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, 20202021
 
or
 
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____to_____
 
Commission file number: 001-35081
kmi-20210930_g1.gif

KINDER MORGAN, INC.
(Exact name of registrant as specified in its charter)
 
Delaware80-0682103
(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 classTrading Symbol(s)Name of each exchange on which registered
Class P Common StockKMINew York Stock Exchange
1.500% Senior Notes due 2022KMI 22New York Stock Exchange
2.250% Senior Notes due 2027KMI 27 ANew York Stock Exchange
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No ☐
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes þ No ☐
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐ No þ
 
As of October 22, 2020,21, 2021, the registrant had 2,263,793,9232,267,425,507 Class P shares outstanding.




KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
  Page
Number
 
 
 
 
 
 
Note 9
Note 10
 
 
 
  
 
1



KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY

Company Abbreviations
CIG=Colorado Interstate Gas Company, L.L.C.KMP=Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries
ELC=Elba Liquefaction Company, L.L.C.
EPNG=El Paso Natural Gas Company, L.L.C.SFPPRuby=SFPP, L.P.Ruby Pipeline Holding Company, L.L.C.
KMBT=Kinder Morgan Bulk Terminals, Inc.SNGSFPP=Southern Natural Gas Company, L.L.C.SFPP, L.P.
KMI=Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiariesSNG=Southern Natural Gas Company, L.L.C.
TGP=Tennessee Gas Pipeline Company, L.L.C.
TMPL=Trans Mountain Pipeline System
KML=Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries
KMLT=Kinder Morgan Liquid Terminals, LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d=per dayEPA=U.S. Environmental Protection Agency
BBtuBbl=billion British Thermal UnitsbarrelFASB=Financial Accounting Standards Board
BcfBBtu=billion cubic feetBritish Thermal UnitsFERC=Federal Energy Regulatory Commission
Bcf=billion cubic feetGAAP=U.S. Generally Accepted Accounting Principles
CERCLA=Comprehensive Environmental Response, Compensation and Liability ActGAAP=U.S. Generally Accepted Accounting Principles
LLC=limited liability company
LIBOR=London Interbank Offered Rate
CO2
=
carbon dioxide or our CO2 business segment
LIBORMBbl=London Interbank Offered Ratethousand barrels
COVID-19=Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturnMBbl=thousand barrels
MMBbl=million barrels
MMtons=million tons
DCF=distributable cash flowMMtonsNGL=million tonsnatural gas liquids
DD&A=depreciation, depletion and amortizationNGLNYMEX=natural gas liquidsNew York Mercantile Exchange
EBDA=earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investmentsNYMEX=New York Mercantile Exchange
OTC=over-the-counter
ROU=Right-of-Use
EBITDA=earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investmentsROU=Right-of-Use
U.S.=United States of America
WTI=West Texas Intermediate


2


Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,“outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or to pay dividends, are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict.

Forward-looking statements in this report include, statements,among others, express or implied concerning, without limitation:statements pertaining to: the long-term demand for our assets and services, the future impact on our businessanticipated dividends, our proposed acquisition of Kinetrex Energy and our capital projects, including expected completion timing and benefits of the global economic consequencesacquisition and those projects.

Important factors that could cause actual results to differ materially from those expressed in or implied by the forward-looking statements in this report include: the impacts of the COVID-19 pandemic and our expected 2020 outlook, including our expected DCF, Adjusted EBITDA,the pace and Net Debt-to-Adjusted EBITDA ratio.

The impactsextent of COVID-19economic recovery; the timing and decreasesextent of changes in commodity prices resulting from oversupplythe supply of and demand weakness are discussedfor the products we transport and handle; commodity prices; and the other risks and uncertainties described in further detail in Part I, Item 1. “Financial Statements (Unaudited)—Note 1 General—COVID-19;” Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition of Operations—General and Basis of Presentation—COVID-19Operations” and—2020 Outlook;” Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk;” and Part II, Item 1A. “Risk Factors,and in Part II, Item 1A. “Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. In addition to the preceding factors,this report, as well asInformation Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019 (2019 Form 10-K),contain a more detailed description of other factors that may affect the forward-looking statements and should be referenced, except2020 (except to the extent such other factors areinformation is modified or superseded by the descriptionsinformation in subsequent reports.reports).

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

3


PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts, unaudited)

Three Months Ended September 30,Nine Months Ended September 30, Three Months Ended
September 30,
Nine Months Ended
September 30,
2020201920202019 2021202020212020
RevenuesRevenues Revenues 
ServicesServices$1,881 $2,014 $5,664 $6,060 Services$1,928 $1,881 $5,734 $5,664 
Commodity salesCommodity sales982 1,154 2,772 3,659 Commodity sales1,868 982 6,343 2,772 
OtherOther56 46 149 138 Other28 56 108 149 
Total RevenuesTotal Revenues2,919 3,214 8,585 9,857 Total Revenues3,824 2,919 12,185 8,585 
Operating Costs, Expenses and OtherOperating Costs, Expenses and Other Operating Costs, Expenses and Other 
Costs of salesCosts of sales655 762 1,759 2,487 Costs of sales1,559 655 4,504 1,759 
Operations and maintenanceOperations and maintenance643 668 1,869 1,912 Operations and maintenance614 643 1,710 1,869 
Depreciation, depletion and amortizationDepreciation, depletion and amortization539 578 1,636 1,750 Depreciation, depletion and amortization526 539 1,595 1,636 
General and administrativeGeneral and administrative153 154 461 456 General and administrative174 153 490 461 
Taxes, other than income taxesTaxes, other than income taxes100 103 295 324 Taxes, other than income taxes106 100 324 295 
Loss (gain) on impairments and divestitures, net (Note 2)11 (3)1,987 (13)
Other (income) expense, net(1)(2)(1)
Loss on impairments and divestitures, net (Note 3)Loss on impairments and divestitures, net (Note 3)11 1,602 1,987 
Other income, netOther income, net(3)(1)(6)(2)
Total Operating Costs, Expenses and OtherTotal Operating Costs, Expenses and Other2,100 2,263 8,005 6,915 Total Operating Costs, Expenses and Other2,980 2,100 10,219 8,005 
Operating IncomeOperating Income819 951 580 2,942 Operating Income844 819 1,966 580 
Other Income (Expense)Other Income (Expense) Other Income (Expense) 
Earnings from equity investmentsEarnings from equity investments194 173 562 526 Earnings from equity investments169 194 392 562 
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments(32)(21)(99)(61)Amortization of excess cost of equity investments(21)(32)(56)(99)
Interest, netInterest, net(383)(447)(1,214)(1,359)Interest, net(368)(383)(1,122)(1,214)
Other, net14 12 32 35 
Other, net (Note 3)Other, net (Note 3)21 14 264 32 
Total Other ExpenseTotal Other Expense(207)(283)(719)(859)Total Other Expense(199)(207)(522)(719)
Income (Loss) Before Income TaxesIncome (Loss) Before Income Taxes612 668 (139)2,083 Income (Loss) Before Income Taxes645 612 1,444 (139)
Income Tax ExpenseIncome Tax Expense(140)(151)(304)(471)Income Tax Expense(134)(140)(248)(304)
Net Income (Loss)Net Income (Loss)472 517 (443)1,612 Net Income (Loss)511 472 1,196 (443)
Net Income Attributable to Noncontrolling InterestsNet Income Attributable to Noncontrolling Interests(17)(11)(45)(32)Net Income Attributable to Noncontrolling Interests(16)(17)(49)(45)
Net Income (Loss) Attributable to Kinder Morgan, Inc.Net Income (Loss) Attributable to Kinder Morgan, Inc.$455 $506 $(488)$1,580 Net Income (Loss) Attributable to Kinder Morgan, Inc.$495 $455 $1,147 $(488)
Class P SharesClass P SharesClass P Shares
Basic and Diluted Earnings (Loss) Per Common Share$0.20 $0.22 $(0.22)$0.69 
Basic and Diluted Earnings (Loss) Per ShareBasic and Diluted Earnings (Loss) Per Share$0.22 $0.20 $0.50 $(0.22)
Basic and Diluted Weighted Average Common Shares Outstanding2,263 2,264 2,263 2,263 
Basic and Diluted Weighted Average Shares OutstandingBasic and Diluted Weighted Average Shares Outstanding2,267 2,263 2,265 2,263 
The accompanying notes are an integral part of these consolidated financial statements.
4


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions, unaudited)
Three Months Ended September 30,Nine Months Ended September 30, Three Months Ended
September 30,
Nine Months Ended
September 30,
2020201920202019 2021202020212020
Net income (loss)Net income (loss)$472 $517 $(443)$1,612 Net income (loss)$511 $472 $1,196 $(443)
Other comprehensive (loss) income, net of taxOther comprehensive (loss) income, net of tax  Other comprehensive (loss) income, net of tax  
Change in fair value of hedge derivatives (net of tax benefit (expense) of $17, $(6), $5, and $39, respectively)(56)20 (16)(132)
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $1, $(13), $(22), and $(11), respectively)(5)40 72 35 
Foreign currency translation adjustments (net of tax benefit (expense) of $0, $2, $0, and $(5), respectively)(7)16 
Benefit plan adjustments (net of tax expense of $2, $3, $7 and $8, respectively)21 23 
Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively)Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively)(131)(56)(444)(16)
Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively)Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively)92 (5)181 72 
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)— — — 
Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively)Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively)28 21 
Total other comprehensive (loss) incomeTotal other comprehensive (loss) income(56)61 78 (58)Total other comprehensive (loss) income(33)(56)(235)78 
Comprehensive income (loss)Comprehensive income (loss)416 578 (365)1,554 Comprehensive income (loss)478 416 961 (365)
Comprehensive income attributable to noncontrolling interestsComprehensive income attributable to noncontrolling interests(17)(8)(45)(28)Comprehensive income attributable to noncontrolling interests(16)(17)(49)(45)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.Comprehensive income (loss) attributable to Kinder Morgan, Inc.$399 $570 $(410)$1,526 Comprehensive income (loss) attributable to Kinder Morgan, Inc.$462 $399 $912 $(410)
The accompanying notes are an integral part of these consolidated financial statements.
5



KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except per share amounts, unaudited)

September 30, 2020December 31, 2019 September 30, 2021December 31, 2020
ASSETSASSETS ASSETS 
Current AssetsCurrent Assets Current Assets 
Cash and cash equivalentsCash and cash equivalents$632 $185 Cash and cash equivalents$102 $1,184 
Restricted depositsRestricted deposits67 24 Restricted deposits177 25 
Marketable securities at fair value925 
Accounts receivableAccounts receivable1,142 1,379 Accounts receivable1,433 1,293 
Fair value of derivative contractsFair value of derivative contracts257 84 Fair value of derivative contracts199 185 
InventoriesInventories317 371 Inventories457 348 
Other current assetsOther current assets257 270 Other current assets318 168 
Total current assetsTotal current assets2,672 3,238 Total current assets2,686 3,203 
Property, plant and equipment, netProperty, plant and equipment, net35,958 36,419 Property, plant and equipment, net35,576 35,836 
InvestmentsInvestments8,014 7,759 Investments7,620 7,917 
GoodwillGoodwill19,851 21,451 Goodwill20,033 19,851 
Other intangibles, netOther intangibles, net2,510 2,676 Other intangibles, net1,744 2,453 
Deferred income taxesDeferred income taxes671 857 Deferred income taxes303 536 
Deferred charges and other assetsDeferred charges and other assets2,145 1,757 Deferred charges and other assets1,678 2,177 
Total AssetsTotal Assets$71,821 $74,157 Total Assets$69,640 $71,973 
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITYLIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY  LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY  
Current LiabilitiesCurrent Liabilities  Current Liabilities  
Current portion of debtCurrent portion of debt$2,057 $2,477 Current portion of debt$2,822 $2,558 
Accounts payableAccounts payable774 914 Accounts payable1,189 837 
Accrued interestAccrued interest351 548 Accrued interest332 525 
Accrued taxesAccrued taxes335 364 Accrued taxes284 267 
Accrued contingenciesAccrued contingencies315 89 Accrued contingencies246 307 
Other current liabilitiesOther current liabilities544 708 Other current liabilities952 580 
Total current liabilitiesTotal current liabilities4,376 5,100 Total current liabilities5,825 5,074 
Long-term liabilities and deferred creditsLong-term liabilities and deferred credits  Long-term liabilities and deferred credits  
Long-term debtLong-term debt  Long-term debt  
OutstandingOutstanding31,281 30,883 Outstanding28,988 30,838 
Debt fair value adjustmentsDebt fair value adjustments1,379 1,032 Debt fair value adjustments1,014 1,293 
Total long-term debtTotal long-term debt32,660 31,915 Total long-term debt30,002 32,131 
Other long-term liabilities and deferred creditsOther long-term liabilities and deferred credits2,093 2,253 Other long-term liabilities and deferred credits2,160 2,202 
Total long-term liabilities and deferred creditsTotal long-term liabilities and deferred credits34,753 34,168 Total long-term liabilities and deferred credits32,162 34,333 
Total LiabilitiesTotal Liabilities39,129 39,268 Total Liabilities37,987 39,407 
Commitments and contingencies (Notes 3 and 9)
Commitments and contingencies (Notes 4 and 10)Commitments and contingencies (Notes 4 and 10)00
Redeemable Noncontrolling InterestRedeemable Noncontrolling Interest747 803 Redeemable Noncontrolling Interest661 728 
Stockholders’ EquityStockholders’ Equity  Stockholders’ Equity  
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,263,749,898 and 2,264,936,054 shares, respectively, issued and outstanding
23 23 
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding
23 23 
Additional paid-in capitalAdditional paid-in capital41,736 41,745 Additional paid-in capital41,788 41,756 
Accumulated deficitAccumulated deficit(9,945)(7,693)Accumulated deficit(10,617)(9,936)
Accumulated other comprehensive lossAccumulated other comprehensive loss(255)(333)Accumulated other comprehensive loss(642)(407)
Total Kinder Morgan, Inc.’s stockholders’ equityTotal Kinder Morgan, Inc.’s stockholders’ equity31,559 33,742 Total Kinder Morgan, Inc.’s stockholders’ equity30,552 31,436 
Noncontrolling interestsNoncontrolling interests386 344 Noncontrolling interests440 402 
Total Stockholders’ EquityTotal Stockholders’ Equity31,945 34,086 Total Stockholders’ Equity30,992 31,838 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ EquityTotal Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$71,821 $74,157 Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$69,640 $71,973 
The accompanying notes are an integral part of these consolidated financial statements.
6


KINDER MORGAN, INC. AND SUBSIDIARIESKINDER MORGAN, INC. AND SUBSIDIARIESKINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWSCONSOLIDATED STATEMENTS OF CASH FLOWSCONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)(In millions, unaudited)(In millions, unaudited)
Nine Months Ended September 30, Nine Months Ended September 30,
20202019 20212020
Cash Flows From Operating ActivitiesCash Flows From Operating Activities Cash Flows From Operating Activities 
Net (loss) income$(443)$1,612 
Adjustments to reconcile net (loss) income to net cash provided by operating activities 
Net income (loss)Net income (loss)$1,196 $(443)
Adjustments to reconcile net income (loss) to net cash provided by operating activitiesAdjustments to reconcile net income (loss) to net cash provided by operating activities 
Depreciation, depletion and amortizationDepreciation, depletion and amortization1,636 1,750 Depreciation, depletion and amortization1,595 1,636 
Deferred income taxesDeferred income taxes164 254 Deferred income taxes236 164 
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments99 61 Amortization of excess cost of equity investments56 99 
Loss (gain) on impairments and divestitures, net (Note 2)1,987 (13)
Loss on impairments and divestitures, net (Note 3)Loss on impairments and divestitures, net (Note 3)1,602 1,987 
Gain on sale of interest in equity investment (Note 3)Gain on sale of interest in equity investment (Note 3)(206)— 
Earnings from equity investmentsEarnings from equity investments(562)(526)Earnings from equity investments(392)(562)
Distributions from equity investment earningsDistributions from equity investment earnings487 412 Distributions from equity investment earnings535 487 
Changes in components of working capitalChanges in components of working capitalChanges in components of working capital
Accounts receivableAccounts receivable238 224 Accounts receivable(119)238 
InventoriesInventories41 (28)Inventories(89)41 
Other current assetsOther current assets14 97 Other current assets(90)14 
Accounts payableAccounts payable(107)(266)Accounts payable362 (107)
Accrued interest, net of interest rate swapsAccrued interest, net of interest rate swaps(208)(218)Accrued interest, net of interest rate swaps(177)(208)
Accrued taxesAccrued taxes(25)(107)Accrued taxes15 (25)
Other current liabilitiesOther current liabilities(111)(136)Other current liabilities71 (93)
Rate reparations, refunds and other litigation reserve adjustmentsRate reparations, refunds and other litigation reserve adjustments(97)48 
Other, netOther, net72 Other, net(58)
Net Cash Provided by Operating ActivitiesNet Cash Provided by Operating Activities3,282 3,121 Net Cash Provided by Operating Activities4,440 3,282 
Cash Flows From Investing ActivitiesCash Flows From Investing ActivitiesCash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquiredAcquisitions of assets and investments, net of cash acquired(1,518)(16)
Capital expendituresCapital expenditures(1,351)(1,719)Capital expenditures(894)(1,351)
Proceeds from sales of assets and investments, net of working capital adjustments907 80 
Proceeds from sales of investmentsProceeds from sales of investments417 907 
Contributions to investmentsContributions to investments(365)(1,148)Contributions to investments(36)(365)
Distributions from equity investments in excess of cumulative earningsDistributions from equity investments in excess of cumulative earnings105 207 Distributions from equity investments in excess of cumulative earnings121 105 
Other, netOther, net(72)(30)Other, net(1)(56)
Net Cash Used in Investing ActivitiesNet Cash Used in Investing Activities(776)(2,610)Net Cash Used in Investing Activities(1,911)(776)
Cash Flows From Financing ActivitiesCash Flows From Financing ActivitiesCash Flows From Financing Activities
Issuances of debtIssuances of debt3,888 5,118 Issuances of debt4,950 3,888 
Payments of debtPayments of debt(3,991)(6,303)Payments of debt(6,459)(3,991)
Debt issue costsDebt issue costs(23)(9)Debt issue costs(20)(23)
Common stock dividends(1,764)(1,593)
DividendsDividends(1,828)(1,764)
Repurchases of common shares(50)(2)
Repurchases of sharesRepurchases of shares— (50)
Contributions from investment partner and noncontrolling interestsContributions from investment partner and noncontrolling interests11 138 Contributions from investment partner and noncontrolling interests11 
Distributions to investment partnerDistributions to investment partner(60)Distributions to investment partner(67)(60)
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds(879)
Distributions to noncontrolling interests - other(11)(42)
Distributions to noncontrolling interestsDistributions to noncontrolling interests(14)(11)
Other, netOther, net(13)(28)Other, net(25)(13)
Net Cash Used in Financing ActivitiesNet Cash Used in Financing Activities(2,013)(3,600)Net Cash Used in Financing Activities(3,459)(2,013)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted DepositsEffect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits(3)26 Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits— (3)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits490 (3,063)
Net (decrease) increase in Cash, Cash Equivalents and Restricted DepositsNet (decrease) increase in Cash, Cash Equivalents and Restricted Deposits(930)490 
Cash, Cash Equivalents, and Restricted Deposits, beginning of periodCash, Cash Equivalents, and Restricted Deposits, beginning of period209 3,331 Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,209 209 
Cash, Cash Equivalents, and Restricted Deposits, end of periodCash, Cash Equivalents, and Restricted Deposits, end of period$699 $268 Cash, Cash Equivalents, and Restricted Deposits, end of period$279 $699 
7


KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWSCONSOLIDATED STATEMENTS OF CASH FLOWSCONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)(In millions, unaudited)(In millions, unaudited)
Nine Months Ended September 30, Nine Months Ended September 30,
20202019 20212020
Cash and Cash Equivalents, beginning of periodCash and Cash Equivalents, beginning of period$185 $3,280 Cash and Cash Equivalents, beginning of period$1,184 $185 
Restricted Deposits, beginning of periodRestricted Deposits, beginning of period24 51 Restricted Deposits, beginning of period25 24 
Cash, Cash Equivalents, and Restricted Deposits, beginning of periodCash, Cash Equivalents, and Restricted Deposits, beginning of period209 3,331 Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,209 209 
Cash and Cash Equivalents, end of periodCash and Cash Equivalents, end of period632 241 Cash and Cash Equivalents, end of period102 632 
Restricted Deposits, end of periodRestricted Deposits, end of period67 27 Restricted Deposits, end of period177 67 
Cash, Cash Equivalents, and Restricted Deposits, end of periodCash, Cash Equivalents, and Restricted Deposits, end of period699 268 Cash, Cash Equivalents, and Restricted Deposits, end of period279 699 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits$490 $(3,063)
Net (decrease) increase in Cash, Cash Equivalents and Restricted DepositsNet (decrease) increase in Cash, Cash Equivalents and Restricted Deposits$(930)$490 
Non-cash Investing and Financing ActivitiesNon-cash Investing and Financing ActivitiesNon-cash Investing and Financing Activities
ROU assets and operating lease obligations recognizedROU assets and operating lease obligations recognized$15 $764 ROU assets and operating lease obligations recognized$35 $15 
Increase in property, plant and equipment from both accruals and contractor retainageIncrease in property, plant and equipment from both accruals and contractor retainage0
Supplemental Disclosures of Cash Flow InformationSupplemental Disclosures of Cash Flow InformationSupplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)Cash paid during the period for interest (net of capitalized interest)1,440 1,584 Cash paid during the period for interest (net of capitalized interest)1,313 1,440 
Cash paid during the period for income taxes, netCash paid during the period for income taxes, net202 364 Cash paid during the period for income taxes, net202 
The accompanying notes are an integral part of these consolidated financial statements.
8


KINDER MORGAN, INC. AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions, unaudited)

Common stockCommon stock
Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total
Balance at June 30, 20202,261 $23 $41,731 $(9,802)$(199)$31,753 $371 $32,124 
Balance at June 30, 2021Balance at June 30, 20212,265 $23 $41,793 $(10,496)$(609)$30,711 $429 $31,140 
Restricted sharesRestricted sharesRestricted shares(5)(5)(5)
Net incomeNet income455 455 17 472 Net income495 495 16 511 
DistributionsDistributions(4)(4)Distributions— (6)(6)
ContributionsContributionsContributions— 
Common stock dividends(598)(598)(598)
DividendsDividends(616)(616)(616)
Other comprehensive lossOther comprehensive loss(56)(56)(56)Other comprehensive loss(33)(33)(33)
Balance at September 30, 20202,264 $23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
Balance at September 30, 2021Balance at September 30, 20212,267 $23 $41,788 $(10,617)$(642)$30,552 $440 $30,992 
Common stock
 Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total
Balance at June 30, 20192,262 $23 $41,734 $(7,670)$(448)$33,639 $846 $34,485 
Restricted shares(7)(7)(7)
Net income506 506 11 517 
Distributions(14)(14)
Contributions
Common stock dividends(569)(569)(569)
Other(1)(1)
Other comprehensive income (loss)64 64 (3)61 
Balance at September 30, 20192,265 $23 $41,727 $(7,733)$(384)$33,633 $841 $34,474 

Common stock
 Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total
Balance at June 30, 20202,261$23 $41,731 $(9,802)$(199)$31,753 $371 $32,124 
Restricted shares3
Net income455 455 17 472 
Distributions— (4)(4)
Contributions— 
Dividends(598)(598)(598)
Other comprehensive loss(56)(56)(56)
Balance at September 30, 20202,264$23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
The accompanying notes are an integral part of these consolidated financial statements.
9


KINDER MORGAN, INC. AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)
(In millions, unaudited)

Common stock
 Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total
Balance at December 31, 20192,265 $23 $41,745 $(7,693)$(333)$33,742 $344 $34,086 
Repurchases of common shares(4)(50)(50)(50)
Restricted shares41 41 41 
Net (loss) income(488)(488)45 (443)
Distributions(11)(11)
Contributions
Common stock dividends(1,764)(1,764)(1,764)
Other comprehensive income78 78 78 
Balance at September 30, 20202,264 $23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
Common stock
 Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total
Balance at December 31, 20202,264 $23 $41,756 $(9,936)$(407)$31,436 $402 $31,838 
Restricted shares32 32 32 
Net income1,147 1,147 49 1,196 
Distributions— (14)(14)
Contributions— 
Dividends(1,828)(1,828)(1,828)
Other— (1)(1)
Other comprehensive loss(235)(235)(235)
Balance at September 30, 20212,267 $23 $41,788 $(10,617)$(642)$30,552 $440 $30,992 
Common stock
 Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total
Balance at December 31, 20182,262$23 $41,701 $(7,716)$(330)$33,678 $853 $34,531 
Impact of adoption of ASU 2017-12(4)(4)(4)
Balance at January 1, 20192,26223 41,701 (7,720)(330)33,674 853 34,527 
Repurchases of common shares(2)(2)(2)
Restricted shares328 28 28 
Net income1,580 1,580 32 1,612 
Distributions(42)(42)
Contributions
Common stock dividends(1,593)(1,593)(1,593)
Other(1)(1)
Other comprehensive loss(54)(54)(4)(58)
Balance at September 30, 20192,265$23 $41,727 $(7,733)$(384)$33,633 $841 $34,474 

Common stock
 Issued sharesPar valueAdditional
paid-in
capital
Accumulated
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-controlling
interests
Total
Balance at December 31, 20192,265$23 $41,745 $(7,693)$(333)$33,742 $344 $34,086 
Repurchases of shares(4)(50)(50)(50)
Restricted shares341 41 41 
Net (loss) income(488)(488)45 (443)
Distributions— (11)(11)
Contributions— 
Dividends(1,764)(1,764)(1,764)
Other comprehensive income78 78 78 
Balance at September 30, 20202,264$23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
The accompanying notes are an integral part of these consolidated financial statements.

10



KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. General

Organization

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

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 20192020 Form 10-K.

The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary.  If such criteria are met, we consolidate the financial statements of such businesses with those of our own.

COVID-19

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

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

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, as discussed above, we evaluate goodwill for impairment on May 31 of each year. For this purpose,our May 31, 2021 evaluation, we havegrouped our businesses into 6 reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; and (vi) Terminals. See Note 23 for results of our May 31, 20202021 goodwill impairment test.

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


11



Earnings per Share

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

11



The following table sets forth the allocation of net income (loss) available to shareholders of Class P shares and participating securities:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except per share amounts)
Net Income (Loss) Available to Common Stockholders$455 $506 $(488)$1,580 
Participating securities:
   Less: Net Income allocated to restricted stock awards(a)(3)(3)(9)(9)
Net Income (Loss) Allocated to Class P Stockholders$452 $503 $(497)$1,571 
Basic Weighted Average Common Shares Outstanding2,263 2,264 2,263 2,263 
Basic Earnings (Loss) Per Common Share$0.20 $0.22 $(0.22)$0.69 
________
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders$495 $455 $1,147 $(488)
Participating securities:
   Less: Net Income allocated to restricted stock awards(a)(4)(3)(10)(9)
Net Income (Loss) Allocated to Class P Stockholders$491 $452 $1,137 $(497)
Basic Weighted Average Shares Outstanding2,267 2,263 2,265 2,263 
Basic Earnings (Loss) Per Share$0.22 $0.20 $0.50 $(0.22)
(a)As of September 30, 2020,2021, there were approximately 13 million restricted stock awards outstanding.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended
September 30,
Nine Months Ended
September 30,
20202019202020192021202020212020
(In millions on a weighted average basis)(In millions on a weighted average basis)
Unvested restricted stock awardsUnvested restricted stock awards13 13 13 13 Unvested restricted stock awards13 13 13 13 
Convertible trust preferred securitiesConvertible trust preferred securitiesConvertible trust preferred securities

2. Acquisitions
2.
As of September 30, 2021, our preliminary allocation of the purchase price for significant acquisitions completed during the nine months ended September 30, 2021 are detailed below.
Assignment of Purchase Price
RefDateAcquisitionPurchase priceCurrent assetsProperty, plant & equipmentDeferred charges & otherGoodwillCurrent liabilitiesLong-term liabilities
(In millions)
(1)8/21Kinetrex Energy$318 $17 $49 $262 $64 $(6)$(68)
(2)7/21Stagecoach Gas Services LLC1,228 52 1,041 23 118 (6)— 

Pro Forma Information

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

(1) Kinetrex Energy Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on 3 additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.
12




(2) Stagecoach Acquisition

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

Goodwill

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

Changes in the amounts of our goodwill for the nine months ended September 30, 2021 are summarized by reporting unit as follows:
Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-Regulated
CO2
Products PipelinesProducts Pipelines TerminalsTerminalsEnergy Transition VenturesTotal
(In millions)
Goodwill as of December 31, 2020$14,249 $2,343 $928 $1,378 $151 $802 $— $19,851 
Acquisitions118 — — — — — 64 182 
Goodwill as of September 30, 2021$14,367 $2,343 $928 $1,378 $151 $802 $64 $20,033 

13



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

We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and nine months ended September 30, 2021 and 2020:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)$— $— $1,600 $— 
Impairment of goodwill(a)— — — 1,000 
Gain on sale of interest in NGPL Holdings LLC(a)— — (206)— 
Loss on write-down of related party note receivable(a)— — 117 — 
Loss (gain) on divestitures of long-lived assets and other write-downs— 11 (1)11 
Products Pipelines
Impairment of long-lived and intangible assets— — — 21 
Terminals
Impairment of long-lived and intangible assets14 — 14 
CO2
Impairment of goodwill(a)— — — 600 
Impairment of long-lived assets(a)— — — 350 
Gain on divestitures of long-lived assets, net(11)— (8)— 
Other loss (gain) on divestitures of long-lived assets, net— (3)— 
Pre-tax loss on impairments, divestitures and other write-downs, net$$11 $1,513 $1,987 
(a)See below for a further discussion of these items.

Impairments

Long-lived Assets

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

During the first quarterhalf of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering eventsevent that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2business segment and conducted interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020, which resulted in impairmentsa non-cash impairment of long-lived assets and goodwill within our CO2business segment during the three months ended March 31, 2020.

Additionally, we performed our annual goodwill impairment testing as of May 31, 2020. For our Natural Gas Pipelines Non-Regulated reporting unit, while no goodwill impairment was required as of March 31, 2020, the additional market and economic indicators existing at May 31, 2020, as further described below, resultedshown in the recognition of a goodwill impairment for that reporting unit during the three months ended June 30, 2020.
12



We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assetsabove table during the nine months ended September 30, 2020 and 2019:
Nine Months Ended September 30,
20202019
(In millions)
Natural Gas Pipelines
Impairment of goodwill$1,000 $
Impairments of inventory11 
Gain on divestitures of long-lived assets(10)
Products Pipelines
Impairment of long-lived and intangible assets21 
Terminals
Impairment of long-lived and intangible assets
Gain on divestitures of long-lived assets(3)
CO2
Impairment of goodwill600 
Impairment of long-lived assets350 
Kinder Morgan Canada
Loss on divestiture of long-lived assets
Other gain on divestitures of long-lived assets(2)
Pre-tax loss (gain) on divestitures and impairments, net$1,987 $(13)

Long-lived Assets

As of March 31, 2020, for our CO2 assets, the long lived asset impairment test involved an assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows.2020.

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

To compute estimated future cash flows for our CO2 source and transportation assets, volume forecasts were developed based on projected demand for our CO2 services based upon management’s projections of the availability of CO2 supply and the future demand for CO2 for use in enhanced oil recovery projects. The CO2 pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO2 pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.

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

13



Goodwill

Changes in the amounts of our goodwill for the nine months ended September 30, 2020 are summarized by reporting unit as follows:
Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-Regulated
CO2
Products PipelinesProducts Pipelines TerminalsTerminalsTotal
(In millions)
Goodwill as of December 31, 2019$14,249 $3,343 $1,528 $1,378 $151 $802 $21,451 
Impairments(1,000)(600)(1,600)
Goodwill as of September 30, 2020$14,249 $2,343 $928 $1,378 $151 $802 $19,851 

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

In regards to our Natural Gas Pipelines Non-Regulated reporting unit, it experienced a sharp decline in customer demand for its services during the second quarter of 2020. This represented a timing lag from the initial economic decline impacts resulting from the severe downturn in the upstream energy industry, including our CO2 business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter.

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

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

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

For our March 31, 2020 interimfair value exceeded the carrying value. The fair value estimates used in the goodwill impairment test are primarily based on Level 3 inputs of the CO2 reporting unit, we applied anfair value hierarchy. The inputs include valuation estimates using market and income approach to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertaintyvaluation methodologies, which include assumptions primarily involving management’s significant judgments and volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.estimates with respect
14




In determiningto market multiples, comparable sales transactions, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding future cash flows based on production growth rate assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value forof our CO2 reporting unit, we applied a 9.25%assets. We use discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used representsrates representing our estimate of the weighted average cost of capital of a theoreticalrisk-adjusted discount rates that would be used by market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO2participants specific to the particular reporting unit of approximately $600 million as of March 31, 2020.unit.

The fair value estimates usedDuring the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 and Natural Gas Pipelines business segments during the nine months ended September 30, 2020 as shown in the long-lived asset and goodwill test were primarily based on Level 3 inputs of the fair value hierarchy.
Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.table above.

As conditions warrant, we routinely evaluate our assets for potential triggering events such as those described above that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Although we did not identify additional triggering events during the third quarter of 2020, in the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.

Sale of an Interest in NGPL Holdings

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

Other Write-downs

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

15



3.4. Debt

The following table provides information on the principal amount of our outstanding debt balances:
September 30, 2020December 31, 2019
(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023$$
Commercial paper notes(a)37 
Current portion of senior notes
6.85%, due February 2020(b)700 
6.50%, due April 2020(c)535 
5.30%, due September 2020(d)600 
6.50%, due September 2020(d)349 
5.00%, due February 2021750 
3.50%, due March 2021750 
5.80%, due March 2021400 
Trust I preferred securities, 4.75%, due March 2028111 111 
Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e)100 
Current portion of other debt46 45 
  Total current portion of debt2,057 2,477 
Long-term debt (excluding current portion)
Senior notes30,578 30,164 
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035369 381 
Trust I preferred securities, 4.75%, due March 2028110 110 
Other224 228 
Total long-term debt31,281 30,883 
Total debt(f)$33,338 $33,360 
_______
September 30, 2021December 31, 2020
(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026(a)$— $— 
$500 million credit facility due November 16, 2023(a)— — 
Commercial paper notes160 — 
Current portion of senior notes
5.00%, due February 2021(b)— 750 
3.50%, due March 2021(b)— 750 
5.80%, due March 2021(b)— 400 
5.00%, due October 2021(c)— 500 
8.625%, due January 2022260 — 
4.15%, due March 2022375 — 
1.50%, due March 2022(d)869 — 
3.95% due September 20221,000 — 
Trust I preferred securities, 4.75%, due March 2028111 111 
Current portion of other debt47 47 
Total current portion of debt2,822 2,558 
Long-term debt (excluding current portion)
Senior notes28,306 30,141 
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035353 364 
Trust I preferred securities, 4.75%, due March 2028110 110 
Other219 223 
Total long-term debt28,988 30,838 
Total debt(e)$31,810 $33,396 
(a)Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.
(b)On January 9, 2020, we soldWe repaid the approximate 25 million sharesprincipal amounts on these senior notes during the first quarter of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to partially repay debt that matured in February 2020. The fair value of the Pembina common equity of $925 million as of December 31, 2019 was reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet.2021.
(c)In April 2020, weThese notes were repaid $535 million of maturing senior notes.on July 1, 2021.
(d)In September 2020, we repaid a combined $949 millionConsists of maturing senior notes using proceeds fromdenominated in Euros that have been converted to U.S. dollars. The September 30, 2021 balance is reported above at the exchange rate of 1.1580 U.S. dollars per Euro. As of September 30, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our newly issued seniordebt balance of $54 million related to these notes.
(e)In December 2019, we notified The cumulative increase in debt due to the holderchanges in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified ascross-currency swaps reflected in “Other current inassets” and “Other current liabilities” on our accompanying consolidated balance sheet assheets. At the time of December 31, 2019. We redeemedissuance, we entered into foreign currency contracts associated with these securities, including accrued dividends, on January 15, 2020.senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 6 “Risk Management—Foreign Currency Risk Management”).
(f)(e)Excludes our “Debt fair value adjustments” which, as of September 30, 20202021 and December 31, 2019,2020, increased our total debt balances by $1,379$1,014 million and $1,032$1,293 million, respectively.

We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.

On August 5, 2020,February 11, 2021, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00%3.60% senior notes due 2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million.

On February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 20302051 and received net proceeds of $991$741 million.

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

Credit Facilities and Restrictive Covenants

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



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

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

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

As of September 30, 2020,2021, we had 0no borrowings outstanding under our $4.0 billion credit facility, 0facilities, $160 million in borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilityfacilities as of September 30, 20202021 was $3,919$3,759 million. As of September 30, 2020,2021, we were in compliance with all required covenants.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below: 
September 30, 2020December 31, 2019
Carrying
value
Estimated
fair value
Carrying
value
Estimated
fair value
(In millions)
Total debt$34,717 $38,253 $34,392 $38,016 
September 30, 2021December 31, 2020
Carrying
value
Estimated
fair value
Carrying
value
Estimated
fair value
(In millions)
Total debt$32,824 $37,797 $34,689 $39,622 

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 20202021 and December 31, 2019.2020.

4.5. Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. In March 2020, we repurchased approximately 3.6 million of our Class P shares for approximately $50 million at an average price of approximately $13.94 per share. Since December 2017, in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $575 million.

Common Stock Dividends

Holders of our common stock participate in common stock dividends declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Per common share cash dividend declared for the period$0.2625 $0.25 $0.7875 $0.75 
Per common share cash dividend paid in the period0.2625 0.25 0.775 0.70 

On October 21, 2020, our board of directors declared a cash dividend of $0.2625 per common share for the quarterly period ended September 30, 2020, which is payable on November 16, 2020 to common shareholders of record as of the close of business on November 2, 2020.
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
Per share cash dividend declared for the period$0.27 $0.2625 $0.81 $0.7875 
Per share cash dividend paid in the period0.27 0.2625 0.8025 0.775 

17



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

Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
Foreign
currency
translation
adjustments
Pension and
other
postretirement
liability adjustments
Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7)$$(326)$(333)
Other comprehensive (loss) gain before reclassifications(16)21 
Loss reclassified from accumulated other comprehensive loss72 72 
Net current-period change in accumulated other comprehensive (loss) income56 21 78 
Balance as of September 30, 2020$49 $$(305)$(255)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
Foreign
currency
translation
adjustments
Pension and
other
postretirement
liability adjustments
Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2020$(13)$— $(394)$(407)
Other comprehensive (loss) gain before reclassifications(444)— 28 (416)
Loss reclassified from accumulated other comprehensive loss181 — — 181 
Net current-period change in accumulated other comprehensive loss(263)— 28 (235)
Balance as of September 30, 2021$(276)$— $(366)$(642)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
Foreign
currency
translation
adjustments
Pension and
other
postretirement
liability adjustments
Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2018$164 $(91)$(403)$(330)
Other comprehensive (loss) gain before reclassifications(132)20 23 (89)
Loss reclassified from accumulated other comprehensive loss35 35 
Net current-period change in accumulated other comprehensive income (loss)(97)20 23 (54)
Balance as of September 30, 2019$67 $(71)$(380)$(384)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
Foreign
currency
translation
adjustments
Pension and
other
postretirement
liability adjustments
Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7)$— $(326)$(333)
Other comprehensive (loss) gain before reclassifications(16)21 
Loss reclassified from accumulated other comprehensive loss72 — — 72 
Net current-period change in accumulated other comprehensive (loss) income56 21 78 
Balance as of September 30, 2020$49 $$(305)$(255)

5.6.  Risk Management

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

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

18



Energy Commodity Price Risk Management

As of September 30, 2020,2021, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price(20.2)(15.9)MMBbl
Crude oil basis(2.6)(6.4)MMBbl
Natural gas fixed price(34.8)(29.5)Bcf
Natural gas basis(34.8)(27.1)Bcf
NGL fixed price(1.2)(1.0)MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(2.4)(1.4)MMBbl
Crude oil basis(0.9)(8.7)MMBbl
Natural gas fixed price(9.7)(8.7)Bcf
Natural gas basis2.2 (22.8)Bcf
NGL fixed price(1.4)(1.9)MMBbl

As of September 30, 2020,2021, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2024.2025.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2020:2021:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)$7,6257,100 Fair value hedgeMarch 2035
Variable-to-fixed interest rate contracts250 Cash flow hedgeJanuary 2023
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts3,5006,250 Mark-to-MarketDecember 20212022
_______
(a)The principal amount of hedged senior notes consisted of $900$750 million included in “Current portion of debt” and $6,725$6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

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

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, 2020:2021:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$1,358 Cash flow hedgeMarch 2027
_______
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.
19




The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
Fair Value of Derivative Contracts
Derivatives AssetDerivatives Liability
September 30,
2020
December 31,
2019
September 30,
2020
December 31,
2019
LocationFair valueFair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)$103 $31 $(25)$(43)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)59 17 (4)(8)
Subtotal162 48 (29)(51)
Interest rate contractsFair value of derivative contracts/(Other current liabilities)134 45 (3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)634 313 (8)(1)
Subtotal768 358 (11)(1)
Foreign currency contractsFair value of derivative contracts/(Other current liabilities)(14)(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)70 46 
Subtotal70 46 (14)(6)
Total1,000 452 (54)(58)
Derivatives not designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)19 (10)(7)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)(1)
Subtotal25 (11)(7)
Interest rate contractsFair value of derivative contracts/(Other current liabilities)(3)
Subtotal(3)
Total25 (14)(7)
Total derivatives$1,025 $460 $(68)$(65)

Fair Value of Derivative Contracts
Derivatives AssetDerivatives Liability
September 30,
2021
December 31,
2020
September 30,
2021
December 31,
2020
LocationFair valueFair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)$13 $42 $(256)$(33)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)33 (96)(8)
Subtotal14 75 (352)(41)
Interest rate contractsFair value of derivative contracts/(Other current liabilities)127 119 (4)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)350 575 (14)(7)
Subtotal477 694 (18)(10)
Foreign currency contractsFair value of derivative contracts/(Other current liabilities)49 — (6)(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)20 138 — — 
Subtotal69 138 (6)(6)
Total560 907 (376)(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)10 24 (63)(21)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)— (3)— 
Subtotal14 24 (66)(21)
Interest rate contractsFair value of derivative contracts/(Other current liabilities)— — (1)— 
 Deferred charges and other assets/(Other long-term liabilities and deferred credits)— — — 
Subtotal— (1)— 
Total15 24 (67)(21)
Total derivatives$575 $931 $(443)$(78)
20



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

Level 1

Level 2

Level 3
Gross amountContracts available for nettingCash collateral held(b)Net amount
Level 1

Level 2

Level 3
Gross amountContracts available for nettingCash collateral held(b)Net amount
(In millions)(In millions)
As of September 30, 2020
As of September 30, 2021As of September 30, 2021
Energy commodity derivative contracts(a)Energy commodity derivative contracts(a)$$184 $$187 $(28)$$159 Energy commodity derivative contracts(a)$15 $13 $— $28 $(26)$— $
Interest rate contractsInterest rate contracts768 768 (2)766 Interest rate contracts— 478 — 478 (9)— 469 
Foreign currency contractsForeign currency contracts70 70 (14)56 Foreign currency contracts— 69 — 69 (6)— 63 
As of December 31, 2019
As of December 31, 2020As of December 31, 2020
Energy commodity derivative contracts(a)Energy commodity derivative contracts(a)$19 $37 $$56 $(19)$(21)$16 Energy commodity derivative contracts(a)$$93 $— $99 $(35)$— $64 
Interest rate contractsInterest rate contracts358 358 358 Interest rate contracts— 694 — 694 (2)— 692 
Foreign currency contractsForeign currency contracts46 46 (6)40 Foreign currency contracts— 138 — 138 (6)— 132 
Balance sheet liability
fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral posted(b)Net amount
(In millions)
As of September 30, 2020
Energy commodity derivative contracts(a)$(29)$(11)$$(40)$28 $$(4)
Interest rate contracts(14)(14)(12)
Foreign currency contracts(14)(14)14 
As of December 31, 2019
Energy commodity derivative contracts(a)$(3)$(55)$$(58)$19 $$(39)
Interest rate contracts(1)(1)(1)
Foreign currency contracts(6)(6)
_______
Balance sheet liability
fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral posted(b)Net amount
(In millions)
As of September 30, 2021
Energy commodity derivative contracts(a)$(111)$(307)$— $(418)$26 $135 $(257)
Interest rate contracts— (19)— (19)— (10)
Foreign currency contracts— (6)— (6)— — 
As of December 31, 2020
Energy commodity derivative contracts(a)$(7)$(56)$— $(63)$35 $(8)$(36)
Interest rate contracts— (10)— (10)— (8)
Foreign currency contracts— (6)— (6)— — 
(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
(b)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of operations and comprehensive income (loss):
Derivatives in fair value hedging relationshipsLocationGain/(loss) recognized in income
on derivative and related hedged item
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Interest rate contractsInterest, net$(50)$117 $409 $453 
Hedged fixed rate debt(a)Interest, net$50 $(119)$(418)$(468)
_______
Derivatives in fair value hedging relationshipsLocationGain/(loss) recognized in income
 on derivative and related hedged item
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions)
Interest rate contractsInterest, net$(39)$(50)$(228)$409 
Hedged fixed rate debt(a)Interest, net$39 $50 $229 $(418)
(a)As of September 30, 2020,2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $777$473 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


21



Derivatives in cash flow hedging relationshipsDerivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)
LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)
LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Three Months Ended September 30,Three Months Ended September 30,Three Months Ended
September 30,
Three Months Ended
September 30,
20202019202020192021202020212020
(In millions)(In millions)(In millions)(In millions)
Energy commodity derivative contractsEnergy commodity derivative contracts$(143)$96 Revenues—Commodity sales$(47)$Energy commodity derivative contracts$(140)$(143)Revenues—Commodity sales$(94)$(47)
Costs of sales(7)
Costs of sales(7)(3)
Interest rate contractsInterest rate contracts(1)Earnings from equity investments(c)(1)Interest rate contracts— Earnings from equity investments(c)— (1)
Foreign currency contractsForeign currency contracts70 (69)Other, net61 (59)Foreign currency contracts(33)70 Other, net(34)61 
TotalTotal$(73)$26 Total$$(53)Total$(172)$(73)Total$(120)$

Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)
LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)(In millions)
Energy commodity derivative contracts$(29)$(74)Revenues—Commodity sales$(145)$15 
Costs of sales(12)
Interest rate contracts(9)(2)Earnings from equity investments(c)(1)
Foreign currency contracts17 (95)Other, net64 (71)
Total$(21)$(171)Total$(94)$(46)
_______
Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)
LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions)(In millions)
Energy commodity derivative contracts$(514)$(29)Revenues—Commodity sales$(167)$(145)
Costs of sales10 (12)
Interest rate contracts(9)Earnings from equity investments(c)— (1)
Foreign currency contracts(68)17 Other, net(79)64 
Total$(579)$(21)Total$(236)$(94)
(a)We expect to reclassify an approximate $68approximately $181 million gainof loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 20202021 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the nine months ended September 30, 2019,2021, we recognized a $12gains of $6 million gain associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).

Derivatives in net investment hedging relationshipsGain/(loss)
recognized in OCI on derivative
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Foreign currency contracts$$$$(8)
Total$$$$(8)


22



Derivatives not designated as hedging instrumentsLocationGain/(loss) recognized in income on derivatives
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$87 $12 $353 $36 
Costs of sales12 18 (3)
Earnings from equity investments(b)
Total(a)$99 $12 $371 $35 
_______
Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$(40)$87 $(703)$353 
Costs of sales(7)12 154 18 
Earnings from equity investments(2)— (4)— 
Total(a)$(49)$99 $(553)$371 
(a)The three and nine months ended September 30, 20202021 amounts include approximate gainslosses of $96$24 million and $349$480 million, respectively, and the three and nine months ended September 30, 20192020 amounts include an approximate lossgains of $4$96 million and $2$349 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.
(b)
22

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, 20202021 and December 31, 2019,2020, we had 0no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2020,2021, we had cash margins of $32$165 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets.sheet. As of December 31, 2019,2020, we had cash margins of $15$3 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets.sheet. The balance at September 30, 20202021 represents the net of our initial margin requirements of $24$30 million and counterparty variation margin requirements of $8$135 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

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

23



6.7. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
Three Months Ended September 30, 2020Three Months Ended September 30, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotalNatural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)(In millions)
Revenues from contracts with customers(a)Revenues from contracts with customers(a)Revenues from contracts with customers(a)
ServicesServicesServices
Firm services(b)Firm services(b)$818 $69 $185 $$(2)$1,071 Firm services(b)$836 $66 $181 $$(2)$1,082 
Fee-based servicesFee-based services173 228 91 503 Fee-based services190 244 93 10 — 537 
Total servicesTotal services991 297 276 1,574 Total services1,026 310 274 11 (2)1,619 
Commodity salesCommodity salesCommodity sales
Natural gas salesNatural gas sales507 (2)506 Natural gas sales1,097 — — (3)1,101 
Product salesProduct sales158 97 180 (5)435 Product sales372 247 279 (11)895 
Total commodity salesTotal commodity sales665 97 181 (7)941 Total commodity sales1,469 247 286 (14)1,996 
Total revenues from contracts with customersTotal revenues from contracts with customers1,656 394 281 190 (6)2,515 Total revenues from contracts with customers2,495 557 282 297 (16)3,615 
Other revenues(c)Other revenues(c)Other revenues(c)
Leasing services(d)Leasing services(d)119 42 143 13 317 Leasing services(d)119 42 140 15 — 316 
Derivatives adjustments on commodity salesDerivatives adjustments on commodity sales(6)46 40 Derivatives adjustments on commodity sales(71)— — (63)— (134)
OtherOther40 (1)47 Other12 — 27 
Total Other revenues153 48 143 61 (1)404 
Total other revenuesTotal other revenues60 48 140 (40)209 
Total revenuesTotal revenues$1,809 $442 $424 $251 $(7)$2,919 Total revenues$2,555 $605 $422 $257 $(15)$3,824 
23



Three Months Ended September 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$818 $69 $185 $$(2)$1,071 
Fee-based services173 228 91 503 
Total services991 297 276 1,574 
Commodity sales
Natural gas sales507 — — (2)506 
Product sales158 97 180 (5)435 
Total commodity sales665 97 181 (7)941 
Total revenues from contracts with customers1,656 394 281 190 (6)2,515 
Other revenues(c)
Leasing services(d)119 42 143 13 — 317 
Derivatives adjustments on commodity sales(6)— — 46 — 40 
Other40 — (1)47 
Total other revenues153 48 143 61 (1)404 
Total revenues$1,809 $442 $424 $251 $(7)$2,919 
Nine Months Ended September 30, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$2,501 $191 $570 $$(2)$3,261 
Fee-based services544 709 258 35 — 1,546 
Total services3,045 900 828 36 (2)4,807 
Commodity sales
Natural gas sales5,090 — — (11)5,088 
Product sales840 529 20 766 (34)2,121 
Total commodity sales5,930 529 20 775 (45)7,209 
Total revenues from contracts with customers8,975 1,429 848 811 (47)12,016 
Other revenues(c)
Leasing services(d)356 128 427 42 — 953 
Derivatives adjustments on commodity sales(726)(1)— (143)— (870)
Other51 16 — 19 — 86 
Total other revenues(319)143 427 (82)— 169 
Total revenues$8,656 $1,572 $1,275 $729 $(47)$12,185 

24




Three Months Ended September 30, 2019Nine Months Ended September 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotalNatural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)(In millions)
Revenues from contracts with customers(a)Revenues from contracts with customers(a)Revenues from contracts with customers(a)
ServicesServicesServices
Firm services(b)Firm services(b)$882 $89 $256 $$(1)$1,227 Firm services(b)$2,479 $215 $563 $$(2)$3,256 
Fee-based servicesFee-based services182 265 132 14 593 Fee-based services523 670 307 31 1,532 
Total servicesTotal services1,064 354 388 15 (1)1,820 Total services3,002 885��870 32 (1)4,788 
Commodity salesCommodity salesCommodity sales
Natural gas salesNatural gas sales618 (1)617 Natural gas sales1,385 — — (5)1,381 
Product salesProduct sales162 84 268 (7)516 Product sales396 255 11 546 (22)1,186 
Total commodity salesTotal commodity sales780 84 268 (8)1,133 Total commodity sales1,781 255 11 547 (27)2,567 
Total revenues from contracts with customersTotal revenues from contracts with customers1,844 438 397 283 (9)2,953 Total revenues from contracts with customers4,783 1,140 881 579 (28)7,355 
Other revenues(c)Other revenues(c)Other revenues(c)
Leasing services(d)Leasing services(d)57 45 111 13 226 Leasing services(d)346 126 404 34 — 910 
Derivatives adjustments on commodity salesDerivatives adjustments on commodity sales23 (1)(1)21 Derivatives adjustments on commodity sales35 — — 173 — 208 
OtherOther10 14 Other91 16 — (1)112 
Total Other revenues90 46 111 15 (1)261 
Total other revenuesTotal other revenues472 142 404 213 (1)1,230 
Total revenuesTotal revenues$1,934 $484 $508 $298 $(10)$3,214 Total revenues$5,255 $1,282 $1,285 $792 $(29)$8,585 

Nine Months Ended September 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$2,479 $215 $563 $$(2)$3,256 
Fee-based services523 670 307 31 1,532 
Total services3,002 885 870 32 (1)4,788 
Commodity sales
Natural gas sales1,385 (5)1,381 
Product sales396 255 11 546 (22)1,186 
Total commodity sales1,781 255 11 547 (27)2,567 
Total revenues from contracts with customers4,783 1,140 881 579 (28)7,355 
Other revenues(c)
Leasing services346 126 404 34 910 
Derivatives adjustments on commodity sales35 173 208 
Other91 16 (1)112 
Total Other revenues472 142 404 213 (1)1,230 
Total revenues$5,255 $1,282 $1,285 $792 $(29)$8,585 

25



Nine Months Ended September 30, 2019
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$2,701 $253 $785 $$(3)$3,737 
Fee-based services561 752 398 45 1,756 
Total services3,262 1,005 1,183 46 (3)5,493 
Commodity sales
Natural gas sales1,979 (7)1,973 
Product sales599 211 16 827 (23)1,630 
Total commodity sales2,578 211 16 828 (30)3,603 
Total revenues from contracts with customers5,840 1,216 1,199 874 (33)9,096 
Other revenues(c)
Leasing services167 129 325 39 660 
Derivatives adjustments on commodity sales61 (10)51 
Other35 10 50 
Total Other revenues263 134 325 39 761 
Total revenues$6,103 $1,350 $1,524 $913 $(33)$9,857 
_______
(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
(c)For the three and nine months ended September 30, 2020 and 2019, amountsAmounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 56 for additional information related to our derivative contracts.

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

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

As of September 30, 20202021 and December 31, 2019,2020, our contract asset balances were $44$62 million and $27$20 million, respectively. Of the contract asset balance at December 31, 2019, $212020, $14 million was transferred to accounts receivable during the nine months ended September 30, 2020.2021. As of September 30, 20202021 and December 31, 2019,2020, our contract liability balances were $237$217 million and $232$239 million, respectively. Of the contract liability balance at December 31, 2019, $572020, $63 million was recognized as revenue during the nine months ended September 30, 2020.2021.

2625




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, 20202021 that we will invoice or transfer from contract liabilities and recognize in future periods:
YearYearEstimated RevenueYearEstimated Revenue
(In millions)(In millions)
Three months ended December 31, 2020$1,152 
20214,102 
Three months ended December 31, 2021Three months ended December 31, 2021$1,178 
202220223,344 20224,022 
202320232,715 20233,186 
202420242,361 20242,711 
202520252,277 
ThereafterThereafter14,722 Thereafter14,018 
TotalTotal$28,396 Total$27,392 

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

7.8.  Reportable Segments

Financial information by segment follows:
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended
September 30,
Nine Months Ended
September 30,
20202019202020192021202020212020
(In millions)(In millions)
RevenuesRevenuesRevenues
Natural Gas PipelinesNatural Gas PipelinesNatural Gas Pipelines
Revenues from external customersRevenues from external customers$1,803 $1,925 $5,229 $6,073 Revenues from external customers$2,541 $1,803 $8,611 $5,229 
Intersegment revenuesIntersegment revenues26 30 Intersegment revenues14 45 26 
Products PipelinesProducts Pipelines442 484 1,282 1,350 Products Pipelines605 442 1,572 1,282 
TerminalsTerminalsTerminals
Revenues from external customersRevenues from external customers423 507 1,282 1,521 Revenues from external customers421 423 1,273 1,282 
Intersegment revenuesIntersegment revenuesIntersegment revenues
CO2
CO2
251 298 792 913 
CO2
257 251 729 792 
Corporate and intersegment eliminationsCorporate and intersegment eliminations(7)(10)(29)(33)Corporate and intersegment eliminations(15)(7)(47)(29)
Total consolidated revenuesTotal consolidated revenues$2,919 $3,214 $8,585 $9,857 Total consolidated revenues$3,824 $2,919 $12,185 $8,585 
2726



Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended
September 30,
Nine Months Ended
September 30,
20202019202020192021202020212020
(In millions)(In millions)
Segment EBDA(a)Segment EBDA(a)  Segment EBDA(a)
Natural Gas PipelinesNatural Gas Pipelines$1,091 $1,092 $2,284 $3,383 Natural Gas Pipelines$1,069 $1,091 $2,602 $2,284 
Products PipelinesProducts Pipelines223 325 719 908 Products Pipelines279 223 792 719 
TerminalsTerminals246 295 732 884 Terminals216 246 689 732 
CO2
CO2
156 164 (453)558 
CO2
163 156 599 (453)
Kinder Morgan Canada(2)
Total Segment EBDATotal Segment EBDA1,716 1,876 3,282 5,731 Total Segment EBDA1,727 1,716 4,682 3,282 
DD&ADD&A(539)(578)(1,636)(1,750)DD&A(526)(539)(1,595)(1,636)
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments(32)(21)(99)(61)Amortization of excess cost of equity investments(21)(32)(56)(99)
General and administrative and corporate chargesGeneral and administrative and corporate charges(150)(162)(472)(478)General and administrative and corporate charges(167)(150)(465)(472)
Interest, netInterest, net(383)(447)(1,214)(1,359)Interest, net(368)(383)(1,122)(1,214)
Income tax expenseIncome tax expense(140)(151)(304)(471)Income tax expense(134)(140)(248)(304)
Total consolidated net income (loss)Total consolidated net income (loss)$472 $517 $(443)$1,612 Total consolidated net income (loss)$511 $472 $1,196 $(443)
September 30, 2020December 31, 2019
(In millions)
Assets
Natural Gas Pipelines$48,522 $50,310 
Products Pipelines9,216 9,468 
Terminals8,808 8,890 
CO2
2,589 3,523 
Corporate assets(b)2,686 1,966 
Total consolidated assets$71,821 $74,157 
_______
September 30, 2021December 31, 2020
(In millions)
Assets
Natural Gas Pipelines$47,576 $48,597 
Products Pipelines9,118 9,182 
Terminals8,507 8,639 
CO2
2,808 2,478 
Corporate assets(b)1,631 3,077 
Total consolidated assets$69,640 $71,973 
(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other (income) expense,income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

8.9.  Income Taxes

Income tax expense included in our accompanying consolidated statements of operations is as follows:
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended
September 30,
Nine Months Ended
September 30,
20202019202020192021202020212020
(In millions, except percentages)(In millions, except percentages)
Income tax expenseIncome tax expense$140 $151 $304 $471 Income tax expense$134 $140 $248 $304 
Effective tax rateEffective tax rate22.9 %22.6 %(218.7)%22.6 %Effective tax rate20.8 %22.9 %17.2 %(218.7)%
The effective tax rate for the three months ended September 30, 2021 is slightly lower than the statutory federal rate of 21% primarily due to dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

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

The effective tax rate for the nine months ended September 30, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus, NGPL Holdings and PPL, partially offset by state income taxes.
27



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

While we would normally expect a federal income tax benefit from our loss before income taxes for the nine months ended September 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period, partially offset by the refund of alternative minimum tax
28


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

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

9.10.   Litigation and Environmental

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

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

On March 21, 2019,The FERC approved the FERC issued a notice of inquiry (NOI) seeking comments regarding whetherSFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the FERC should revise its policies for determiningSFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the base returnEL Settlement were fully accrued on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI sought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC. On May 21, 2020, the FERC issued its Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines (Policy Statement). As it applies to natural gas and oil pipelines, the Policy Statement requires averaging the results of the discounted cash flow model and capital asset pricing model, giving equal weight to each model, retains its existing two-thirds/one-third weighting of short and long-term growth projections in the discounted cash flow model, and excludes the risk premium or expected earnings models. On other matters raised in this proceeding, the FERC declined to adopt rigid policy changes, and will address issues, such as the appropriate sources for data sets and the specific companies to use for a given proxy group, as those issues arise in future rate proceedings on a pipeline-by-pipeline, case-by-case basis. The Policy Statement does not result in any immediate changes to any existing rates or ROEs for any of our pipelines, and any future changes to rates or ROEs for a pipeline will depend on a variety of factors that remain to be determined when they are raised and argued in connection with future or existing rate proceedings, including the OR16-6 proceeding referenced in “SFPP FERC Proceedings” below.

SFPP FERC Proceedingsbefore December 31, 2020.

The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. These include IS08-390, filed in June 2008, in which various shippers are challenging SFPP’s West Line rates (pending before the D.C. Circuit Court on rehearing following an order that upheld the FERC’s underlying decision); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (pending before the FERC on rehearing); OR11-13/16/18, filed in June 2011, in which various shippers are seeking to challenge SFPP’s North Line, Oregon Line, and West Line rates (pending before the FERC for an order on the complaint); OR14-35/36, filed in June 2014, in which various shippers are challenging SFPP’s index increases in 2012 and 2013 (dismissed by the FERC, but remanded back to the FERC from the D.C. Circuit for further consideration); OR16-6, filed in December 2015, in which various shippers are challenging SFPP’s East line rates (the FERC issued Order 571 which largely confirmed the initial decision, but granted SFPP’s motion to reopen the record and allowed the parties to file written submissions addressing the FERC’s Policy Statement on ROE for purposes of establishing SFPP’s ROE in this matter); and OR19-21/33/37, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 (pending before the FERC for an order on the complaints). In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two yeartwo-year period preceding the filing date of their complaints (OR cases) and/or prospective refunds in protest cases from the
29


date of protest, (IS cases), and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings at the FERC that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million in rate refunds and unspecified rate reductions as of the date of their complaints in 2014 and 2018. The claims pleaded by the shippers are expected to change due to the passage of time and interest. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.

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

EPNG FERC Proceedings

The tariffs and rates charged by EPNG are subject to 2 ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it would apply its findings in Opinion 517-A to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A)ongoing proceedings will have a material adverse impact on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC the refund calculations, and that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. EPNG’s appeals in the 2008 and 2010 rate cases as well as the intervenors’ appeal in the 2010 rate case were consolidated. The U.S. Court of Appeals for the D.C. Circuit denied all petitions for review on July 24, 2020.our business.

Gulf LNG Facility Disputes

On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy.  Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement.  On June 29, 2018, the arbitration paneltribunal delivered itsan Award and the panel's rulingthat called for the termination of the agreement and Eni USA'sUSA’s payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash
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impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

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

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By itsEni USA’s second Notice of Arbitration, Eni USA seeksarbitration sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response, to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the second arbitration. On January 10, 2020, the Court of Chancery enteredcross-appeals from an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denyingCourt of Chancery, the motion to enjoinDelaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from pursuing the second arbitration, ofincluding the breach of contract claims. The parties filed cross appeals ofand negligent misrepresentation claims therein. On October 4, 2021, the Final Judgment. The Delaware cross appeals were argued to the DelawareU.S. Supreme Court on September 9, 2020. Thedenied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration proceeding remains pending, but has been stayed by agreement pendingand the Delaware Supreme Court’s decision.
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claims asserted therein.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A., filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also seekssought a declaration on substantially the same allegations asserted previously by Eni USA in arbitration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have givengave rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seekssought a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in thisOn July 15, 2021, the arbitration is expected bytribunal delivered a Final Award on the endmerits of all claims submitted to the second quarter of 2021.

GLNG intends to continue to vigorously prosecutetribunal and defenddenied all of the foregoing proceedings.ALSS’s claims with prejudice.

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

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties).  CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225$276 million. Hiland Partners denies and will vigorously defend against these claims.

Freeport LNG Winter Storm Litigation

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

Pipeline Integrity and Releases

From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with
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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, 20202021 and December 31, 2019,2020, our total reserve for legal matters was $280$192 million and $203$273 million, respectively.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal,local, state and localfederal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.

We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act.regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater
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and soil remediation efforts under state or federal administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the remediation.remediation efforts.

In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas or CO2.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated by the EPA to be approximately $1.1more than $3 billion and active cleanup is expected to take as long as 13more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of 2 facilities acquired from GATX Terminals Corporation)facilities) and KMBT (in connection with its ownership or operation of 2 facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around October 2023. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.

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Uranium Mines in Vicinity of Cameron, Arizona

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

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

EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI,(collectively EPEC) are involvedidentified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged thatRiver in New Jersey. EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are alsoEPEC is part of a joint defense group of approximately 44 cooperating parties referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
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On March 4, 2016, the EPA issued itsa Record of Decision (ROD) for the lower 8 miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower 8 miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins.

In addition, the EPA and numerous PRPs, including EPEC, Polymers, are engaged in an allocation process for the implementation of the remedy for the lower 8 miles of the Site. We anticipate thatThat process will bewas completed by December 31, 2020.28, 2020 and certain PRPs, including EPEC, are engaged in discussions with the EPA as a result thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper 9 miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There is alsoremains significant uncertainty as to the impactimplementation and associated costs of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sedimentsset forth in the upper nine miles of the Site.mile ROD. Until the allocation process and FS are completed, andongoing discussions with the RI/FS is finalized,EPA conclude, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the Site, will have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

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

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the U.S. District Court ordered the case wasto be remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals.The defendants appealed that decision. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing whichrehearing. On August 5, 2021, the Fifth Circuit remanded the case to the U.S. District Court to
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determine whether there is pending.federal officer jurisdiction. The case remains effectively stayed pending a final ruling by the U.S. District Court of Appeals.on the federal officer issue. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

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

Louisiana Landowner Coastal Erosion Litigation

Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including 24 cases against TGP, 23 cases against SNG, and 2 cases1 case against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The plaintiffsPlaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees,
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interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The plaintiffsPlaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. One of these cases filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana. On May 4, 2018, the U.S. District Court entered a judgment ruling in favor of the plaintiffs on certain of their contract claims. The Court stayed the judgment pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. In October 2018, the Court of Appeals dismissed the appeals for lack of subject matter jurisdiction. In April 2019, the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. On October 2, 2020, the case was settled for an amount which is not material to our business. We will continue to vigorously defend the remaining cases.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of September 30, 20202021 and December 31, 2019,2020, we have accrued a total reserve for environmental liabilities in the amount of $253$242 million and $259$250 million, respectively. In addition, as of both September 30, 20202021 and December 31, 2019,2020, we have recordedhad a receivable of $12 million and $15 million, respectively,recorded for expected cost recoveries that have been deemed probable.

10.11. Recent Accounting Pronouncements

ASU No. 2018-14

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

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

On March 12, 2020, the FASB issued ASUAccounting Standards Update (ASU) No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate. Entities can elect not to apply certain modification accounting requirements to contracts affected by this reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.

On January 7, 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.

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The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of this ASUTopic 848 to our financial statements.

ASU No. 2020-06

On August 5, 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features,features; (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted methodmethod; and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year ending December 31,beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2021-05

On July 19, 2021, the FASB issued ASU No. 2021-05, “Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments.” This ASU requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or rate as an operating lease if another classification (i.e. sales-type or direct financing) would trigger a day-one loss. ASU No. 2021-05 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

General and Basis of Presentation

The following discussion and analysis should be read in conjunction with our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes andin our 2020 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 20192020 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2020 Form 10-K; and (iv) “Risk Factors” in our 2020 Form 10-K.

SaleLong-lived Asset Impairment

During the second quarter 2021 we recognized a non-cash, long-lived asset impairment of U.S. Portion$1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipeline business segment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of Cochin Pipeline and KMLcontracts expiring through 2024.

Stagecoach Acquisition

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

COVID-19

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

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

We have placedSale of an Interest in NGPL Holdings LLC

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a priority on protecting our employees during this pandemic while continuing to provide essential services to our customers. We continue to follow the Centers for Disease Control guidelines for those employees that perform essential taskscombined 25% interest in our operations and have takenjoint venture, NGPL Holdings LLC (NGPL Holdings), to a cautious enterprise-wide approach with a phased return to workplace processfund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our employees who are currently working remotely. Duringproportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the nine months ended September 30, 2020, our incremental employee safety costs associated with COVID-19 mitigation have been approximately $11 million, primarily for personal protective equipment, enhanced cleaning protocols, temperature screening2021. We and other measures we adopted to protect our employees. We continue to operate our assets safely and efficiently during this challenging period.Brookfield now each hold a 37.5% interest in NGPL Holdings.

2020 OutlookFebruary 2021 Winter Storm

As previously announced, for 2020Our year-to-date earnings reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below. Some of the transactions executed during the winter storm remain subject to risks, including counterparty financial risk, potential disputed purchases and sales and potential legislative or regulatory action in response to, or litigation arising out of, the unprecedented circumstances of the winter storm, which could adversely affect our original budget contemplated DCF of approximately $5.1 billion ($2.24 per common share)future earnings, cash flows and Adjusted EBITDA of approximately $7.6 billion. We now expect DCF to be below plan by slightly more than 10% and Adjusted EBITDA to be below plan by slightly more than 8%. As a result, we now expect to end 2020 with a Net Debt-to-Adjusted EBITDA ratio of approximately 4.6 times.financial condition.

Market conditions also negatively impacted2021 Dividends and Discretionary Capital

We expect to declare dividends of $1.08 per share for 2021, a number3% increase from the 2020 declared dividends of planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. We therefore$1.05 per share. Excluding the recent acquisitions, we expect the budgeted $2.4to invest $0.8 billion in expansion projects and contributions to joint ventures for 2020 to be lower by approximately $680 million. With this reduction, DCF less expansion capital expenditures is improved by approximately $135 million compared to budget, helping to keep our balance sheet strong. In addition, to help preserve flexibility and maintain balance sheet strength, our board of directors has maintained the dividend level and declared a dividend of $0.2625 per share, or $1.05 per share annualized, for the third quarter of 2020. This represents a 5% increase over the dividend declared for the third quarter of 2019 rather than the previously budgeted dividend of $0.3125,during 2021.

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

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

Considerable uncertainty exists with respect to the future pace and extent of a global economic recovery from the effects of the COVID-19 pandemic. Our updatedThe expectations for 20202021 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statements. Please read Part II, Item 1A. “Risk Factorsbelow and “Information Regarding Forward-Looking Statementsat the beginning of this report for more information. Furthermore, we disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.statement.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 7,8, “Reportable Segments”), net income (loss) and netNet income (loss) attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA Net Debt and Net Debt to Adjusted EBITDA.Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the three and nine months ended September 30, 20202021 and 20192020 present Segment EBDA net income (loss) and netNet income (loss) attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures

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

Certain Items

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

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Adjusted Earnings

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

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DCF

DCF is calculated by adjusting netNet income (loss) attributable to Kinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is netNet income (loss) attributable to Kinder Morgan, Inc. DCF per common share is DCF divided by average outstanding common shares, including restricted stock awards that participate in common share dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” and “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate segment cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is netNet income (loss). attributable to Kinder Morgan, Inc. In prior periods Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” below.

Amounts from Joint Ventures

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

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

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Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.
Three Months Ended September 30,Three Months Ended
September 30,
20202019Earnings
increase/(decrease)
20212020Earnings
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Segment EBDA(a)Segment EBDA(a)Segment EBDA(a)
Natural Gas PipelinesNatural Gas Pipelines$1,091 $1,092 $(1)— %Natural Gas Pipelines$1,069 $1,091 $(22)(2)%
Products PipelinesProducts Pipelines223 325 (102)(31)%Products Pipelines279 223 56 25 %
TerminalsTerminals246 295 (49)(17)%Terminals216 246 (30)(12)%
CO2
CO2
156 164 (8)(5)%
CO2
163 156 %
Total Segment EBDATotal Segment EBDA1,716 1,876 (160)(9)%Total Segment EBDA1,727 1,716 11 %
DD&ADD&A(539)(578)39 %DD&A(526)(539)13 %
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments(32)(21)(11)(52)%Amortization of excess cost of equity investments(21)(32)11 34 %
General and administrative and corporate chargesGeneral and administrative and corporate charges(150)(162)12 %General and administrative and corporate charges(167)(150)(17)(11)%
Interest, netInterest, net(383)(447)64 14 %Interest, net(368)(383)15 %
Income before income taxesIncome before income taxes612 668 (56)(8)%Income before income taxes645 612 33 %
Income tax expenseIncome tax expense(140)(151)11 %Income tax expense(134)(140)%
Net incomeNet income472 517 (45)(9)%Net income511 472 39 %
Net income attributable to noncontrolling interestsNet income attributable to noncontrolling interests(17)(11)(6)(55)%Net income attributable to noncontrolling interests(16)(17)%
Net income attributable to Kinder Morgan, Inc.Net income attributable to Kinder Morgan, Inc.$455 $506 $(51)(10)%Net income attributable to Kinder Morgan, Inc.$495 $455 $40 %

Nine Months Ended September 30,
20202019Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$2,284 $3,383 $(1,099)(32)%
Products Pipelines719 908 (189)(21)%
Terminals732 884 (152)(17)%
CO2
(453)558 (1,011)(181)%
Kinder Morgan Canada— (2)100 %
Total Segment EBDA3,282 5,731 (2,449)(43)%
DD&A(1,636)(1,750)114 %
Amortization of excess cost of equity investments(99)(61)(38)(62)%
General and administrative and corporate charges(472)(478)%
Interest, net(1,214)(1,359)145 11 %
(Loss) income before income taxes(139)2,083 (2,222)(107)%
Income tax expense(304)(471)167 35 %
Net (loss) income(443)1,612 (2,055)(127)%
Net income attributable to noncontrolling interests(45)(32)(13)(41)%
Net (loss) income attributable to Kinder Morgan, Inc.$(488)$1,580 $(2,068)(131)%
_______
Nine Months Ended September 30,
20212020Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$2,602 $2,284 $318 14 %
Products Pipelines792 719 73 10 %
Terminals689 732 (43)(6)%
CO2
599 (453)1,052 232 %
Total Segment EBDA4,682 3,282 1,400 43 %
DD&A(1,595)(1,636)41 %
Amortization of excess cost of equity investments(56)(99)43 43 %
General and administrative and corporate charges(465)(472)%
Interest, net(1,122)(1,214)92 %
Income (loss) before income taxes1,444 (139)1,583 1,139 %
Income tax expense(248)(304)56 18 %
Net income (loss)1,196 (443)1,639 370 %
Net income attributable to noncontrolling interests(49)(45)(4)(9)%
Net income (loss) attributable to Kinder Morgan, Inc.$1,147 $(488)$1,635 335 %
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other (income) expense,income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

39
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Income (loss) beforeNet income taxes decreased $56attributable to Kinder Morgan, Inc. increased $40 million and $2,222$1,635 million for the three and nine months ended September 30, 2020,2021, respectively, as compared to the respective prior year periods. The decreasesthird quarter increase in results were impacted by lowerhigher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals in the comparative three-month periods and from all of ourNatural Gas Pipelines business segments in the comparative nine-month periodsand higher general and administrative and corporate charges expense. The year-to-date increase was primarily attributable to COVID-19-related reduced energy demand and commodity price impacts and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 onimpacted by higher earnings from our Natural Gas Pipelines and TerminalsCO2 business segments partially offset byprimarily related to the benefitFebruary 2021 winter storm and therefore largely nonrecurring, and a decrease of completed expansion projects$362 million of impairments in 2021 as compared to 2020 primarily reflecting the $1,600 million pre-tax non-cash asset impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipelines businessPipeline segment and by lower interest expense and DD&A expense. The year-to-date decrease also included ain 2021 compared to the combined $1.95 billion$1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO2 business segment. The impacts of the long-lived asset impairments for both periods were partially offset by associated tax benefits. The year-to-date increase was also impacted by higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals business segment.

Certain Items Affecting Consolidated Earnings Results
Three Months Ended September 30,Three Months Ended September 30,
2020201920212020
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earningsGAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)(In millions)
Segment EBDASegment EBDASegment EBDA
Natural Gas PipelinesNatural Gas Pipelines$1,091 $(9)$1,082 $1,092 $(2)$1,090 $(8)Natural Gas Pipelines$1,069 $21 $1,090 $1,091 $(9)$1,082 $
Products PipelinesProducts Pipelines223 46 269 325 11 336 (67)Products Pipelines279 280 223 46 269 11 
TerminalsTerminals246 — 246 295 — 295 (49)Terminals216 17 233 246 — 246 (13)
CO2
CO2
156 (2)154 164 (15)149 
CO2
163 (9)154 156 (2)154 — 
Total Segment EBDA(a)Total Segment EBDA(a)1,716 35 1,751 1,876 (6)1,870 (119)Total Segment EBDA(a)1,727 30 1,757 1,716 35 1,751 
DD&A and amortization of excess cost of equity investmentsDD&A and amortization of excess cost of equity investments(571)— (571)(599)— (599)28 DD&A and amortization of excess cost of equity investments(547)— (547)(571)— (571)24 
General and administrative and corporate charges(a)General and administrative and corporate charges(a)(150)11 (139)(162)(157)18 General and administrative and corporate charges(a)(167)— (167)(150)11 (139)(28)
Interest, net(a)Interest, net(a)(383)(8)(391)(447)(5)(452)61 Interest, net(a)(368)(8)(376)(383)(8)(391)15 
Income before income taxesIncome before income taxes612 38 650 668 (6)662 (12)Income before income taxes645 22 667 612 38 650 17 
Income tax expense(b)Income tax expense(b)(140)(8)(148)(151)(143)(5)Income tax expense(b)(134)(12)(146)(140)(8)(148)
Net incomeNet income472 30 502 517 519 (17)Net income511 10 521 472 30 502 19 
Net income attributable to noncontrolling interests(a)Net income attributable to noncontrolling interests(a)(17)— (17)(11)— (11)(6)Net income attributable to noncontrolling interests(a)(16)— (16)(17)— (17)
Net income attributable to Kinder Morgan, Inc.Net income attributable to Kinder Morgan, Inc.$455 $30 $485 $506 $$508 $(23)Net income attributable to Kinder Morgan, Inc.$495 $10 $505 $455 $30 $485 $20 

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Nine Months Ended September 30,
20202019
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts
increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$2,284 $993 $3,277 $3,383 $(21)$3,362 $(85)
Products Pipelines719 50 769 908 28 936 (167)
Terminals732 — 732 884 — 884 (152)
CO2
(453)938 485 558 (36)522 (37)
Kinder Morgan Canada— — — (2)— — 
Total Segment EBDA(a)3,282 1,981 5,263 5,731 (27)5,704 (441)
DD&A and amortization of excess cost of equity investments(1,735)— (1,735)(1,811)— (1,811)76 
General and administrative and corporate charges(a)(472)36 (436)(478)11 (467)31 
Interest, net(a)(1,214)(8)(1,222)(1,359)(6)(1,365)143 
(Loss) income before income taxes(139)2,009 1,870 2,083 (22)2,061 (191)
Income tax expense(b)(304)(114)(418)(471)15 (456)38 
Net (loss) income(443)1,895 1,452 1,612 (7)1,605 (153)
Net income attributable to noncontrolling interests(a)(45)— (45)(32)(1)(33)(12)
Net (loss) income attributable to Kinder Morgan, Inc.$(488)$1,895 $1,407 $1,580 $(8)$1,572 $(165)
_______
Nine Months Ended September 30,
20212020
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$2,602 $1,646 $4,248 $2,284 $993 $3,277 $971 
Products Pipelines792 44 836 719 50 769 67 
Terminals689 17 706 732 — 732 (26)
CO2
599 (3)596 (453)938 485 111 
Total Segment EBDA(a)4,682 1,704 6,386 3,282 1,981 5,263 1,123 
DD&A and amortization of excess cost of equity investments(1,651)— (1,651)(1,735)— (1,735)84 
General and administrative and corporate charges(a)(465)— (465)(472)36 (436)(29)
Interest, net(a)(1,122)(17)(1,139)(1,214)(8)(1,222)83 
Income (loss) before income taxes1,444 1,687 3,131 (139)2,009 1,870 1,261 
Income tax expense(b)(248)(439)(687)(304)(114)(418)(269)
Net income (loss)1,196 1,248 2,444 (443)1,895 1,452 992 
Net income attributable to noncontrolling interests(a)(49)— (49)(45)— (45)(4)
Net income (loss) attributable to Kinder Morgan, Inc.$1,147 $1,248 $2,395 $(488)$1,895 $1,407 $988 
(a)For a more detailed discussion of Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(b)The combined net effect of the income tax Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

Net income (loss) attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) decreasedincreased by $23$20 million and $165$988 million for the three and nine months ended September 30, 2020,2021, respectively, as compared to the respective prior year periods. Decreases in Adjusted Segment EBDA from the priorThe third quarter and year-to-date periods wereincrease was primarily due to lowerhigher earnings from our Products Pipelines Terminals and Natural Gas Pipelines business segments primarily attributable to COVID-19-related reduced energy demand and commodity price impacts discussed abovelower DD&A expense (including amortization of excess cost of equity investments) and the impact of the KMLinterest expense partially offset by higher general and U.S. Cochin Sale in the fourth quarter of 2019 onadministrative and corporate charges expense and lower earnings from our Terminals business segment. The year-to-date increase was impacted by higher earnings from our Natural Gas Pipelines and TerminalsCO2 business segments primarily related to the February 2021 winter storm, and therefore largely nonrecurring, higher earnings from our Products Pipelines business segment and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by the benefit of completed expansion projects inhigher general and administrative and corporate charges expense and lower earnings from our Natural Gas PipelinesTerminals business segment.

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Non-GAAP Financial Measures

Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended
September 30,
Nine Months Ended September 30,
20202019202020192021202020212020
(In millions)(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)$455 $506 $(488)$1,580 Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)$495 $455 $1,147 $(488)
Total Certain ItemsTotal Certain Items30 1,895 (8)Total Certain Items10 30 1,248 1,895 
Adjusted Earnings(a)Adjusted Earnings(a)485 508 1,407 1,572 Adjusted Earnings(a)505 485 2,395 1,407 
DD&A and amortization of excess cost of equity investments for DCF(b)DD&A and amortization of excess cost of equity investments for DCF(b)662 694 2,012 2,093 DD&A and amortization of excess cost of equity investments for DCF(b)612 662 1,854 2,012 
Income tax expense for DCF(a)(b)Income tax expense for DCF(a)(b)171 164 484 521 Income tax expense for DCF(a)(b)165 171 754 484 
Cash taxes(c)(b)Cash taxes(c)(b)(49)(12)(57)(76)Cash taxes(c)(b)(12)(49)(56)(57)
Sustaining capital expenditures(c)(b)Sustaining capital expenditures(c)(b)(177)(173)(477)(477)Sustaining capital expenditures(c)(b)(241)(177)(558)(477)
Other items(d)(c)Other items(d)(c)(7)(41)(22)Other items(d)(c)(16)(7)(22)(22)
DCFDCF$1,085 $1,140 $3,347 $3,639 DCF$1,013 $1,085 $4,367 $3,347 

Adjusted Segment EBDA to Adjusted EBITDA to DCF
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except per share amounts)
Natural Gas Pipelines$1,082 $1,090 $3,277 $3,362 
Products Pipelines269 336 769 936 
Terminals246 295 732 884 
CO2
154 149 485 522 
Adjusted Segment EBDA(a)1,751 1,870 5,263 5,704 
General and administrative and corporate charges(a)(139)(157)(436)(467)
Joint venture DD&A and income tax expense(a)(e)114 123 343 368 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)(17)(2)(45)(7)
Adjusted EBITDA1,709 1,834 5,125 5,598 
Interest, net(a)(391)(452)(1,222)(1,365)
Cash taxes(c)(49)(12)(57)(76)
Sustaining capital expenditures(c)(177)(173)(477)(477)
KML noncontrolling interests DCF adjustments(f)— (16)— (47)
Other items(d)(7)(41)(22)
DCF$1,085 $1,140 $3,347 $3,639 
Adjusted Earnings per common share$0.21 $0.22 $0.62 $0.69 
Weighted average common shares outstanding for dividends(g)2,276 2,277 2,276 2,276 
DCF per common share$0.48 $0.50 $1.47 $1.60 
Declared dividends per common share$0.2625 $0.25 $0.7875 $0.75 
_______
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions, except per share amounts)
Natural Gas Pipelines$1,090 $1,082 $4,248 $3,277 
Products Pipelines280 269 836 769 
Terminals233 246 706 732 
CO2
154 154 596 485 
Adjusted Segment EBDA(a)1,757 1,751 6,386 5,263 
General and administrative and corporate charges(a)(167)(139)(465)(436)
Joint venture DD&A and income tax expense(a)(b)84 114 270 343 
Net income attributable to noncontrolling interests(a)(16)(17)(49)(45)
Adjusted EBITDA1,658 1,709 6,142 5,125 
Interest, net(a)(376)(391)(1,139)(1,222)
Cash taxes(b)(12)(49)(56)(57)
Sustaining capital expenditures(b)(241)(177)(558)(477)
Other items(c)(16)(7)(22)(22)
DCF$1,013 $1,085 $4,367 $3,347 
Adjusted Earnings per share$0.22 $0.21 $1.05 $0.62 
Weighted average shares outstanding for dividends(d)2,279 2,276 2,278 2,276 
DCF per share$0.44 $0.48 $1.92 $1.47 
Declared dividends per share$0.27 $0.2625 $0.81 $0.7875 
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.
(b)Includes or represents DD&A, or income tax expense, ascash taxes and/or sustaining capital expenditures (as applicable for each item) from unconsolidated joint ventures, reduced by consolidated joint venture partners’ DD&A. 2019 amounts are also net of DD&A or income tax expense attributable to KML noncontrolling interests.ventures. See tables included in “—Supplemental Information” below.
(c)Includes cash taxes or sustaining capital expenditures, as applicable, from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “—Supplemental Information” below.
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(d)Includespension contributions, non-cash pension expense and non-cash compensation associated with our restricted stock program.
(e)Represents unconsolidated joint venture DD&A and income tax expense, reduced by consolidated joint venture partners’ DD&A. See tables included in “—Supplemental Information” below.
(f)2019 amounts represent the combined net income, DD&A and income tax expense adjusted for Certain Items, as applicable, attributable to KML noncontrolling interests. See table included in “—Supplemental Information” below.
(g)(d)Includes restricted stock awards that participate in common share dividends.
40


Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Net income (loss) (GAAP)$472 $517 $(443)$1,612 
Certain Items:
Fair value amortization(5)(7)(17)(22)
Legal, environmental and taxes other than income tax reserves46 11 38 28 
Change in fair value of derivative contracts(a)(6)(14)(10)(22)
Loss (gain) on impairments and divestitures, net(b)11 — 382 (5)
Loss on impairment of goodwill(c)— — 1,600 — 
COVID-19 costs11 — 11 — 
Income tax Certain Items(8)(114)15 
Noncontrolling interests associated with Certain Items— — — (1)
Other(19)(1)
Total Certain Items(d)30 1,895 (8)
DD&A and amortization of excess cost of equity investments571 599 1,735 1,811 
Income tax expense(e)148 143 418 456 
Joint venture DD&A and income tax expense(e)(f)114 123 343 368 
Interest, net(e)391 452 1,222 1,365 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(e))(17)(2)(45)(6)
Adjusted EBITDA$1,709 $1,834 $5,125 $5,598 
______
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)(a)$495 $455 $1,147 $(488)
Certain Items:
Fair value amortization(7)(5)(15)(17)
Legal, environmental and taxes other than income tax reserves— 46 112 38 
Change in fair value of derivative contracts(b)22 (6)64 (10)
Loss on impairments, divestitures and other write-downs, net(c)11 1,515 382 
Loss on impairments of goodwill(d)— — — 1,600 
COVID-19 costs— 11 — 11 
Income tax Certain Items(12)(8)(439)(114)
Other(19)11 
Total Certain Items(e)10 30 1,248 1,895 
DD&A and amortization of excess cost of equity investments547 571 1,651 1,735 
Income tax expense(f)146 148 687 418 
Joint venture DD&A and income tax expense(f)(g)84 114 270 343 
Interest, net(f)376 391 1,139 1,222 
Adjusted EBITDA$1,658 $1,709 $6,142 $5,125 
(a)In prior periods, Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.
(b)Gains or losses are reflected in our DCF when realized.
(b)(c)Three and nine months ended September 30, 2021 amounts include a non-cash impairment of $14 million related to the reclassification of an asset to held for sale within our Terminals business segment, offset partially by a gain of $10 million on the sale of assets within our CO2 business segment. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from lower expectations regarding the volumes and rates associated with re-contracting and a write-down of $117 million, reported within “Earnings from equity investments” on the accompanying consolidated statement of operations, on a long-term subordinated note receivable from an equity investee, Ruby, offset partially by a pre-tax gain of $206 million, reported within “Other, net” on the accompanying consolidated statement of operations, associated with the sale of a partial interest in our equity investment in NGPL Holdings. Nine months ended September 30, 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment whichsegment. Except as otherwise noted above, these amounts are reported within “Loss (gain) on impairments and divestitures, net” on our Consolidated Earnings Results (GAAP) table above.the accompanying consolidated statement of operations.
(c)(d)Nine months ended September 30, 2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2reporting units, respectively.
(d)(e)Three months ended September 30, 20202021 and 20192020 amounts include $(4)$2 million and $(2)$(4) million, respectively, and nine months ended September 30, 20202021 and 20192020 amounts include $(4)$129 million and $(15)$(4) million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.
(e)(f)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
(f)(g)Represents unconsolidated joint venture DD&A and income tax expense, reduced by consolidated joint venture partners’ DD&A.expense. See tabletables included in “—Supplemental Information” below.


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Supplemental Information
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
DD&A (GAAP)$539 $578 $1,636 $1,750 
Amortization of excess cost of equity investments (GAAP)32 21 99 61 
DD&A and amortization of excess cost of equity investments571 599 1,735 1,811 
Joint venture DD&A91 100 277 297 
DD&A attributable to KML noncontrolling interests— (5)— (15)
DD&A and amortization of excess cost of equity investments for DCF$662 $694 $2,012 $2,093 
Income tax expense (GAAP)$140 $151 $304 $471 
Certain Items(8)114 (15)
Income tax expense(a)148 143 418 456 
Unconsolidated joint venture income tax expense(a)23 23 66 71 
Income tax expense attributable to KML noncontrolling interests(a)— (2)— (6)
Income tax expense for DCF(a)$171 $164 $484 $521 
KML activities prior to December 16, 2019
Net income attributable to KML noncontrolling interests$— $$— $25 
KML noncontrolling interests associated with Certain Items— — — 
KML noncontrolling interests(a)— — 26 
DD&A attributable to KML noncontrolling interests— — 15 
Income tax expense attributable to KML noncontrolling interests(a)— — 
KML noncontrolling interests DCF adjustments(a)$— $16 $— $47 
Net income attributable to noncontrolling interests (GAAP)$17 $11 $45 $32 
Less: KML noncontrolling interests(a)— — 26 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))17 45 
Noncontrolling interests associated with Certain Items— — — 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)$17 $$45 $
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Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Additional joint venture information
Unconsolidated joint venture DD&A$101 $104 $306 $308 
Consolidated joint venture partners’ DD&A(10)(4)(29)(11)
Joint venture DD&A91 100 277 297 
Unconsolidated joint venture income tax expense(a)23 23 66 71 
Joint venture DD&A and income tax expense(a)$114 $123 $343 $368 
Unconsolidated joint venture cash taxes(b)$(41)$(16)$(51)$(50)
Unconsolidated joint venture sustaining capital expenditures$(32)$(35)$(84)$(85)
Consolidated joint venture partners’ sustaining capital expenditures
Joint venture sustaining capital expenditures$(30)$(33)$(80)$(80)
______
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions)
DD&A (GAAP)$526 $539 $1,595 $1,636 
Amortization of excess cost of equity investments (GAAP)21 32 56 99 
DD&A and amortization of excess cost of equity investments547 571 1,651 1,735 
Joint venture DD&A65 91 203 277 
DD&A and amortization of excess cost of equity investments for DCF$612 $662 $1,854 $2,012 
Income tax expense (GAAP)$134 $140 $248 $304 
Certain Items12 439 114 
Income tax expense(a)146 148 687 418 
Unconsolidated joint venture income tax expense(a)(b)19 23 67 66 
Income tax expense for DCF(a)$165 $171 $754 $484 
Additional joint venture information
Unconsolidated joint venture DD&A$76 $101 $236 $306 
Less: Consolidated joint venture partners’ DD&A11 10 33 29 
Joint venture DD&A65 91 203 277 
Unconsolidated joint venture income tax expense(a)(b)19 23 67 66 
Joint venture DD&A and income tax expense(a)$84 $114 $270 $343 
Unconsolidated joint venture cash taxes(b)$(13)$(41)$(47)$(51)
Unconsolidated joint venture sustaining capital expenditures$(29)$(32)$(81)$(84)
Less: Consolidated joint venture partners’ sustaining capital expenditures(2)(2)(5)(4)
Joint venture sustaining capital expenditures$(27)$(30)$(76)$(80)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and PlantationProducts (SE) Pipe Line equity investments.

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Segment Earnings Results

Natural Gas Pipelines
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except operating statistics)
Revenues$1,809 $1,934 $5,255 $6,103 
Operating expenses(878)(993)(2,455)(3,190)
(Loss) gain on impairments and divestitures, net(11)— (1,011)10 
Other income— — 
Earnings from equity investments169 141 484 431 
Other, net10 10 27 
Segment EBDA1,091 1,092 2,284 3,383 
Certain Items(a)(b)(9)(2)993 (21)
Adjusted Segment EBDA$1,082 $1,090 $3,277 $3,362 
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(128)(7)%$(852)(14)%
Adjusted Segment EBDA(8)(1)%(85)(3)%
Volumetric data(c)
Transport volumes (BBtu/d)36,453 37,028 37,091 35,958 
Sales volumes (BBtu/d)2,382 2,647 2,330 2,435 
Gathering volumes (BBtu/d)2,925 3,380 3,109 3,335 
NGLs (MBbl/d)22 33 27 32 
_______
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions, except operating statistics)
Revenues$2,555 $1,809 $8,656 $5,255 
Operating expenses(1,634)(878)(4,981)(2,455)
Loss on impairments and divestitures, net— (11)(1,599)(1,011)
Other income— — 
Earnings from equity investments144 169 311 484 
Other, net213 10 
Segment EBDA1,069 1,091 2,602 2,284 
Certain Items(a)21 (9)1,646 993 
Adjusted Segment EBDA$1,090 $1,082 $4,248 $3,277 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$$971 
Volumetric data(b)
Transport volumes (BBtu/d)38,527 37,475 38,593 37,887 
Sales volumes (BBtu/d)2,616 2,382 2,480 2,330 
Gathering volumes (BBtu/d)2,808 2,925 2,662 3,109 
NGLs (MBbl/d)29 22 30 27 
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $(4)$21 million and $(5)$1,646 million for the three and nine months ended September 30, 2021, respectively, and $(9) million and $993 million for the three and nine months ended September 30, 2020, respectively, and $(1) million for both threerespectively. Three and nine months ended September 30, 2019 which includes $(14)2021 amounts include decreases in revenues of $14 million of amortization of
45


regulatory liabilities (three and nine months 2020), partially offset by$36 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales (all periods).
(b)Includes non-revenue Certain Item amountssales. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash asset impairment loss of $(5)$1,600 million resulting from lower expectations regarding the volumes and $998rates associated with re-contracting related to our South Texas gathering and processing assets, a write-down of $117 million foron a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a litigation reserve partially offset by a pre-tax gain of $206 million associated with the threesale of a partial interest in our equity investment in NGPL Holdings. Three and nine months ended September 30, 2020 respectively, and $(1)amounts both include an increase in revenues of $(14) million and $(20) million for the three and nineof amortization of regulatory liabilities, largely offset by non-cash amounts related to mark-to-market derivative contracts. Nine months ended September 30, 2019, respectively. Nine-month 2020 amount primarily resulted fromalso includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit. Nine-month 2019 amounts are primarily related to an increase in earnings from certain equity investees’ amortization of regulatory liabilities.
Other
(c)(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented. Volumes for acquired pipelines are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

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Below are the changes in both Adjusted Segment EBDA and adjusted revenues in the comparable three and nine-month periods ended September 30, 20202021 and 2019:2020:

Three Months Ended September 30, 20202021 versus Three Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues increase/(decrease)Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
MidstreamMidstream$(68)(21)%$(208)(19)%Midstream$29 11%
East RegionEast Region1%
West RegionWest Region(5)(2)%— %West Region(29)(11)%
East Region65 13 %77 15 %
Intrasegment eliminations— — %40 %
Total Natural Gas PipelinesTotal Natural Gas Pipelines$(8)(1)%$(128)(7)%Total Natural Gas Pipelines$%

Nine Months Ended September 30, 20202021 versus Nine Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues
increase/(decrease)
Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
MidstreamMidstream$(183)(18)%$(1,033)(29)%Midstream$998 123%
East RegionEast Region25 1%
West RegionWest Region(19)(2)%— %West Region(52)(7)%
East Region117 %173 11 %
Intrasegment eliminations— — %33 %
Total Natural Gas PipelinesTotal Natural Gas Pipelines$(85)(3)%$(852)(14)%Total Natural Gas Pipelines$971 30 %

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 20202021 and 2019:2020:
Midstream’s decreases of $68$29 million (21%(11%) and $183$998 million (18%(123%), increases, respectively, in Midstream were primarily due to (i) decreases of $40 million and $112 million, respectively, related to the sale of the Cochin Pipeline on December 16, 2019 to Pembina; (ii) lower prices and quarter-to-date volumes on South Texas assets; (iii) lower volumes on KinderHawk; (iv) lower contract rates on our North Texas assets; and (v) lower sales margins partially offset by higher transportation revenues driven by new customer contracts on Texas intrastate natural gas pipeline operations. These decreases were partially offset by higher equity earnings due to the Gulf Coast ExpressPermian Highway Pipeline (Gulf Coast) being placed in service in September 2019. January 2021; (ii) higher sales margins driven by higher commodity prices on our Texas intrastate natural gas pipeline operations; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets. The year-to-date increase was also impacted by higher commodity prices as a result of the February 2021 winter storm on our South Texas assets and Texas intrastate natural gas pipeline operations partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations on our Oklahoma assets. Overall Midstream’s revenues decreased in both the three and nine-month periodsincreased primarily due to lowerhigher commodity prices and volumes which was largelypartially offset by corresponding decreasesincreases in costs of sales;
West Region’s decreases of $5$8 million (2%(1%) and $19$25 million (2%(1%), increases, respectively, in the East Region were primarily due to decreases in earnings from (i) Ruby Pipeline Company, L.L.C. primarily due to lower transportation revenues and an increase in operating expenses due to the recognition of a credit loss reserve associated with a shipper; (ii) Cheyenne Plains Gas Pipeline Company, L.L.C. as a resultour July 2021 acquisition of the expiration of one shipper’s contract; and (iii) EPNG driven by higher operating expenses,Stagecoach assets partially offset by lower earnings on Fayetteville Express Pipeline LLC driven by lower revenues resulting from contract expirations. The year-to-date increase was also impacted by higher earnings from TGP due to weather-driven increases in reservation and park and loan revenues mostly during the first quarter of 2021 and increased earnings from CIG resulting from an expansion project in the Denver Julesburg basin; and
East Region’s increases of $65 million (13%) and $117 million (7%), respectively, were primarily due to increases in earnings from ELC and Southern LNGElba Liquefaction Company, L.L.C. resulting from the liquefaction units of the Elba Liquefaction project being placed into servicefully operational as of August 2020; and
$29 million (11%) and $52 million (7%) decreases, respectively, in the later part of 2019West Region were primarily due to lower earnings from Wyoming Interstate Company, LLC, Colorado Interstate Gas Company, L.L.C. and through the first eight months of 2020Cheyenne Plains Gas Pipeline Company, L.L.C. driven by lower revenues due to contract expirations and increasedlower equity earnings from Ruby. The third quarter decrease was also impacted by lower earnings from EPNG driven by lower park and loan revenues.

4644


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

Products Pipelines
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except operating statistics)
Revenues$442 $484 $1,282 $1,350 
Operating expenses(233)(177)(585)(500)
Loss on impairments and divestitures, net— — (21)— 
Earnings from equity investments14 17 42 52 
Other, net— 
Segment EBDA223 325 719 908 
Certain Items(a)46 11 50 28 
Adjusted Segment EBDA$269 $336 $769 $936 
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(42)(9)%$(68)(5)%
Adjusted Segment EBDA(67)(20)%(167)(18)%
Volumetric data(b)
Gasoline(c)941 1,066 888 1,045 
Diesel fuel383 393 371 370 
Jet fuel160 318 184 305 
Total refined product volumes1,484 1,777 1,443 1,720 
Crude and condensate530 639 570 644 
Total delivery volumes (MBbl/d)2,014 2,416 2,013 2,364 
_______
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions, except operating statistics)
Revenues$605 $442 $1,572 $1,282 
Operating expenses(341)(233)(828)(585)
Loss on impairments and divestitures, net— — — (21)
Earnings from equity investments15 14 48 42 
Other, net— — — 
Segment EBDA279 223 792 719 
Certain Items(a)46 44 50 
Adjusted Segment EBDA$280 $269 $836 $769 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$11 $67 
Volumetric data(b)
Gasoline(c)1,023 941 987 888 
Diesel fuel389 383 395 371 
Jet fuel250 160 217 184 
Total refined product volumes1,662 1,484 1,599 1,443 
Crude and condensate491 530 503 570 
Total delivery volumes (MBbl/d)2,153 2,014 2,102 2,013 
Certain Items affecting Segment EBDA
(a)Includes non-revenue Certain Item amounts of $1 million and $44 million for the three and nine months ended September 30, 2021, respectively, and $46 million and $50 million for the three and nine months ended September 30, 2020, respectively, and $11respectively. Nine month 2021 amount includes increases in expense of $28 million and $28$15 million for the threerelated to a litigation reserve and nine months ended September 30, 2019,an environmental reserve adjustment, respectively. Three and nine-monthnine month 2020 amounts both include a $46 million unfavorable rate case reserve adjustment. Nine-monthNine month 2020 amount also includes a non-cash loss on impairment of our Belton Terminal of $21 million andpartially offset by a $17 million favorable adjustment for tax reserves, other than income taxes. Three and nine-month 2019 amounts include an unfavorable environmental reserve adjustment. Nine-month 2019 amount also includes a $17 million unfavorable adjustment of tax reserves, other than income taxes.
Other
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

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Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and nine-month periods ended September 30, 20202021 and 2019.2020:

Three Months Ended September 30, 20202021 versus Three Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues increase/(decrease)Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
West Coast Refined ProductsWest Coast Refined Products$(31)(21)%$(19)(10)%West Coast Refined Products$17 15 %
Southeast Refined ProductsSoutheast Refined Products10 %
Crude and CondensateCrude and Condensate(27)(22)%%Crude and Condensate(12)(12)%
Southeast Refined Products(9)(13)%(24)(22)%
Total Products PipelinesTotal Products Pipelines$(67)(20)%$(42)(9)%Total Products Pipelines$11 %

Nine Months Ended September 30, 20202021 versus Nine Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues
increase/(decrease)
Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
West Coast Refined ProductsWest Coast Refined Products$(51)(13)%$(45)(8)%West Coast Refined Products$38 11 %
Southeast Refined ProductsSoutheast Refined Products39 25 %
Crude and CondensateCrude and Condensate(76)(21)%— %Crude and Condensate(10)(4)%
Southeast Refined Products(40)(20)%(25)(8)%
Total Products Pipelines Total Products Pipelines $(167)(18)%$(68)(5)%Total Products Pipelines$67 %

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, 20202021 and 2019:2020:
$17 million (15%) and $38 million (11%) increases, respectively, in West Coast Refined Products’ decreases of $31 million (21%) and $51 million (13%), respectively,Products were primarily due to decreasedincreased earnings on Pacific (SFPP) operations,, and to a lesser extent, on Calnev Pipe Line LLC and West Coast terminals driven by lower serviceshigher revenues from the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expense primarily as a result of a reduction in volumes due to COVID-19;higher integrity management spending on SFPP;
Crude and Condensate’s decreases of $27$6 million (22%(10%) and $76$39 million (21%(25%), increases, respectively, in Southeast Refined Products were primarily due to South East Terminals resulting from increased revenues from higher volumes driven by continued recovery of volumes from 2020. The year-to-date increase was also driven by higher 2021 earnings at our Transmix processing operations primarily due to higher prices and first quarter 2020 unfavorable inventory adjustments, and an increase in equity earnings from Products (SE) Pipe Line primarily due to product net gains resulting from higher prices; and
$12 million (12%) and $10 million (4%) decreases, respectively, in Crude and Condensate were primarily due to decreased earnings from the Bakken Crude assets and KM Condensate Processing Facility (KMCC - Splitter) partially offset by increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s decreased earnings were due to lower contracted rates and lower volumes. . The Bakken Crude assetsassets’ decreased earnings were primarily driven by lower volumes, contracts renewed at lower average rates, and reduced re-contracted rates.contract expirations partially offset by lower field operating expenses. KMCC - Splitter’s decreased earnings were driven by higher field maintenance expenses. KMCC’s increased earnings were primarily due to higher deficiency revenues and lower field operating expense partially offset by contract expirations. Bakken Crude assetsassets’ and KMCC’s year-to-date decreaseschanges respectively, were also impacted by first quarter 2020 unfavorable inventory valuation adjustments driven by declinesadjustments. In addition, increased marketing activities within KMCC have resulted in commodity prices during the firstthird quarter and year-to-date increases in revenues with corresponding increases in cost of 2020; andsales.
Southeast Refined Products’ decreases of $9 million (13%) and $40 million (20%), respectively, were primarily due to decreased earnings from our South East Terminals and Central Florida Pipeline and a decrease in equity earnings from Plantation Pipe Line as a result of decreased transportation revenues driven by lower volumes and prices due to COVID-19. The year-to-date decrease was also impacted by lower earnings from our Transmix processing operations driven by unfavorable inventory adjustments resulting from commodity price declines during the first quarter 2020.
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Terminals
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended
September 30,
Nine Months Ended
September 30,
20202019202020192021202020212020
(In millions, except operating statistics)(In millions, except operating statistics)
RevenuesRevenues$424 $508 $1,285 $1,524 Revenues$422 $424 $1,275 $1,285 
Operating expensesOperating expenses(185)(223)(570)(660)Operating expenses(200)(185)(588)(570)
Gain (loss) on divestitures and impairments, net— (5)
Loss on impairments and divestitures, netLoss on impairments and divestitures, net(14)— (14)(5)
Other incomeOther income— — 
Earnings from equity investmentsEarnings from equity investments19 15 Earnings from equity investments10 19 
Other, netOther, net— Other, net— 
Segment EBDASegment EBDA246 295 732 884 Segment EBDA216 246 689 732 
Certain Items(a)Certain Items(a)— — — — Certain Items(a)17 — 17 — 
Adjusted Segment EBDAAdjusted Segment EBDA$246 $295 $732 $884 Adjusted Segment EBDA$233 $246 $706 $732 
Change from prior periodChange from prior periodIncrease/(Decrease)Change from prior periodIncrease/(Decrease)
Adjusted revenues$(84)(17)%$(239)(16)%
Adjusted Segment EBDAAdjusted Segment EBDA(49)(17)%(152)(17)%Adjusted Segment EBDA$(13)$(26)
Volumetric data(a)
Volumetric data(b)Volumetric data(b)
Liquids leasable capacity (MMBbl)Liquids leasable capacity (MMBbl)79.4 79.5 79.4 79.5 Liquids leasable capacity (MMBbl)79.9 79.6 79.9 79.6 
Liquids utilization %(b)96.2 %94.4 %96.2 %94.4 %
Liquids utilization %(c)Liquids utilization %(c)94.2 %96.3 %94.2 %96.3 %
Bulk transload tonnage (MMtons)Bulk transload tonnage (MMtons)11.3 14.1 35.4 42.0 Bulk transload tonnage (MMtons)13.5 11.3 38.1 35.4 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $17 million for both three and nine months ended September 30, 2021 primarily resulting from a pre-tax non-cash impairment loss of $14 million related to the reclassification of an asset to held for sale.
Other
(a)(b)Volumes for assets sold are excluded for all periods presented.
(b)(c)The ratio of our tankage capacity in service to tankage capacity available for service.

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Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and nine-month periods ended September 30, 20202021 and 2019.2020:

Three Months Ended September 30, 20202021 versus Three Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues increase/(decrease)
(In millions, except percentages)
Alberta Canada$(31)(100)%$(47)(100)%
Gulf Liquids(5)(6)%(4)(4)%
West Coast(5)(100)%(18)(100)%
Gulf Bulk(4)(27)%(3)(10)%
Mid Atlantic(3)(23)%(4)(14)%
All others (including intrasegment eliminations)(1)(1)%(8)(3)%
Total Terminals$(49)(17)%$(84)(17)%
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Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Marine operations$(15)(29)%
Gulf Central19 %
Mid Atlantic40 %
Northeast(2)(7)%
All others (including intrasegment eliminations)(5)(4)%
Total Terminals$(13)(5)%

Nine Months Ended September 30, 20202021 versus Nine Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Alberta Canada$(96)(100)%$(144)(100)%
Gulf Liquids(21)(9)%(10)(3)%
West Coast(17)(100)%(51)(100)%
Gulf Bulk(4)(8)%(3)(3)%
Mid Atlantic(12)(24)%(16)(17)%
All others (including intrasegment eliminations)(2)— %(15)(2)%
Total Terminals$(152)(17)%$(239)(16)%
Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Marine operations$(39)(25)%
Gulf Central(7)(8)%
Mid Atlantic21 %
Northeast13 %
All others (including intrasegment eliminations)%
Total Terminals$(26)(4)%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 20202021 and 2019:2020:
combined decreases of $36$15 million and $113 million, respectively, associated with our Alberta Canada terminals and our West Coast terminals due to the sale of KML assets to Pembina on December 16, 2019;
decreases of $5 million (6%(29%) and $21$39 million (9%(25%), decreases, respectively, from our Gulf Liquids terminals primarily driven by lower volumes and associated ancillary fees related to demand reduction attributable to COVID-19. Year-to-date decrease was also impacted by tanks being temporarily off-lease as they are transitioned to new customers following the termination of a major customer contract;
decreases of $4 million (27%) and $4 million (8%), respectively, from our Gulf Bulk terminalsin Marine operations were primarily due to lower revenues driven by lower refinery petroleum coke productionfleet utilization and the expiration of a customer contract in January 2020; andaverage charter rates;
decreases of $3$5 million (23%(19%) increase and $7 million (8%) decrease, respectively, in the Gulf Central terminals. The third quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol, petroleum coke, and coal volumes. The year-to-date decrease in earnings was primarily driven by unfavorable petroleum coke volumes due to refinery outages associated with the February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC;
$4 million (40%) and $12$8 million (24%(21%), increases, respectively, from ourin the Mid Atlantic terminals were primarily due to lowerhigher coal volumes at our Pier IX facilityfacility; and
$2 million (7%) decrease and $9 million (13%) increase, respectively, in the Northeast terminals. The year-to-date increase was primarily driven by coal market weakness largely attributable to demand reductionincreased revenues associated with COVID-19.

higher throughput levels and new contracts.
5048


CO2
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except operating statistics)
Revenues$251 $298 $792 $913 
Operating expenses(99)(143)(312)(383)
Loss on impairments and divestitures, net— — (950)— 
Earnings from equity investments17 28 
Segment EBDA156 164 (453)558 
Certain Items(a)(b)(2)(15)938 (36)
Adjusted Segment EBDA$154 $149 $485 $522 
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(34)(12)%$(97)(11)%
Adjusted Segment EBDA%(37)(7)%
Volumetric data
SACROC oil production21.2 23.2 22.1 24.0 
Yates oil production6.4 6.8 6.7 7.1 
Katz and Goldsmith oil production2.6 3.6 2.8 3.8 
Tall Cotton oil production1.4 2.1 1.9 2.4 
Total oil production, net (MBbl/d)(c)31.6 35.7 33.5 37.3 
NGL sales volumes, net (MBbl/d)(c)9.1 10.2 9.4 10.2 
CO2 sales volumes, net (Bcf/d)
0.4 0.6 0.5 0.6 
Realized weighted average oil price per Bbl$54.83 $49.45 $53.28 $49.36 
Realized weighted average NGL price per Bbl$17.65 $21.12 $17.77 $23.54 
_______
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
(In millions, except operating statistics)
Revenues$257 $251 $729 $792 
Operating expenses(112)(99)(161)(312)
Gain (loss) on impairments and divestitures, net11 — (950)
Earnings from equity investments23 17 
Segment EBDA163 156 599 (453)
Certain Items(a)(9)(2)(3)938 
Adjusted Segment EBDA$154 $154 $596 $485 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$— $111 
Volumetric data
SACROC oil production20.1 21.2 19.9 22.1 
Yates oil production6.5 6.4 6.5 6.7 
Katz and Goldsmith oil production2.1 2.6 2.3 2.8 
Tall Cotton oil production1.1 1.4 1.0 1.9 
Total oil production, net (MBbl/d)(b)29.8 31.6 29.7 33.5 
NGL sales volumes, net (MBbl/d)(b)9.7 9.1 9.3 9.4 
CO2 sales volumes, net (Bcf/d)
0.4 0.4 0.4 0.5 
Realized weighted average oil price ($ per Bbl)$53.03 $54.83 $52.21 $53.28 
Realized weighted average NGL price ($ per Bbl)$28.01 $17.65 $23.73 $17.77 
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $(9) million and $(3) million for the three and nine months ended September 30, 2021, respectively, and $(2) million and $(12)$938 million for the three and nine months ended September 30, 2020, respectively, and $(15) million and $(36) million for the three and nine months ended September 30, 2019, respectively, related to mark-to-market gains associated with derivative contracts used to hedge forecasted commodity sales.
(b)Includes non-revenue Certain Itemrespectively. Nine month 2020 amount of $950 million for the nine months ended September 30, 2020 resultingprimarily resulted from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on our oil and gas producing assets.
Other
(c)(b)Net of royalties and outside working interests.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and nine-month periods ended September 30, 20202021 and 2019.2020:

Three Months Ended September 30, 20202021 versus Three Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues increase/(decrease)Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Oil and Gas Producing activitiesOil and Gas Producing activities$27 35 %$(10)(5)%Oil and Gas Producing activities$(42)(40)%
Source and Transportation activitiesSource and Transportation activities(22)(31)%(28)(29)%Source and Transportation activities40 82 %
Intrasegment eliminations— — %80 %
SubtotalSubtotal(2)(1)%
Energy Transition VenturesEnergy Transition Venturesn/a
Total CO2
Total CO2
$%$(34)(12)%
Total CO2
$— — %

5149



Nine Months Ended September 30, 20202021 versus Nine Months Ended September 30, 20192020

Adjusted Segment EBDA
increase/(decrease)
Adjusted revenues
increase/(decrease)
Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Oil and Gas Producing activitiesOil and Gas Producing activities$23 %$(37)(6)%Oil and Gas Producing activities$73 23 %
Source and Transportation activitiesSource and Transportation activities(60)(27)%(73)(25)%Source and Transportation activities36 22 %
Intrasegment eliminations— — %13 72 %
SubtotalSubtotal109 22 %
Energy Transition VenturesEnergy Transition Venturesn/a
Total CO2
Total CO2
$(37)(7)%$(97)(11)%
Total CO2
$111 23 %
n/a - not applicable

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 20202021 and 2019:2020:
increases of $27$42 million (35%(40%) decrease and $23$73 million (8%(23%), increase, respectively, from ourin Oil and Gas Producing activitiesactivities. The third quarter decrease was primarily due to (i)a settlement for a terminated affiliate purchase contract with Source and Transportation activities which increased operating expenses by $38 million and lower crude oil sales revenues of $14 million due to lower volumes and realized prices partially offset by higher realized NGL prices which increased revenues by $12 million. The year-to-date increase was primarily due to lower operating expenses of $32$118 million driven by a benefit in the 2021 period realized from returning power to the grid by curtailing oil production during the February 2021 winter storm, net of the impact of the terminated affiliate contract noted above, and $50higher realized NGL prices which increased revenues by $27 million, respectively;partially offset by lower crude oil volumes which decreased revenues by $45 million, driven in part, by the curtailed oil production and (ii) higherby lower realized crude oil prices which increased revenues by $18 million and $42 million, respectively, offset by (i) lower volumes which decreased revenues by $25 million and $61 million, respectively; and (ii) lower NGL prices which decreased revenues by $3 million and $19 million, respectively;$22 million; and
decreases of $22$40 million (31%(82%) and $60$36 million (27%(22%), increases, respectively, from ourin Source and Transportation activities primarily due to decreasesa settlement for a terminated affiliate sales contract with Oil and Gas Producing activities which resulted in an increase in revenues of $28$38 million. The year-to-date increase was also impacted by a decrease in revenues of $19 million and $77 million, respectively, related to lower CO2 sales volumes partially offset by an increase in equity earnings of $6 million and lower operating expenses of $9 million and $22 million, respectively.$5 million.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of September 30, 2020.2021.

Remaining 20202021202220232024
Crude Oil(a)
Price ($/barrel)$56.07 $52.00 $53.05 $50.14 $43.40 
Volume (barrels per day)30,684 20,300 8,600 5,150 950 
NGLs
Price ($/barrel)$28.17 $26.61 
Volume (barrels per day)6,315 2,474 
Midland-to-Cushing Basis Spread
Price ($/barrel)$0.14 $0.40 
Volume (barrels per day)31,100 1,500 
_______
Remaining 20212022202320242025
Crude Oil(a)
Price ($ per Bbl)$50.38 $53.41 $51.70 $50.97 $52.19 
Volume (MBbl/d)25.70 17.00 11.20 5.90 2.85 
NGLs
Price ($ per Bbl)$36.39 $47.76 
Volume (MBbl/d)6.03 2.56 
Midland-to-Cushing Basis Spread
Price ($ per Bbl)$0.26 $0.59 
Volume (MBbl/d)24.55 14.00 
(a)Includes West Texas Intermediate hedges.

5250


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

Three Months Ended September 30,Earnings
increase/(decrease)
Three Months Ended
September 30,
Earnings
increase/(decrease)
2020201920212020Earnings
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
DD&A (GAAP)DD&A (GAAP)$(526)$(539)$13 %
General and administrative (GAAP)General and administrative (GAAP)$(153)$(154)$%General and administrative (GAAP)$(174)$(153)$(21)(14)%
Corporate benefit (charges)(8)11 138 %
Corporate benefitCorporate benefit133 %
Certain Items(a)Certain Items(a)11 120 %Certain Items(a)— 11 (11)(100)%
General and administrative and corporate charges(b)General and administrative and corporate charges(b)$(139)$(157)$18 11 %General and administrative and corporate charges(b)$(167)$(139)$(28)(20)%
Interest, net (GAAP)Interest, net (GAAP)$(383)$(447)$64 14 %Interest, net (GAAP)$(368)$(383)$15 %
Certain Items(c)Certain Items(c)(8)(5)(3)(60)%Certain Items(c)(8)(8)— — %
Interest, net(b)Interest, net(b)$(391)$(452)$61 13 %Interest, net(b)$(376)$(391)$15 %
Net income attributable to noncontrolling interests (GAAP)Net income attributable to noncontrolling interests (GAAP)$(17)$(11)$(6)(55)%Net income attributable to noncontrolling interests (GAAP)$(16)$(17)$%
Certain Items— — — — %
Certain Items(d)Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)Net income attributable to noncontrolling interests(b)$(17)$(11)$(6)(55)%Net income attributable to noncontrolling interests(b)$(16)$(17)$%

Nine Months Ended September 30,Earnings
increase/(decrease)
Nine Months Ended September 30,Earnings
increase/(decrease)
2020201920212020Earnings
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
DD&A (GAAP)DD&A (GAAP)$(1,595)$(1,636)$41 %
General and administrative (GAAP)General and administrative (GAAP)$(461)$(456)$(5)(1)%General and administrative (GAAP)$(490)$(461)$(29)(6)%
Corporate charges(11)(22)11 50 %
Corporate benefit (charges)Corporate benefit (charges)25 (11)36 327 %
Certain Items(a)Certain Items(a)36 11 25 227 %Certain Items(a)— 36 (36)(100)%
General and administrative and corporate charges(b)General and administrative and corporate charges(b)$(436)$(467)$31 %General and administrative and corporate charges(b)$(465)$(436)$(29)(7)%
Interest, net (GAAP)Interest, net (GAAP)$(1,214)$(1,359)$145 11 %Interest, net (GAAP)$(1,122)$(1,214)$92 %
Certain Items(c)Certain Items(c)(8)(6)(2)(33)%Certain Items(c)(17)(8)(9)(113)%
Interest, net(b)Interest, net(b)$(1,222)$(1,365)$143 10 %Interest, net(b)$(1,139)$(1,222)$83 %
Net income attributable to noncontrolling interests (GAAP)Net income attributable to noncontrolling interests (GAAP)$(45)$(32)$(13)(41)%Net income attributable to noncontrolling interests (GAAP)$(49)$(45)$(4)(9)%
Certain Items— (1)100 %
Certain Items(d)Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)Net income attributable to noncontrolling interests(b)$(45)$(33)$(12)(36)%Net income attributable to noncontrolling interests(b)$(49)$(45)$(4)(9)%
Certain items
(a)Three and nine-monthnine month 2020 amounts both include an increase in expense of $11 million related to costs incurred associated with COVID-19 mitigation. Nine-monthNine month 2020 amount also includes an increase in expense of $23 million associated with the non-cash fair value adjustment of and the dividend onaccrual prior to the sale of our investment in Pembina common stock.
(b)Amounts are adjusted for Certain Items.
(c)Three and nine-monthnine month 2021 amounts include decreases in interest expense of $7 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and nine month 2020 amounts include (i) decreases in interest expense of $5 million and $17 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) a decrease in expense of $3 million and an increase in expense of $11 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.
(d)Three and nine-month 2019nine months ended September 30, 2021 and 2020 amounts each include (i) decreases in interest expenseless than $1 million of $7 million and $22 million, respectively, related to non-cash debt fair value adjustmentsnoncontrolling interests associated with acquisitions and (ii) increases in expense of $2 million and $15 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.Certain Items.
51



General and administrative expenses and corporate charges adjusted for Certain Items decreased $18 million and $31 million for the three and nine months ended September 30, 2020, respectively,2021 when compared with the respective prior year periods increased $28 million and $29 million, respectively, primarily due to lower non-cash pension expensescapitalized costs of $11$18 million and $34$41 million, respectively, lower expensesreflecting reduced capital spending primarily by our Natural Gas Pipelines business segment, non-recurring cost savings realized in the 2020 period as a result of $6the global pandemic of $10 million and $27$17 million, respectively, due to the KML and U.S. Cochin Sale, $7higher benefit-related costs of $10 million and $16 million, respectively, partially offset by $12 million and $36 million, respectively, of cost
53


savings in the 2021 period associated with reduced business activity during the pandemic, partially offset byorganizational efficiency efforts, and lower capitalizedpension costs of $4 million and $43$14 million, respectively, reflecting the COVID-19-related cutback on capital projects primarily by our CO2 and Natural Gas Pipelines business segments and our Gulf Coast project being placed in service in September 2019. The year-to-date decrease was also impacted by $8 million for a reduction in other benefit-related costs and a 2019 project write-off in our Terminals segment.respectively.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our consolidated interest expense, net of interest income adjusted for Certain Items for the three and nine months ended September 30, 20202021 when compared with the respective prior year periods decreased $61$15 million and $143$83 million, respectively, primarily due to lower weighted average long-term debt balances, lower LIBOR rates, and lower LIBORlong-term interest rates, partially offset by lower capitalized interest.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of September 30, 20202021 and December 31, 2019,2020, approximately 16%15% and 27%16%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The percentage at September 30, 2021 includes our variable-to-fixed interest rate derivative contracts not designated as hedging instruments which hedge our exposure through 2021. For more information on our interest rate swaps, see Note 56 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2020 when compared with the respective prior year periods increased $6 million and $12 million, respectively.

Income Taxes

Our tax expense for the three months ended September 30, 20202021 was approximately $140$134 million as compared with $151$140 million of expense for the same period of 2019.2020. The $11$6 million decrease in tax expense was due primarily due to a slightly lower pre-tax book income in the 2020 period.2021 effective tax rate caused by multiple factors.

Our tax expense for the nine months ended September 30, 20202021 was approximately $304$248 million as compared with $471$304 million of expense for the same period of 2019.2020. The $167$56 million decrease in tax expense was due primarily to (i) lowerthe prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment, (ii) higher dividend-received deductions in 2021, and (iii) the current year release of the valuation allowance on our investment in NGPL Holdings, partially offset by federal and state taxes on higher pre-tax book income in the 2020 period; (ii) lower foreign income taxes as a result of the KML2021 and U.S. Cochin Sale in 2019; and (iii) the refund of alternative minimum tax sequestration credits in 2020.

Liquidity and Capital Resources

General

As of September 30, 2020,2021, we had $632$102 million of “Cash and cash equivalents,” an increasea decrease of $447$1,082 million from December 31, 2019.2020. We used $1.2 billion of cash on hand to complete the acquisition on July 9, 2021 of subsidiaries of Stagecoach. Additionally, as of September 30, 2020,2021, we had borrowing capacity of approximately $3.9$3.8 billion under our $4 billion revolving credit facilityfacilities (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facilityfacilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flowflows from operations, providing a source of funds of $3,282$4,440 million and $3,121$3,282 million in the first nine months of 20202021 and 2019,2020, respectively. The period-to-period increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures. We believe our current cash on hand, our cash from operations, and our borrowing capacity under our revolving credit facility are more than adequate to allow us to manage our cash requirements, including maturing debt, through 2021;expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.

Our board of directors declared a quarterly dividend of $0.2625$0.27 per share for the third quarter of 2020, unchanged from the previous quarter. This represents a 5% increase over2021, consistent with the dividend declared for the third quarter of 2019. As previously announced, market conditions have negatively impacted a number of our current year and future planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. As a result, our estimated capital expenditures for expansion projects and contributions to joint ventures will be almost 30% below our 2020 budget.previous quarter. We
54


continue to expect to fully fund our dividend payments as well as our discretionary spending for 20202021 without funding from the capital markets.
52



On August 5, 2020,February 11, 2021, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00%3.60% senior notes due 2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million. We used a portion of the proceeds to repay maturing debt.

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

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

Short-term Liquidity

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

As of September 30, 2020,2021, our $2,057$2,822 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. Although we used the proceeds from the sale of the Pembina common equity that we received for the sale of KML to reduce debt during 2020, we generallyWe intend to fund our debt, as it becomes due, primarily through cash on hand, credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 20192020 was $2,477$2,558 million.

We had working capital (defined as current assets less current liabilities) deficits of $1,704$3,139 million and $1,862$1,871 million as of September 30, 20202021 and December 31, 2019,2020, respectively. OurFrom time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $158$1,268 million favorableunfavorable change from year-end 20192020 was primarily due to (i) an increasea $1,082 million decrease in cash and cash equivalents primarily resulting from utilizing cash on hand to acquire subsidiaries of $447 million;Stagecoach; (ii) a decreasenet unfavorable short-term fair value adjustment of approximately $284$253 million on derivative contract assets and liabilities in 2021; (iii) an increase in accounts payable, net of change in accounts receivable, of $212 million; (iv) a $160 million increase in commercial paper borrowings; and (iv) an increase of $104 million in senior notes that mature in the next twelve months; (iii) a favorable asset fair value adjustment of $173 million on derivative contracts in 2020; and (iv) the $100 million repayment of the preferred interest in Kinder Morgan G.P. Inc.;months, partially offset by (i) a $193 million decrease in accrued interest; (ii) an increase of $925$152 million in restricted deposits primarily related to the sale of Pembina common equitymargin calls in January 2020.our derivative activities; (iii) a $109 million increase in inventories, primarily storage gas and product inventories; and (iv) a $61 million decrease in accrued contingencies. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

Counterparty Creditworthiness

Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices, or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. The balance of our allowance for credit losses as of September 30, 20202021 and December 31, 2019,2020, was $25$2 million and $9$26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets which includes reserves for counterparty bankruptcies recorded during the nine months ended September 30, 2020. Our outlook as discussed under “.2020 Outlook” takes into account the estimated impact attributable to counterparty bankruptcy filings to date. See also our “Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, Part II, Item 1A. Risk Factors —Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.”
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Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures that increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results of Operations—Overview—Non-GAAP Financial Measures—DCF”). With respect to our oil and gas producing
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activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e., production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those that maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as a maintenance/sustaining or as an expansion capital expenditure is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.

Our capital expenditures for the nine months ended September 30, 2020,2021, and the amount we expect to spend for the remainder of 20202021 to sustain and grow our businesses are as follows:
Nine Months Ended September 30, 20202020 RemainingTotal 2020(a)
(In millions)
Sustaining capital expenditures(b)(c)$477 $181 $658 
Discretionary capital investments(c)(d)(e)1,397 321 1,718 
_______
Nine Months Ended September 30, 20212021 RemainingTotal 2021
(In millions)
Sustaining capital expenditures(a)(b)$558 $300 $858 
Discretionary capital investments(b)(c)(d)2,049 256 2,305 
(a)Amounts include reductions due to revised outlook, as discussed above in “—General.”
(b)Nine months ended September 30, 2020, 20202021, 2021 Remaining, and Total 20202021 amounts include $80$76 million, $35$31 million, and $115$107 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “Non-GAAP Financial Measures—Supplemental Information.
(b)Nine months ended September 30, 2021 amount excludes $6 million due to increases in accrued capital expenditures and contractor retainage and net changes in other.
(c)Nine months ended September 30, 20202021 amount includes $1 million of net changes from accrued capital expenditures, contractor retainage, and other.
(d)Nine months ended September 30, 2020 amount includes $442$135 million of our contributions to certain unconsolidated joint ventures for capital investments. Both Nine months ended September 30, 2021 and Total 2021 amounts also include $1,508 million for our acquisitions of Stagecoach and Kinetrex.
(e)(d)Amounts include our actual or estimated contributions to certain equity investees, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 20192020 in our 20192020 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 20202021 and December 31, 20192020 were $192$201 million and $439$141 million, respectively. The decreaseincrease of $247$60 million was primarily driven by capital commitments related to our Natural Gas PipelinesTerminals business segment.

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Cash Flows

Operating Activities

Cash provided by operating activities increased $161$1,158 million in the nine months ended September 30, 20202021 compared to the respective 20192020 period primarily due to:

a $161$1,206 million increase in cash primarily resulting from $202after adjusting the $1,639 million ofincrease in net income taxby $433 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) loss from impairments and divestitures, net (see discussion above in “—Results of Operations”); (ii) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “—General and Basis of Presentation”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred
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income taxes; and (v) earnings from equity investments (including a non-cash write-down of a related party note receivable from Ruby); partially offset by,
a $48 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by payments for litigation matters in the 20202021 period which was partially offset by a net increase in working capital items and higher distributions from equity investment earnings in the 2021 period compared to $364 million of net income tax payments in the 2019 period, which in both periods were primarily for foreign income taxes associated with the sale of certain Canadian assets. The income tax payments for the 2020 period are net of a $20 million refund related to alternative minimum tax sequestration credits.period.

Investing Activities

Cash used in investing activities decreased $1,834increased $1,135 million for the nine months ended September 30, 20202021 compared to the respective 20192020 period primarily attributable to:

an $827a $1,502 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,197 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 2 “Acquisitions” to our consolidated financial statements for further information regarding these transactions; and
a $490 million decrease in cash primarily due to $412 million of net proceeds received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period, versus the $907 million of proceeds received from the sale of the Pembina shares in the 2020 period;period. See Note 3 “Losses and Gains on Impairments, Divestitures and Other Write-downs” to our consolidated financial statements for further information regarding the transaction of the sale of an interest in NGPL Holdings; partially offset by,
a $783$457 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and
a $329 million decrease in cash used for contributions to equity investmentsinvestees driven primarily by lower contributions to Gulf Coast ExpressPermian Highway Pipeline LLC Midcontinent Express Pipeline LLC, Citrus, and Fayetteville Express Pipeline LLCSNG in the 20202021 period compared with the 2019 period, partially offset by contributions made to SNG in the 2020 period; and
a $368 million decrease in capital expenditures in the 2020 period over the comparative 2019 period primarily due to lower expenditures on the Elba Liquefaction expansion and also reflecting our reduction of expansion capital projects in the wake of COVID-19; partially offset by,
a $102 million decrease in distributions received from equity investments in excess of cumulative earnings primarily from Ruby Pipeline Holding Company L.L.C. and Fayetteville Express Pipeline LLC in the 2020 period over the comparative 2019 period.

Financing Activities

Cash used in financing activities decreased $1,587increased $1,446 million for the nine months ended September 30, 20202021 compared to the respective 20192020 period primarily attributable to:

a $1,068$1,403 million net decreaseincrease in cash used related to debt activity as a result of lowerhigher net debt payments in the 20202021 period compared to the 2019 period; and
an $879 million increase in cash reflecting the distribution of the TMPL sale proceeds to the owners of KML restricted voting shares in the 2019 period; partially offset by,
a $171 million increase in dividend payments to our common shareholders; and
a $127 million decrease in contributions received from investment partner and noncontrolling interests primarily driven by lower contributions received from EIG Global Energy Partners in the 2020 period compared to the 2019 period.

Common Stock Dividends

We expect to declare common stock dividends of $1.05$1.08 per share on our common stock for 2020.2021. The table below reflects our 2020 common stock2021 dividends declared:
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
DecemberMarch 31, 20192021$0.25 January 22, 2020February 3, 2020February 18, 2020
March 31, 20200.26250.27 April 22, 202021, 2021April 30, 2021May 4, 2020May 15, 202017, 2021
June 30, 202020210.26250.27 July 22, 202021, 2021August 3, 20202, 2021August 17, 202016, 2021
September 30, 202020210.26250.27 October 21, 202020, 2021November 2, 20201, 2021November 16, 202015, 2021

The actual amount of common stock dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide
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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 20192020 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.

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Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or subsidiary issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for subsidiary issuers and guarantors, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X that we early adopted effective January 1, 2020.S-X.  Also, see Exhibit 10.1 to this report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of September 30, 2020.2021.

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

Excluding fair value adjustments, as of September 30, 20202021 and December 31, 2019,2020, the Obligated Group had $32,502$30,994 million and $32,409$32,563 million, respectively, of Guaranteed Notes outstanding.

Summarized combined balance sheet and income statement information for the Obligated Group follows:
Summarized Combined Balance Sheet InformationSummarized Combined Balance Sheet InformationSeptember 30, 2020December 31, 2019Summarized Combined Balance Sheet InformationSeptember 30, 2021December 31, 2020
(In millions)(In millions)
Current assetsCurrent assets$2,418 $1,918 Current assets$2,412 $2,957 
Current assets - affiliatesCurrent assets - affiliates1,073 1,146 Current assets - affiliates1,118 1,151 
Noncurrent assetsNoncurrent assets62,131 63,298 Noncurrent assets62,129 61,783 
Noncurrent assets - affiliatesNoncurrent assets - affiliates615 441 Noncurrent assets - affiliates507 616 
Total AssetsTotal Assets$66,237 $66,803 Total Assets$66,166 $66,507 
Current liabilitiesCurrent liabilities$3,810 $4,569 Current liabilities$5,390 $4,528 
Current liabilities - affiliatesCurrent liabilities - affiliates1,118 1,139 Current liabilities - affiliates1,269 1,209 
Noncurrent liabilitiesNoncurrent liabilities34,320 33,612 Noncurrent liabilities31,803 33,907 
Noncurrent liabilities - affiliatesNoncurrent liabilities - affiliates1,057 1,325 Noncurrent liabilities - affiliates1,006 1,078 
Total LiabilitiesTotal Liabilities40,305 40,645 Total Liabilities39,468 40,722 
Redeemable noncontrolling interestRedeemable noncontrolling interest747 803 Redeemable noncontrolling interest661 728 
Kinder Morgan, Inc.’s stockholders’ equityKinder Morgan, Inc.’s stockholders’ equity25,185 25,355 Kinder Morgan, Inc.’s stockholders’ equity26,037 25,057 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ EquityTotal Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$66,237 $66,803 Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$66,166 $66,507 
Summarized Combined Income Statement InformationSummarized Combined Income Statement InformationThree Months Ended September 30, 2020Nine Months Ended September 30, 2020Summarized Combined Income Statement InformationThree Months Ended September 30, 2021Nine Months Ended September 30, 2021
(In millions)(In millions)
RevenuesRevenues$2,653 $7,840 Revenues$3,472 $11,211 
Operating incomeOperating income788 1,032 Operating income699 1,697 
Net incomeNet income463 113 Net income373 937 

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

For a discussion ofThere have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2019,2020, in Item 7A in our 20192020 Form 10-K, see Item 2, “Management's Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook”and10-K. For more information on our risk management activities, refer to Item 1, Note 56 “Risk Management” to our consolidated financial statements for more information on our risk management activities, both of which are incorporated in this item by reference.statements.

Item 4.  Controls and Procedures.

As of September 30, 2020,2021, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 20202021 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

See Part I, Item 1, Note 910 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 20192020 Form 10-K and in Part II,10-K. For more information on our risk management activities, refer to Item 1A.1, Note 6Risk FactorsManagementofto our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.consolidated financial statements.

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

None. 

Item 3.  Defaults Upon Senior Securities.

None. 

Item 4.  Mine Safety Disclosures.

The Company does not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. The Company has not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended September 30, 2020.2021.

Item 5.  Other Information.

None.Effective October 20, 2021, our board of directors approved the Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (the “Amended Director Plan”), which amends and restates the previous Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors dated January 1, 2015, as
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amended (the “Previous Plan”). The Amended Director Plan amends and restates the Previous Plan to increase the number of shares available for issuance under the Amended Director Plan.

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

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

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

the total cash compensation awarded to such director and

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

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

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

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Item 6.  Exhibits.
Exhibit
Number                     Description
4.1 
10.1 
10.2 *
10.3 *
10.4 
10.5 
22.1 
31.1 
31.2 
32.1 
32.2 
101 
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Operations for the three and nine months ended September 30, 20202021 and 2019;2020; (ii) our Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 20202021 and 2019;2020; (iii) our Consolidated Balance Sheets as of September 30, 20202021 and December 31, 2019;2020; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 20202021 and 2019;2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 20202021 and 2019;2020; and (vi) the notes to our Consolidated Financial Statements.
104 Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.

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

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
KINDER MORGAN, INC.
Registrant
Date:October 23, 202022, 2021By:/s/ David P. Michels
David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)
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