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 SeptemberJune 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-20210630_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,” “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 OctoberJuly 22, 2020,2021, the registrant had 2,263,793,9232,266,520,797 Class P shares outstanding.



KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
  Page
Number
2
 
3
 
Consolidated Statements of Operations - Three and NineSix Months Ended SeptemberJune 30, 20202021 and 20192020
4
 
Consolidated Statements of Comprehensive (Loss) Income (Loss) - Three and NineSix Months Ended SeptemberJune 30, 20202021 and 20192020
5
 
Consolidated Balance Sheets - as of SeptemberJune 30, 20202021 and December 31, 20192020
6
 
Consolidated Statements of Cash Flows - NineSix Months Ended SeptemberJune 30, 20202021 and 20192020
7
Consolidated Statements of Stockholders’ Equity - Three and NineSix Months Ended SeptemberJune 30, 20202021 and 20192020
9
 
Notes to Consolidated Financial Statements
11
Note 1
11
Note 2
1213
Note 3
1615
Note 4
1716
Note 5
1817
Note 6
2422
Note 7
2725
Note 8
2826
Note 9
2927
Note 10
3431
 
General and Basis of Presentation
3533
 
Results of Operations
3634
Overview
3634
Consolidated Earnings Results (GAAP)
3936
Non-GAAP Financial Measures
4239
Segment Earnings Results
4542
DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
5350
Income Taxes
5452
 
Liquidity and Capital Resources
5452
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
5956
6057
6057
  
6057
6057
6057
6057
6057
6057
6158
 
6259
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 as “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019 (2019 Form 10-K),contain a more detailed description of other factors that may affect the forward-looking statements and should be referenced, 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 June 30,Six Months Ended June 30,
2020201920202019 2021202020212020
RevenuesRevenues Revenues 
ServicesServices$1,881 $2,014 $5,664 $6,060 Services$1,889 $1,791 $3,806 $3,783 
Commodity salesCommodity sales982 1,154 2,772 3,659 Commodity sales1,246 723 4,475 1,790 
OtherOther56 46 149 138 Other15 46 80 93 
Total RevenuesTotal Revenues2,919 3,214 8,585 9,857 Total Revenues3,150 2,560 8,361 5,666 
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 sales936 441 2,945 1,104 
Operations and maintenanceOperations and maintenance643 668 1,869 1,912 Operations and maintenance582 606 1,096 1,226 
Depreciation, depletion and amortizationDepreciation, depletion and amortization539 578 1,636 1,750 Depreciation, depletion and amortization528 532 1,069 1,097 
General and administrativeGeneral and administrative153 154 461 456 General and administrative160 155 316 308 
Taxes, other than income taxesTaxes, other than income taxes100 103 295 324 Taxes, other than income taxes108 103 218 195 
Loss (gain) on impairments and divestitures, net (Note 2)11 (3)1,987 (13)
Other (income) expense, net(1)1 (2)(1)
Loss on impairments and divestitures, net (Note 2)Loss on impairments and divestitures, net (Note 2)1,602 1,005 1,598 1,976 
Other income, netOther income, net(2)0 (3)(1)
Total Operating Costs, Expenses and OtherTotal Operating Costs, Expenses and Other2,100 2,263 8,005 6,915 Total Operating Costs, Expenses and Other3,914 2,842 7,239 5,905 
Operating Income819 951 580 2,942 
Operating (Loss) IncomeOperating (Loss) Income(764)(282)1,122 (239)
Other Income (Expense)Other Income (Expense) Other Income (Expense) 
Earnings from equity investmentsEarnings from equity investments194 173 562 526 Earnings from equity investments157 176 223 368 
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments(32)(21)(99)(61)Amortization of excess cost of equity investments(13)(35)(35)(67)
Interest, netInterest, net(383)(447)(1,214)(1,359)Interest, net(377)(395)(754)(831)
Other, net14 12 32 35 
Other, net (Note 2)Other, net (Note 2)20 16 243 18 
Total Other ExpenseTotal Other Expense(207)(283)(719)(859)Total Other Expense(213)(238)(323)(512)
Income (Loss) Before Income Taxes612 668 (139)2,083 
(Loss) Income Before Income Taxes(Loss) Income Before Income Taxes(977)(520)799 (751)
Income Tax Expense(140)(151)(304)(471)
Income Tax Benefit (Expense)Income Tax Benefit (Expense)237 (104)(114)(164)
Net Income (Loss)472 517 (443)1,612 
Net (Loss) IncomeNet (Loss) Income(740)(624)685 (915)
Net Income Attributable to Noncontrolling InterestsNet Income Attributable to Noncontrolling Interests(17)(11)(45)(32)Net Income Attributable to Noncontrolling Interests(17)(13)(33)(28)
Net Income (Loss) Attributable to Kinder Morgan, Inc.$455 $506 $(488)$1,580 
Net (Loss) Income Attributable to Kinder Morgan, Inc.Net (Loss) Income Attributable to Kinder Morgan, Inc.$(757)$(637)$652 $(943)
Class P SharesClass P SharesClass P Shares
Basic and Diluted Earnings (Loss) Per Common Share$0.20 $0.22 $(0.22)$0.69 
Basic and Diluted (Loss) Earnings Per ShareBasic and Diluted (Loss) Earnings Per Share$(0.34)$(0.28)$0.29 $(0.42)
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 Outstanding2,265 2,261 2,264 2,263 
The accompanying notes are an integral part of these consolidated financial statements.
4

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (LOSS)
(In millions, unaudited)
 Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
Net income (loss)$472 $517 $(443)$1,612 
Other comprehensive (loss) income, net of tax  
Change in fair value of hedge derivatives (net of tax benefit (expense) of $17, $(6), $5, and $39, respectively)(56)20 (16)(132)
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $1, $(13), $(22), and $(11), respectively)(5)40 72 35 
Foreign currency translation adjustments (net of tax benefit (expense) of $0, $2, $0, and $(5), respectively)0 (7)1 16 
Benefit plan adjustments (net of tax expense of $2, $3, $7 and $8, respectively)5 8 21 23 
Total other comprehensive (loss) income(56)61 78 (58)
Comprehensive income (loss)416 578 (365)1,554 
Comprehensive income attributable to noncontrolling interests(17)(8)(45)(28)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.$399 $570 $(410)$1,526 
 Three Months Ended June 30,Six Months Ended June 30,
 2021202020212020
Net (loss) income$(740)$(624)$685 $(915)
Other comprehensive (loss) income, net of tax  
Change in fair value of hedge derivatives (net of tax benefit (expense) of $47, $57, $94 and $(12), respectively)(157)(189)(313)40 
Reclassification of change in fair value of derivatives to net (loss) income (net of tax expense of $9, $14, $27 and $23, respectively)30 47 89 77 
Foreign currency translation adjustments (net of tax expense of $0, $0, $0 and $0, respectively)0 0 0 1 
Benefit plan adjustments (net of tax expense of $1, $2, $5 and $5, respectively)5 5 22 16 
Total other comprehensive (loss) income(122)(137)(202)134 
Comprehensive (loss) income(862)(761)483 (781)
Comprehensive income attributable to noncontrolling interests(17)(13)(33)(28)
Comprehensive (loss) income attributable to Kinder Morgan, Inc.$(879)$(774)$450 $(809)
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 June 30, 2021December 31, 2020
ASSETSASSETS ASSETS 
Current AssetsCurrent Assets Current Assets 
Cash and cash equivalentsCash and cash equivalents$632 $185 Cash and cash equivalents$1,365 $1,184 
Restricted depositsRestricted deposits67 24 Restricted deposits604 25 
Marketable securities at fair value0 925 
Accounts receivableAccounts receivable1,142 1,379 Accounts receivable1,416 1,293 
Fair value of derivative contractsFair value of derivative contracts257 84 Fair value of derivative contracts221 185 
InventoriesInventories317 371 Inventories396 348 
Other current assetsOther current assets257 270 Other current assets281 168 
Total current assetsTotal current assets2,672 3,238 Total current assets4,283 3,203 
Property, plant and equipment, netProperty, plant and equipment, net35,958 36,419 Property, plant and equipment, net34,570 35,836 
InvestmentsInvestments8,014 7,759 Investments7,650 7,917 
GoodwillGoodwill19,851 21,451 Goodwill19,851 19,851 
Other intangibles, netOther intangibles, net2,510 2,676 Other intangibles, net1,585 2,453 
Deferred income taxesDeferred income taxes671 857 Deferred income taxes492 536 
Deferred charges and other assetsDeferred charges and other assets2,145 1,757 Deferred charges and other assets1,744 2,177 
Total AssetsTotal Assets$71,821 $74,157 Total Assets$70,175 $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$2,183 $2,558 
Accounts payableAccounts payable774 914 Accounts payable949 837 
Accrued interestAccrued interest351 548 Accrued interest479 525 
Accrued taxesAccrued taxes335 364 Accrued taxes217 267 
Accrued contingenciesAccrued contingencies315 89 Accrued contingencies232 307 
Other current liabilitiesOther current liabilities544 708 Other current liabilities999 580 
Total current liabilitiesTotal current liabilities4,376 5,100 Total current liabilities5,059 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 Outstanding30,008 30,838 
Debt fair value adjustmentsDebt fair value adjustments1,379 1,032 Debt fair value adjustments1,069 1,293 
Total long-term debtTotal long-term debt32,660 31,915 Total long-term debt31,077 32,131 
Other long-term liabilities and deferred creditsOther long-term liabilities and deferred credits2,093 2,253 Other long-term liabilities and deferred credits2,216 2,202 
Total long-term liabilities and deferred creditsTotal long-term liabilities and deferred credits34,753 34,168 Total long-term liabilities and deferred credits33,293 34,333 
Total LiabilitiesTotal Liabilities39,129 39,268 Total Liabilities38,352 39,407 
Commitments and contingencies (Notes 3 and 9)Commitments and contingencies (Notes 3 and 9)Commitments and contingencies (Notes 3 and 9)00
Redeemable Noncontrolling InterestRedeemable Noncontrolling Interest747 803 Redeemable Noncontrolling Interest683 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, 2,264,604,747 and 2,264,257,336 shares, respectively, issued and outstanding
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,604,747 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 capital41,793 41,756 
Accumulated deficitAccumulated deficit(9,945)(7,693)Accumulated deficit(10,496)(9,936)
Accumulated other comprehensive lossAccumulated other comprehensive loss(255)(333)Accumulated other comprehensive loss(609)(407)
Total Kinder Morgan, Inc.’s stockholders’ equityTotal Kinder Morgan, Inc.’s stockholders’ equity31,559 33,742 Total Kinder Morgan, Inc.’s stockholders’ equity30,711 31,436 
Noncontrolling interestsNoncontrolling interests386 344 Noncontrolling interests429 402 
Total Stockholders’ EquityTotal Stockholders’ Equity31,945 34,086 Total Stockholders’ Equity31,140 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$70,175 $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, Six Months Ended June 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)$685 $(915)
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 amortization1,069 1,097 
Deferred income taxesDeferred income taxes164 254 Deferred income taxes105 28 
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments99 61 Amortization of excess cost of equity investments35 67 
Loss (gain) on impairments and divestitures, net (Note 2)1,987 (13)
Loss on impairments and divestitures, net (Note 2)Loss on impairments and divestitures, net (Note 2)1,598 1,976 
Gain on sale of interest in equity investment (Note 2)Gain on sale of interest in equity investment (Note 2)(206)0 
Earnings from equity investmentsEarnings from equity investments(562)(526)Earnings from equity investments(223)(368)
Distributions from equity investment earningsDistributions from equity investment earnings487 412 Distributions from equity investment earnings346 317 
Changes in components of working capitalChanges in components of working capitalChanges in components of working capital
Accounts receivableAccounts receivable238 224 Accounts receivable(130)335 
InventoriesInventories41 (28)Inventories(51)28 
Other current assetsOther current assets14 97 Other current assets(31)48 
Accounts payableAccounts payable(107)(266)Accounts payable145 (182)
Accrued interest, net of interest rate swapsAccrued interest, net of interest rate swaps(208)(218)Accrued interest, net of interest rate swaps(42)(65)
Accrued taxesAccrued taxes(25)(107)Accrued taxes(51)(23)
Other current liabilitiesOther current liabilities(111)(136)Other current liabilities195 (96)
Rate reparations, refunds and other litigation reserve adjustmentsRate reparations, refunds and other litigation reserve adjustments(102)(12)
Other, netOther, net72 5 Other, net(31)(3)
Net Cash Provided by Operating ActivitiesNet Cash Provided by Operating Activities3,282 3,121 Net Cash Provided by Operating Activities3,311 2,232 
Cash Flows From Investing ActivitiesCash Flows From Investing ActivitiesCash Flows From Investing Activities
Capital expendituresCapital expenditures(1,351)(1,719)Capital expenditures(545)(963)
Proceeds from sales of assets and investments, net of working capital adjustments907 80 
Proceeds from sales of investmentsProceeds from sales of investments413 907 
Contributions to investmentsContributions to investments(365)(1,148)Contributions to investments(26)(225)
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 earnings48 86 
Other, netOther, net(72)(30)Other, net(1)(46)
Net Cash Used in Investing ActivitiesNet Cash Used in Investing Activities(776)(2,610)Net Cash Used in Investing Activities(111)(241)
Cash Flows From Financing ActivitiesCash Flows From Financing ActivitiesCash Flows From Financing Activities
Issuances of debtIssuances of debt3,888 5,118 Issuances of debt3,110 2,652 
Payments of debtPayments of debt(3,991)(6,303)Payments of debt(4,273)(3,037)
Debt issue costsDebt issue costs(23)(9)Debt issue costs(12)(11)
Common stock dividends(1,764)(1,593)
DividendsDividends(1,212)(1,166)
Repurchases of common shares(50)(2)
Repurchases of sharesRepurchases of shares0 (50)
Contributions from investment partner and noncontrolling interestsContributions from investment partner and noncontrolling interests11 138 Contributions from investment partner and noncontrolling interests3 9 
Distributions to investment partnerDistributions to investment partner(60)0 Distributions to investment partner(45)(38)
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds0 (879)
Distributions to noncontrolling interests - other(11)(42)
Distributions to noncontrolling interestsDistributions to noncontrolling interests(8)(7)
Other, netOther, net(13)(28)Other, net(3)(1)
Net Cash Used in Financing ActivitiesNet Cash Used in Financing Activities(2,013)(3,600)Net Cash Used in Financing Activities(2,440)(1,649)
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 Deposits0 (5)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits490 (3,063)
Net Increase in Cash, Cash Equivalents and Restricted DepositsNet Increase in Cash, Cash Equivalents and Restricted Deposits760 337 
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$1,969 $546 
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, Six Months Ended June 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 period1,365 526 
Restricted Deposits, end of periodRestricted Deposits, end of period67 27 Restricted Deposits, end of period604 20 
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 period1,969 546 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits$490 $(3,063)
Net Increase in Cash, Cash Equivalents and Restricted DepositsNet Increase in Cash, Cash Equivalents and Restricted Deposits$760 $337 
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$28 $8 
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)807 891 
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, net8 136 
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 March 31, 2021Balance at March 31, 20212,264 $23 $41,775 $(9,124)$(487)$32,187 $416 $32,603 
Restricted sharesRestricted shares3 5 5 5 Restricted shares1 18 18 18 
Net income455 455 17 472 
Net (loss) incomeNet (loss) income(757)(757)17 (740)
DistributionsDistributions0 (4)(4)Distributions0 (5)(5)
ContributionsContributions0 2 2 Contributions0 1 1 
Common stock dividends(598)(598)(598)
DividendsDividends(615)(615)(615)
Other comprehensive lossOther comprehensive loss(56)(56)(56)Other comprehensive loss(122)(122)(122)
Balance at September 30, 20202,264 $23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
Balance at June 30, 2021Balance at June 30, 20212,265 $23 $41,793 $(10,496)$(609)$30,711 $429 $31,140 
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 shares3 (7)(7)(7)
Net income506 506 11 517 
Distributions0 (14)(14)
Contributions0 2 2 
Common stock dividends(569)(569)(569)
Other0 (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 March 31, 20202,261$23 $41,713 $(8,568)$(62)$33,106 $358 $33,464 
Restricted shares18 18 18 
Net (loss) income(637)(637)13 (624)
Distributions0 (4)(4)
Contributions0 4 4 
Dividends(597)(597)(597)
Other comprehensive loss(137)(137)(137)
Balance at June 30, 20202,261$23 $41,731 $(9,802)$(199)$31,753 $371 $32,124 
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 shares3 41 41 41 
Net (loss) income(488)(488)45 (443)
Distributions0 (11)(11)
Contributions0 8 8 
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 shares1 37 37 37 
Net income652 652 33 685 
Distributions0 (8)(8)
Contributions0 3 3 
Dividends(1,212)(1,212)(1,212)
Other0 (1)(1)
Other comprehensive loss(202)(202)(202)
Balance at June 30, 20212,265 $23 $41,793 $(10,496)$(609)$30,711 $429 $31,140 
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 
Distributions0 (42)(42)
Contributions0 3 3 
Common stock dividends(1,593)(1,593)(1,593)
Other0 (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 shares36 36 36 
Net (loss) income(943)(943)28 (915)
Distributions0 (7)(7)
Contributions0 6 6 
Dividends(1,166)(1,166)(1,166)
Other comprehensive income134 134 134 
Balance at June 30, 20202,261$23 $41,731 $(9,802)$(199)$31,753 $371 $32,124 
The accompanying notes are an integral part of these consolidated financial statements.

10


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

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines and 147144 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 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-19Stagecoach 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 billion, including a preliminary purchase price adjustment for working capital. The COVID-19 pandemic-related reduction in energy demandStagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and the dramatic decline in commodity prices that begana network of FERC-regulated natural gas transportation pipelines with multiple interconnects to impact usmajor interstate natural gas pipelines 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 wakenortheast region 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,U.S., including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities.TGP.

These events, among other factors, resultedKinetrex Energy Acquisition

On July 16, 2021, we announced an agreement to acquire Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $310 million. Kinetrex is a supplier of liquefied natural gas in certain non-cash impairments charges during 2020the 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 as further discussedwell as signed commercial agreements to begin construction on three additional landfill based RNG facilities. The transaction requires regulatory approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and is expected to close in Note 2.the third quarter of 2021.

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, as discussed above, we evaluate goodwill for impairment on May 31 of each year. For this purpose, we have 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 2 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.

The following table sets forth the allocation of net (loss) 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)$0.69 
________
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions, except per share amounts)
Net (Loss) Income Available to Stockholders$(757)$(637)$652 $(943)
Participating securities:
   Less: Net Income allocated to restricted stock awards(a)(3)(3)(6)(6)
Net (Loss) Income Allocated to Class P Stockholders$(760)$(640)$646 $(949)
Basic Weighted Average Shares Outstanding2,265 2,261 2,264 2,263 
Basic (Loss) Earnings Per Share$(0.34)$(0.28)$0.29 $(0.42)
(a)As of SeptemberJune 30, 2020,2021, there were approximately 1312 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 June 30,Six Months Ended June 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 awards12 12 12 12 
Convertible trust preferred securitiesConvertible trust preferred securities3 3 3 3 Convertible trust preferred securities3 3 3 3 

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2. 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 six months ended June 30, 2021 and 2020:
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)$1,600 $0 $1,600 $0 
Impairment of goodwill(a)0 1,000 0 1,000 
Gain on sale of interest in NGPL Holdings LLC(a)0 0 (206)0 
Loss on write-down of related party note receivable(a)0 0 117 0 
Gain on divestitures of long-lived assets(1)0 (1)0 
Products Pipelines
Impairment of long-lived and intangible assets0 0 0 21 
Terminals
Impairment of long-lived and intangible assets0 5 0 5 
Loss on divestitures of long-lived assets1 0 0 0 
CO2
Impairment of goodwill(a)0 0 0 600 
Impairment of long-lived assets(a)0 0 0 350 
Loss on divestitures of long-lived assets3 0 3 0 
Other gain on divestitures of long-lived assets(1)0 (4)0 
Pre-tax loss on impairments, divestitures and other write-downs, net$1,602 $1,005 $1,509 $1,976 
(a)See below for a further discussion of these items.

Impairments

Long-lived Assets

During the quarter ended June 30, 2021, we recognized a non-cash, long-lived asset impairment of $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 contracts expiring through 2024. The long-lived asset impairment test involves two steps. Step one is an assessment as to whether the asset’s net book value is 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 the 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, which we believe represented the estimated weighted average cost of capital of a theoretical market participant.

During the first quarter ofsix months ended June 30, 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 which resulted in a non-cash impairment of long-lived assets within our CO2 business segment shown in the above table during the six months ended June 30, 2020.

Goodwill

The results of our May 31, 2021 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. The fair value estimates used in the goodwill impairment test are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect
13


to market multiples, comparable sales transactions, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding future cash flows based on production growth rate assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit.

During the first quarter of 2020, we conducted interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, as of March 31, 2020, which resulted in impairments of long-lived assets and goodwill within our CO2 business segment during the three months ended March 31, 2020.

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


We recognized2020, we conducted our annual test of the followingrecoverability of goodwill for all of our reporting units which resulted in non-cash pre-tax loss (gain) on impairments and divestitures on assetsof goodwill within our CO2 business segment during the ninesix months ended SeptemberJune 30, 2020 and 2019:
Nine Months Ended September 30,
20202019
(In millions)
Natural Gas Pipelines
Impairment of goodwill$1,000 $0 
Impairments of inventory11 0 
Gain on divestitures of long-lived assets0 (10)
Products Pipelines
Impairment of long-lived and intangible assets21 0 
Terminals
Impairment of long-lived and intangible assets5 0 
Gain on divestitures of long-lived assets0 (3)
CO2
Impairment of goodwill600 0 
Impairment of long-lived assets350 0 
Kinder Morgan Canada
Loss on divestiture of long-lived assets0 2 
Other gain on divestitures of long-lived assets0 (2)
Pre-tax loss (gain) on divestitures and impairments, net$1,987 $(13)

Long-lived Assets

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

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

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

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

13


Goodwill

Changes in the amounts of our goodwill for the nine months ended September 30, 2020 are summarized by reporting unit as follows:
Natural Gas Pipelines 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 
Impairments0 (1,000)(600)0 0 0 (1,600)
Goodwill as of September 30, 2020$14,249 $2,343 $928 $1,378 $151 $802 $19,851 

•Our May 31, 2020 goodwill impairment tests of the Products Pipelines, Products Pipelines Terminals, Natural Gas Pipelines Regulated and 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 towithin our Natural Gas Pipelines Non-Regulated reporting unit, it experienced a sharp decline in customer demand for its servicesbusiness segment during the second quarter of 2020. This represented a timing lag from the initial economic decline impacts resulting from the severe downturnthree and six months ended June 30, 2020 as shown in the upstream energy industry, including our COtable above.2 business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter.

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

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

The results of the Natural Gas Pipelines Non-Regulated reporting unit goodwill impairment analysis was a partial impairment of goodwill of approximately $1,000 million as of May 31, 2020.

•For our March 31, 2020 interim goodwill impairment test of the CO2 reporting unit, we applied an income approach to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertainty and volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.
14



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

The fair value estimates used in the long-lived asset and goodwill test were primarily based on Level 3 inputs of the fair value hierarchy.
Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.

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

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 $413 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 six months ended June 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. 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.

1514


3. 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$0 $0 
Commercial paper notes(a)0 37 
Current portion of senior notes
6.85%, due February 2020(b)0 700 
6.50%, due April 2020(c)0 535 
5.30%, due September 2020(d)0 600 
6.50%, due September 2020(d)0 349 
5.00%, due February 2021750 0 
3.50%, due March 2021750 0 
5.80%, due March 2021400 0 
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)0 100 
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 
_______
June 30, 2021December 31, 2020
(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023$0 $0 
Commercial paper notes0 0 
Current portion of senior notes
5.00%, due February 2021(a)0 750 
3.50%, due March 2021(a)0 750 
5.80%, due March 2021(a)0 400 
5.00%, due October 2021(b)500 500 
8.625%, due January 2022260 0 
4.15%, due March 2022375 0 
1.50%, due March 2022(c)890 0 
Trust I preferred securities, 4.75%, due March 2028111 111 
Current portion of other debt47 47 
Total current portion of debt2,183 2,558 
Long-term debt (excluding current portion)
Senior notes29,320 30,141 
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035357 364 
Trust I preferred securities, 4.75%, due March 2028110 110 
Other221 223 
Total long-term debt30,008 30,838 
Total debt(d)$32,191 $33,396 
(a)Weighted average interest rateWe repaid the principal amounts on borrowings outstanding asthese senior notes during the first quarter of December 31, 2019 was 1.90%.2021.
(b)On January 9, 2020, we sold the approximate 25These notes were repaid on July 1, 2021. As of June 30, 2021, $506 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the salerepayment of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, whichthese maturing notes and associated accrued interest were used to partially repay debt that maturedheld 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”escrow and included in the accompanying consolidated balance sheet.sheet within “Restricted deposits.”
(c)In April 2020, we repaid $535 millionConsists of maturing senior notes.
(d)In September 2020, we repaid a combined $949 million of maturing senior notes using proceeds fromdenominated in Euros that have been converted to U.S. dollars. The June 30, 2021 balance is reported above at the exchange rate of 1.1858 U.S. dollars per Euro. As of June 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 $75 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 5 “Risk Management—Foreign Currency Risk Management”).
(f)(d)Excludes our “Debt fair value adjustments” which, as of SeptemberJune 30, 20202021 and December 31, 2019,2020, increased our total debt balances by $1,379$1,069 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.
16



Credit Facility

As of SeptemberJune 30, 2020,2021, we had 0 borrowings outstanding under our $4.0 billion credit facility, 0 borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of SeptemberJune 30, 20202021 was $3,919 million. As of SeptemberJune 30, 2020,2021, we were in compliance with all required covenants.

15


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 
June 30, 2021December 31, 2020
Carrying
value		Estimated
fair value		Carrying
value		Estimated
fair value
(In millions)
Total debt$33,260 $38,498 $34,689 $39,622 

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

4. Stockholders’ Equity

Class P Common Stock

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

Common Stock Dividends

Holders of our common stock participate in common stock dividends declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:
Three Months Ended September 30,Nine Months Ended September 30,
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 
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Per share cash dividend declared for the period$0.27 $0.2625 $0.54 $0.525 
Per share cash dividend paid in the period0.27 0.2625 0.5325 0.5125 

On OctoberJuly 21, 2020,2021, our board of directors declared a cash dividend of $0.2625$0.27 per common share for the quarterly period ended SeptemberJune 30, 2020,2021, which is payable on NovemberAugust 16, 20202021 to common shareholders of record as of the close of business on NovemberAugust 2, 2020.2021.

17


Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7)$0 $(326)$(333)
Other comprehensive (loss) gain before reclassifications(16)1 21 6 
Loss reclassified from accumulated other comprehensive loss72 0 0 72 
Net current-period change in accumulated other comprehensive (loss) income56 1 21 78 
Balance as of September 30, 2020$49 $1 $(305)$(255)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2020$(13)$0 $(394)$(407)
Other comprehensive (loss) gain before reclassifications(313)0 22 (291)
Loss reclassified from accumulated other comprehensive loss89 0 0 89 
Net current-period change in accumulated other comprehensive loss(224)0 22 (202)
Balance as of June 30, 2021$(237)$0 $(372)$(609)
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 0 0 35 
Net current-period change in accumulated other comprehensive income (loss)(97)20 23 (54)
Balance as of September 30, 2019$67 $(71)$(380)$(384)
16


Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7)$0 $(326)$(333)
Other comprehensive gain before reclassifications40 1 16 57 
Loss reclassified from accumulated other comprehensive loss77 0 0 77 
Net current-period change in accumulated other comprehensive (loss) income117 1 16 134 
Balance as of June 30, 2020$110 $1 $(310)$(199)


5.  Risk Management

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

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

18


Energy Commodity Price Risk Management

As of SeptemberJune 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)(7.9)MMBbl
Natural gas fixed price(34.8)(31.7)Bcf
Natural gas basis(34.8)(26.2)Bcf
NGL fixed price(1.2)(1.0)MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(2.4)(1.2)MMBbl
Crude oil basis(0.9)(9.8)MMBbl
Natural gas fixed price(9.7)(3.4)Bcf
Natural gas basis2.2 (15.8)Bcf
NGL fixed price(1.4)(2.1)MMBbl

As of SeptemberJune 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.

17


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 SeptemberJune 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 contracts3,5002,500 Mark-to-MarketDecember 2021
_______
(a)The principal amount of hedged senior notes consisted of $900$250 million included in “Current portion of debt” and $6,725$6,850 million included in “Long-term debt” on our accompanying consolidated balance sheet.

During the three months ended March 31, 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 rate through February 2028.

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 SeptemberJune 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
18



The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
Fair Value of Derivative ContractsFair Value of Derivative ContractsFair Value of Derivative Contracts
Derivatives AssetDerivatives LiabilityDerivatives AssetDerivatives Liability
September 30,
2020		December 31,
2019		September 30,
2020		December 31,
2019		June 30,
2021		December 31,
2020		June 30,
2021		December 31,
2020
LocationFair valueFair valueLocationFair valueFair value
(In millions)(In millions)
Derivatives designated as hedging instrumentsDerivatives designated as hedging instrumentsDerivatives designated as hedging instruments
Energy commodity derivative contractsEnergy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)$103 $31 $(25)$(43)Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)$18 $42 $(206)$(33)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)59 17 (4)(8)Deferred charges and other assets/(Other long-term liabilities and deferred credits)2 33 (87)(8)
SubtotalSubtotal162 48 (29)(51)Subtotal20 75 (293)(41)
Interest rate contractsInterest rate contractsFair value of derivative contracts/(Other current liabilities)134 45 (3)0 Interest rate contractsFair value of derivative contracts/(Other current liabilities)118 119 (3)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)634 313 (8)(1)Deferred charges and other assets/(Other long-term liabilities and deferred credits)395 575 (12)(7)
SubtotalSubtotal768 358 (11)(1)Subtotal513 694 (15)(10)
Foreign currency contractsForeign currency contractsFair value of derivative contracts/(Other current liabilities)0 0 (14)(6)Foreign currency contractsFair value of derivative contracts/(Other current liabilities)67 0 (8)(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)70 46 0 0 Deferred charges and other assets/(Other long-term liabilities and deferred credits)38 138 0 0 
SubtotalSubtotal70 46 (14)(6)Subtotal105 138 (8)(6)
TotalTotal1,000 452 (54)(58)Total638 907 (316)(57)
Derivatives not designated as hedging instrumentsDerivatives not designated as hedging instrumentsDerivatives not designated as hedging instruments
Energy commodity derivative contractsEnergy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)19 8 (10)(7)Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)18 24 (46)(21)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)6 0 (1)0 Deferred charges and other assets/(Other long-term liabilities and deferred credits)0 0 (5)0 
SubtotalSubtotal25 8 (11)(7)Subtotal18 24 (51)(21)
Interest rate contractsInterest rate contractsFair value of derivative contracts/(Other current liabilities)0 0 (3)0 Interest rate contractsFair value of derivative contracts/(Other current liabilities)0 0 (1)0 
SubtotalSubtotal0 0 (3)0 Subtotal0 0 (1)0 
TotalTotal25 8 (14)(7)Total18 24 (52)(21)
Total derivativesTotal derivatives$1,025 $460 $(68)$(65)Total derivatives$656 $931 $(368)$(78)

2019


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 June 30, 2021As of June 30, 2021
Energy commodity derivative contracts(a)Energy commodity derivative contracts(a)$3 $184 $0 $187 $(28)$0 $159 Energy commodity derivative contracts(a)$18 $20 $0 $38 $(35)$0 $3 
Interest rate contractsInterest rate contracts0 768 0 768 (2)0 766 Interest rate contracts0 513 0 513 (5)0 508 
Foreign currency contractsForeign currency contracts0 70 0 70 (14)0 56 Foreign currency contracts0 105 0 105 (8)0 97 
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 $0 $56 $(19)$(21)$16 Energy commodity derivative contracts(a)$6 $93 $0 $99 $(35)$0 $64 
Interest rate contractsInterest rate contracts0 358 0 358 0 0 358 Interest rate contracts0 694 0 694 (2)0 692 
Foreign currency contractsForeign currency contracts0 46 0 46 (6)0 40 Foreign currency contracts0 138 0 138 (6)0 132 
Balance sheet liability
fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral posted(b)Net amount
(In millions)
As of September 30, 2020
Energy commodity derivative contracts(a)$(29)$(11)$0 $(40)$28 $8 $(4)
Interest rate contracts0 (14)0 (14)2 0 (12)
Foreign currency contracts0 (14)0 (14)14 0 0 
As of December 31, 2019
Energy commodity derivative contracts(a)$(3)$(55)$0 $(58)$19 $0 $(39)
Interest rate contracts0 (1)0 (1)0 0 (1)
Foreign currency contracts0 (6)0 (6)6 0 0 
_______
Balance sheet liability
fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral posted(b)Net amount
(In millions)
As of June 30, 2021
Energy commodity derivative contracts(a)$(46)$(298)$0 $(344)$35 $55 $(254)
Interest rate contracts0 (16)0 (16)5 0 (11)
Foreign currency contracts0 (8)0 (8)8 0 0 
As of December 31, 2020
Energy commodity derivative contracts(a)$(7)$(56)$0 $(63)$35 $(8)$(36)
Interest rate contracts0 (10)0 (10)2 0 (8)
Foreign currency contracts0 (6)0 (6)6 0 0 
(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 June 30,Six Months Ended June 30,
2021202020212020
(In millions)
Interest rate contractsInterest, net$28 $26 $(189)$459 
Hedged fixed rate debt(a)Interest, net$(28)$(28)$190 $(468)
(a)As of SeptemberJune 30, 2020,2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $777$512 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


21
20


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 June 30,Three Months Ended June 30,
20202019202020192021202020212020
(In millions)(In millions)(In millions)(In millions)
Energy commodity derivative contractsEnergy commodity derivative contracts$(143)$96 Revenues—Commodity sales$(47)$9 Energy commodity derivative contracts$(215)$(273)Revenues—Commodity sales$(53)$(84)
Costs of sales(2)(2)
Costs of sales(7)(3)
Interest rate contractsInterest rate contracts0 (1)Earnings from equity investments(c)(1)0 Interest rate contracts1 (1)Earnings from equity investments(c)0 0 
Foreign currency contractsForeign currency contracts70 (69)Other, net61 (59)Foreign currency contracts10 28 Other, net16 25 
TotalTotal$(73)$26 Total$6 $(53)Total$(204)$(246)Total$(39)$(61)

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)$15 
Costs of sales(12)8 
Interest rate contracts(9)(2)Earnings from equity investments(c)(1)2 
Foreign currency contracts17 (95)Other, net64 (71)
Total$(21)$(171)Total$(94)$(46)
_______
Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Six Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions)(In millions)
Energy commodity derivative contracts$(374)$114 Revenues—Commodity sales$(73)$(98)
Costs of sales2 (5)
Interest rate contracts2 (9)Earnings from equity investments(c)0 0 
Foreign currency contracts(35)(53)Other, net(45)3 
Total$(407)$52 Total$(116)$(100)
(a)We expect to reclassify an approximate $68approximately $121 million gainof loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of SeptemberJune 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 ninesix months ended SeptemberJune 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$0 $0 $0 $(8)
Total$0 $0 $0 $(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 0 18 (3)
Earnings from equity investments(b)0 0 0 2 
Total(a)$99 $12 $371 $35 
_______
Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$(33)$149 $(663)$266 
Costs of sales(2)2 160 6 
Earnings from equity investments(2)0 (2)0 
Total(a)$(37)$151 $(505)$272 
(a)The three and ninesix months ended SeptemberJune 30, 20202021 amounts include approximate gainslosses of $96$7 million and $349$455 million, respectively, and the three and ninesix months ended SeptemberJune 30, 20192020 amounts include an approximate lossgains of $4$179 million and $2$253 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.
(b)Amounts represent our share of an equity investee’s income (loss).

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of SeptemberJune 30, 20202021 and December 31, 2019,2020, we had 0
21


outstanding letters of credit supporting our commodity price risk management program. As of SeptemberJune 30, 2020,2021, we had cash margins of $32$77 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 SeptemberJune 30, 20202021 represents the net of our initial margin requirements of $24$22 million and counterparty variation margin requirements of $8$55 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 SeptemberJune 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 $169 million of additional collateral.

23


6. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
Three Months Ended September 30, 2020Three Months Ended June 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 $1 $(2)$1,071 Firm services(b)$799 $66 $198 $0 $0 $1,063 
Fee-based servicesFee-based services173 228 91 8 3 503 Fee-based services176 244 84 10 0 514 
Total servicesTotal services991 297 276 9 1 1,574 Total services975 310 282 10 0 1,577 
Commodity salesCommodity salesCommodity sales
Natural gas salesNatural gas sales507 0 0 1 (2)506 Natural gas sales674 0 0 1 (3)672 
Product salesProduct sales158 97 5 180 (5)435 Product sales248 157 7 258 (13)657 
Total commodity salesTotal commodity sales665 97 5 181 (7)941 Total commodity sales922 157 7 259 (16)1,329 
Total revenues from contracts with customersTotal revenues from contracts with customers1,656 394 281 190 (6)2,515 Total revenues from contracts with customers1,897 467 289 269 (16)2,906 
Other revenues(c)Other revenues(c)Other revenues(c)
Leasing services(d)Leasing services(d)119 42 143 13 0 317 Leasing services(d)118 43 144 15 1 321 
Derivatives adjustments on commodity salesDerivatives adjustments on commodity sales(6)0 0 46 0 40 Derivatives adjustments on commodity sales(37)(1)0 (47)0 (85)
OtherOther40 6 0 2 (1)47 Other(2)5 0 6 (1)8 
Total Other revenues153 48 143 61 (1)404 
Total other revenuesTotal other revenues79 47 144 (26)0 244 
Total revenuesTotal revenues$1,809 $442 $424 $251 $(7)$2,919 Total revenues$1,976 $514 $433 $243 $(16)$3,150 
2422



Three Months Ended June 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$796 $67 $189 $0 $0 $1,052 
Fee-based services157 182 95 10 (2)442 
Total services953 249 284 10 (2)1,494 
Commodity sales
Natural gas sales377 0 0 0 (1)376 
Product sales102 49 3 134 (4)284 
Total commodity sales479 49 3 134 (5)660 
Total revenues from contracts with customers1,432 298 287 144 (7)2,154 
Other revenues(c)
Leasing services(d)114 42 132 11 0 299 
Derivatives adjustments on commodity sales(11)0 0 75 0 64 
Other36 5 0 2 0 43 
Total other revenues139 47 132 88 0 406 
Total revenues$1,571 $345 $419 $232 $(7)$2,560 
Three 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)$882 $89 $256 $1 $(1)$1,227 
Fee-based services182 265 132 14 0 593 
Total services1,064 354 388 15 (1)1,820 
Commodity sales
Natural gas sales618 0 0 0 (1)617 
Product sales162 84 9 268 (7)516 
Total commodity sales780 84 9 268 (8)1,133 
Total revenues from contracts with customers1,844 438 397 283 (9)2,953 
Other revenues(c)
Leasing services57 45 111 13 0 226 
Derivatives adjustments on commodity sales23 0 0 (1)(1)21 
Other10 1 0 3 0 14 
Total Other revenues90 46 111 15 (1)261 
Total revenues$1,934 $484 $508 $298 $(10)$3,214 

Nine Months Ended September 30, 2020Six Months Ended June 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)$2,479 $215 $563 $1 $(2)$3,256 Firm services(b)$1,665 $125 $389 $0 $0 $2,179 
Fee-based servicesFee-based services523 670 307 31 1 1,532 Fee-based services354 465 165 25 0 1,009 
Total servicesTotal services3,002 885 870 32 (1)4,788 Total services2,019 590 554 25 0 3,188 
Commodity salesCommodity salesCommodity sales
Natural gas salesNatural gas sales1,385 0 0 1 (5)1,381 Natural gas sales3,993 0 0 2 (8)3,987 
Product salesProduct sales396 255 11 546 (22)1,186 Product sales468 282 12 487 (23)1,226 
Total commodity salesTotal commodity sales1,781 255 11 547 (27)2,567 Total commodity sales4,461 282 12 489 (31)5,213 
Total revenues from contracts with customersTotal revenues from contracts with customers4,783 1,140 881 579 (28)7,355 Total revenues from contracts with customers6,480 872 566 514 (31)8,401 
Other revenues(c)Other revenues(c)Other revenues(c)
Leasing services(d)Leasing services(d)346 126 404 34 0 910 Leasing services(d)237 86 287 27 0 637 
Derivatives adjustments on commodity salesDerivatives adjustments on commodity sales35 0 0 173 0 208 Derivatives adjustments on commodity sales(655)(1)0 (80)0 (736)
OtherOther91 16 0 6 (1)112 Other39 10 0 11 (1)59 
Total Other revenues472 142 404 213 (1)1,230 
Total other revenuesTotal other revenues(379)95 287 (42)(1)(40)
Total revenuesTotal revenues$5,255 $1,282 $1,285 $792 $(29)$8,585 Total revenues$6,101 $967 $853 $472 $(32)$8,361 

2523


Nine Months Ended September 30, 2019Six Months Ended June 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)$2,701 $253 $785 $1 $(3)$3,737 Firm services(b)$1,661 $146 $378 $0 $0 $2,185 
Fee-based servicesFee-based services561 752 398 45 0 1,756 Fee-based services350 442 216 23 (2)1,029 
Total servicesTotal services3,262 1,005 1,183 46 (3)5,493 Total services2,011 588 594 23 (2)3,214 
Commodity salesCommodity salesCommodity sales
Natural gas salesNatural gas sales1,979 0 0 1 (7)1,973 Natural gas sales878 0 0 0 (3)875 
Product salesProduct sales599 211 16 827 (23)1,630 Product sales238 158 6 366 (17)751 
Total commodity salesTotal commodity sales2,578 211 16 828 (30)3,603 Total commodity sales1,116 158 6 366 (20)1,626 
Total revenues from contracts with customersTotal revenues from contracts with customers5,840 1,216 1,199 874 (33)9,096 Total revenues from contracts with customers3,127 746 600 389 (22)4,840 
Other revenues(c)Other revenues(c)Other revenues(c)
Leasing services(d)Leasing services(d)167 129 325 39 0 660 Leasing services(d)227 84 261 21 0 593 
Derivatives adjustments on commodity salesDerivatives adjustments on commodity sales61 0 0 (10)0 51 Derivatives adjustments on commodity sales41 0 0 127 0 168 
OtherOther35 5 0 10 0 50 Other51 10 0 4 0 65 
Total Other revenues263 134 325 39 0 761 
Total other revenuesTotal other revenues319 94 261 152 0 826 
Total revenuesTotal revenues$6,103 $1,350 $1,524 $913 $(33)$9,857 Total revenues$3,446 $840 $861 $541 $(22)$5,666 
_______
(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 5 for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

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

As of SeptemberJune 30, 20202021 and December 31, 2019,2020, our contract asset balances were $44$48 million and $27$20 million, respectively. Of the contract asset balance at December 31, 2019, $212020, $12 million was transferred to accounts receivable during the ninesix months ended SeptemberJune 30, 2020.2021. As of SeptemberJune 30, 20202021 and December 31, 2019,2020, our contract liability balances were $237$232 million and $232$239 million, respectively. Of the contract liability balance at December 31, 2019, $572020, $45 million was recognized as revenue during the ninesix months ended SeptemberJune 30, 2020.2021.

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Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of SeptemberJune 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 
Six months ended December 31, 2021Six months ended December 31, 2021$2,232 
202220223,344 20223,766 
202320232,715 20233,040 
202420242,361 20242,590 
202520252,191 
ThereafterThereafter14,722 Thereafter13,776 
TotalTotal$28,396 Total$27,595 

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.  Reportable Segments

Financial information by segment follows:
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended June 30,Six Months Ended June 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$1,960 $1,565 $6,070 $3,426 
Intersegment revenuesIntersegment revenues6 9 26 30 Intersegment revenues16 6 31 20 
Products PipelinesProducts Pipelines442 484 1,282 1,350 Products Pipelines514 345 967 840 
TerminalsTerminalsTerminals
Revenues from external customersRevenues from external customers423 507 1,282 1,521 Revenues from external customers433 418 852 859 
Intersegment revenuesIntersegment revenues1 1 3 3 Intersegment revenues0 1 1 2 
CO2
CO2
251 298 792 913 
CO2
243 232 472 541 
Corporate and intersegment eliminationsCorporate and intersegment eliminations(7)(10)(29)(33)Corporate and intersegment eliminations(16)(7)(32)(22)
Total consolidated revenuesTotal consolidated revenues$2,919 $3,214 $8,585 $9,857 Total consolidated revenues$3,150 $2,560 $8,361 $5,666 
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Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended June 30,Six Months Ended June 30,
2020201920202019 2021202020212020
(In millions)(In millions)
Segment EBDA(a)Segment EBDA(a)  Segment EBDA(a)  
Natural Gas PipelinesNatural Gas Pipelines$1,091 $1,092 $2,284 $3,383 Natural Gas Pipelines$(570)$(3)$1,533 $1,193 
Products PipelinesProducts Pipelines223 325 719 908 Products Pipelines265 227 513 496 
TerminalsTerminals246 295 732 884 Terminals246 229 473 486 
CO2
CO2
156 164 (453)558 
CO2
150 146 436 (609)
Kinder Morgan Canada0 0 0 (2)
Total Segment EBDATotal Segment EBDA1,716 1,876 3,282 5,731 Total Segment EBDA91 599 2,955 1,566 
DD&ADD&A(539)(578)(1,636)(1,750)DD&A(528)(532)(1,069)(1,097)
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments(32)(21)(99)(61)Amortization of excess cost of equity investments(13)(35)(35)(67)
General and administrative and corporate chargesGeneral and administrative and corporate charges(150)(162)(472)(478)General and administrative and corporate charges(150)(157)(298)(322)
Interest, netInterest, net(383)(447)(1,214)(1,359)Interest, net(377)(395)(754)(831)
Income tax expense(140)(151)(304)(471)
Income tax benefit (expense)Income tax benefit (expense)237 (104)(114)(164)
Total consolidated net income (loss)$472 $517 $(443)$1,612 
Total consolidated net (loss) incomeTotal consolidated net (loss) income$(740)$(624)$685 $(915)
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 
_______
June 30, 2021December 31, 2020
(In millions)
Assets
Natural Gas Pipelines$46,445 $48,597 
Products Pipelines9,138 9,182 
Terminals8,555 8,639 
CO2
2,433 2,478 
Corporate assets(b)3,604 3,077 
Total consolidated assets$70,175 $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.  Income Taxes

Income tax (benefit) expense included in our accompanying consolidated statements of operations is as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except percentages)
Income tax expense$140 $151 $304 $471 
Effective tax rate22.9 %22.6 %(218.7)%22.6 %

Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions, except percentages)
Income tax (benefit) expense$(237)$104 $114 $164 
Effective tax rate24.3 %(20.0)%14.3 %(21.8)%
The effective tax rate for the three months ended SeptemberJune 30, 20202021 is higher than the statutory federal rate of 21% primarily due to state income taxes.

The effective tax rate for the ninesix months ended SeptemberJune 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 Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

The effective tax rate for the three months ended June 30, 2020 is “negative” and lower than the statutory federal rate of 21% due to the $1,000 million 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 dividend-received deductions from our investments in Citrus and PPL.
26


The effective tax rate for the six months ended June 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 three and six months ended June 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.   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
27

impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

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

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seekssought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery 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 enjoin arbitrationDelaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from re-arbitrating both the breach of contract and negligent misrepresentation claims. The partiesOn April 15, 2021, Eni USA filed cross appealsa petition for writ of certiorari with the Final Judgment. The Delaware cross appeals were argued to the DelawareU.S. Supreme Court on September 9, 2020. The arbitration proceeding remains pending, but has been stayed by agreement pendingseeking review of the Delaware Supreme Court’s decision.
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This petition remains pending.

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 million. Hiland Partners denies and will vigorously defend against these claims.

Pipeline Integrity and Releases

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

General

As of SeptemberJune 30, 20202021 and December 31, 2019,2020, our total reserve for legal matters was $280$185 million and $203$273 million, respectively.

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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.

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
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mines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

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

EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
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On March 4, 2016, the EPA issued its 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 Polymers, 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 ROD. There is also uncertaintyROD as well as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the allocation process andongoing discussions with the EPA conclude, or the FS areis completed and the RI/FS is finalized, 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, 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 case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August
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10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Court of Appeals.Fifth Circuit. 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 SeptemberJune 30, 20202021 and December 31, 2019,2020, we have accrued a total reserve for environmental liabilities in the amount of $253$248 million and $259$250 million, respectively. In addition, as of Septemberboth June 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. 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 quarter ended June 30, 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 billion, 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 interest in KML. On January 9, 2020, we sold our Pembina shares and received proceeds of approximately $907 million ($764 million after tax) which were used to repay maturing debt. The assets sold were part of our Natural Gas Pipelines and Terminals business segments.TGP.

COVID-19Kinetrex Energy Acquisition

The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that beganOn July 16, 2021, we announced an agreement to impact usacquire Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $310 million. Kinetrex is a supplier of liquefied natural gas in the firstMidwest 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 as well as signed commercial agreements to begin construction on three additional landfill based RNG facilities. Once they all become operational next year, total annual RNG production from the four sites is estimated to be over 4 Bcf. The transaction requires regulatory approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and is expected to close in the third 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.2021.

The events as described above resultedSale of an Interest in decreasesNGPL Holdings LLC

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of current and estimated long-term crude oil and NGL sale prices and volumes we expecta combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to realize and in significant reductions toa fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $413 million for our proportionate share of the market capitalizationinterests sold which included the transfer of many midstream and oil and gas producing companies. These events triggered us to review the carrying value$125 million of our long-lived assets$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 six months ended June 30, 2021. We and recoverabilityBrookfield now each hold a 37.5% interest in NGPL Holdings.

February 2021 Winter Storm

Our year-to-date earnings reflect impacts of goodwill asthe February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below. Some of March 31, 2020 and impacted our annual goodwill testing performed as of May 31, 2020. Our evaluations resulted in the recognitiontransactions executed during the first six monthswinter 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, 2020the unprecedented circumstances of a $350 million impairment for long-lived assets inthe winter storm, which could adversely affect our CO2 business segmentfuture earnings, cash flows and goodwill impairments of $1,000 millionfinancial condition.

2021 Dividends 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.”Discretionary Capital

We have placed a priority on protecting our employees during this pandemic while continuing to provide essential services to our customers. We continue to follow the Centers for Disease Control guidelines for those employees that perform essential tasks in our operations and have taken a cautious enterprise-wide approach with a phased return to workplace process for our employees who are currently working remotely. During the nine months ended September 30, 2020, our incremental employee safety costs associated with COVID-19 mitigation have been approximately $11 million, primarily for personal protective equipment, enhanced cleaning protocols, temperature screening and other measures we adopted to protect our employees. We continue to operate our assets safely and efficiently during this challenging period.

2020 Outlook

As previously announced, for 2020 our original budget contemplated DCF of approximately $5.1 billion ($2.24 per common share) and Adjusted EBITDA of approximately $7.6 billion. We now expect DCF to be below plan by slightly more than 10% and Adjusted EBITDA to be below plan by slightly more than 8%. As a result, we now expect to enddeclare dividends of $1.08 per share for 2021, a 3% increase from the 2020 with a Net Debt-to-Adjusted EBITDA ratiodeclared dividends of approximately 4.6 times.

Market conditions also negatively impacted a number of planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. We therefore$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 Measures”below.

Considerable uncertainty exists with respect to the future pace and extent of a global economic recovery from the effects of the COVID-19 pandemic. Our 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 Factors”below and “Information Regarding Forward-Looking Statements”at the beginning of this report for more information. Furthermore, we disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.statement.

Results of Operations

Overview

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

GAAP Financial Measures

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

Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP netNet (loss) 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 (loss) 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 (Loss) 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 (loss) 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 (loss) 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 (loss) earnings per common share. See “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) 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 (loss) 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 (loss) 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 (Loss) 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 (loss) income attributable to Kinder Morgan, Inc. In prior periods Net (loss). income was considered the comparable GAAP measure and has been updated to Net (loss) income 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 (Loss) 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.)
37


Net Debt

Net Debt is calculated, based on amounts as of June 30, 2021, by subtracting the following amounts from our debt balance of $33,260 million: (i) cash and cash equivalents;equivalents of $1,365 million (which, as of June 30, 2021, the cash and cash equivalents component of Net Debt includes “Restricted deposits” of approximately $506 million held in escrow that were used on July 1, 2021 for the repayment of senior notes plus associated accrued interest); (ii) the preferred interest in the general partner of KMP (which was redeemed in January 2020); (iii) debt fair value adjustments;adjustments of $1,069 million; and (iv)(iii) the foreign exchange impact on Euro-denominated bonds of $125 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.

3835

Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.
Three Months Ended September 30,Three Months Ended June 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 $(1)— %Natural Gas Pipelines$(570)$(3)$(567)(18,900)%
Products PipelinesProducts Pipelines223 325 (102)(31)%Products Pipelines265 227 38 17 %
TerminalsTerminals246 295 (49)(17)%Terminals246 229 17 7 %
CO2
CO2
156 164 (8)(5)%
CO2
150 146 4 3 %
Total Segment EBDATotal Segment EBDA1,716 1,876 (160)(9)%Total Segment EBDA91 599 (508)(85)%
DD&ADD&A(539)(578)39 7 %DD&A(528)(532)4 1 %
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments(32)(21)(11)(52)%Amortization of excess cost of equity investments(13)(35)22 63 %
General and administrative and corporate chargesGeneral and administrative and corporate charges(150)(162)12 7 %General and administrative and corporate charges(150)(157)7 4 %
Interest, netInterest, net(383)(447)64 14 %Interest, net(377)(395)18 5 %
Income before income taxes612 668 (56)(8)%
Income tax expense(140)(151)11 7 %
Loss before income taxesLoss before income taxes(977)(520)(457)(88)%
Income tax benefit (expense)Income tax benefit (expense)237 (104)341 328 %
Net income472 517 (45)(9)%
Net lossNet loss(740)(624)(116)(19)%
Net income attributable to noncontrolling interestsNet income attributable to noncontrolling interests(17)(11)(6)(55)%Net income attributable to noncontrolling interests(17)(13)(4)(31)%
Net income attributable to Kinder Morgan, Inc.$455 $506 $(51)(10)%
Net loss attributable to Kinder Morgan, Inc.Net loss attributable to Kinder Morgan, Inc.$(757)$(637)$(120)(19)%

Nine Months Ended September 30,
20202019Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$2,284 $3,383 $(1,099)(32)%
Products Pipelines719 908 (189)(21)%
Terminals732 884 (152)(17)%
CO2
(453)558 (1,011)(181)%
Kinder Morgan Canada— (2)2 100 %
Total Segment EBDA3,282 5,731 (2,449)(43)%
DD&A(1,636)(1,750)114 7 %
Amortization of excess cost of equity investments(99)(61)(38)(62)%
General and administrative and corporate charges(472)(478)6 1 %
Interest, net(1,214)(1,359)145 11 %
(Loss) income before income taxes(139)2,083 (2,222)(107)%
Income tax expense(304)(471)167 35 %
Net (loss) income(443)1,612 (2,055)(127)%
Net income attributable to noncontrolling interests(45)(32)(13)(41)%
Net (loss) income attributable to Kinder Morgan, Inc.$(488)$1,580 $(2,068)(131)%
_______
Six Months Ended June 30,
20212020Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$1,533 $1,193 $340 28 %
Products Pipelines513 496 17 3 %
Terminals473 486 (13)(3)%
CO2
436 (609)1,045 172 %
Total Segment EBDA2,955 1,566 1,389 89 %
DD&A(1,069)(1,097)28 3 %
Amortization of excess cost of equity investments(35)(67)32 48 %
General and administrative and corporate charges(298)(322)24 7 %
Interest, net(754)(831)77 9 %
Income (loss) before income taxes799 (751)1,550 206 %
Income tax expense(114)(164)50 30 %
Net income (loss)685 (915)1,600 175 %
Net income attributable to noncontrolling interests(33)(28)(5)(18)%
Net income (loss) attributable to Kinder Morgan, Inc.$652 $(943)$1,595 169 %
(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
36


Income (loss) before income taxes decreased $56 million and $2,222Net loss attributable to Kinder Morgan, Inc. increased $120 million for the three and nine months ended SeptemberJune 30, 2020, respectively,2021 and Net income attributable to Kinder Morgan, Inc. increased $1,595 million for the six months ended June 30, 2021 as compared to the respective prior year periods. The decreasessecond quarter increased loss was primarily due to a $1,600 million pre-tax non-cash impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in results were2021 resulting from anticipated lower volumes and rates on contract renewals compared to the $1 billion non-cash impairment of goodwill associated with our Natural Gas Pipelines Non-Regulated reporting unit recognized in 2020. The year-to-date increase was primarily impacted by lowerhigher earnings from our Products Pipelines and Terminals in the comparative three-month periods and from all of our business segments in the comparative nine-month periods primarily attributable to COVID-19-related reduced energy demand and commodity price impacts and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and TerminalsCO2 business segments partially offset byprimarily related to the benefitFebruary 2021 winter storm and therefore largely nonrecurring, and a decrease of completed expansion projects$350 million of impairments in 2021 as compared to 2020 reflecting the $1,600 million pre-tax non-cash asset impairment loss in 2021 in our Natural Gas PipelinesPipeline business segment and by lower interest expense and DD&A expense. The year-to-date decrease also included acompared 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 CO2business segment. The impacts of the long-lived asset impairments for both periods were partially offset by associated tax benefits. In addition to the above, the second quarter and year-to-date changes were favorably impacted by higher earnings from our Products Pipelines business segment, lower interest expense, DD&A expense (including amortization of excess cost of equity investments), and general and administrative and corporate charges expense.

Certain Items Affecting Consolidated Earnings Results
Three Months Ended September 30,Three Months Ended June 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 $(8)Natural Gas Pipelines$(570)$1,634 $1,064 $(3)$1,019 $1,016 $48 
Products PipelinesProducts Pipelines223 46 269 325 11 336 (67)Products Pipelines265 28 293 227 — 227 66 
TerminalsTerminals246 — 246 295 — 295 (49)Terminals246 — 246 229 — 229 17 
CO2
CO2
156 (2)154 164 (15)149 5 
CO2
150 1 151 146 10 156 (5)
Total Segment EBDA(a)Total Segment EBDA(a)1,716 35 1,751 1,876 (6)1,870 (119)Total Segment EBDA(a)91 1,663 1,754 599 1,029 1,628 126 
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(541)— (541)(567)— (567)26 
General and administrative and corporate charges(a)General and administrative and corporate charges(a)(150)11 (139)(162)5 (157)18 General and administrative and corporate charges(a)(150)— (150)(157)— (157)7 
Interest, net(a)Interest, net(a)(383)(8)(391)(447)(5)(452)61 Interest, net(a)(377)(3)(380)(395)(1)(396)16 
Income before income taxes612 38 650 668 (6)662 (12)
Income tax expense(b)(140)(8)(148)(151)8 (143)(5)
Net income472 30 502 517 2 519 (17)
(Loss) income before income taxes(Loss) income before income taxes(977)1,660 683 (520)1,028 508 175 
Income tax benefit (expense)(b)Income tax benefit (expense)(b)237 (387)(150)(104)(10)(114)(36)
Net (loss) incomeNet (loss) income(740)1,273 533 (624)1,018 394 139 
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)(17)— (17)(13)— (13)(4)
Net income attributable to Kinder Morgan, Inc.$455 $30 $485 $506 $2 $508 $(23)
Net (loss) income attributable to Kinder Morgan, Inc.Net (loss) income attributable to Kinder Morgan, Inc.$(757)$1,273 $516 $(637)$1,018 $381 $135 

4037

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 $(85)
Products Pipelines719 50 769 908 28 936 (167)
Terminals732 — 732 884 — 884 (152)
CO2
(453)938 485 558 (36)522 (37)
Kinder Morgan Canada— — — (2)2 — — 
Total Segment EBDA(a)3,282 1,981 5,263 5,731 (27)5,704 (441)
DD&A and amortization of excess cost of equity investments(1,735)— (1,735)(1,811)— (1,811)76 
General and administrative and corporate charges(a)(472)36 (436)(478)11 (467)31 
Interest, net(a)(1,214)(8)(1,222)(1,359)(6)(1,365)143 
(Loss) income before income taxes(139)2,009 1,870 2,083 (22)2,061 (191)
Income tax expense(b)(304)(114)(418)(471)15 (456)38 
Net (loss) income(443)1,895 1,452 1,612 (7)1,605 (153)
Net income attributable to noncontrolling interests(a)(45)— (45)(32)(1)(33)(12)
Net (loss) income attributable to Kinder Morgan, Inc.$(488)$1,895 $1,407 $1,580 $(8)$1,572 $(165)
_______
Six Months Ended June 30,
20212020
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$1,533 $1,625 $3,158 $1,193 $1,002 $2,195 $963 
Products Pipelines513 43 556 496 4 500 56 
Terminals473 — 473 486 — 486 (13)
CO2
436 6 442 (609)940 331 111 
Total Segment EBDA(a)2,955 1,674 4,629 1,566 1,946 3,512 1,117 
DD&A and amortization of excess cost of equity investments(1,104)— (1,104)(1,164)— (1,164)60 
General and administrative and corporate charges(a)(298)— (298)(322)25 (297)(1)
Interest, net(a)(754)(9)(763)(831)— (831)68 
Income (loss) before income taxes799 1,665 2,464 (751)1,971 1,220 1,244 
Income tax expense(b)(114)(427)(541)(164)(106)(270)(271)
Net income (loss)685 1,238 1,923 (915)1,865 950 973 
Net income attributable to noncontrolling interests(a)(33)— (33)(28)— (28)(5)
Net income (loss) attributable to Kinder Morgan, Inc.$652 $1,238 $1,890 $(943)$1,865 $922 $968 
(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$135 million and $165$968 million for the three and ninesix months ended SeptemberJune 30, 2020,2021, respectively, as compared to the respective prior year periods. Decreases in Adjusted Segment EBDA from the priorThe second 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 and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 oninterest expense. The year-to-date increase was impacted by higher earnings from our Natural Gas Pipelines and TerminalsCO2 business segments partially offset byprimarily related to the benefit of completed expansion projects inFebruary 2021 winter storm, and therefore largely nonrecurring, higher earnings from our Natural GasProducts Pipelines business segment.segment and lower interest expense and DD&A expense.

4138

Non-GAAP Financial Measures

Reconciliation of Net (Loss) 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 June 30,Six Months Ended June 30,
20202019202020192021202020212020
(In millions)(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)$455 $506 $(488)$1,580 
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)$(757)$(637)$652 $(943)
Total Certain ItemsTotal Certain Items30 2 1,895 (8)Total Certain Items1,273 1,018 1,238 1,865 
Adjusted Earnings(a)Adjusted Earnings(a)485 508 1,407 1,572 Adjusted Earnings(a)516 381 1,890 922 
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)604 659 1,242 1,350 
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)170 132 589 313 
Cash taxes(c)(b)Cash taxes(c)(b)(49)(12)(57)(76)Cash taxes(c)(b)(45)(5)(44)(8)
Sustaining capital expenditures(c)(b)Sustaining capital expenditures(c)(b)(177)(173)(477)(477)Sustaining capital expenditures(c)(b)(210)(159)(317)(300)
Other items(d)(c)Other items(d)(c)(7)(41)(22)6 Other items(d)(c)(10)(7)(6)(15)
DCFDCF$1,085 $1,140 $3,347 $3,639 DCF$1,025 $1,001 $3,354 $2,262 

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)6 
DCF$1,085 $1,140 $3,347 $3,639 
Adjusted Earnings per common share$0.21 $0.22 $0.62 $0.69 
Weighted average common shares outstanding for dividends(g)2,276 2,277 2,276 2,276 
DCF per common share$0.48 $0.50 $1.47 $1.60 
Declared dividends per common share$0.2625 $0.25 $0.7875 $0.75 
_______
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions, except per share amounts)
Natural Gas Pipelines$1,064 $1,016 $3,158 $2,195 
Products Pipelines293 227 556 500 
Terminals246 229 473 486 
CO2
151 156 442 331 
Adjusted Segment EBDA(a)1,754 1,628 4,629 3,512 
General and administrative and corporate charges(a)(150)(157)(298)(297)
Joint venture DD&A and income tax expense(a)(b)83 110 186 229 
Net income attributable to noncontrolling interests(a)(17)(13)(33)(28)
Adjusted EBITDA1,670 1,568 4,484 3,416 
Interest, net(a)(380)(396)(763)(831)
Cash taxes(b)(45)(5)(44)(8)
Sustaining capital expenditures(b)(210)(159)(317)(300)
Other items(c)(10)(7)(6)(15)
DCF$1,025 $1,001 $3,354 $2,262 
Adjusted Earnings per share$0.23 $0.17 $0.83 $0.40 
Weighted average shares outstanding for dividends(d)2,277 2,274 2,277 2,275 
DCF per share$0.45 $0.44 $1.47 $0.99 
Declared dividends per share$0.27 $0.2625 $0.54 $0.525 
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net (Loss) 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.
42

(d)Includes non-cash pension expense and non-cash compensation associated with our restricted stock program.program, non-cash pension expense and pension contributions.
(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.
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Reconciliation of Net (Loss) 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)8 (114)15 
Noncontrolling interests associated with Certain Items— — — (1)
Other(19)4 5 (1)
Total Certain Items(d)30 2 1,895 (8)
DD&A and amortization of excess cost of equity 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 $5,598 
______
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions)
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)(a)$(757)$(637)$652 $(943)
Certain Items:
Fair value amortization(4)(4)(8)(12)
Legal, environmental and taxes other than income tax reserves28 — 112 (8)
Change in fair value of derivative contracts(b)28 32 42 (4)
Loss on impairments, divestitures and other write-downs, net(c)1,600 — 1,511 371 
Loss on impairments of goodwill(d)— 1,000 — 1,600 
Income tax Certain Items(387)(10)(427)(106)
Other8 — 8 24 
Total Certain Items(e)1,273 1,018 1,238 1,865 
DD&A and amortization of excess cost of equity investments541 567 1,104 1,164 
Income tax expense(f)150 114 541 270 
Joint venture DD&A and income tax expense(f)(g)83 110 186 229 
Interest, net(f)380 396 763 831 
Adjusted EBITDA$1,670 $1,568 $4,484 $3,416 
(a)In prior periods, Net (loss) income was considered the comparable GAAP measure and has been updated to Net (loss) income 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)NineThree and six months ended SeptemberJune 30, 2021 amounts include 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 anticipated lower volumes and rates on contract renewals. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings, offset partially by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby. Six months ended June 30, 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment, which are reported within “Loss (gain) on impairments and divestitures, net” on our Consolidated Earnings Results (GAAP) table above.the accompanying consolidated statement of operations.
(c)(d)NineThree and six months ended SeptemberJune 30, 2020 amount includesamounts include a non-cash impairmentsimpairment of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated andreporting unit. Six months ended June 30, 2020 amount also includes a non-cash impairment of goodwill associated with our CO2reporting units, respectively.unit.
(d)(e)Three months ended September 30, 2020 and 2019 amounts include $(4)2021 amount includes $127 million and $(2)2020 amount includes less than $1 million respectively, and nine months ended September 30, 2020 and 2019 amounts include $(4) million and $(15) million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.
(e)(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.


4340

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 Items8 (8)114 (15)
Income tax expense(a)148 143 418 456 
Unconsolidated joint venture income tax expense(a)23 23 66 71 
Income tax expense attributable to KML noncontrolling interests(a)— (2)— (6)
Income tax expense for DCF(a)$171 $164 $484 $521 
KML activities prior to December 16, 2019
Net income attributable to KML noncontrolling interests$— $9 $— $25 
KML noncontrolling interests associated with Certain Items— — — 1 
KML noncontrolling interests(a)— 9 — 26 
DD&A attributable to KML noncontrolling interests— 5 — 15 
Income tax expense attributable to KML noncontrolling interests(a)— 2 — 6 
KML noncontrolling interests DCF adjustments(a)$— $16 $— $47 
Net income attributable to noncontrolling interests (GAAP)$17 $11 $45 $32 
Less: KML noncontrolling interests(a)— 9 — 26 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))17 2 45 6 
Noncontrolling interests associated with Certain Items— — — 1 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)$17 $2 $45 $7 
44

Three Months Ended September 30,Nine Months Ended September 30,
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)$(85)
Consolidated joint venture partners’ sustaining capital expenditures2 2 4 5 
Joint venture sustaining capital expenditures$(30)$(33)$(80)$(80)
______
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In millions)
DD&A (GAAP)$528 $532 $1,069 $1,097 
Amortization of excess cost of equity investments (GAAP)13 35 35 67 
DD&A and amortization of excess cost of equity investments541 567 1,104 1,164 
Joint venture DD&A63 92 138 186 
DD&A and amortization of excess cost of equity investments for DCF$604 $659 $1,242 $1,350 
Income tax (benefit) expense (GAAP)$(237)$104 $114 $164 
Certain Items387 10 427 106 
Income tax expense(a)150 114 541 270 
Unconsolidated joint venture income tax expense(a)(b)20 18 48 43 
Income tax expense for DCF(a)$170 $132 $589 $313 
Additional joint venture information
Unconsolidated joint venture DD&A$74 $102 $160 $205 
Less: Consolidated joint venture partners’ DD&A11 10 22 19 
Joint venture DD&A63 92 138 186 
Unconsolidated joint venture income tax expense(a)(b)20 18 48 43 
Joint venture DD&A and income tax expense(a)$83 $110 $186 $229 
Unconsolidated joint venture cash taxes(b)$(34)$(6)$(34)$(10)
Unconsolidated joint venture sustaining capital expenditures$(32)$(26)$(52)$(52)
Less: Consolidated joint venture partners’ sustaining capital expenditures(2)(1)(3)(2)
Joint venture sustaining capital expenditures$(30)$(25)$(49)$(50)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and PlantationProducts (SE) Pipe Line equity investments.

41

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— — 1 2 
Earnings from equity investments169 141 484 431 
Other, net2 10 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 June 30,Six Months Ended June 30,
2021202020212020
(In millions, except operating statistics)
Revenues$1,976 $1,571 $6,101 $3,446 
Operating expenses(1,077)(729)(3,347)(1,577)
Loss on impairments and divestitures, net(1,599)(1,000)(1,599)(1,000)
Other income1 — 2 1 
Earnings from equity investments126 151 167 315 
Other, net3 4 209 8 
Segment EBDA(570)(3)1,533 1,193 
Certain Items(a)1,634 1,019 1,625 1,002 
Adjusted Segment EBDA$1,064 $1,016 $3,158 $2,195 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$48 $963 
Volumetric data(b)
Transport volumes (BBtu/d)36,537 35,080 36,878 36,704 
Sales volumes (BBtu/d)2,561 2,112 2,411 2,303 
Gathering volumes (BBtu/d)2,667 3,043 2,588 3,202 
NGLs (MBbl/d)30 29 30 30 
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $(4)$1,634 million and $(5)$1,625 million for the three and ninesix months ended SeptemberJune 30, 2021, respectively, and $1,019 million and $1,002 million for the three and six months ended June 30, 2020, respectively,respectively. Three and $(1) million for both three and ninesix months ended SeptemberJune 30, 2019 which includes $(14)2021 amounts include a pre-tax non-cash asset impairment loss of $1,600 million resulting from anticipated lower volumes and rates on contract renewals related to our South Texas gathering and processing assets and decreases in revenues of amortization of
45

regulatory liabilities (three$16 million and nine months 2020), partially offset by$22 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales (all periods).
(b)Includes non-revenue Certain Item amounts of $(5) million and $998 million for the three and ninesales. Six months ended SeptemberJune 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings, partially offset by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a certain litigation matter. Three and six months ended June 30, 2020 respectively, and $(1) million and $(20) million for the three and nine months ended September 30, 2019, respectively. Nine-month 2020 amountamounts primarily resulted from a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit. Nine-month 2019 amounts are primarily related tounit and a decrease in revenues of $23 million and an increase in earnings from certain equity investees’ amortizationrevenues of regulatory liabilities.$1 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales.
Other
(c)(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.

42

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

Three Months Ended SeptemberJune 30, 20202021 versus Three Months Ended SeptemberJune 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$68 29%
West RegionWest Region(5)(2)%1 — %West Region(18)(7)%
East RegionEast Region65 13 %77 15 %East Region(2)—%
Intrasegment eliminations— — %2 40 %
Total Natural Gas PipelinesTotal Natural Gas Pipelines$(8)(1)%$(128)(7)%Total Natural Gas Pipelines$48 5 %

NineSix Months Ended SeptemberJune 30, 20202021 versus NineSix Months Ended SeptemberJune 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$969 177%
West RegionWest Region(19)(2)%4 — %West Region(23)(4)%
East RegionEast Region117 7 %173 11 %East Region17 2%
Intrasegment eliminations— — %4 33 %
Total Natural Gas PipelinesTotal Natural Gas Pipelines$(85)(3)%$(852)(14)%Total Natural Gas Pipelines$963 44 %

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-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019:2020:
•Midstream’s decreases of $68$68 million (21%(29%) and $183$969 million (18%(177%), 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 higherand 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 offsetdriven by higher transportation revenues driven by new customer contractscommodity prices on our Texas intrastate natural gas pipeline operations. Toperationshese decreases were partially offset by ; (ii) higher volumes on our Hiland Midstream assets; and (iii) higher equity earnings due to the Gulf Coast ExpressPermian Highway Pipeline (Gulf Coast) being placed in service in September 2019. January 2021. These increases were partially offset by lower earnings on KinderHawk and South Texas assets due to lower volumes. 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 to certain purchase contracts 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$18 million (2%(7%) and $19$23 million (2%(4%), decreases, respectively, in the West Region were primarily due to decreases inlower earnings from (i) Ruby PipelineWyoming Interstate Company, L.L.C. primarily due to lower transportation revenuesLLC and an increase in operating expenses due to the recognition of a credit loss reserve associated with a shipper; (ii) Cheyenne PlainsColorado Interstate Gas Pipeline Company, L.L.C. as a result of the expiration of one shipper’s contract; and (iii) EPNG driven by higher operating expenses, partially offset by increased earnings from CIG resulting from an expansion project in the Denver Julesburg basin;lower revenues due to contract expirations; and
•$2 million (—%) decrease and $17 million (2%) increase, respectively, in the East Region’s increases of $65 million (13%) and $117 million (7%), respectively,Region were primarily due to (i) lower earnings on Fayetteville Express Pipeline LLC driven by lower revenues as a result of contract expirations; (ii) higher earnings from TGP due to weather-driven increases in reservation and park and loan revenues mostly during first quarter of 2021; and (iii) increased earnings from ELC and Southern LNGElba Liquefaction Company, L.L.C. resulting from the liquefaction units of the Elba Liquefaction project being placed into service in the later partfully operational as of 2019 and through the first eight months of 2020 and increased equityAugust 2020.

4643

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— 1 1 6 
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 June 30,Six Months Ended June 30,
2021202020212020
(In millions, except operating statistics)
Revenues$514 $345 $967 $840 
Operating expenses(268)(131)(487)(352)
Loss on impairments and divestitures, net— — — (21)
Earnings from equity investments19 13 33 28 
Other, net— — — 1 
Segment EBDA265 227 513 496 
Certain Items(a)28 — 43 4 
Adjusted Segment EBDA$293 $227 $556 $500 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$66 $56 
Volumetric data(b)
Gasoline(c)1,046 762 969 862 
Diesel fuel418 371 398 365 
Jet fuel224 98 200 196 
Total refined product volumes1,688 1,231 1,567 1,423 
Crude and condensate510 479 508 590 
Total delivery volumes (MBbl/d)2,198 1,710 2,075 2,013 
Certain Items affecting Segment EBDA
(a)Includes non-revenue Certain Item amounts of $46$28 million and $50$43 million for the three and ninesix months ended SeptemberJune 30, 2020,2021, respectively, and $11 million and $28$4 million for the three and ninesix months ended SeptemberJune 30, 2019, respectively.2020. Three and nine-month 2020six month 2021 amounts both include increases in expense of $28 million related to an adjustment to a $46litigation reserve. Six month 2021 amount also includes an increase in expense of $15 million unfavorable rate caserelated to an environmental reserve adjustment. Nine-monthSix month 2020 amount also includes a non-cash loss on impairment of our Belton Terminal of $21 million and a $17 million favorable adjustment for tax reserves, other than income taxes. Three and nine-month 2019 amounts include an unfavorable environmental reserve adjustment. Nine-month 2019 amount also includes a $17 million unfavorable adjustment of tax reserves, other than income taxes.
Other
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

4744

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

Three Months Ended SeptemberJune 30, 20202021 versus Three Months Ended SeptemberJune 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$34 36 %
Southeast Refined ProductsSoutheast Refined Products20 41 %
Crude and CondensateCrude and Condensate(27)(22)%1 1 %Crude and Condensate12 14 %
Southeast Refined Products(9)(13)%(24)(22)%
Total Products PipelinesTotal Products Pipelines$(67)(20)%$(42)(9)%Total Products Pipelines$66 29 %

NineSix Months Ended SeptemberJune 30, 20202021 versus NineSix Months Ended SeptemberJune 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$21 10 %
Southeast Refined ProductsSoutheast Refined Products33 33 %
Crude and CondensateCrude and Condensate(76)(21)%2 — %Crude and Condensate2 1 %
Southeast Refined Products(40)(20)%(25)(8)%
Total Products Pipelines Total Products Pipelines $(167)(18)%$(68)(5)%Total Products Pipelines$56 11 %

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-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019:2020:
•$34 million (36%) and $21 million (10%) 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 Calnev Pipe Line LLC and West Coast terminals driven by lower serviceshigher revenues from the recovery of volumes in second quarter 2021 compared to 2020 which was impacted by COVID, partially offset by an increase in expense related to an adjustment to a litigation reserve on SFPP. The year-to-date increase was 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$20 million (22%(41%) and $76$33 million (21%(33%), increases, respectively, in Southeast Refined Products were primarily due to decreasedan increase in equity earnings from Products (SE) Pipe Line and increased revenues from our South East Terminals as a result of higher volumes and from our Transmix processing operations primarily due to higher prices. The year-to-date increase was also driven by higher 2021 earnings at our Transmix processing operations primarily due to first quarter 2020 unfavorable inventory adjustments and by product net gains as a result of higher prices and volumes on South East Terminals; and
•$12 million (14%) and $2 million (1%) increases, respectively, in Crude and Condensate were primarily due to increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s decreasedincreased earnings were primarily due to lower contracted rates and lower volumes.higher deficiency revenues partially offset by contract expirations. The Bakken Crude assets decreasedassets’ second quarter increase in earnings werewas primarily driven by higher commodity prices and higher volumes. Bakken Crude assets’ year-to-date increase in earnings was impacted by lower volumesfield operating expenses partially offset by renegotiated contracts at lower average rates and reduced re-contracted rates.by contract expirations. KMCC and Bakken Crude assets year-to-date decreasesincreases were also impacted bydue to lower operating expenses attributable to first quarter 2020 unfavorable inventory valuation adjustments driven by declines in commodity prices during the first quarter of 2020; andadjustments.
•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.
4845

Terminals
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended June 30,Six Months Ended June 30,
20202019202020192021202020212020
(In millions, except operating statistics)(In millions, except operating statistics)
RevenuesRevenues$424 $508 $1,285 $1,524 Revenues$433 $419 $853 $861 
Operating expensesOperating expenses(185)(223)(570)(660)Operating expenses(191)(193)(388)(385)
Gain (loss) on divestitures and impairments, net— 3 (5)3 
Loss on impairments and divestitures, netLoss on impairments and divestitures, net(1)(5)— (5)
Earnings from equity investmentsEarnings from equity investments7 6 19 15 Earnings from equity investments4 7 7 12 
Other, netOther, net— 1 3 2 Other, net1 1 1 3 
Segment EBDASegment EBDA246 295 732 884 Segment EBDA246 229 473 486 
Certain ItemsCertain Items— — — — Certain Items— — — — 
Adjusted Segment EBDAAdjusted Segment EBDA$246 $295 $732 $884 Adjusted Segment EBDA$246 $229 $473 $486 
Change from prior periodChange from prior periodIncrease/(Decrease)Change from prior periodIncrease/(Decrease)
Adjusted revenues$(84)(17)%$(239)(16)%
Adjusted Segment EBDAAdjusted Segment EBDA(49)(17)%(152)(17)%Adjusted Segment EBDA$17 $(13)
Volumetric data(a)Volumetric data(a)Volumetric data(a)
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)Liquids utilization %(b)96.2 %94.4 %96.2 %94.4 %Liquids utilization %(b)93.6 %95.6 %93.6 %95.6 %
Bulk transload tonnage (MMtons)Bulk transload tonnage (MMtons)11.3 14.1 35.4 42.0 Bulk transload tonnage (MMtons)13.6 11.1 24.6 24.0 
Other
(a)Volumes for assets sold are excluded for all periods presented.
(b)The ratio of our tankage capacity in service to tankage capacity available for service.

46

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

Three Months Ended SeptemberJune 30, 20202021 versus Three Months Ended SeptemberJune 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)%
49

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Northeast$8 38 %
Midwest6 50 %
Mid Atlantic6 50 %
Gulf Central3 10 %
Marine operations(14)(27)%
All others (including intrasegment eliminations)8 8 %
Total Terminals$17 7 %

NineSix Months Ended SeptemberJune 30, 20202021 versus NineSix Months Ended SeptemberJune 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)
Northeast$11 24 %
Midwest5 17 %
Mid Atlantic4 14 %
Gulf Central(12)(19)%
Marine operations(24)(23)%
All others (including intrasegment eliminations)3 1 %
Total Terminals$(13)(3)%

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-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019:2020:
•combined decreases of $36$8 million (38%) and $113$11 million (24%) increases, respectively, in the Northeast terminals were primarily driven by increased revenues associated with our Alberta Canada terminalshigher throughput levels and our West Coast terminals due to the sale of KML assets to Pembina on December 16, 2019;new contracts;
•decreases of$6 million (50%) and $5 million (6%(17%) and $21 million (9%),increases, respectively, fromin the Midwest terminals were primarily the result of an impairment associated with 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 followingMuscatine facility realized in the terminationsecond quarter of a major customer contract;2020;
•decreases of $4$6 million (27%(50%) and $4 million (8%(14%), increases, respectively, from our Gulf Bulkin the Mid Atlantic terminals were primarily due to lower revenues driven by lower refinery petroleum coke production and the expiration of a customer contract in January 2020; and
•decreases of $3 million (23%) and $12 million (24%), respectively, from our Mid Atlantic terminals primarily due to lowerhigher coal volumes at our Pier IX facilityfacility;
•$3 million (10%) increase and $12 million (19%) decrease, respectively, in the Gulf Central terminals. The second quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol and coal volumes. The year-to-date decrease in earnings was primarily driven by coal market weakness largely attributableunfavorable petroleum coke volumes due to demand reductionrefinery outages associated with COVID-19.the February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC; and
•$14 million (27%) and $24 million (23%) decreases, respectively, in Marine operations were primarily due to lower fleet utilization and average charter rates.

5047

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 investments4 9 17 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 EBDA5 3 %(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 June 30,Six Months Ended June 30,
2021202020212020
(In millions, except operating statistics)
Revenues$243 $232 $472 $541 
Operating expenses(98)(91)(49)(213)
Loss on impairments and divestitures, net(3)— (3)(950)
Earnings from equity investments8 5 16 13 
Segment EBDA150 146 436 (609)
Certain Items(a)1 10 6 940 
Adjusted Segment EBDA$151 $156 $442 $331 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$(5)$111 
Volumetric data
SACROC oil production20.2 22.0 19.8 22.6 
Yates oil production6.7 6.7 6.4 6.9 
Katz and Goldsmith oil production2.2 2.5 2.4 2.9 
Tall Cotton oil production1.0 1.8 1.0 2.1 
Total oil production, net (MBbl/d)(b)30.1 33.0 29.6 34.5 
NGL sales volumes, net (MBbl/d)(b)9.5 9.4 9.1 9.6 
CO2 sales volumes, net (Bcf/d)
0.4 0.4 0.4 0.5 
Realized weighted average oil price ($ per Bbl)$52.50 $50.31 $51.79 $52.56 
Realized weighted average NGL price ($ per Bbl)$22.58 $15.84 $21.42 $17.84 
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $(2)$1 million and $(12)$6 million for the three and ninesix months ended SeptemberJune 30, 2020,2021, respectively, and $(15)$10 million and $(36)$940 million for the three and ninesix months ended September 30, 2019, respectively, related to mark-to-market gains associated with derivative contracts used to hedge forecasted commodity sales.
(b)Includes non-revenue Certain Item amount of $950 million for the nine months ended SeptemberJune 30, 2020, resultingrespectively. Six month 2020 amount primarily resulted from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on our oil and gas producing assets.assets
Other
(c)(b)Net of royalties and outside working interests.

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

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

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$27 35 %$(10)(5)%
Source and Transportation activities(22)(31)%(28)(29)%
Intrasegment eliminations— — %4 80 %
Total CO2
$5 3 %$(34)(12)%
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Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$(8)(7)%
Source and Transportation activities3 6 %
Total CO2
$(5)(3)%

NineSix Months Ended SeptemberJune 30, 20202021 versus NineSix Months Ended SeptemberJune 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$23 8 %$(37)(6)%Oil and Gas Producing activities$115 53 %
Source and Transportation activitiesSource and Transportation activities(60)(27)%(73)(25)%Source and Transportation activities(4)(4)%
Intrasegment eliminations— — %13 72 %
Total CO2
Total CO2
$(37)(7)%$(97)(11)%
Total CO2
$111 34 %

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-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019:2020:
•increases of $27$8 million (35%(7%) decrease and $23$115 million (8%(53%), increase, respectively, from ourin Oil and Gas Producing activitiesactivities. The second quarter decrease was primarily due to (i)higher operating and other expenses of $8 million and lower revenues of $12 million due to lower crude oil volumes partially offset by higher realized crude oil and NGL prices that resulted in increased revenues of $15 million. The year-to-date increase was primarily due to lower operating expenses of $32$156 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, partially offset by lower volumes resulting in decreased revenues of $37 million, driven in part, by the curtailed oil production and $50 million, respectively; and (ii) higherlower 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;$8 million; and
•decreases of $22$3 million (31%(6%) increase and $60$4 million (27%(4%), decrease, respectively, from ourin Source and Transportation activitiesactivities. The second quarter increase was primarily due to decreases of $28 million and $77 million, respectively,an increase in equity earnings offset by a decrease in revenues related to lower CO2sales prices. The year-to-date decrease was primarily due to a decrease in revenues of $17 million related to lower CO2 sales volumes partially offset by lower operating expenses of $9$7 million and $22 million, respectively.an increase in equity earnings.

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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 SeptemberJune 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 $52.68 $49.86 $47.76 $49.95 
Volume (MBbl/d)25.70 16.20 9.25 3.80 1.40 
NGLs
Price ($ per Bbl)$33.81 $48.06 
Volume (MBbl/d)5.70 1.36 
Midland-to-Cushing Basis Spread
Price ($ per Bbl)$0.26 $0.73 
Volume (MBbl/d)24.55 10.25 
(a)Includes West Texas Intermediate hedges.

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

Three Months Ended September 30,Earnings
increase/(decrease)		Three Months Ended June 30,Earnings
increase/(decrease)
2020201920212020Earnings
increase/(decrease)
(In millions, except percentages)
DD&A (GAAP)DD&A (GAAP)$(528)$(532)$4 1 %
(In millions, except percentages)
General and administrative (GAAP)General and administrative (GAAP)$(153)$(154)$1 1 %General and administrative (GAAP)$(160)$(155)$(5)(3)%
Corporate benefit (charges)Corporate benefit (charges)3 (8)11 138 %Corporate benefit (charges)10 (2)12 600 %
Certain Items(a)Certain Items(a)11 5 6 120 %Certain Items(a)— — — — %
General and administrative and corporate charges(b)General and administrative and corporate charges(b)$(139)$(157)$18 11 %General and administrative and corporate charges(b)$(150)$(157)$7 4 %
Interest, net (GAAP)Interest, net (GAAP)$(383)$(447)$64 14 %Interest, net (GAAP)$(377)$(395)$18 5 %
Certain Items(c)Certain Items(c)(8)(5)(3)(60)%Certain Items(c)(3)(1)(2)(200)%
Interest, net(b)Interest, net(b)$(391)$(452)$61 13 %Interest, net(b)$(380)$(396)$16 4 %
Net income attributable to noncontrolling interests (GAAP)Net income attributable to noncontrolling interests (GAAP)$(17)$(11)$(6)(55)%Net income attributable to noncontrolling interests (GAAP)$(17)$(13)$(4)(31)%
Certain Items— — — — %
Certain Items(d)Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)Net income attributable to noncontrolling interests(b)$(17)$(11)$(6)(55)%Net income attributable to noncontrolling interests(b)$(17)$(13)$(4)(31)%

Nine Months Ended September 30,Earnings
increase/(decrease)
20202019
(In millions, except percentages)
General and administrative (GAAP)$(461)$(456)$(5)(1)%
Corporate charges(11)(22)11 50 %
Certain Items(a)36 11 25 227 %
General and administrative and corporate charges(b)$(436)$(467)$31 7 %
Interest, net (GAAP)$(1,214)$(1,359)$145 11 %
Certain Items(c)(8)(6)(2)(33)%
Interest, net(b)$(1,222)$(1,365)$143 10 %
Net income attributable to noncontrolling interests (GAAP)$(45)$(32)$(13)(41)%
Certain Items— (1)1 100 %
Net income attributable to noncontrolling interests(b)$(45)$(33)$(12)(36)%
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Six Months Ended June 30,Earnings
increase/(decrease)
20212020
(In millions, except percentages)
DD&A (GAAP)$(1,069)$(1,097)$28 3 %
General and administrative (GAAP)$(316)$(308)$(8)(3)%
Corporate benefit (charges)18 (14)32 229 %
Certain Items(a)— 25 (25)(100)%
General and administrative and corporate charges(b)$(298)$(297)$(1)— %
Interest, net (GAAP)$(754)$(831)$77 9 %
Certain Items(c)(9)— (9)— %
Interest, net(b)$(763)$(831)$68 8 %
Net income attributable to noncontrolling interests (GAAP)$(33)$(28)$(5)(18)%
Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)$(33)$(28)$(5)(18)%
Certain items
(a)Three and nine-monthSix month 2020 amounts both include an increase in expense of $11 million related to costs incurred associated with COVID-19 mitigation. Nine-month 2020 amount also includes an increase in expense of $23 million associated with the non-cash fair value adjustment of and the dividend onaccrual prior to the sale of our investment in Pembina common stock.
(b)Amounts are adjusted for Certain Items.
(c)Three and nine-month 2020six month 2021 amounts include (i) decreases in interest expense of $5$4 million and $17$8 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.acquisitions. Three and nine-month 2019six month 2020 amounts include (i) decreases in interest expense of $7$4 million and $22$12 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $2$3 million and $15$14 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 six months ended June 30, 2021 and 2020 amounts each include less than $1 million of noncontrolling interests associated with Certain Items.

General and administrative expenses and corporate charges adjusted for Certain Items decreased $18 million and $31$7 million for the three and nine months ended SeptemberJune 30, 2020, respectively,2021 and increased $1 million for the six months ended June 30, 2021, when compared with the respective prior year periods primarily due to lower non-cash pension expenses of $11$12 million and $34$24 million, respectively, of cost savings associated with organizational efficiency efforts and lower expensespension costs of $6 million and $27$10 million, respectively, due to the KML and U.S. Cochin Sale, $7 million and $12 million, respectively, of cost
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savings associated with reduced business activity during the pandemic, partially offset by lower capitalized costs of $4$7 million and $43$23 million, respectively, reflecting the COVID-19-related cutback onreduced capital projectsspending primarily by our CO2 and Natural Gas Pipelines business segmentssegment 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 otherhigher benefit-related costs of $4 million and a 2019 project write-off in our Terminals segment.$6 million, 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 ninesix months ended SeptemberJune 30, 20202021 when compared with the respective prior year periods decreased $61$16 million and $143$68 million, respectively, primarily due to lower weighted average long-term debt balances and lower LIBOR and long-term interest rates, partially offset by lower capitalized interest.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of SeptemberJune 30, 20202021 and December 31, 2019,2020, approximately 16%14% 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. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. Net income attributable to noncontrolling interests

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Income Taxes

Our tax benefit for the three and nine months ended SeptemberJune 30, 2020 when2021 was approximately $237 million as compared with $104 million of expense for the respectivesame period of 2020. The $341 million decrease in tax expense was due to the prior year periods increased $6 million and $12 million, respectively.

Income Taxesdisallowance of a tax benefit for the non-tax deductible goodwill impairment.

Our tax expense for the threesix months ended SeptemberJune 30, 20202021 was approximately $140$114 million as compared with $151$164 million for the same period of 2019.2020. The $11 million decrease in tax expense was due primarily due to lower pre-tax book income in the 2020 period.

Our tax expense for the nine months ended September 30, 2020 was approximately $304 million as compared with $471 million for the same period of 2019. The $167$50 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 and the current year release of the valuation allowance on our investment in NGPL Holdings, 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 period and U.S. Cochin Sale in 2019; and (iii) the refund of alternative minimum tax sequestration credits in 2020.the 2020 period.

Liquidity and Capital Resources

General

As of SeptemberJune 30, 2020,2021, we had $632$1,365 million of “Cash and cash equivalents,” an increase of $447$181 million from December 31, 2019.2020. As of June 30, 2021, our “Restricted deposits” included $506 million held in escrow for the repayment of senior notes and accrued interest made on July 1, 2021. We also used $1.2 billion of cash on hand to complete the acquisition on July 9, 2021 of subsidiaries of Stagecoach. Additionally, as of SeptemberJune 30, 2020,2021, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flowflows from operations, providing a source of funds of $3,282$3,311 million and $3,121$2,232 million in the first ninesix 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 flows from operations, and our borrowing capacity under our revolving credit facility are more than adequate to allow us to manage our cash requirements, including maturing debt, through 2021; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.

Our board of directors declared a quarterly dividend of $0.2625$0.27 per share for the thirdsecond 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
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continue to expect to fully fund our dividend payments as well as our discretionary spending for 20202021 without funding from the capital markets.

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.

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

Short-term Liquidity

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

As of SeptemberJune 30, 2020,2021, our $2,057$2,183 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$776 million and $1,862$1,871 million as of SeptemberJune 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$1,095 million favorable change from year-end 20192020 was primarily due to (i) an increase in cash and cash equivalents of $447 million; (ii) a decrease of approximately $284$375 million in senior notes that mature in the next twelve months; (ii) a $604
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million increase in restricted deposits primarily related to cash held in escrow for $506 million in senior notes and accrued interest that were repaid on July 1, 2021; (iii) a favorable asset$181 million increase in cash and cash equivalents; and (iv) a $75 million decrease in accrued contingencies, partially offset by a $176 million increase in current regulatory liabilities and a net unfavorable short-term fair value adjustment of $173$164 million on derivative contractscontract assets and liabilities in 2020; and (iv) the $100 million repayment of the preferred interest in Kinder Morgan G.P. Inc.; partially offset by a decrease of $925 million related to the sale of Pembina common equity in January 2020.2021. 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 SeptemberJune 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 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 ninesix months ended SeptemberJune 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 
_______
Six Months Ended June 30, 20212021 RemainingTotal 2021
(In millions)
Sustaining capital expenditures(a)(b)$317 $557 $874 
Discretionary capital investments(b)(c)(d)302 1,683 1,985 
(a)Amounts include reductions due to revised outlook, as discussed above in “—General.”
(b)NineSix months ended SeptemberJune 30, 2020, 20202021, 2021 Remaining, and Total 20202021 amounts include $80$49 million, $35$60 million, and $115$109 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.”
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(c)
(b)NineSix months ended SeptemberJune 30, 20202021 amount includes $1excludes $45 million of net changes fromdue to decreases in accrued capital expenditures and contractor retainage and net changes in other.
(d)(c)NineSix months ended SeptemberJune 30, 20202021 amount includes $442$70 million of our contributions to certain unconsolidated joint ventures for capital investments. Both 2021 Remaining and Total 2021 amounts include $1.2 billion for our acquisition of subsidiaries of Stagecoach.
(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 SeptemberJune 30, 20202021 and December 31, 20192020 were $192$227 million and $439$141 million, respectively. The decreaseincrease of $247$86 million was primarily driven by capital commitments related to our Terminals and Natural Gas Pipelines business segment.segments.

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Cash Flows

Operating Activities

Cash provided by operating activities increased $161$1,079 million in the ninesix months ended SeptemberJune 30, 20202021 compared to the respective 20192020 period primarily due to:

•a $161$1,178 million increase in cash primarily resulting from $202after adjusting the $1,600 million ofincrease in net income taxby $422 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 “—Results of Operations”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments (including a non-cash write-down of a related party note receivable from Ruby); partially offset by,
•a $99 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 a net unfavorable change in the timing of accounts receivable collections and trade payable payments in the 20202021 period compared to $364 million of net income taxthe 2020 period. The decrease was also driven by payments for litigation matters 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.2021 period.

Investing Activities

Cash used in investing activities decreased $1,834$130 million for the ninesix months ended SeptemberJune 30, 20202021 compared to the respective 20192020 period primarily attributable to:

•a $418 million decrease in capital expenditures reflecting an $827overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and
•a $199 million increasedecrease in cash used for contributions to equity investees driven by lower contributions to Permian Highway Pipeline and SNG in the 2021 period compared with the 2020 period; partially offset by,
•a $494 million decrease in cash primarily due to $413 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 2 “a $783 million decreaseLosses 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 cash used for contributions to equity investments driven by lower contributions to Gulf Coast Express Pipeline LLC, Midcontinent Express Pipeline LLC, Citrus, and Fayetteville Express Pipeline LLC in the 2020 period compared with the 2019 period, partially offset by contributions made to SNG in the 2020 period; and
•a $368 million decrease in capital expenditures in the 2020 period over the comparative 2019 period primarily due to lower expenditures on the Elba Liquefaction expansion and also reflecting our reduction of expansion capital projects in the wake of COVID-19; partially offset by,
•a $102 million decrease in distributions received from equity investments in excess of cumulative earnings primarily from Ruby Pipeline Holding Company L.L.C. and Fayetteville Express Pipeline LLC in the 2020 period over the comparative 2019 period.NGPL Holdings.

Financing Activities

Cash used in financing activities decreased $1,587increased $791 million for the ninesix months ended SeptemberJune 30, 20202021 compared to the respective 20192020 period primarily attributable to:

•a $1,068$779 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
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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, 202017, 2021
May 15, 2020
June 30, 202020210.26250.27 July 22, 202021, 2021August 3, 20202, 2021August 17, 2020
September 30, 20200.2625 October 21, 2020November 2, 2020November 16, 20202021

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 SeptemberJune 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 SeptemberJune 30, 20202021 and December 31, 2019,2020, the Obligated Group had $32,502$31,369 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 InformationJune 30, 2021December 31, 2020
(In millions)(In millions)
Current assetsCurrent assets$2,418 $1,918 Current assets$3,996 $2,957 
Current assets - affiliatesCurrent assets - affiliates1,073 1,146 Current assets - affiliates1,195 1,151 
Noncurrent assetsNoncurrent assets62,131 63,298 Noncurrent assets59,088 61,783 
Noncurrent assets - affiliatesNoncurrent assets - affiliates615 441 Noncurrent assets - affiliates507 616 
Total AssetsTotal Assets$66,237 $66,803 Total Assets$64,786 $66,507 
Current liabilitiesCurrent liabilities$3,810 $4,569 Current liabilities$4,654 $4,528 
Current liabilities - affiliatesCurrent liabilities - affiliates1,118 1,139 Current liabilities - affiliates1,213 1,209 
Noncurrent liabilitiesNoncurrent liabilities34,320 33,612 Noncurrent liabilities32,887 33,907 
Noncurrent liabilities - affiliatesNoncurrent liabilities - affiliates1,057 1,325 Noncurrent liabilities - affiliates945 1,078 
Total LiabilitiesTotal Liabilities40,305 40,645 Total Liabilities39,699 40,722 
Redeemable noncontrolling interestRedeemable noncontrolling interest747 803 Redeemable noncontrolling interest683 728 
Kinder Morgan, Inc.’s stockholders’ equityKinder Morgan, Inc.’s stockholders’ equity25,185 25,355 Kinder Morgan, Inc.’s stockholders’ equity24,404 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$64,786 $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 June 30, 2021Six Months Ended June 30, 2021
(In millions)(In millions)
RevenuesRevenues$2,653 $7,840 Revenues$2,837 $7,739 
Operating income788 1,032 
Net income463 113 
Operating (loss) incomeOperating (loss) income(831)998 
Net (loss) incomeNet (loss) income(813)564 

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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 5 “Risk Management” to our consolidated financial statements for more information on our risk management activities, both of which are incorporated in this item by reference.statements.

Item 4.  Controls and Procedures.

As of SeptemberJune 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 SeptemberJune 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 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 20192020 Form 10-K and in Part II,10-K. For more information on our risk management activities, refer to Item 1A.1, Note 5 “Risk FactorsManagement” ofto our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.consolidated financial statements.

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

None. 

Item 3.  Defaults Upon Senior Securities.

None. 

Item 4.  Mine Safety Disclosures.

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

Item 5.  Other Information.

None.

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Item 6.  Exhibits.
Exhibit
Number                     Description
4.1 
10.1 
10.2 
10.3 
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 ninesix months ended SeptemberJune 30, 20202021 and 2019;2020; (ii) our Consolidated Statements of Comprehensive (Loss) Income (Loss) for the three and ninesix months ended SeptemberJune 30, 20202021 and 2019;2020; (iii) our Consolidated Balance Sheets as of SeptemberJune 30, 20202021 and December 31, 2019;2020; (iv) our Consolidated Statements of Cash Flows for the ninesix months ended SeptemberJune 30, 20202021 and 2019;2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and ninesix months ended SeptemberJune 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.


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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:OctoberJuly 23, 20202021By:/s/ David P. Michels
David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)
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