(28		)	38
Other current assets	95			(18		)
Accounts payable	(266		)	(27		)
Accrued interest, net of interest rate swaps	(218		)	(198		)
Accrued taxes	(107		)	238
Other current liabilities	(136		)	(284		)
Other, net	25			45
Net Cash Provided by Operating Activities	3,121			3,375
Cash Flows From Investing Activities
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 2)	(28		)	3,003
Acquisitions of assets and investments	(3		)	(20		)
Capital expenditures	(1,719		)	(2,206		)
Proceeds from sales of equity investments	108			33
Contributions to investments	(1,148		)	(294		)
Distributions from equity investments in excess of cumulative earnings	207			197
Loans to related party	(23		)	(23		)
Other, net	(4		)	(4		)
Net Cash (Used in) Provided by Investing Activities	(2,610		)	686
Cash Flows From Financing Activities
Issuances of debt	5,118			11,837
Payments of debt	(6,303		)	(11,221		)
Debt issue costs	(9		)	(31		)
Cash dividends - common shares	(1,593		)	(1,163		)
Cash dividends - preferred shares	—			(117		)
Repurchases of common shares	(2		)	(250		)
Contributions from investment partner	135			148
Contributions from noncontrolling interests	3			19
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds	(879		)	—
Distributions to noncontrolling interests - other	(42		)	(58		)
Other, net	(28		)	(17		)
Net Cash Used in Financing Activities	(3,600		)	(853		)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	26			26
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(3,063		)	3,234
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3,331			326
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	268		$	3,560

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

	Nine Months Ended September 30,
	2019			2018
Cash and Cash Equivalents, beginning of period	$	3,280		$	264
Restricted Deposits, beginning of period	51			62
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3,331			326
Cash and Cash Equivalents, end of period	241			3,459
Restricted Deposits, end of period	27			101
Cash, Cash Equivalents, and Restricted Deposits, end of period	268			3,560
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(3,063	)	$	3,234

Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized (Note 10)	$	764
Increase in property, plant and equipment from both accruals and contractor retainage				$	35
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,584			1,593
Cash paid during the period for income taxes, net	364			37

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			Retained 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



	Preferred stock			Common stock
	Issued shares	Par value		Issued shares	Par value		Additional paid-in capital		Retained deficit			Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI			Non-controlling interests			Total
Balance at June 30, 2018	2	$	—	2,204	$	22	$	41,696	$	(7,993	)	$	(690	)	$	33,035		$	1,459		$	34,494
Restricted shares				1			8								8						8
Net income									732						732			273			1,005
Distributions															—			(25		)	(25		)
Contributions															—			4			4
Preferred stock dividends									(39		)				(39		)				(39		)
Common stock dividends									(444		)				(444		)				(444		)
Other															—			2			2
Other comprehensive income												195			195			66			261
Balance at September 30, 2018	2	$	—	2,205	$	22	$	41,704	$	(7,744	)	$	(495	)	$	33,487		$	1,779		$	35,266

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			Retained 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 (Note 5)							(4		)				(4		)				(4		)
Balance at January 1, 2019	2,262	23		41,701			(7,720		)	(330		)	33,674			853			34,527
Repurchase of 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



	Preferred stock			Common stock
	Issued shares	Par value		Issued shares		Par value		Additional paid-in capital			Retained deficit			Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI			Non-controlling interests			Total
Balance at December 31, 2017	2	$	—	2,217		$	22	$	41,909		$	(7,754	)	$	(541	)	$	33,636		$	1,488		$	35,124
Impact of adoption of ASU (Note 4)											175			(109		)	66						66
Balance at January 1, 2018	2	—		2,217		22		41,909			(7,579		)	(650		)	33,702			1,488			35,190
Repurchase of shares				(13	)			(250		)							(250		)				(250		)
Restricted shares				1				45									45						45
Net income											1,115						1,115			302			1,417
Distributions																	—			(69		)	(69		)
Contributions																	—			30			30
Preferred stock dividends											(117		)				(117		)				(117		)
Common stock dividends											(1,163		)				(1,163		)				(1,163		)
Other																	—			2			2
Other comprehensive income														155			155			26			181
Balance at September 30, 2018	2	$	—	2,205		$	22	$	41,704		$	(7,744	)	$	(495	)	$	33,487		$	1,779		$	35,266

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 84,300 miles of pipelines and 157 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, crude oil, diesel fuel, chemicals, metals and petroleum coke.

Basis of Presentation

General

Our reporting currency is U.S. dollars, and all references to “dollars” are U.S. dollars, unless stated otherwise. 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 2018 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.

For a discussion of Accounting Standards Updates (ASU) we adopted on January 1, 2019 and 2018, see Notes 4, 5 and 10.

Goodwill

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. The evaluation of goodwill for impairment involves a two-step test.

The results of our May 31, 2019 annual step 1 impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. A future period of volatile commodity prices could result in a deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital and our cash flow estimates. Changes to any one or combination of these factors would result in a change to the reporting unit fair values discussed above, which could lead to future impairment charges. Such potential impairment could have a material effect on our results of operations.

The fair value estimates used in step 1 of the goodwill test are based on Level 3 inputs of the fair value hierarchy. The level 3 inputs include valuation estimates using industry standard market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions prices, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit.

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 include dividend equivalent payments, do not participate in excess distributions over earnings.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net Income Available to Common Stockholders	$	506		$	693		$	1,580		$	998
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(3		)	(4		)	(9		)	(5		)
Net Income Allocated to Class P Stockholders	$	503		$	689		$	1,571		$	993

Basic Weighted Average Common Shares Outstanding	2,264			2,205			2,263			2,205
Basic Earnings Per Common Share	$	0.22		$	0.31		$	0.69		$	0.45

________


(a)	As of September 30, 2019, there were approximately 12 million restricted stock awards outstanding.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share (in millions on a weighted-average basis):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Unvested restricted stock awards	13	13	13	11
Convertible trust preferred securities	3	3	3	3
Mandatory convertible preferred stock(a)	—	58	—	58

_______


(a)	The holder of each convertible preferred share participated in our earnings by receiving preferred stock dividends through the mandatory conversion date of October 26, 2018, at which time our convertible preferred shares were converted to common shares.

2. Divestitures

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

On August 21, 2019, we announced an agreement to sell the U.S. portion of the Cochin Pipeline to Pembina Pipeline Corporation (Pembina) for $1.546 billion in cash. Also, KML announced that it reached an agreement with Pembina under which Pembina has agreed to acquire all of the outstanding common equity of KML, including our 70% interest, subject to the terms of the arrangement agreement between KML and Pembina. Subject to and upon closing, KML shareholders will receive 0.3068 shares of Pembina common stock for each share of KML common stock whereby we will receive approximately 25 million shares of Pembina common stock, with a pre-tax value of approximately $927 million as of September 30, 2019, for our 70% interest in KML. The closing of the two transactions are cross-conditioned upon each other, subject to KML’s shareholder and applicable regulatory approvals.

Sale of Trans Mountain Pipeline System and Its Expansion Project

gain from the TMPL Sale of $622 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated statements of income during both the three and nine months ended September 30, 2018. During the first quarter of 2019, KML settled an additional C$37 million (U.S.$28 million) of working capital adjustments, which amount is included in the accompanying consolidated statements of cash flows within “Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments” for the nine months ended September 30, 2019 and which we had substantially accrued for as of December 31, 2018.

On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion, and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.

3. Debt

The following table provides information on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions):



	September 30, 2019		December 31, 2018
Current portion of debt
$500 million, 364-day credit facility due November 15, 2019	$	—	$	—
$4 billion credit facility due November 16, 2023	—		—
Commercial paper notes(a)	532		433
KML C$500 million credit facility, due August 31, 2022(b)(c)	34		—
Current portion of senior notes
9.00%, due February 2019	—		500
2.65%, due February 2019	—		800
3.05%, due December 2019	1,500		1,500
6.85%, due February 2020	700		—
6.50%, due April 2020	535		—
5.30%, due September 2020	600		—
6.50%, due September 2020	349		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	45		44
Total current portion of debt	4,406		3,388

Long-term debt (excluding current portion)
Senior notes	30,124		32,380
EPC Building, LLC, promissory note, 3.967%, due 2018 through 2035	385		395
Kinder Morgan G.P. Inc., $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d)	100		100
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	230		220
Total long-term debt	30,949		33,205
Total debt(e)	$	35,355	$	36,593

_______


(a)	Weighted average interest rates on borrowings outstanding as of September 30, 2019 and December 31, 2018 were 2.47% and 3.10%, respectively.


(b)	Weighted average interest rate on borrowings outstanding as of September 30, 2019 was 3.41%.


(c)	Borrowings under the KML $500 million credit facility are denominated in C$ and are presented above in U.S. dollars. At September 30, 2019, the exchange rate was 0.7551 U.S. dollars per C$. See “—Credit Facilities—KML” below.


(d)	On July 17, 2019, we entered into a guarantee agreement for the payment obligations to the holders of these securities.

(e)

Excludes our “Debt fair value adjustments” which, as of September 30, 2019 and December 31, 2018, increased our total debt balances by $1,162 million and $731 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements.

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. For more information, see Note 13.

Credit Facilities

KMI

As of September 30, 2019, we had no borrowings outstanding under our $4.5 billion credit facilities (in the aggregate), $532 million outstanding under our commercial paper program and $84 million in letters of credit. Our availability under the credit facilities as of September 30, 2019 was $3,884 million. As of September 30, 2019, we were in compliance with all required covenants.

KML

As of September 30, 2019, KML had C$45 million (U.S.$34 million) of borrowings outstanding under its 4-year, C$500 million unsecured revolving credit facility, due August 31, 2022, with C$452 million (U.S.$341 million) available after further reducing the C$500 million (U.S.$378 million) capacity for C$3 million (U.S.$3 million) in letters of credit. As of September 30, 2019, KML was in compliance with all required covenants. As of December 31, 2018, KML had no borrowings outstanding under its credit facility.

4. Stockholders’ Equity

Common Equity

As of September 30, 2019, our common equity consisted of our Class P common stock. For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2018 Form 10-K.

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the nine months ended September 30, 2019, we settled repurchases of approximately 0.1 million of our Class P shares for approximately $2 million. Since December 2017, in total, we have repurchased approximately 29 million of our Class P shares under the program at an average price of approximately $18.18 per share for approximately $525 million.

KMI 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,
	2019		2018		2019		2018
Per common share cash dividend declared for the period	$	0.25	$	0.20	$	0.75	$	0.60
Per common share cash dividend paid in the period	$	0.25	$	0.20	$	0.70	$	0.525

On October 16, 2019, our board of directors declared a cash dividend of $0.25 per common share for the quarterly period ended September 30, 2019, which is payable on November 15, 2019 to common shareholders of record as of the close of business on October 31, 2019.

Noncontrolling Interests

KML

On August 21, 2019, KML announced that it reached an agreement with Pembina under which Pembina has agreed to acquire all the outstanding common and preferred equity of KML, including our 70% interest. See Note 2 for more information.

Distributions

KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. For additional information regarding our KML distributions, see Note 11 to our consolidated financial statements included in our 2018 Form 10-K.

During the three and nine months ended September 30, 2019, KML paid dividends to the public on its restricted voting shares of $4 million and $13 million, respectively, and on its Series 1 and Series 3 Preferred Shares of $5 million and $16 million, respectively.

On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its restricted voting shareholders as a return of capital.

Adoption of Accounting Pronouncements

On January 1, 2018, we adopted ASU No. 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU, which required us to apply the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our “Retained deficit” balance. The cumulative effect of our adoption of this ASU was a $66 million, net of income taxes, adjustment to our beginning “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018. This ASU also required us to classify EIG’s cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable noncontrolling interest” on our consolidated balance sheets as of September 30, 2019 and December 31, 2018, as EIG has the right to redeem their interests for cash under certain conditions.

On January 1, 2018, we adopted ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” Our accounting policy for the release of stranded tax effects in accumulated other comprehensive income is on an aggregate portfolio basis. This ASU permits companies to reclassify the income tax effects of the 2017 Tax Reform on items within accumulated other comprehensive income to retained earnings. The FASB refers to these amounts as “stranded tax effects.” Only the stranded tax effects resulting from the 2017 Tax Reform are eligible for reclassification. Our adoption of this ASU resulted in a $109 million reclassification adjustment of stranded income tax effects from “Accumulated other comprehensive loss” to “Retained deficit” on our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018.

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 and net investments in foreign operations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

On January 1, 2019, we adopted ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The ASU better aligns an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. We applied ASU No. 2017-12 using a modified retrospective approach for cash flow and fair value hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. Our adoption of ASU No. 2017-12 did not have a material impact on our consolidated financial statements.

Energy Commodity Price Risk Management

As of September 30, 2019, 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 instruments
Crude oil fixed price	(20.0	)	MMBbl
Crude oil basis	(8.8	)	MMBbl
Natural gas fixed price	(46.5	)	Bcf
Natural gas basis	(36.0	)	Bcf
NGL fixed price	(0.9	)	MMBbl
Derivatives not designated as hedging instruments
Crude oil fixed price	(0.8	)	MMBbl
Crude oil basis	(5.0	)	MMBbl
Natural gas fixed price	(8.3	)	Bcf
Natural gas basis	(18.2	)	Bcf
NGL fixed price	(2.2	)	MMBbl

As of September 30, 2019, 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 2023.

Interest Rate Risk Management

As of September 30, 2019 and December 31, 2018, we had a combined notional principal amount of $10,225 million and $10,575 million, respectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of the London Interbank Offered Rate (LIBOR) plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of September 30, 2019, the principal amount of hedged senior notes consisted of $2,600 million included in “Current portion of debt” and $7,625 million included in “Long-term debt” on our accompanying consolidated balance sheets. As of September 30, 2019, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of debt due to interest rate risk is through March 15, 2035.

During the nine months ended September 30, 2019, we entered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $250 million, which was designated as a cash flow hedge. This agreement effectively converts the interest expense associated with certain variable rate debt issuances from floating rates to fixed rates. As of September 30, 2019, the maximum length of time over which we have hedged a portion of our exposure to the variability in future interest payments is through January 15, 2023.

Foreign Currency Risk Management

As of both September 30, 2019 and December 31, 2018, we had a combined notional principal amount of $1,358 million of cross-currency swap agreements to manage the foreign currency risk related to our Euro-denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar-denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7-year and 12-year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The critical terms of the cross-currency swap agreements correspond to the related hedged senior notes.

During the year ended December 31, 2018, we entered into foreign currency swap agreements with a combined notional principal amount of C$2,450 million (U.S.$1,888 million). These swaps resulted in our selling fixed C$ and receiving fixed U.S.$, effectively hedging the foreign currency risk associated with a substantial portion of our share of the TMPL Sale proceeds which were held in Canadian dollar denominated accounts until KML’s board of directors and shareholder-approved distribution of the proceeds was made on January 3, 2019. At such time, our share of the TMPL Sale proceeds were then transferred into a U.S. dollar denominated account, our exposure to foreign currency risk was eliminated, and our foreign currency swaps were settled. These foreign currency swaps were accounted for as net investment hedges as the foreign currency risk was related to our investment in Canadian dollar denominated foreign operations, and the critical risks of the forward contracts coincided with those of the net investment. As a result, the change in fair value of the foreign currency swaps

while outstanding were reflected in the “Foreign currency translation adjustments” section of “Other comprehensive income (loss), net of tax” on our consolidated statements of comprehensive income.

Impact of Derivative Contracts on Our Consolidated Financial Statements

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



Fair Value of Derivative Contracts
		Derivative Assets				Derivative Liabilities
		September 30, 2019		December 31, 2018		September 30, 2019			December 31, 2018
	Location	Fair value				Fair value
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	73	$	135	$	(35	)	$	(45	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	47		64		(1		)	—
Subtotal		120		199		(36		)	(45		)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	53		12		(2		)	(37		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	421		121		(2		)	(78		)
Subtotal		474		133		(4		)	(115		)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	—		91		(14		)	(6		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		106		—			—
Subtotal		20		197		(14		)	(6		)
Total		614		529		(54		)	(166		)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	18		22		(4		)	(5		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		(1		)	—
Total		19		22		(5		)	(5		)
Total derivatives		$	633	$	551	$	(59	)	$	(171	)

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



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,
		2019			2018			2019			2018

Interest rate contracts	Interest, net	$	117		$	(72	)	$	453		$	(326	)

Hedged fixed rate debt(a)	Interest, net	$	(119	)	$	70		$	(468	)	$	315

_______


(a)	As of September 30, 2019, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $475 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.



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,
	2019			2018				2019			2018
Energy commodity derivative contracts	$	96		$	(109	)	Revenues—Natural gas sales	$	11		$	(4	)
							Revenues—Product sales and other	(2		)	(3		)
							Costs of sales	(3		)	2
Interest rate contracts	(1		)	—			Earnings from equity investments(c)	—			—
Foreign currency contracts	(69		)	(4		)	Other, net	(59		)	(10		)
Total	$	26		$	(113	)	Total	$	(53	)	$	(15	)



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,
	2019			2018				2019			2018
Energy commodity derivative contracts	$	(74	)	$	(160	)	Revenues—Natural gas sales	$	16		$	(9	)
							Revenues—Product sales and other	(1		)	(40		)
							Costs of sales	8			3
Interest rate contracts	(2		)	3			Earnings from equity investments(c)	2			(5		)
Foreign currency contracts	(95		)	(15		)	Other, net	(71		)	(50		)
Total	$	(171	)	$	(172	)	Total	$	(46	)	$	(101	)

_______

(a)

We expect to reclassify an approximate $69 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2019 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. During the nine months ended September 30, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring. 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					Location	Gain/(loss) reclassified from Accumulated OCI into income(a)
	Three Months Ended September 30,						Three Months Ended September 30,
	2019		2018				2019		2018
Foreign currency contracts	$	—	$	(14	)	(Gain) loss on divestitures and impairments, net	$	—	$	26
Total	$	—	$	(14	)	Total	$	—	$	26



Derivatives in net investment hedging relationships	Gain/(loss) recognized in OCI on derivative						Location	Gain/(loss) reclassified from Accumulated OCI into income(a)
	Nine Months Ended September 30,							Nine Months Ended September 30,
	2019			2018				2019		2018
Foreign currency contracts	$	(8	)	$	(14	)	(Gain) loss on divestitures and impairments, net	$	—	$	26
Total	$	(8	)	$	(14	)	Total	$	—	$	26

_______


(a)	During the three and nine months ended September 30, 2018, we recognized a $26 million gain as a result of the TMPL Sale. See Note 2.



Derivatives not designated as hedging instruments	Location	Gain/(loss) recognized in income on derivative
		Three Months Ended September 30,					Nine Months Ended September 30,
		2019		2018			2019			2018
Energy commodity derivative contracts	Revenues—Natural gas sales	$	1	$	—		$	26		$	2
	Revenues—Product sales and other	11		(65		)	10			(111		)
	Costs of sales	—		—			(3		)	1
	Earnings from equity investments(b)	—		—			2			—
Total(a)		$	12	$	(65	)	$	35		$	(108	)

_______


(a)	The three and nine months ended September 30, 2019 include approximate losses of $4 million and $2 million, respectively, and the three and nine months ended September 30, 2018 include approximate losses of $14 million and $11 million, respectively. These 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, 2019 and December 31, 2018, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2019 and December 31, 2018, we had cash margins of $19 million and $16 million, respectively, 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, 2019 represents the net of our initial margin requirements of $15 million, offset by counterparty variation margin requirements of $34 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, 2019, 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.

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 (in millions):



	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjustments			Total accumulated other comprehensive loss
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 (loss) income	(97		)	20			23			(54		)
Balance as of September 30, 2019	$	67		$	(71	)	$	(380	)	$	(384	)



	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjustments			Total accumulated other comprehensive loss
Balance as of December 31, 2017	$	(27	)	$	(189	)	$	(325	)	$	(541	)
Other comprehensive (loss) gain before reclassifications	(133		)	(51		)	16			(168		)
Losses reclassified from accumulated other comprehensive loss	78			223			22			323
Impact of adoption of ASU 2018-02 (Note 4)	(4		)	(36		)	(69		)	(109		)
Net current-period change in accumulated other comprehensive (loss) income	(59		)	136			(31		)	46
Balance as of September 30, 2018	$	(86	)	$	(53	)	$	(356	)	$	(495	)

6. Fair Value

The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.

The three broad levels of inputs defined by the fair value hierarchy are as follows:


•	Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;


•	Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and


•	Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

Fair Value of Derivative Contracts

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the ASC (in millions). 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														Net amount
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting			Cash collateral held(b)			Net amount
As of September 30, 2019
Energy commodity derivative contracts(a)	$	23	$	116	$	—	$	139	$	(19	)	$	(34	)	$	86
Interest rate contracts	—		474		—		474		(1		)	—			473
Foreign currency contracts	—		20		—		20		(14		)	—			6
As of December 31, 2018
Energy commodity derivative contracts(a)	$	28	$	193	$	—	$	221	$	(39	)	$	(25	)	$	157
Interest rate contracts	—		133		—		133		(7		)	—			126
Foreign currency contracts	—		197		—		197		(6		)	—			191



	Balance sheet liability fair value measurements by level															Net amount
	Level 1			Level 2			Level 3		Gross amount			Contracts available for netting		Cash collateral posted(b)		Net amount
As of September 30, 2019
Energy commodity derivative contracts(a)	$	(2	)	$	(39	)	$	—	$	(41	)	$	19	$	—	$	(22	)
Interest rate contracts	—			(4		)	—		(4		)	1		—		(3		)
Foreign currency contracts	—			(14		)	—		(14		)	14		—		—
As of December 31, 2018
Energy commodity derivative contracts(a)	$	(11	)	$	(39	)	$	—	$	(50	)	$	39	$	—	$	(11	)
Interest rate contracts	—			(115		)	—		(115		)	7		—		(108		)
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 such cash collateral 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.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):



	September 30, 2019				December 31, 2018
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
Total debt	$	36,517	$	40,056	$	37,324	$	37,469

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2019 and December 31, 2018.

7. Revenue Recognition

Disaggregation of Revenues

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



	Three Months Ended September 30, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total
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 revenues	1,064		354		388		15		(1		)	1,820
Sales
Natural gas sales	618		—		—		—		(1		)	617
Product sales	162		84		9		268		(7		)	516
Total sales revenues	780		84		9		268		(8		)	1,133
Total revenues from contracts with customers	1,844		438		397		283		(9		)	2,953
Other revenues(c)	90		46		111		15		(1		)	261
Total revenues	$	1,934	$	484	$	508	$	298	$	(10	)	$	3,214



	Three Months Ended September 30, 2018
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂			Kinder Morgan Canada(d)		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	819	$	95	$	232	$	—		$	—	$	—		$	1,146
Fee-based services	174		246		163		17			41		—			641
Total services revenues	993		341		395		17			41		—			1,787
Sales
Natural gas sales	806		—		—		—			—		(3		)	803
Product sales	358		94		9		313			—		(11		)	763
Total sales revenues	1,164		94		9		313			—		(14		)	1,566
Total revenues from contracts with customers	2,157		435		404		330			41		(14		)	3,353
Other revenues(c)	35		40		100		(14		)	3		—			164
Total revenues	$	2,192	$	475	$	504	$	316		$	44	$	(14	)	$	3,517



	Nine Months Ended September 30, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total
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 revenues	3,262		1,005		1,183		46		(3		)	5,493
Sales
Natural gas sales	1,979		—		—		1		(7		)	1,973
Product sales	599		211		16		827		(23		)	1,630
Total sales revenues	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)	263		134		325		39		—			761
Total revenues	$	6,103	$	1,350	$	1,524	$	913	$	(33	)	$	9,857



	Nine Months Ended September 30, 2018
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂			Kinder Morgan Canada(d)		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,490	$	286	$	751	$	1		$	—	$	(2	)	$	3,526
Fee-based services	500		706		460		50			167		—			1,883
Total services revenues	2,990		992		1,211		51			167		(2		)	5,409
Sales
Natural gas sales	2,370		—		—		1			—		(6		)	2,365
Product sales	904		310		16		948			—		(28		)	2,150
Total sales revenues	3,274		310		16		949			—		(34		)	4,515
Total revenues from contracts with customers	6,264		1,302		1,227		1,000			167		(36		)	9,924
Other revenues(c)	161		118		287		(130		)	3		—			439
Total revenues	$	6,425	$	1,420	$	1,514	$	870		$	170	$	(36	)	$	10,363

_______


(a)	Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c) below).


(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 are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.


(c)	Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 and primarily include leases and derivatives. See Notes 5 and 10 for additional information related to our derivative contracts and lessor contracts, respectively.


(d)	On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 2).

Contract Balances

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

The following table presents the activity in our contract assets and liabilities (in millions):



	Nine Months Ended September 30, 2019
Contract Assets
Balance at December 31, 2018(a)	$	24
Additions	77
Transfer to Accounts receivable	(27		)
Other	(1		)
Balance at September 30, 2019(b)	$	73
Contract Liabilities
Balance at December 31, 2018(c)	$	292
Additions	305
Transfer to Revenues	(285		)
Other(d)	(15		)
Balance at September 30, 2019(e)	$	297

_______


(a)	Includes current and non-current balances of $14 million and $10 million, respectively.


(b)	Includes current and non-current balances of $63 million and $10 million, respectively.


(c)	Includes current and non-current balances of $80 million and $212 million, respectively.


(d)	Includes foreign currency translation adjustments.


(e)	Includes current and non-current balances of $74 million and $223 million, respectively.

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, 2019 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):



Year	Estimated Revenue
Three months ended December 31, 2019	$	1,290
2020	4,631
2021	3,961
2022	3,346
2023	2,771
Thereafter	15,834
Total	$	31,833

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 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 or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue at the amount for which we have the right to invoice for services performed.

8. Reportable Segments

For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments. As a result, individual segment results for the three and nine months ended September 30, 2018 and balances as of December 31, 2018 have been reclassified to conform to the current presentation in the following tables.

Financial information by segment follows (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,925		$	2,180		$	6,073		$	6,391
Intersegment revenues	9			12			30			34
Products Pipelines	484			475			1,350			1,420
Terminals
Revenues from external customers	507			503			1,521			1,512
Intersegment revenues	1			1			3			2
CO₂	298			316			913			870
Kinder Morgan Canada(a)	—			44			—			170
Corporate and intersegment eliminations	(10		)	(14		)	(33		)	(36		)
Total consolidated revenues(b)	$	3,214		$	3,517		$	9,857		$	10,363



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Segment EBDA(c)
Natural Gas Pipelines	$	1,092		$	930		$	3,383		$	2,368
Products Pipelines	325			325			908			912
Terminals	295			301			884			872
CO₂	164			205			558			561
Kinder Morgan Canada(a)	—			654			(2		)	746
Total Segment EBDA(d)	1,876			2,415			5,731			5,459
DD&A	(578		)	(569		)	(1,750		)	(1,710		)
Amortization of excess cost of equity investments	(21		)	(21		)	(61		)	(77		)
General and administrative and corporate charges	(162		)	(151		)	(478		)	(485		)
Interest, net	(447		)	(473		)	(1,359		)	(1,456		)
Income tax expense	(151		)	(196		)	(471		)	(314		)
Total consolidated net income	$	517		$	1,005		$	1,612		$	1,417



	September 30, 2019		December 31, 2018
Assets
Natural Gas Pipelines	$	51,164	$	50,261
Products Pipelines	9,501		9,598
Terminals	9,903		9,415
CO₂	3,757		3,928
Corporate assets(e)	2,606		5,664
Total consolidated assets(f)	$	76,931	$	78,866

_______


(a)	On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 2).

(b)

Revenues previously reported (before reclassifications) for the three months ended September 30, 2018 were $2,227 million, $432 million, $502 million and $(4) million and for the nine months ended September 30, 2018 were $6,559 million, $1,273 million, $1,508 million and $(17) million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, and the Corporate and intersegment eliminations, respectively.


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


(d)	Segment EBDA previously reported (before reclassifications) for the three months ended September 30, 2018 were $976 million, $279 million and $301 million and for the nine months ended September 30, 2018 were $2,425 million, $857 million and $870 million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, respectively.

(e)

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


(f)	Assets previously reported as of December 31, 2018 were $51,562 million, $8,429 million and $9,283 million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, respectively. The reclassification included a transfer of $450 million of goodwill from the Natural Gas Pipelines Non-Regulated reporting unit to the Products Pipelines reporting unit.

9. Income Taxes

Income tax expense included in our accompanying consolidated statements of income are as follows (in millions, except percentages):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Income tax expense	$	151		$	196		$	471		$	314
Effective tax rate	22.6		%	16.3		%	22.6		%	18.1		%

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 income taxes, partially offset by dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings LLC (NGPL) and Plantation Pipe Line Company (Plantation).

The effective tax rate for the three and nine months ended September 30, 2018 is lower than the statutory federal rate of 21% primarily due to the lower Canadian capital gains tax rate applicable to the TMPL Sale, dividend-received deductions from our investments in Citrus, Plantation and NGPL, and a reduction of our income tax reserve for uncertain tax positions as a result of the settlement of income tax audits. These reductions are partially offset by state income taxes.

10. Leases

Effective January 1, 2019, we adopted ASU No. 2016-02, “Leases (Topic 842)” and the series of related Accounting Standards Updates that followed (collectively referred to as “Topic 842”). The most significant changes under the new guidance include clarification of the definition of a lease, and the requirements for lessees to recognize a ROU asset and a lease liability for all qualifying leases with terms longer than twelve months in the consolidated balance sheet. In addition, under Topic 842, additional disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

We elected the practical expedient available to us under ASU 2018-11 “Leases: Targeted Improvements” which allows us to apply the transition provision for Topic 842 at our adoption date instead of at the earliest comparative period presented in our financial statements. Therefore, we recognized and measured leases existing at January 1, 2019 but without retrospective application. In addition, we elected the optional practical expedient permitted under the transition guidance related to land easements which allows us to carry forward our historical accounting treatment for land easements on existing agreements upon adoption. We also elected all other available practical expedients except the hindsight practical expedient.

The impact of Topic 842 on our consolidated balance sheet beginning January 1, 2019 was through the recognition of ROU assets and lease liabilities for operating leases, while our accounting for finance leases remained substantially unchanged. Our finance leases were immaterial prior to the adoption of Topic 842, and no change was made to the classification for these leases. Amounts recognized at January 1, 2019 for operating leases were as follows (in millions):



	January 1, 2019
ROU assets	$	696
Short-term lease liability	52
Long-term lease liability	644

No impact was recorded to the income statement or beginning retained earnings for Topic 842.

Lessee

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 34 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.

Beginning January 1, 2019, operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Operating leases in effect prior to January 1, 2019 were recognized at the present value of the remaining payments on the remaining lease term as of January 1, 2019. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, were reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when agreements are modified.

Following are components of our lease cost (in millions):



	Nine Months Ended September 30, 2019
Operating leases	$	107
Short-term and variable leases	58
Total lease cost(a)	$	165

_______


(a)	Includes $29 million of capitalized lease costs.

Other information related to our operating leases are as follows (in millions, except lease term and discount rate):



	Nine Months Ended September 30, 2019
Operating cash flows from operating leases	$	(136	)
Investing cash flows from operating leases	(29		)
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion	70
Amortization of ROU assets	52

Weighted average remaining lease term	16.31 years
Weighted average discount rate	5.87		%

Amounts recognized in the accompanying consolidated balance sheet are as follows (in millions):



Lease Activity	Balance sheet location	September 30, 2019
ROU assets	Deferred charges and other assets	$	714
Short-term lease liability	Other current liabilities	53
Long-term lease liability	Other long-term liabilities and deferred credits	661
Finance lease assets	Property, plant and equipment, net	2
Finance lease liabilities	Long-term debt—Outstanding	2

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of September 30, 2019 are as follows (in millions):



Three months ended December 31, 2019	$	26
2020	90
2021	81
2022	74
2023	67
Thereafter	825
Total lease payments(a)	1,163
Less: Interest	(449		)
Present value of lease liabilities	$	714

_______


(a)	Amount excludes future minimum rights-of-way obligations (ROW) as they do not constitute a lease obligation. The amounts in our future minimum ROW obligations as presented in the table below have not materially changed since December 31, 2018.

Undiscounted future gross minimum operating lease payments and ROW obligations as of December 31, 2018 are as follows (in millions):



	Leases		ROW		Total(a)
2019	$	90	$	25	$	115
2020	75		25		100
2021	70		25		95
2022	65		26		91
2023	59		25		84
Thereafter	771		88		859
Total payments	$	1,130	$	214	$	1,344

_______

(a)

This table has been revised from the previously reported December 31, 2018 future gross minimum rental commitments under our operating leases and ROW obligations table in our 2018 Form 10-K to (i) separately present lease and ROW obligations and (ii) to correct amounts previously reported to include an additional $482 million of undiscounted future lease payments, primarily in the “Thereafter” amount associated with the 2018 extension of KML’s, Edmonton South tank lease through December 2038.

Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.

Lessor

Our assets that we lease to others under operating leases consists primarily of specific facilities where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating and gas equipment and pipelines with separate control locations. Our leases have remaining lease terms of one to 32 years, some of which have options to extend the lease for up to an additional 25 years, and some of which may include options to terminate the lease within one year. We determine if an arrangement is a lease at inception or upon modification. None of our leases allow the lessee to purchase the leased asset.

Lease income for the three and nine months ended September 30, 2019 totaled $226 million and $660 million, respectively, including a significant amount of variable lease payments that is excluded from the following disclosure as the amounts cannot be reasonably estimated for future periods.

Future minimum operating lease payments to be received based on contractual agreements are as follows (in millions):



	September 30, 2019
2019 (three months ended December 31, 2019)	$	98
2020	370
2021	344
2022	329
2023	299
Thereafter	3,699
Total	$	5,139

Options for a lessee to renew the agreement are not included as part of future minimum operating lease revenues. We elected the practical expedient available to us to not separate lease and non-lease components under these agreements. Any modification of a lease will result in a reevaluation of the lease classification.

11. 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 on our business, financial position, results of operations or dividends to our shareholders. 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 Proceedings

FERC Rulemaking on Tax Cuts and Jobs Act for Jurisdictional Natural Gas Pipelines

In July 2018, the FERC issued an order requiring an informational filing by interstate natural gas pipelines on a new Form 501-G, evaluating the impact of the 2017 Tax Reform and the Revised Tax Policy on tax allowances for the pipelines. KMI and certain of its pipeline affiliates successfully worked with their shippers to achieve settlements without the need for litigation or any additional intervention by the FERC. The FERC has approved settlements filed by EPNG, SNG, TGP, Young Gas Storage, and Bear Creek Storage Company, L.L.C. and terminated all of our remaining 501-G proceedings without taking further action. Accordingly, our 501-G exposure has been resolved.

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 seeks 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 and there is no deadline or requirement for the FERC to take action on this matter.

SFPP

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 (currently on appeal to the D.C. Circuit Court); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (currently 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 (not yet been set for hearing by the FERC); 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 (pending before the FERC for an order on the initial decision); and OR19-21, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 (currently 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 are entitled to seek reparations (which may reach back up to two years prior to the filing date of their complaints) or refunds of any excess rates paid, 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.

Per order of the FERC, in May 2019 SFPP paid refunds to shippers in the IS08-390 proceeding based on the 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 $30 million in annual rate reductions and approximately $330 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

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 will 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. On February 21, 2017, the reviewing court delayed the case until the FERC ruled on the rehearing requests pending in the 2010 Rate Case. 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. On August 23, 2018, the reviewing court established a briefing schedule and consolidated EPNG’s delayed appeal from the 2008 rate case, EPNG’s appeal from the 2010 rate case, and the intervenors’ delayed appeal in the 2010 case. In accordance with that schedule, briefing has been completed and oral argument is scheduled for November 25, 2019.

Other Commercial Matters

Gulf LNG Facility Arbitration

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. On June 3, 2019, Eni USA

filed a second Notice of Arbitration against GLNG asserting the same breach of contract claim 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 Delaware Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Delaware Court of Chancery together with a motion seeking to permanently enjoin the arbitration. The Delaware Court of Chancery heard oral argument on GLNG’s complaint and related motion in August 2019, and all deadlines in the Second Arbitration are stayed pending the Court’s decision. GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.

Price Reporting Litigation

Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. All of the cases have been settled or dismissed, including the settlement of the final Wisconsin class action lawsuit which was approved by the U.S. District Court in Nevada on August 5, 2019. The amount that was paid in settlement of this matter is not material to our results of operations, cash flows or dividends to shareholders.

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, 2019 and December 31, 2018, our total reserve for legal matters was $188 million and $207 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, 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, could result in substantial costs and liabilities to us.

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, individually or in the aggregate, will be material. 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 and 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. 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). Our share of responsibility for Portland Harbor Superfund Site 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 site. 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 site. 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, given the U.S. is the owner of the Navajo Reservation, the U.S.’s exploration and reclamation activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. After a trial which concluded in March 2019, the U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the government. The decision was not appealed by any party. 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 this decision will have a material adverse impact to our results of operations, cash flows, or dividends to KMI shareholders.

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. The final cleanup plan in the ROD is 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 expected to take four years to complete and the cleanup is expected to take six years to complete. On June 30, 2018 and July 13, 2018, respectively, OCC filed two separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each

defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018.

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. 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 recent 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 this FS is completed and the RI/FS is finalized and allocations are determined, the scope of potential EPA claims for the Site and liability therefor are not reasonably estimable.

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). The Plaintiffs allege the defendants’ operations caused substantial damage to the coastal waters of Louisiana and nearby lands, including marsh (Coastal Zone). The alleged damages include erosion of property within the Coastal Zone, and discharge of pollutants that are alleged to have adversely impacted the Coastal Zone, including plants and wildlife. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected Coastal Zone to its original condition. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) routinely intervene in these cases, and we expect the LDNR and LAG to intervene in any additional cases that may be filed. 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 defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and that those operations caused substantial damage to the Coastal Zone. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. In 2016, the LAG and LDNR intervened in the lawsuit. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana on several grounds including federal officer liability. Plaquemines Parish, along with the intervenors, moved to remand the case to the state district court. On May 28, 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified the federal officer liability jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals and on June 11, 2019, the U.S. District Court stayed the remand order pending the outcome of that review. The case is effectively stayed pending resolution of the federal officer liability issue by the Court of Appeals. 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 Zone. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. On April 5, 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. On May 28, 2019, Orleans moved to remand the case to the state district court. 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 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. Plaintiffs allege that 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. Plaintiffs seek, among other relief, unspecified money damages, attorneys’ 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. Plaintiffs allege that defendants are obligated to restore and remediate the affected property without regard to the value of the property. Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. In one case filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant that was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana, $80 million was sought in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. On May 4, 2018, the District Court entered a judgment dismissing the tort and negligence claims against all of the defendants, and dismissing certain of the contract claims against TGP. In ruling in favor of plaintiffs on the remaining contract claims, the District Court ordered the defendants to pay $1,104 in money damages, and issued a permanent injunction ordering the defendants to restore a total of 9.6 acres of land and maintain certain canals at widths designated by the right of way agreements in effect. The Court stayed the judgment and the injunction pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. On September 13, 2018, the third-party defendant filed a motion to vacate the judgment and dismiss all of the appeals for lack of subject matter jurisdiction. On October 2, 2018 the Court of Appeals dismissed the appeals and on April 17, 2019 the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. The case is set for trial February 3, 2020. We will continue to vigorously defend these 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, financial position, results of operations or cash flows. As of September 30, 2019 and December 31, 2018, we have accrued a total reserve for environmental liabilities in the amount of $258 million and $271 million, respectively. In addition, as of both September 30, 2019 and December 31, 2018, we have recorded a receivable of $13 million for expected cost recoveries that have been deemed probable.

12. Recent Accounting Pronouncements

ASU No. 2016-13

On June 16, 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to utilize a new forward-looking “expected loss” methodology that generally will result in the earlier recognition of allowance for losses. ASU No. 2016-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-04

On January 26, 2017, the FASB issued ASU No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This ASU simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2018-13

On August 28, 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU amends existing fair value measurement disclosure requirements by adding, changing, or removing certain disclosures. ASU No. 2018-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

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.

13. Guarantee of Securities of Subsidiaries

KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s 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. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the Parent Issuer, Subsidiary Issuer and other subsidiaries are all guarantors of each series of public debt.

Excluding fair value adjustments, as of September 30, 2019, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $15,220 million, $16,610 million, and $2,535 million, respectively, of Guaranteed Notes outstanding. Included in the Subsidiary Guarantors debt balance as presented in the accompanying September 30, 2019 condensed consolidating balance sheet is approximately $169 million of other financing obligations that are not subject to the cross guarantee agreement.

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended September 30, 2019 (In Millions, Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	2,910		$	317		$	(13	)	$	3,214

Operating Costs, Expenses and Other
Costs of sales	—			—			734			29			(1		)	762
Depreciation, depletion and amortization	5			—			505			68			—			578
Other operating expense	2			1			804			128			(12		)	923
Total Operating Costs, Expenses and Other	7			1			2,043			225			(13		)	2,263

Operating (Loss) Income	(7		)	(1		)	867			92			—			951

Other Income (Expense)
Earnings from consolidated subsidiaries	840			780			92			17			(1,729		)	—
Earnings from equity investments	—			—			173			—			—			173
Interest, net	(191		)	1			(253		)	(4		)	—			(447		)
Amortization of excess cost of equity investments and other, net	(4		)	—			(5		)	—			—			(9		)

Income Before Income Tax	638			780			874			105			(1,729		)	668

Income Tax Expense	(132		)	—			(16		)	(3		)	—			(151		)

Net Income	506			780			858			102			(1,729		)	517
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(11		)	(11		)
Net Income Attributable to Controlling Interests	$	506		$	780		$	858		$	102		$	(1,740	)	$	506

Net Income	$	506		$	780		$	858		$	102		$	(1,729	)	$	517
Total other comprehensive income (loss)	64			83			81			(5		)	(162		)	61
Comprehensive income	570			863			939			97			(1,891		)	578
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(8		)	(8		)
Comprehensive income attributable to controlling interests	$	570		$	863		$	939		$	97		$	(1,899	)	$	570

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended September 30, 2018 (In Millions, Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	3,159		$	385		$	(27	)	$	3,517

Operating Costs, Expenses and Other
Costs of sales	—			—			1,083			68			(16		)	1,135
Depreciation, depletion and amortization	5			—			487			77			—			569
Other operating (income) expense	(23		)	—			783			(451		)	(11		)	298
Total Operating Costs, Expenses and Other	(18		)	—			2,353			(306		)	(27		)	2,002

Operating Income	18			—			806			691			—			1,515

Other Income (Expense)
Earnings from consolidated subsidiaries	1,183			1,138			579			28			(2,928		)	—
Earnings from equity investments	—			—			160			—			—			160
Interest, net	(201		)	(2		)	(273		)	3			—			(473		)
Amortization of excess cost of equity investments and other, net	7			—			1			(9		)	—			(1		)

Income Before Income Tax	1,007			1,136			1,273			713			(2,928		)	1,201

Income Tax (Expense) Benefit	(275		)	73			(20		)	26			—			(196		)

Net Income	732			1,209			1,253			739			(2,928		)	1,005
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(273		)	(273		)

Net Income Attributable to Controlling Interests	732			1,209			1,253			739			(3,201		)	732

Preferred Stock Dividends	(39		)	—			—			—			—			(39		)
Net Income Available to Common Shareholders	$	693		$	1,209		$	1,253		$	739		$	(3,201	)	$	693

Net Income	$	732		$	1,209		$	1,253		$	739		$	(2,928	)	$	1,005
Total other comprehensive income	195			207			166			431			(738		)	261
Comprehensive income	927			1,416			1,419			1,170			(3,666		)	1,266
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(339		)	(339		)
Comprehensive income attributable to controlling interests	$	927		$	1,416		$	1,419		$	1,170		$	(4,005	)	$	927

Condensed Consolidating Statements of Income and Comprehensive Income for the Nine Months Ended September 30, 2019 (In Millions, Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	8,994		$	941		$	(78	)	$	9,857

Operating Costs, Expenses and Other
Costs of sales	—			—			2,413			117			(43		)	2,487
Depreciation, depletion and amortization	15			—			1,531			204			—			1,750
Other operating expense	5			1			2,312			395			(35		)	2,678
Total Operating Costs, Expenses and Other	20			1			6,256			716			(78		)	6,915

Operating (Loss) Income	(20		)	(1		)	2,738			225			—			2,942

Other Income (Expense)
Earnings from consolidated subsidiaries	2,579			2,438			226			53			(5,296		)	—
Earnings from equity investments	—			—			526			—			—			526
Interest, net	(575		)	(4		)	(761		)	(19		)	—			(1,359		)
Amortization of excess cost of equity investments and other, net	(11		)	—			(13		)	(2		)	—			(26		)

Income Before Income Tax	1,973			2,433			2,716			257			(5,296		)	2,083

Income Tax Expense	(393		)	(2		)	(58		)	(18		)	—			(471		)

Net Income	1,580			2,431			2,658			239			(5,296		)	1,612
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(32		)	(32		)
Net Income Attributable to Controlling Interests	$	1,580		$	2,431		$	2,658		$	239		$	(5,328	)	$	1,580

Net Income	$	1,580		$	2,431		$	2,658		$	239		$	(5,296	)	$	1,612
Total other comprehensive (loss) income	(54		)	(66		)	(75		)	30			107			(58		)
Comprehensive income	1,526			2,365			2,583			269			(5,189		)	1,554
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(28		)	(28		)
Comprehensive income attributable to controlling interests	$	1,526		$	2,365		$	2,583		$	269		$	(5,217	)	$	1,526

Condensed Consolidating Statements of Income and Comprehensive Income for the Nine Months Ended September 30, 2018 (In Millions, Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	9,286		$	1,170		$	(93	)	$	10,363

Operating Costs, Expenses and Other
Costs of sales	—			—			3,084			197			(59		)	3,222
Depreciation, depletion and amortization	14			—			1,457			239			—			1,710
Other operating (income) expense	(42		)	1			2,903			(133		)	(34		)	2,695
Total Operating Costs, Expenses and Other	(28		)	1			7,444			303			(93		)	7,627

Operating Income (Loss)	28			(1		)	1,842			867			—			2,736

Other Income (Expense)
Earnings from consolidated subsidiaries	1,987			1,828			726			48			(4,589		)	—
Earnings from equity investments	—			—			438			—			—			438
Interest, net	(578		)	(8		)	(819		)	(51		)	—			(1,456		)
Amortization of excess cost of equity investments and other, net	20			—			(14		)	7			—			13

Income Before Income Tax	1,457			1,819			2,173			871			(4,589		)	1,731

Income Tax (Expense) Benefit	(342		)	69			(65		)	24			—			(314		)

Net Income	1,115			1,888			2,108			895			(4,589		)	1,417
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(302		)	(302		)

Net Income Attributable to Controlling Interests	1,115			1,888			2,108			895			(4,891		)	1,115

Preferred Stock Dividends	(117		)	—			—			—			—			(117		)
Net Income Available to Common Shareholders	$	998		$	1,888		$	2,108		$	895		$	(4,891	)	$	998

Net Income	$	1,115		$	1,888		$	2,108		$	895		$	(4,589	)	$	1,417
Total other comprehensive income	155			109			65			295			(443		)	181
Comprehensive income	1,270			1,997			2,173			1,190			(5,032		)	1,598
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(328		)	(328		)
Comprehensive income attributable to controlling interests	$	1,270		$	1,997		$	2,173		$	1,190		$	(5,360	)	$	1,270

Condensed Consolidating Balance Sheets as of September 30, 2019 (In Millions, Unaudited)

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - KMP		Subsidiary Guarantors		Subsidiary Non-Guarantors		Consolidating Adjustments			Consolidated KMI
ASSETS
Cash and cash equivalents	$	2	$	—	$	—	$	239	$	—		$	241
Other current assets - affiliates	5,615		4,253		28,568		1,063		(39,499		)	—
All other current assets	121		40		1,781		201		(19		)	2,124
Property, plant and equipment, net	236		—		30,725		6,973		—			37,934
Investments	664		—		7,625		98		—			8,387
Investments in subsidiaries	45,755		42,907		4,514		4,401		(97,577		)	—
Goodwill	13,789		22		5,165		2,988		—			21,964
Notes receivable from affiliates	920		20,334		481		1,241		(22,976		)	—
Deferred income taxes	2,757		—		—		—		(1,433		)	1,324
Other non-current assets	686		279		3,878		469		(355		)	4,957
Total assets	$	70,545	$	67,835	$	82,737	$	17,673	$	(161,859	)	$	76,931

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	2,381	$	1,835	$	30	$	160	$	—		$	4,406
Other current liabilities - affiliates	18,152		14,212		6,101		1,034		(39,499		)	—
All other current liabilities	427		142		1,495		367		(11		)	2,420
Long-term debt	13,259		15,197		3,009		646		—			32,111
Notes payable to affiliates	1,644		448		20,529		355		(22,976		)	—
Deferred income taxes	—		—		556		877		(1,433		)	—
All other long-term liabilities and deferred credits	1,049		30		1,202		801		(363		)	2,719
Total liabilities	36,912		31,864		32,922		4,240		(64,282		)	41,656

Redeemable noncontrolling interest	—		—		801		—		—			801
Stockholders’ equity
Total KMI equity	33,633		35,971		49,014		13,433		(98,418		)	33,633
Noncontrolling interests	—		—		—		—		841			841
Total stockholders’ equity	33,633		35,971		49,014		13,433		(97,577		)	34,474
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	70,545	$	67,835	$	82,737	$	17,673	$	(161,859	)	$	76,931

Condensed Consolidating Balance Sheets as of December 31, 2018 (In Millions)

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - KMP		Subsidiary Guarantors		Subsidiary Non-Guarantors		Consolidating Adjustments			Consolidated KMI
ASSETS
Cash and cash equivalents	$	8	$	—	$	—	$	3,277	$	(5	)	$	3,280
Other current assets - affiliates	4,465		4,788		23,851		1,031		(34,135		)	—
All other current assets	171		17		2,056		212		(14		)	2,442
Property, plant and equipment, net	231		—		30,750		6,916		—			37,897
Investments	664		—		6,718		99		—			7,481
Investments in subsidiaries	42,096		40,049		6,077		4,324		(92,546		)	—
Goodwill	13,789		22		5,166		2,988		—			21,965
Notes receivable from affiliates	945		20,345		247		1,043		(22,580		)	—
Deferred income taxes	3,137		—		—		—		(1,571		)	1,566
Other non-current assets	233		105		3,823		74		—			4,235
Total assets	$	65,739	$	65,326	$	78,688	$	19,964	$	(150,851	)	$	78,866

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	1,933	$	1,300	$	30	$	125	$	—		$	3,388
Other current liabilities - affiliates	14,189		14,087		4,898		961		(34,135		)	—
All other current liabilities	486		354		1,838		1,510		(19		)	4,169
Long-term debt	13,474		16,799		3,020		643		—			33,936
Notes payable to affiliates	1,234		448		20,543		355		(22,580		)	—
Deferred income taxes	—		—		503		1,068		(1,571		)	—
Other long-term liabilities and deferred credits	745		59		944		428		—			2,176
Total liabilities	32,061		33,047		31,776		5,090		(58,305		)	43,669

Redeemable noncontrolling interest	—		—		666		—		—			666
Stockholders’ equity
Total KMI equity	33,678		32,279		46,246		14,874		(93,399		)	33,678
Noncontrolling interests	—		—		—		—		853			853
Total stockholders’ equity	33,678		32,279		46,246		14,874		(92,546		)	34,531
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	65,739	$	65,326	$	78,688	$	19,964	$	(150,851	)	$	78,866

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2019 (In Millions, Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Net cash (used in) provided by operating activities	$	(2,666	)	$	3,126		$	10,978		$	299		$	(8,616	)	$	3,121

Cash flows from investing activities
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 2)	—			—			—			(28		)	—			(28		)
Acquisitions of assets and investments	—			—			(3		)	—			—			(3		)
Capital expenditures	(27		)	—			(1,325		)	(367		)	—			(1,719		)
Proceeds from sales of equity investments	—			—			108			—			—			108
Contributions to investments	(128		)	—			(1,018		)	(2		)	—			(1,148		)
Distributions from equity investments in excess of cumulative earnings	1,315			—			197			—			(1,305		)	207
Funding to affiliates	(4,604		)	(255		)	(7,583		)	(649		)	13,091			—
Loans to related party	—			—			(23		)	—			—			(23		)
Other, net	7			—			(5		)	(6		)	—			(4		)
Net cash used in investing activities	(3,437		)	(255		)	(9,652		)	(1,052		)	11,786			(2,610		)

Cash flows from financing activities
Issuances of debt	5,027			—			—			91			—			5,118
Payments of debt	(4,928		)	(1,300		)	(8		)	(67		)	—			(6,303		)
Debt issue costs	(8		)	—			—			(1		)	—			(9		)
Cash dividends - common shares	(1,593		)	—			—			—			—			(1,593		)
Repurchases of common shares	(2		)	—			—			—			—			(2		)
Funding from affiliates	7,629			2,145			2,744			573			(13,091		)	—
Contributions from investment partner	—			—			135			—			—			135
Contributions from parents	—			—			3			—			(3		)	—
Contributions from noncontrolling interests	—			—			—			—			3			3
Distributions to parents	—			(3,716		)	(4,200		)	(2,931		)	10,847			—
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds	—			—			—			—			(879		)	(879		)
Distributions to noncontrolling interests - other	—			—			—			—			(42		)	(42		)
Other, net	(28		)	—			—			—			—			(28		)
Net cash provided by (used in) financing activities	6,097			(2,871		)	(1,326		)	(2,335		)	(3,165		)	(3,600		)

Effect of exchange rate changes on cash, cash equivalents and restricted deposits	—			—			—			26			—			26

Net decrease in Cash, Cash Equivalents and Restricted Deposits	(6		)	—			—			(3,062		)	5			(3,063		)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	8			—			—			3,328			(5		)	3,331
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	2		$	—		$	—		$	266		$	—		$	268

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2018 (In Millions, Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Net cash (used in) provided by operating activities	$	(2,355	)	$	2,879		$	8,204		$	869		$	(6,222	)	$	3,375

Cash flows from investing activities
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 2)	—			—			—			3,003			—			3,003
Acquisitions of assets and investments	—			—			(20		)	—			—			(20		)
Capital expenditures	(3		)	—			(1,433		)	(770		)	—			(2,206		)
Proceeds from sales of equity investments	—			—			33			—			—			33
Contributions to investments	—			—			(287		)	(7		)	—			(294		)
Distributions from equity investments in excess of cumulative earnings	1,932			—			197			—			(1,932		)	197
Funding to affiliates	(5,452		)	(30		)	(5,366		)	(780		)	11,628			—
Loans to related party	—			—			(23		)	—			—			(23		)
Other, net	6			—			(18		)	8			—			(4		)
Net cash (used in) provided by investing activities	(3,517		)	(30		)	(6,917		)	1,454			9,696			686

Cash flows from financing activities
Issuances of debt	11,229			—			—			608			—			11,837
Payments of debt	(9,277		)	(975		)	(780		)	(189		)	—			(11,221		)
Debt issue costs	(24		)	—			—			(7		)	—			(31		)
Cash dividends - common shares	(1,163		)	—			—			—			—			(1,163		)
Cash dividends - preferred shares	(117		)	—			—			—			—			(117		)
Repurchases of common shares	(250		)	—			—			—			—			(250		)
Funding from affiliates	5,484			1,971			3,510			663			(11,628		)	—
Contribution from investment partner	—			—			148			—			—			148
Contributions from parents	—			—			19			—			(19		)	—
Contributions from noncontrolling interests	—			—			—			—			19			19
Distributions to parents	—			(3,801		)	(4,184		)	(228		)	8,213			—
Distributions to noncontrolling interests	—			—			—			—			(58		)	(58		)
Other, net	(12		)	—			—			(5		)	—			(17		)
Net cash provided by (used in) financing activities	5,870			(2,805		)	(1,287		)	842			(3,473		)	(853		)

Effect of exchange rate changes on cash, cash equivalents and restricted deposits	—			—			—			26			—			26

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(2		)	44			—			3,191			1			3,234
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3			1			—			323			(1		)	326
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	1		$	45		$	—		$	3,514		$	—		$	3,560

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 2018 Form 10-K.

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

On August 21, 2019, we announced an agreement to sell the U.S. portion of the Cochin Pipeline to Pembina Pipeline Corporation (Pembina) for $1.546 billion in cash. KML also announced that it had reached an agreement with Pembina under which Pembina had agreed to acquire all of the outstanding common equity of KML, including our 70% interest, subject to the terms of the arrangement agreement between KML and Pembina. Subject to and upon closing, KML shareholders will receive 0.3068 shares of Pembina common stock for each share of KML common stock whereby we will receive approximately 25 million shares of Pembina common stock, with a pre-tax value of approximately $927 million as of September 30, 2019, for our 70% interest in KML. We expect to ultimately convert these shares into cash and plan to do so in an opportunistic and non-disruptive manner. We intend to use a portion of the proceeds from these transactions to pay down debt to maintain our leverage targets and use the remainder to invest in attractive projects and/or opportunistically repurchase common shares under our buy-back program. The closing of the two transactions are cross-conditioned upon each other, subject to KML’s shareholder and applicable regulatory approvals, and are expected to close late in the fourth quarter of 2019 or in the first quarter of 2020.

Sale of Trans Mountain Pipeline System and Its Expansion Project

On August 31, 2018, KML completed the sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for net cash consideration of C$4.4 billion (U.S.$3.4 billion), net of working capital adjustments (TMPL Sale). We recognized a pre-tax gain from the TMPL Sale of $622 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated statements of income during both the three and nine months ended September 30, 2018. During the first quarter of 2019, KML settled the remaining C$37 million (U.S.$28 million) of working capital adjustments, which amount is included in the accompanying consolidated statement of cash flows within “Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments” for the nine months ended September 30, 2019 and for which we had substantially accrued for as of December 31, 2018.

2019 Outlook

We expect DCF for 2019 to be slightly below our $5.0 billion budget primarily due to the delay in ELC’s in-service date (the first of ten liquefaction units went into commercial service in late September 2019), lower commodity prices and volumes impacting our CO₂ business segment and the impact of 501-G settlements, partially offset by the strong performance in the West Region of our Natural Gas Pipelines business segment and lower interest expense. For 2019, we also budgeted to invest $3.1 billion in growth projects and contributions to joint ventures. We now expect to be slightly below this amount primarily due to lower capital expenditures in our CO₂ business segment.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA, Net Income and Net Income Available to Common Stockholders, along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, and Adjusted Segment EBDA and Adjusted EBITDA.

GAAP Performance Measures

The Consolidated Earnings Results for the three and nine months ended September 30, 2019 and 2018 present Segment EBDA, Net Income and Net Income Available to Common Stockholders 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 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 Performance Measures

Our non-GAAP performance measures described below should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP performance measures may differ from similarly titled measures used by others. You should not consider these non-GAAP performance 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 performance 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.

The format of the reconciliations between our non-GAAP and comparable GAAP financial measures has been modified to provide further transparency and information on our business performance. The modified reconciliations also include the non-GAAP financial measures of Adjusted Earnings, both in aggregate and per share, and Adjusted EBITDA. The amounts and key components of our non-GAAP financial measures remain unchanged from prior periods.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP performance measures, are items that are required by GAAP to be reflected in net income, 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). See tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP Performance Measures—Reconciliation of Net Income (GAAP) to Adjusted EBITDA” and “—Non-GAAP Performance 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 Available to Common stockholders 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 available to common stockholders. 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 Performance Measures—Reconciliation of Net Income Available to Common Stockholders (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting Net Income Available to Common Stockholders 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. 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 Available to Common Stockholders. 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 Performance Measures—Reconciliation of Net Income Available to Common Stockholders (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 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, our share of unconsolidated joint venture DD&A and income tax expense (net of our partners’ share of consolidating joint venture DD&A and income tax expense), and net income attributable to noncontrolling interests that is further adjusted for KML noncontrolling interests (net of its applicable Certain Items). Adjusted EBITDA is used by management and external users as an additional performance measure. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net Income. (See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Performance Measures—Reconciliation of Net Income (GAAP) to Adjusted EBITDA” below).

For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments. As a result, individual segment results for the three and nine months ended September 30, 2018 have been reclassified to conform to the current presentation in the following MD&A tables. The reclassified amounts were not material.

Consolidated Earnings Results (GAAP)

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



	Three Months Ended September 30,
	2019			2018			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,092		$	930		$	162		17	%
Products Pipelines	325			325			—			—	%
Terminals	295			301			(6		)	(2	)%
CO₂	164			205			(41		)	(20	)%
Kinder Morgan Canada(b)	—			654			(654		)	(100	)%
Total Segment EBDA	1,876			2,415			(539		)	(22	)%
DD&A	(578		)	(569		)	(9		)	(2	)%
Amortization of excess cost of equity investments	(21		)	(21		)	—			—	%
General and administrative and corporate charges	(162		)	(151		)	(11		)	(7	)%
Interest, net	(447		)	(473		)	26			5	%
Income before income taxes	668			1,201			(533		)	(44	)%
Income tax expense	(151		)	(196		)	45			23	%
Net income	517			1,005			(488		)	(49	)%
Net income attributable to noncontrolling interests	(11		)	(273		)	262			96	%
Net income attributable to Kinder Morgan, Inc.	506			732			(226		)	(31	)%
Preferred stock dividends	—			(39		)	39			100	%
Net income available to common stockholders	$	506		$	693		$	(187	)	(27	)%



	Nine Months Ended September 30,
	2019			2018			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	3,383		$	2,368		$	1,015		43	%
Products Pipelines	908			912			(4		)	—	%
Terminals	884			872			12			1	%
CO₂	558			561			(3		)	(1	)%
Kinder Morgan Canada(b)	(2		)	746			(748		)	(100	)%
Total Segment EBDA	5,731			5,459			272			5	%
DD&A	(1,750		)	(1,710		)	(40		)	(2	)%
Amortization of excess cost of equity investments	(61		)	(77		)	16			21	%
General and administrative and corporate charges	(478		)	(485		)	7			1	%
Interest, net	(1,359		)	(1,456		)	97			7	%
Income before income taxes	2,083			1,731			352			20	%
Income tax expense	(471		)	(314		)	(157		)	(50	)%
Net income	1,612			1,417			195			14	%
Net income attributable to noncontrolling interests	(32		)	(302		)	270			89	%
Net income attributable to Kinder Morgan, Inc.	1,580			1,115			465			42	%
Preferred stock dividends	—			(117		)	117			100	%
Net income available to common stockholders	$	1,580		$	998		$	582		58	%

_______


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


(b)	As a result of the TMPL Sale on August 31, 2018, this segment does not have results of operations on a prospective basis.

In our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to dispositions and acquisitions separately from those that are attributable to businesses owned in both periods.

Certain Items Affecting Consolidated Earnings Results



	Three Months Ended September 30,
	2019									2018
	GAAP			Certain Items			Adjusted			GAAP			Certain Items			Adjusted			Adjusted amounts increase/(decrease)
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,092		$	(2	)	$	1,090		$	930		$	75		$	1,005		$	85
Products Pipelines	325			11			336			325			(12		)	313			23
Terminals	295			—			295			301			(2		)	299			(4		)
CO₂	164			(15		)	149			205			28			233			(84		)
Kinder Morgan Canada	—			—			—			654			(622		)	32			(32		)
Total Segment EBDA(a)	1,876			(6		)	1,870			2,415			(533		)	1,882			(12		)
DD&A and amortization of excess cost of equity investments	(599		)	—			(599		)	(590		)	—			(590		)	(9		)
General and administrative and corporate charges(a)	(162		)	5			(157		)	(151		)	8			(143		)	(14		)
Interest, net(a)	(447		)	(5		)	(452		)	(473		)	—			(473		)	21
Income before income taxes	668			(6		)	662			1,201			(525		)	676			(14		)
Income tax expense(b)	(151		)	8			(143		)	(196		)	45			(151		)	8
Net income	517			2			519			1,005			(480		)	525			(6		)
Net income attributable to noncontrolling interests(a)	(11		)	—			(11		)	(273		)	256			(17		)	6
Preferred stock dividends	—			—			—			(39		)	—			(39		)	39
Net income available to common stockholders	$	506		$	2		$	508		$	693		$	(224	)	$	469		$	39



	Nine Months Ended September 30,
	2019									2018
	GAAP			Certain Items			Adjusted			GAAP			Certain Items			Adjusted			Adjusted amounts increase/(decrease)
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	3,383		$	(21	)	$	3,362		$	2,368		$	709		$	3,077		$	285
Products Pipelines	908			28			936			912			18			930			6
Terminals	884			—			884			872			33			905			(21		)
CO₂	558			(36		)	522			561			130			691			(169		)
Kinder Morgan Canada	(2		)	2			—			746			(622		)	124			(124		)
Total Segment EBDA(a)	5,731			(27		)	5,704			5,459			268			5,727			(23		)
DD&A and amortization of excess cost of equity investments	(1,811		)	—			(1,811		)	(1,787		)	—			(1,787		)	(24		)
General and administrative and corporate charges(a)	(478		)	11			(467		)	(485		)	18			(467		)	—
Interest, net(a)	(1,359		)	(6		)	(1,365		)	(1,456		)	34			(1,422		)	57
Income before income taxes	2,083			(22		)	2,061			1,731			320			2,051			10
Income tax expense(b)	(471		)	15			(456		)	(314		)	(149		)	(463		)	7
Net income	1,612			(7		)	1,605			1,417			171			1,588			17
Net income attributable to noncontrolling interests(a)	(32		)	(1		)	(33		)	(302		)	248			(54		)	21
Preferred stock dividends	—			—			—			(117		)	—			(117		)	117
Net income available to common stockholders	$	1,580		$	(8	)	$	1,572		$	998		$	419		$	1,417		$	155

_______


(a)	For a more detail discussion of these 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.

After giving effect to Certain Items, which are discussed in more detail in the discussions that follow, the remaining decrease in income before income taxes from the prior year quarter was $14 million and the remaining increase in income before income taxes from the prior year-to-date period was $10 million. The third quarter decrease from 2018 is primarily attributable to lower earnings from our CO₂business segment, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale, and increased general and administrative and corporate charges and DD&A expense, partially offset by increased performance from our Natural Gas Pipelines and Products Pipelines business segments and decreased interest expense, net. The year-to-date increase from 2018 is primarily attributable to increased performance from our Natural Gas Pipelines business segment and decreased interest expense, net partially offset by lower earnings from our CO₂and Terminals business segments, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale and increased DD&A expense.

Non-GAAP Performance Measures

Reconciliation of Net Income Available to Common Stockholders (GAAP) to Adjusted Earnings to DCF



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
Net income available to common stockholders (GAAP)	$	506		$	693		$	1,580		$	998
Total Certain Items	2			(224		)	(8		)	419
Adjusted Earnings(a)	508			469			1,572			1,417
DD&A and amortization of excess cost of equity investments for DCF(b)	694			682			2,093			2,056
Income tax expense for DCF(a)(b)	164			169			521			512
Cash taxes(c)	(12		)	(14		)	(76		)	(60		)
Sustaining capital expenditures(c)	(173		)	(194		)	(477		)	(471		)
Other items(d)	(41		)	(19		)	6			3
DCF	$	1,140		$	1,093		$	3,639		$	3,457

Adjusted Segment EBDA to Adjusted EBITDA to DCF



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions, except per share amounts)
Natural Gas Pipelines	$	1,090		$	1,005		$	3,362		$	3,077
Products Pipelines	336			313			936			930
Terminals	295			299			884			905
CO₂	149			233			522			691
Kinder Morgan Canada	—			32			—			124
Adjusted Segment EBDA(a)	1,870			1,882			5,704			5,727
General and administrative and corporate charges(a)	(157		)	(143		)	(467		)	(467		)
KMI’s share of joint venture DD&A and income tax expense(a)(e)	123			120			368			355
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)	(2		)	(2		)	(7		)	(9		)
Adjusted EBITDA	1,834			1,857			5,598			5,606
Interest, net(a)	(452		)	(473		)	(1,365		)	(1,422		)
Cash taxes(c)	(12		)	(14		)	(76		)	(60		)
Sustaining capital expenditures(c)	(173		)	(194		)	(477		)	(471		)
KML noncontrolling interests DCF adjustments(f)	(16		)	(25		)	(47		)	(82		)
Preferred stock dividends	—			(39		)	—			(117		)
Other items(d)	(41		)	(19		)	6			3
DCF	$	1,140		$	1,093		$	3,639		$	3,457

Adjusted Earnings per common share	$	0.22		$	0.21		$	0.69		$	0.64
Weighted average common shares outstanding for dividends(g)	2,277			2,218			2,276			2,217
DCF per common share	$	0.50		$	0.49		$	1.60		$	1.56
Declared dividends per common share	$	0.25		$	0.20		$	0.75		$	0.60

_______


(a)	Amounts are adjusted for Certain Items.


(b)	Includes KMI’s share of DD&A or income tax expense from joint ventures, net of DD&A or income tax expense attributable to KML noncontrolling interests, as applicable. See tables included in “—Supplemental Information” below.


(c)	Includes KMI’s share of cash taxes or sustaining capital expenditures from joint ventures, as applicable. See tables included in “—Supplemental Information” below.


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


(e)	KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.


(f)	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 (GAAP) to Adjusted EBITDA



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
Net income (GAAP)	$	517		$	1,005		$	1,612		$	1,417
Certain Items:
Fair value amortization	(7		)	(7		)	(22		)	(27		)
Legal and environmental reserves	11			16			11			53
Change in fair market value of derivative contracts(a)	(14		)	47			(22		)	190
(Gain) loss on divestitures and impairments, net	—			(582		)	(5		)	208
Hurricane recoveries, net	—			(1		)	—			(25		)
Refund and reserve adjustment of taxes, other than income taxes	—			(12		)	17			(51		)
Income tax Certain Items	8			45			15			(149		)
Noncontrolling interests associated with Certain Items	—			256			(1		)	248
Other	4			14			(1		)	(28		)
Total Certain Items	2			(224		)	(8		)	419
DD&A and amortization of excess cost of equity investments	599			590			1,811			1,787
Income tax expense(b)	143			151			456			463
KMI’s share of joint venture DD&A and income tax expense(b)(c)	123			120			368			355
Interest, net(b)	452			473			1,365			1,422
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(b))	(2		)	(258		)	(6		)	(257		)
Adjusted EBITDA	$	1,834		$	1,857		$	5,598		$	5,606

______


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


(b)	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.


(c)	KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.

Supplemental Information



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
DD&A (GAAP)	$	578		$	569		$	1,750		$	1,710
Amortization of excess cost of equity investments (GAAP)	21			21			61			77
DD&A and amortization of excess cost of equity investments	599			590			1,811			1,787
Our share of joint venture DD&A	100			98			297			293
DD&A attributable to KML noncontrolling interests	(5		)	(6		)	(15		)	(24		)
DD&A and amortization of excess cost of equity investments for DCF	$	694		$	682		$	2,093		$	2,056

Income tax expense (GAAP)	$	151		$	196		$	471		$	314
Certain Items	(8		)	(45		)	(15		)	149
Income tax expense(a)	143			151			456			463
Our share of taxable joint venture income tax expense(a)	23			22			71			62
Income tax expense attributable to KML noncontrolling interests(a)	(2		)	(4		)	(6		)	(13		)
Income tax expense for DCF(a)	$	164		$	169		$	521		$	512

Net income attributable to KML noncontrolling interests	$	9		$	270		$	25		$	291
KML noncontrolling interests associated with Certain Items	—			(255		)	1			(246		)
KML noncontrolling interests(a)	9			15			26			45
DD&A attributable to KML noncontrolling interests	5			6			15			24
Income tax expense attributable to KML noncontrolling interests(a)	2			4			6			13
KML noncontrolling interests DCF adjustments(a)	$	16		$	25		$	47		$	82

Net income attributable to noncontrolling interests (GAAP)	$	11		$	273		$	32		$	302
Less: KML noncontrolling interests(a)	9			15			26			45
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))	2			258			6			257
Noncontrolling interests associated with Certain Items	—			(256		)	1			(248		)
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)	$	2		$	2		$	7		$	9

Additional joint venture information:
Our share of joint venture DD&A	$	100		$	98		$	297		$	293
Our share of joint venture income tax expense(a)	23			22			71			62
Our share of joint venture DD&A and income tax expense(a)	$	123		$	120		$	368		$	355

Our share of taxable joint venture cash taxes	$	(16	)	$	(12	)	$	(50	)	$	(50	)

Our share of joint venture sustaining capital expenditures	$	(35	)	$	(37	)	$	(85	)	$	(77	)

______


(a)	Amounts are adjusted for Certain Items.

Segment Earnings Results

Natural Gas Pipelines



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	1,934		$	2,192		$	6,103		$	6,425
Operating expenses	(993		)	(1,357		)	(3,190		)	(3,803		)
(Loss) gain on divestitures and impairments, net	—			(35		)	10			(634		)
Other income	—			—			2			1
Earnings from equity investments	141			130			431			346
Other, net	10			—			27			33
Segment EBDA	1,092			930			3,383			2,368
Certain Items(a)(b)	(2		)	75			(21)			709
Adjusted Segment EBDA	$	1,090		$	1,005		$	3,362		$	3,077

Change from prior period	Increase/(Decrease)
Adjusted revenues	$	(277	)	(13		)%	$	(332	)	(5		)%
Adjusted Segment EBDA	85			8		%	285			9		%

Volumetric data
Transport volumes (BBtu/d)(c)	37,029			32,879			35,958			32,238
Sales volumes (BBtu/d)(c)	2,647			2,615			2,435			2,517
Gathering volumes (BBtu/d)(c)	3,380			3,025			3,335			2,877
NGLs (MBbl/d)(c)	129			117			126			118

_______

Certain Items affecting Segment EBDA

(a)

Includes revenue Certain Item amounts of $(1) million for both three and nine months ended September 30, 2019 and $18 million and $9 million for the three and nine months ended September 30, 2018, respectively. These Certain Item amounts are primarily related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales in the 2019 and 2018 periods, and additionally in the 2018 nine month period, to a transportation contract refund and the early termination of a long-term natural gas transportation contract.

(b)

Includes non-revenue Certain Item amounts of $(1) million and $(20) million for the three and nine months ended September 30, 2019, respectively, and $57 million and $700 million for the three and nine months ended September 30, 2018, respectively. Three and nine month 2019 amounts are primarily related to increases in earnings for our share of certain equity investees’ amortization of regulatory liabilities. Three and nine month 2018 amounts include a decrease in earnings of $35 million for both periods associated with a project write-off on the Utica Marcellus Texas pipeline and a decrease in earnings of $15 million for both periods associated with certain litigation matters. Nine month 2018 amount also includes (i) a $600 million non-cash loss on impairment of certain gathering and processing assets in Oklahoma; (ii) a net loss of $89 million in our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG), due to a ruling by an arbitration panel affecting a customer contract, which resulted in a non-cash impairment of our investment partially offset by our share of earnings recognized by Gulf LNG on the respective customer contract; and (iii) an increase in earnings of $41 million for our share of certain equity investees’ 2017 Tax Reform provisional adjustments and 2017 Tax Reform adjustments related to our FERC-regulated business.

Other


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

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and nine month periods ended September 30, 2019 and 2018:

Three Months Ended September 30, 2019 versus Three Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Midstream	$	37		13	%	$	(347	)	(24	)%
West Region	26			11	%	26			9	%
North Region	23			7	%	39			10	%
South Region	(3		)	(2	)%	3			4	%
Other	2			200	%	2			200	%
Total Natural Gas Pipelines	$	85		8	%	$	(277	)	(13	)%

Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Midstream	$	89		10	%	$	(552	)	(14	)%
West Region	90			13	%	87			9	%
North Region	106			11	%	123			10	%
South Region	(6		)	(1	)%	10			4	%
Other	6			150	%	6			150	%
Intrasegment eliminations	—			—	%	(6		)	(33	)%
Total Natural Gas Pipelines	$	285		9	%	$	(332	)	(5	)%

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, 2019 and 2018:

•

Midstream’s increases of $37 million (13%) and $89 million (10%), respectively, were primarily due to increased earnings from Texas intrastate natural gas pipeline operations, Gulf Coast Express, Cochin pipeline, KinderHawk Field Services LLC and South Texas Midstream partially offset by decreased earnings from Hiland Midstream. Texas intrastate natural gas operations were favorably impacted by higher sales margins. Gulf Coast Express increased earnings were driven by equity earnings from the Gulf Coast Express pipeline project that was placed in service in September 2019. Cochin pipeline’s increased earnings were primarily driven by higher volumes and higher tariff rates. KinderHawk Field Services LLC and South Texas Midstream benefited from increased drilling and production in the Haynesville and Eagle Ford basins, respectively. Hiland Midstream’s decreased earnings were primarily due to lower commodity prices and higher operations and maintenance expense. Overall Midstream’s revenues decreased primarily due to lower commodity prices which was largely offset by corresponding decreases in costs of sales;

•

West Region’s increases of $26 million (11%) and $90 million (13%), respectively, were primarily due to increases in earnings from EPNG and CIG. The increase on EPNG was the result of capacity sales due to increased activity in the Permian Basin, partially offset by the negative impact of EPNG’s 501-G rate settlement. Increased earnings on CIG were due to capacity sales resulting from increased activity in the Denver Julesburg basin; and

•

North Region’s increases of $23 million (7%) and $106 million (11%), respectively, were the result of an increase in earnings from TGP and Kinder Morgan Louisiana Pipeline LLC (KMLP). The increase on TGP was driven by expansion projects placed into service in 2018 partially offset by higher operations and maintenance expense. Increased earnings at KMLP were driven by revenues from the Sabine Pass expansion project that was placed into service in December 2018.

Products Pipelines



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	484		$	475		$	1,350		$	1,420
Operating expenses	(177		)	(167		)	(500		)	(559		)
Other income	—			—			—			2
Earnings from equity investments	17			16			52			48
Other, net	1			1			6			1
Segment EBDA	325			325			908			912
Certain Items(a)	11			(12		)	28			18
Adjusted Segment EBDA	$	336		$	313		$	936		$	930

Change from prior period	Increase/(Decrease)
Adjusted revenues	$	9		2		%	$	(70	)	(5		)%
Adjusted Segment EBDA	23			7		%	6			1		%

Volumetric data
Gasoline(b)	1,066			1,066			1,045			1,043
Diesel fuel	393			386			370			370
Jet fuel	318			312			305			302
Total refined product volumes(c)	1,777			1,764			1,720			1,715
Crude and condensate(c)	639			617			644			617
Total delivery volumes (MBbl/d)	2,416			2,381			2,364			2,332

_______

Certain Items affecting Segment EBDA

(a)

Includes non-revenue Certain Item amounts of $11 million and $28 million for the three and nine months ended September 30, 2019, respectively, and $(12) million and $18 million for the three and nine months ended September 30, 2018, respectively, primarily related to (i) an unfavorable adjustment of an environmental reserve (three and nine month 2019 periods); (ii) an unfavorable adjustment of tax reserves, other than income taxes (nine month 2019 period); (iii) an increase in earnings of $12 million as a result of property tax refunds (both three and nine month 2018 periods); and (iv) an increase in expense of $31 million associated with a Pacific operations litigation matter (nine month 2018 period).

Other


(b)	Volumes include ethanol pipeline volumes.


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

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and nine month periods ended September 30, 2019 and 2018.

Three Months Ended September 30, 2019 versus Three Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)				Adjusted revenues increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	17	13	%	$	4		2	%
Southeast Refined Products	5		8	%	7			7	%
Crude and Condensate	1		1	%	(2		)	(1	)%
Total Products Pipelines	$	23	7	%	$	9		2	%

Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
West Coast Refined Products	$	10		3	%	$	11		2	%
Southeast Refined Products	13			7	%	(12		)	(4	)%
Crude and Condensate	(17		)	(5	)%	(69		)	(12	)%
Total Products Pipelines	$	6		1	%	$	(70	)	(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, 2019 and 2018:


•	West Coast Refined Products’ increases of $17 million (13%) and $10 million (3%), respectively, were primarily due to increased earnings on Pacific operations driven by a decrease in operating expenses associated with environmental reserves and higher margins primarily due to an increase in tariff rates in 2019;

•

Southeast Refined Products’ increases of $5 million (8%) and $13 million (7%), respectively, were primarily due to increased earnings from Central Florida Pipeline due to higher volumes and higher transportation and terminaling rates and increased earnings from our Transmix processing operations primarily due to increased volumes and higher processing rates. The year-to-date increase was also impacted by increased earnings from South East Terminals driven primarily by a gain recognized from an exchange of joint venture interests, and to a lesser extent increased equity earnings from Plantation Pipe Line as a result of increased transportation revenues driven by higher volumes and average tariff rate. The year-to date decrease in revenues was primarily due to lower sales volumes as a result of a Transmix facility temporary shutdown in second quarter 2019 which was largely offset by a corresponding decrease in costs of sales; and

•

Crude and Condensate’s increase of $1 million (1%) and decrease of $17 million (5%), respectively, were impacted by increased earnings in the third quarter from the Bakken Crude assets primarily due to higher crude oil gathering and delivery volumes and increased tariff rates, largely offset by a decrease of earnings from Kinder Morgan Crude & Condensate Pipeline due to lower services revenues as a result of unfavorable rates on contract renewals and a decrease in recognition of deficiency revenue. Similar factors contributed to the year-to-date change; however, the year-to-date decrease was primarily driven by the decrease in earnings on Kinder Morgan Crude & Condensate Pipeline and partially offset by the increased earnings from the Bakken Crude.

Terminals



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	508		$	504		$	1,524		$	1,514
Operating expenses	(223		)	(210		)	(660		)	(608		)
Gain (loss) on divestitures and impairments, net	3			1			3			(53		)
Earnings from equity investments	6			5			15			17
Other, net	1			1			2			2
Segment EBDA	295			301			884			872
Certain Items(a)(b)	—			(2		)	—			33
Adjusted Segment EBDA	$	295		$	299		$	884		$	905

Change from prior period	Increase/(Decrease)
Adjusted revenues	$	4		1		%	$	12		1		%
Adjusted Segment EBDA	(4		)	(1		)%	(21		)	(2		)%

Volumetric data
Liquids tankage capacity available for service (MMBbl)	89.1			88.7			89.1			88.7
Liquids utilization %(c)	94.5		%	93.5		%	94.5		%	93.5		%
Bulk transload tonnage (MMtons)	15.4			16.3			45.2			47.6

_______

Certain Items affecting Segment EBDA


(a)	Includes revenue Certain Item amounts of $(2) million for the nine months ended September 30, 2018.


(b)	Includes non-revenue Certain Item amounts of $(2) million and $35 million for the three and nine months ended September 30, 2018, respectively, primarily related to losses on divestitures and impairments, net and hurricane damage insurance recoveries, net of repair costs.

Other


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

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and nine month periods ended September 30, 2019 and 2018.

Three Months Ended September 30, 2019 versus Three Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Alberta Canada	$	(4	)	(11	)%	$	3		7	%
Mid Atlantic	(4		)	(29	)%	(3		)	(12	)%
Gulf Central	(1		)	(7	)%	(1		)	(4	)%
Gulf Liquids	(1		)	(1	)%	5			5	%
Southeast	4			33	%	—			—	%
All others (including intrasegment eliminations)	2			1	%	—			—	%
Total Terminals	$	(4	)	(1	)%	$	4		1	%

Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Alberta Canada	$	(15	)	(14	)%	$	12		9	%
Mid Atlantic	(6		)	(13	)%	(6		)	(7	)%
Gulf Central	(8		)	(16	)%	(8		)	(11	)%
Gulf Liquids	9			4	%	16			5	%
Southeast	2			5	%	3			3	%
All others (including intrasegment eliminations)	(3		)	(1	)%	(5		)	(1	)%
Total Terminals	$	(21	)	(2	)%	$	12		1	%

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, 2019 and 2018:


•	decreases of $4 million (11%) and $15 million (14%), respectively, from our Alberta Canada terminals primarily due to an increase in operating expenses associated with lease fees at our Edmonton South Terminal following the TMPL Sale, partially offset by an increase in earnings due to the commencement of operations at our Base Line Terminal joint venture;


•	decreases of $4 million (29%) and $6 million (13%), respectively, from our Mid Atlantic terminals primarily due to lower coal volumes at our Pier IX facility;


•	decreases of $1 million (7%) and $8 million (16%), respectively, from our Gulf Central terminals primarily related to the termination of a customer contract in August 2018 at our Deer Park Rail Terminal and an unfavorable impact resulting from certain tanks being temporarily out of service for scheduled inspections and repairs at Battleground Oil Specialty Terminal Company LLC;


•	decrease of $1 million (1%) and increase of $9 million (4%), respectively, from our Gulf Liquids terminals. The year-to-date increase was primarily driven by higher volumes and associated ancillary fees, annual rate escalations on existing storage contracts and a customer rebate adversely impacting revenue recognized in the prior comparable period; and


•	increases of $4 million (33%) and $2 million (5%), respectively, from our Southeast terminals primarily related to gains on the sales of non-core assets.

CO2



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	298		$	316		$	913		$	870
Operating expenses	(143		)	(120		)	(383		)	(336		)
Earnings from equity investments	9			9			28			27
Segment EBDA	164			205			558			561
Certain Items(a)(b)	(15		)	28			(36		)	130
Adjusted Segment EBDA	$	149		$	233		$	522		$	691

Change from prior period	Increase/(Decrease)
Adjusted revenues	$	(61	)	(18		)%	$	(144	)	(14		)%
Adjusted Segment EBDA	(84		)	(36		)%	(169		)	(24		)%

Volumetric data
SACROC oil production	23.2			23.9			24.0			24.3
Yates oil production	6.8			7.5			7.1			7.5
Katz and Goldsmith oil production	3.6			4.3			3.8			4.7
Tall Cotton oil production	2.1			2.5			2.4			2.3
Total oil production, net (MBbl/d)(c)	35.7			38.2			37.3			38.8
NGL sales volumes, net (MBbl/d)(c)	10.2			10.4			10.2			10.2
CO₂ production, net (Bcf/d)	0.6			0.6			0.6			0.6
Realized weighted-average oil price per Bbl	$	49.45		$	57.96		$	49.36		$	58.59
Realized weighted-average NGL price per Bbl	$	21.12		$	36.46		$	23.54		$	33.30

_______

Certain Items affecting Segment EBDA


(a)	Includes revenue Certain Item amounts of $(15) million and $(36) million for the three and nine months ended September 30, 2019, respectively, and $28 million and $151 million for the three and nine months ended September 30, 2018, respectively, related to unrealized gains and losses associated with derivative contracts used to hedge forecasted commodity sales.


(b)	Includes non-revenue Certain Item amount of $(21) million for the nine months ended September 30, 2018 as a result of a severance tax refund.

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, 2019 and 2018.

Three Months Ended September 30, 2019 versus Three Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	(78	)	(50	)%	$	(60	)	(24	)%
Source and Transportation Activities	(6		)	(8	)%	(5		)	(5	)%
Intrasegment eliminations	—			—	%	4			44	%
Total CO2	$	(84	)	(36	)%	$	(61	)	(18	)%

Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	(169	)	(36	)%	$	(155	)	(20	)%
Source and Transportation Activities	—			—	%	4			1	%
Intrasegment eliminations	—			—	%	7			28	%
Total CO2	$	(169	)	(24	)%	$	(144	)	(14	)%

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, 2019 and 2018:

•

decreases of $78 million (50%) and $169 million (36%), respectively, from our Oil and Gas Producing activities primarily due to decreased revenues of $60 million and $155 million, respectively, driven by lower crude oil and NGL prices which reduced revenues by $48 million and $133 million, respectively, and lower volumes which reduced revenues by $12 million and $22 million, respectively, higher operating expenses of $16 million and $11 million, respectively, and higher severance tax expense of $2 million and $3 million; and

•

decrease of $6 million (8%) and flat, respectively, from our Source and Transportation activities primarily due to lower CO₂sales of $5 million and higher CO₂ sales of $3 million, respectively, driven by lower contract sales prices of $7 million and $10 million, respectively, partially offset by higher volumes of $2 million and $13 million, respectively, and higher operating expenses of $1 million and $4 million, respectively. Year-to-date was also impacted by $1 million increased earnings from an equity investee.

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



	Three Months Ended September 30,						Earnings
	2019			2018			Increase/(decrease)
	(In millions, except percentages)
General and administrative (GAAP)	$	(154	)	$	(154	)	$	—		—	%
Corporate (benefit) charges	(8		)	3			(11		)	(367	)%
Certain Items(a)	5			8			(3		)	(38	)%
General and administrative and corporate charges(b)	$	(157	)	$	(143	)	$	(14	)	(10	)%

Interest, net (GAAP)	$	(447	)	$	(473	)	$	26		5	%
Certain Items(c)	(5		)	—			(5		)	n/a
Interest, net(b)	$	(452	)	$	(473	)	$	21		4	%

Net loss attributable to noncontrolling interests (GAAP)	$	(11	)	$	(273	)	$	262		96	%
Certain Items(d)	—			256			(256		)	(100	)%
Net loss attributable to noncontrolling interests(b)	$	(11	)	$	(17	)	$	6		35	%



	Nine Months Ended September 30,						Earnings
	2019			2018			Increase/(decrease)
	(In millions, except percentages)
General and administrative (GAAP)	$	(456	)	$	(491	)	$	35		7	%
Corporate (benefit) charges	(22		)	6			(28		)	(467	)%
Certain Items(a)	11			18			(7		)	(39	)%
General and administrative and corporate charges(b)	$	(467	)	$	(467	)	$	—		—	%

Interest, net (GAAP)	$	(1,359	)	$	(1,456	)	$	97		7	%
Certain Items(c)	(6		)	34			(40		)	(118	)%
Interest, net(b)	$	(1,365	)	$	(1,422	)	$	57		4	%

Net loss attributable to noncontrolling interests (GAAP)	$	(32	)	$	(302	)	$	270		89	%
Certain Items(d)	(1		)	248			(249		)	(100	)%
Net loss attributable to noncontrolling interests(b)	$	(33	)	$	(54	)	$	21		39	%

_______

n/a - not applicable

Certain items

(a)

Three and nine month 2018 amounts include increases in expense of (i) $5 million and $7 million, respectively, of asset sale related costs; and (ii) $1 million and $8 million, respectively, related to certain corporate litigation matters. Nine month 2018 amount also includes a decrease in expense of $12 million related to an adjustment of tax reserves, other than income taxes and an increase in expense of $10 million associated with an environmental reserve adjustment.


(b)	Amounts are adjusted for Certain Items.

(c)

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 previous 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 hedged debt. Three and nine month 2018 amounts include (i) decreases in interest expense of $7 million and $25 million, respectively, related to non-cash debt fair value adjustments associated with historical acquisitions; (ii) increases in interest expense of $2 million and $10 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and hedged debt; and (iii) increases in interest expense of $1 million and $47 million, respectively, related to the write-off of capitalized KML credit facility fees.


(d)	Three and nine month 2018 amounts are primarily associated with the noncontrolling interests portion of the $622 million gain on the TMPL Sale.

General and administrative expenses and corporate charges adjusted for Certain Items increased $14 million and was flat for the three and nine months ended September 30, 2019, respectively, when compared with the respective prior year periods. The third quarter increase was primarily due to higher pension and benefit-related costs of $9 million and lower capitalized costs of $6 million as a result of the winding down of certain pipeline projects, partially offset by lower expenses of $3 million due to the TMPL Sale. Year-to-date comprised of the following offsetting charges: (i) higher pension and benefit-related costs of $41 million; (ii) higher capitalized costs of $24 million driven by our large Permian basin pipeline projects; and (iii) lower expenses of $17 million due to the TMPL Sale.

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, 2019 when compared with the respective prior year periods decreased $21 million and $57 million, respectively. The decreases in interest expense were primarily due to lower average debt balances, partially offset by higher LIBOR rates which impacted our interest rate swap agreements. The year-to-date decrease in interest expense was also impacted by lower weighted average long-term debt interest rates.

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, 2019 and December 31, 2018, approximately 31% 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 adjusted for Certain Items for the three and nine months ended September 30, 2019 when compared with the respective prior year periods decreased $6 million and $21 million, respectively, primarily due to the TMPL Sale.

Income Taxes

Our tax expense for the three months ended September 30, 2019 was approximately $151 million as compared with $196 million for the same period of 2018. The $45 million decrease in tax expense was primarily due to a decrease in pre-tax earnings primarily as a result of the gain from our 2018 TMPL Sale, partially offset by a reduction in 2018 of our income tax reserve for uncertain tax positions as a result of the settlement of state income tax audits.

Our tax expense for the nine months ended September 30, 2019 was approximately $471 million as compared with $314 million for the same period of 2018. The $157 million increase in tax expense was primarily due to an increase in pre-tax earnings as a result of 2018 midstream asset impairments and a reduction in 2018 of our income tax reserve for uncertain tax positions as a result of the settlement of federal and state income tax audits, partially offset by the gain from our 2018 TMPL Sale.

Liquidity and Capital Resources

General

As of September 30, 2019, we had $241 million of “Cash and cash equivalents,” a decrease of $3,039 million (93%) from December 31, 2018. The 2018 TMPL Sale mentioned above in “—General and Basis of Presentation—Sale of Trans Mountain Pipeline System and Its Expansion Project” was the primary source of cash on hand as of December 31, 2018. We believe our cash position, remaining borrowing capacity on our credit facilities (discussed below in “—Short-term Liquidity”), and cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

We have consistently generated substantial cash flow from operations, providing a source of funds of $3,121 million and $3,375 million in the first nine months of 2019 and 2018, respectively. The period-to-period decrease is discussed below in “—Cash Flows—Operating Activities.” Generally, 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 also generally expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations. Moreover, as a result of our current common stock dividend policy and our continued focus on disciplined capital allocation, we do not expect the need to access the equity capital markets to fund our growth projects for the foreseeable future.

Short-term Liquidity

As of September 30, 2019, our principal sources of short-term liquidity are (i) cash from operations; (ii) our $4.5 billion revolving credit facilities and associated commercial paper program; and (iii) KML’s 4-year, C$500 million unsecured revolving credit facility (for KML’s working capital needs). The loan commitments under our revolving credit facilities can be used for working capital and other general corporate purposes and, additionally for us, as a backup to our commercial paper program. Letters of credit reduce borrowings allowed under our and KML’s respective credit facilities. Issuances of commercial paper also reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facilities and, as previously discussed, have consistently generated strong cash flows from operations.

As of September 30, 2019, our $4,406 million of short-term debt consisted primarily of (i) $3,684 million of senior notes that mature in the next twelve months; (ii) $532 million outstanding under our commercial paper program; and (iii) $34 million outstanding borrowings under KML’s C$500 million revolving credit facility. We intend to use the proceeds from the pending sale of the U.S. portion of the Cochin Pipeline to reduce debt to maintain our leverage target, and use the remainder to invest in attractive projects and/or opportunistically repurchase common shares. Otherwise, as our debt becomes due, we intend to fund our short-term debt primarily through credit facility borrowings, commercial paper borrowings, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2018 was $3,388 million.

We had working capital (defined as current assets less current liabilities) deficits of $4,461 million and $1,835 million as of September 30, 2019 and December 31, 2018, 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 $2,626 million (143%) unfavorable change from year-end 2018 was primarily due to (i) a decrease in cash and cash equivalents of $3,039 million and (ii) increase in short-term debt of $1,018 million partially offset by (i) a decrease in distributions payable of $876 million and (ii) a net decrease in accounts payable, accrued interest and accrued taxes. 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. As of December 31, 2018, KML’s cash and cash equivalents included approximately U.S. $2.8 billion return of capital payment to us ($1.9 billion) and KML’s public owners of its restricted voting shares ($0.9 billion) on January 3, 2019, which was accrued for as of December 31, 2018.

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 Performance 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, 2019, and the amount we expect to spend for the remainder of 2019 to sustain and grow our businesses are as follows:



	Nine Months Ended September 30, 2019		2019 Remaining		Total 2019
	(In millions)
Sustaining capital expenditures(a)(b)	$	477	$	218	$	695
KMI Discretionary capital investments(b)(c)(d)	$	2,168	$	587	$	2,755
KML Discretionary capital investments(b)	$	15	$	12	$	27

_______


(a)	Nine months ended September 30, 2019, 2019 Remaining, and Total 2019 amounts include $85 million, $38 million, and $123 million, respectively, for our proportionate share of (i) certain equity investees’ (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.


(b)	Nine months ended September 30, 2019 amounts exclude $106 million of net changes from accrued capital expenditures, contractor retainage, and other.


(c)	Nine months ended September 30, 2019 amount includes $962 million of our contributions to certain unconsolidated joint ventures for capital investments.


(d)	Amounts include our actual or estimated contributions to certain equity investees, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements

Other than commitments for the purchase of property, plant and equipment discussed below, 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, 2018 in our 2018 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2019 and December 31, 2018 were $473 million and $304 million, respectively. The increase of $169 million was primarily driven by capital commitments related to our Natural Gas Pipelines business segment.

Cash Flows

Operating Activities

The net decrease of $254 million in cash provided by operating activities for the nine months ended September 30, 2019 compared to the respective 2018 period was primarily attributable to:


•	a $327 million increase in income tax payments in the 2019 period primarily for foreign income tax associated with the TMPL Sale; partially offset by,


•	a $73 million increase in cash driven by a reduction in litigation payments resulting from rate case refunds made to EPNG shippers in 2018, offset partially by a decrease in cash from other operating activities in the 2019 period compared to the 2018 period.

Investing Activities

The $3,296 million net increase in cash used in investing activities for the nine months ended September 30, 2019 compared to the respective 2018 period was primarily attributable to:


•	a $3,031 million decrease in cash reflecting proceeds received in the 2018 period from the TMPL Sale, net of cash disposed, and a final working capital payment made in the 2019 period; and

•

an $854 million increase in cash used for contributions to equity investments driven by contributions made in 2019 to Midcontinent Express Pipeline LLC, Citrus Corporation and Fayetteville Express Pipeline LLC to fund our proportionate share of these equity investees’ 2019 maturing debt obligations, and higher contributions to Gulf Coast Express Pipeline LLC and Permian Highway Pipeline LLC in the 2019 period compared with the 2018 period; partially offset by,


•	a $487 million decrease in capital expenditures in the 2019 period over the comparative 2018 period primarily due to no expenditures in 2019 for the TMEP, and to a lesser extent lower expenditures in our Natural Gas Pipelines and Terminals business segments; and


•	a $75 million increase in cash from proceeds from sales of interests in equity investments in the 2019 period compared to the 2018 period.

Financing Activities

The net increase of $2,747 million in cash used in financing activities for the nine months ended September 30, 2019 compared to the respective 2018 period was primarily attributable to:


•	a $1,779 million net increase in cash used related to debt activity as a result of $1,194 million of net debt payments in the 2019 period compared to $585 million of net debt issuances in the 2018 period. See Note 3 “Debt” for further information regarding our debt activity;


•	an $879 million distribution of the TMPL Sale proceeds to the owners of KML restricted voting shares in the 2019 period; and


•	a $430 million increase in dividend payments to our common shareholders; partially offset by,


•	a $248 million decrease in cash used due to fewer common shares repurchased under our common share buy-back program in the 2019 period compared to the 2018 period; and


•	a $117 million decrease in cash used reflecting dividends paid to our mandatory convertible preferred shareholders in the 2018 period.

Dividends

KMI Common Stock Dividends

We expect to declare common stock dividends of $1.00 per share on our common stock for 2019.



Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
December 31, 2018	$	0.20	January 16, 2019	January 31, 2019	February 15, 2019
March 31, 2019	0.25		April 17, 2019	April 30, 2019	May 15, 2019
June 30, 2019	0.25		July 17, 2019	July 31, 2019	August 15, 2019
September 30, 2019	0.25		October 16, 2019	October 31, 2019	November 15, 2019

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 2018 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.

Noncontrolling Interests

KML Distributions

KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its distributable cash flow. The payment of dividends is not guaranteed, and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. KML intends to pay quarterly dividends, if any, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter.

On October 15, 2019, KML’s board of directors declared a dividend for the quarterly period ended September 30, 2019 of C$0.1625 per restricted voting share, payable on November 15, 2019 to KML restricted voting shareholders of record as of the close of business on October 31, 2019.

KML Dividends on its Series 1 Preferred Shares and Series 3 Preferred Shares

KML also pays dividends on its 12,000,000 Series 1 Preferred Shares and 10,000,000 Series 3 Preferred Shares, which are fixed, cumulative, preferential, and payable quarterly in the annual amount of C$1.3125 per share and C$1.3000 per share, respectively, on the 15th day of February, May, August and November, as and when declared by KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022 and February 15, 2023, respectively.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2018, in Item 7A in our 2018 Form 10-K. For more information on our risk management activities, see Item 1, Note 5 “Risk Management” to our consolidated financial statements.

LIBOR is used as a reference rate for certain of our financial instruments, such as our revolving credit facilities and the interest rate swap agreements that we use to hedge our interest rate exposure. LIBOR is set to be phased out at the end of 2021. We are currently reviewing how the LIBOR phase-out will affect the Company, but we do not expect the impact to be material.

Item 4. Controls and Procedures.

As of September 30, 2019, 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, 2019 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 11 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 2018 Form 10-K.

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, 2019.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number Description

10.1			Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of September 30, 2019.

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 Income for the three and nine months ended September 30, 2019 and 2018; (ii) our Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2019 and 2018; (iii) our Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2019 and 2018; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2019 and 2018; and (vi) the notes to our Consolidated Financial Statements.

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

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

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 18, 2019	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)