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 June 30, 2020March 31, 2021
 
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-20210331_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 July 23, 2020,April 22, 2021, the registrant had 2,263,535,6852,264,582,583 Class P shares outstanding.



KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
  Page
Number
2
 
3
 Consolidated Statements of Operations - Three and Six Months Ended June 30,March 31, 2021 and 2020 and 2019
4
  Consolidated Statements of Comprehensive Income (Loss) Income - Three and Six Months Ended June 30,March 31, 2021 and 2020 and 2019
5
 Consolidated Balance Sheets - as of June 30, 2020March 31, 2021 and December 31, 20192020
6
 Consolidated Statements of Cash Flows - SixThree Months Ended June 30,March 31, 2021 and 2020 and 2019
7
Consolidated Statements of Stockholders’ Equity - Three and Six Months Ended June 30,March 31, 2021 and 2020 and 2019
9
 
Notes to Consolidated Financial Statements
1110
Note 1
1110
Note 2
1211
Note 3
1612
Note 4
1713
Note 5
1814
Note 6
2419
Note 7
2721
Note 8
2822
Note 9
2923
Note 10
3427
 
General and Basis of Presentation
3529
 
Results of Operations
3729
Overview
3729
Consolidated Earnings Results (GAAP)
3932
Non-GAAP Financial Measures
4234
Segment Earnings Results
4537
DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
5242
Income Taxes
5343
 
Liquidity and Capital Resources
5343
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
5747
5848
5848
  
5848
5848
5848
5848
5848
5848
5949
 
6050
1


KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY

Company Abbreviations
CIG=Colorado Interstate Gas Company, L.L.C.KMPKMLT=Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiariesLiquid Terminals, LLC
ELC=Elba Liquefaction Company, L.L.C.Ruby=Ruby Pipeline Holding Company, L.L.C.
EPNG=El Paso Natural Gas Company, L.L.C.SFPP=SFPP, L.P.
KMBT=Kinder Morgan Bulk Terminals, Inc.SNG=Southern Natural Gas Company, L.L.C.
KMI=Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiariesTGP=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, includingand amortization of excess cost of equity investmentsROU=Right-of-Use
U.S.=United States of America
WTI=West Texas Intermediate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.


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 business of the global economic consequences of the COVID-19 pandemic, including the timing and extent of any economic recovery, and our anticipated dividends and capital projects, including expected 2020 outlook including, our expected DCF, Adjusted EBITDA, expected Net Debt-to-Adjusted EBITDA ratiocompletion timing and the sensitivity to changes in commodity volume and price assumptions.benefits of those projects.

TheImportant 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 decreasesthe pace and extent of economic recovery; the timing and extent 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 this report.subsequent reports).

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

3

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts, unaudited)
 Three Months Ended June 30,Six Months Ended June 30,
 2020201920202019
Revenues 
Services$1,791  $2,009  $3,783  $4,046  
Commodity sales723  1,156  1,790  2,505  
Other46  49  93  92  
Total Revenues2,560  3,214  5,666  6,643  
Operating Costs, Expenses and Other 
Costs of sales441  777  1,104  1,725  
Operations and maintenance606  646  1,226  1,244  
Depreciation, depletion and amortization532  579  1,097  1,172  
General and administrative155  148  308  302  
Taxes, other than income taxes103  103  195  221  
Loss (gain) on impairments and divestitures, net (Note 2)1,005  (10) 1,976  (10) 
Other income, net—  (2) (1) (2) 
Total Operating Costs, Expenses and Other2,842  2,241  5,905  4,652  
Operating (Loss) Income(282) 973  (239) 1,991  
Other Income (Expense) 
Earnings from equity investments176  161  368  353  
Amortization of excess cost of equity investments(35) (19) (67) (40) 
Interest, net(395) (452) (831) (912) 
Other, net16  13  18  23  
Total Other Expense(238) (297) (512) (576) 
(Loss) Income Before Income Taxes(520) 676  (751) 1,415  
Income Tax Expense(104) (148) (164) (320) 
Net (Loss) Income(624) 528  (915) 1,095  
Net Income Attributable to Noncontrolling Interests(13) (10) (28) (21) 
Net (Loss) Income Attributable to Kinder Morgan, Inc.$(637) $518  $(943) $1,074  
Class P Shares
Basic and Diluted (Loss) Earnings Per Common Share$(0.28) $0.23  $(0.42) $0.47  
Basic and Diluted Weighted Average Common Shares Outstanding2,261  2,262  2,263  2,262  

 Three Months Ended March 31,
 20212020
Revenues 
Services$1,917 $1,992 
Commodity sales3,229 1,067 
Other65 47 
Total Revenues5,211 3,106 
Operating Costs, Expenses and Other 
Costs of sales2,009 663 
Operations and maintenance514 620 
Depreciation, depletion and amortization541 565 
General and administrative156 153 
Taxes, other than income taxes110 92 
(Gain) loss on divestitures and impairments, net (Note 2)(4)971 
Other income, net(1)(1)
Total Operating Costs, Expenses and Other3,325 3,063 
Operating Income1,886 43 
Other Income (Expense) 
Earnings from equity investments66 192 
Amortization of excess cost of equity investments(22)(32)
Interest, net(377)(436)
Other, net (Note 2)223 2 
Total Other Expense(110)(274)
Income (Loss) Before Income Taxes1,776 (231)
Income Tax Expense(351)(60)
Net Income (Loss)1,425 (291)
Net Income Attributable to Noncontrolling Interests(16)(15)
Net Income (Loss) Attributable to Kinder Morgan, Inc.$1,409 $(306)
Class P Shares
Basic and Diluted Earnings (Loss) Per Share$0.62 $(0.14)
Basic and Diluted Weighted Average Shares Outstanding2,264 2,264 
The accompanying notes are an integral part of these consolidated financial statements.
4

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) INCOME
(In millions, unaudited)
 Three Months Ended June 30,Six Months Ended June 30,
 2020201920202019
Net (loss) income$(624) $528  $(915) $1,095  
Other comprehensive income (loss), net of tax  
Change in fair value of hedge derivatives (net of tax benefit (expense) of $57, $(19), $(12), and $45, respectively)(189) 63  40  (152) 
Reclassification of change in fair value of derivatives to net income (net of tax (expense) benefit of $(14), $6, $(23), and $2, respectively)47  (18) 77  (5) 
Foreign currency translation adjustments (net of tax expense of $—, $2, $—, and $7, respectively)—  13  1  23  
Benefit plan adjustments (net of tax expense of $2, $3, $5 and $5, respectively)5  7  16  15  
Total other comprehensive (loss) income(137) 65  134  (119) 
Comprehensive (loss) income(761) 593  (781) 976  
Comprehensive income attributable to noncontrolling interests(13) (15) (28) (20) 
Comprehensive (loss) income attributable to Kinder Morgan, Inc.$(774) $578  $(809) $956  
 Three Months Ended March 31,
 20212020
Net income (loss)$1,425 $(291)
Other comprehensive (loss) income, net of tax  
Change in fair value of hedge derivatives (net of tax benefit (expense) of $47 and $(67), respectively)(156)222 
Reclassification of change in fair value of derivatives to net income (net of tax expense of $18 and $11, respectively)59 37 
Foreign currency translation adjustments (net of tax expense of $0 and $0, respectively)0 1 
Benefit plan adjustments (net of tax expense of $4 and $3, respectively)17 11 
Total other comprehensive (loss) income(80)271 
Comprehensive income (loss)1,345 (20)
Comprehensive income attributable to noncontrolling interests(16)(15)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.$1,329 $(35)
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)

June 30, 2020December 31, 2019 March 31, 2021December 31, 2020
ASSETSASSETS ASSETS 
Current AssetsCurrent Assets Current Assets 
Cash and cash equivalentsCash and cash equivalents$526  $185  Cash and cash equivalents$1,377 $1,184 
Restricted depositsRestricted deposits20  24  Restricted deposits46 25 
Marketable securities at fair value—  925  
Accounts receivableAccounts receivable1,073  1,379  Accounts receivable1,425 1,293 
Fair value of derivative contractsFair value of derivative contracts295  84  Fair value of derivative contracts218 185 
InventoriesInventories336  371  Inventories389 348 
Other current assetsOther current assets240  270  Other current assets279 168 
Total current assetsTotal current assets2,490  3,238  Total current assets3,734 3,203 
Property, plant and equipment, netProperty, plant and equipment, net36,027  36,419  Property, plant and equipment, net35,605 35,836 
InvestmentsInvestments7,892  7,759  Investments7,693 7,917 
GoodwillGoodwill19,851  21,451  Goodwill19,851 19,851 
Other intangibles, netOther intangibles, net2,567  2,676  Other intangibles, net2,396 2,453 
Deferred income taxesDeferred income taxes790  857  Deferred income taxes213 536 
Deferred charges and other assetsDeferred charges and other assets2,167  1,757  Deferred charges and other assets1,716 2,177 
Total AssetsTotal Assets$71,784  $74,157  Total Assets$71,208 $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$3,006  $2,477  Current portion of debt$2,173 $2,558 
Accounts payableAccounts payable698  914  Accounts payable968 837 
Accrued interestAccrued interest501  548  Accrued interest304 525 
Accrued taxesAccrued taxes335  364  Accrued taxes205 267 
Accrued contingenciesAccrued contingencies157 307 
Other current liabilitiesOther current liabilities662  797  Other current liabilities811 580 
Total current liabilitiesTotal current liabilities5,202  5,100  Total current liabilities4,618 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  
OutstandingOutstanding29,976  30,883  Outstanding30,007 30,838 
Debt fair value adjustmentsDebt fair value adjustments1,465  1,032  Debt fair value adjustments1,054 1,293 
Total long-term debtTotal long-term debt31,441  31,915  Total long-term debt31,061 32,131 
Other long-term liabilities and deferred creditsOther long-term liabilities and deferred credits2,249  2,253  Other long-term liabilities and deferred credits2,221 2,202 
Total long-term liabilities and deferred creditsTotal long-term liabilities and deferred credits33,690  34,168  Total long-term liabilities and deferred credits33,282 34,333 
Total LiabilitiesTotal Liabilities38,892  39,268  Total Liabilities37,900 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 Interest768  803  Redeemable Noncontrolling Interest705 728 
Stockholders’ EquityStockholders’ Equity  Stockholders’ Equity  
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,261,444,654 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, 2,264,470,730 and 2,264,257,336 shares, respectively, issued and outstanding
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,470,730 and 2,264,257,336 shares, respectively, issued and outstanding
23 23 
Additional paid-in capitalAdditional paid-in capital41,731  41,745  Additional paid-in capital41,775 41,756 
Accumulated deficitAccumulated deficit(9,802) (7,693) Accumulated deficit(9,124)(9,936)
Accumulated other comprehensive lossAccumulated other comprehensive loss(199) (333) Accumulated other comprehensive loss(487)(407)
Total Kinder Morgan, Inc.’s stockholders’ equityTotal Kinder Morgan, Inc.’s stockholders’ equity31,753  33,742  Total Kinder Morgan, Inc.’s stockholders’ equity32,187 31,436 
Noncontrolling interestsNoncontrolling interests371  344  Noncontrolling interests416 402 
Total Stockholders’ EquityTotal Stockholders’ Equity32,124  34,086  Total Stockholders’ Equity32,603 31,838 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ EquityTotal Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$71,784  $74,157  Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$71,208 $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)
Six Months Ended June 30, Three Months Ended March 31,
20202019 20212020
Cash Flows From Operating ActivitiesCash Flows From Operating Activities Cash Flows From Operating Activities 
Net (loss) income$(915) $1,095  
Adjustments to reconcile net (loss) income to net cash provided by operating activities 
Net income (loss)Net income (loss)$1,425 $(291)
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 amortization1,097  1,172  Depreciation, depletion and amortization541 565 
Deferred income taxesDeferred income taxes28  111  Deferred income taxes347 (69)
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments67  40  Amortization of excess cost of equity investments22 32 
Loss (gain) on impairments and divestitures, net (Note 2)1,976  (10) 
(Gain) loss on divestitures and impairments, net (Note 2)(Gain) loss on divestitures and impairments, net (Note 2)(4)971 
Gain from sale of interest in equity investment (Note 2)Gain from sale of interest in equity investment (Note 2)(206)0 
Earnings from equity investmentsEarnings from equity investments(368) (353) Earnings from equity investments(66)(192)
Distributions from equity investment earningsDistributions from equity investment earnings317  257  Distributions from equity investment earnings184 152 
Changes in components of working capitalChanges in components of working capitalChanges in components of working capital
Accounts receivableAccounts receivable335  279  Accounts receivable(122)222 
InventoriesInventories28  (73) Inventories(47)59 
Other current assetsOther current assets48  108  Other current assets4 50 
Accounts payableAccounts payable(182) (255) Accounts payable26 (200)
Accrued interest, net of interest rate swapsAccrued interest, net of interest rate swaps(65) (49) Accrued interest, net of interest rate swaps(204)(202)
Accrued taxesAccrued taxes(23) (195) Accrued taxes(63)(59)
Other current liabilitiesOther current liabilities(119) (74) Other current liabilities157 (131)
Rate reparations, refunds and other litigation reserve adjustmentsRate reparations, refunds and other litigation reserve adjustments(144)10 
Other, netOther, net8  45  Other, net23 (24)
Net Cash Provided by Operating ActivitiesNet Cash Provided by Operating Activities2,232  2,098  Net Cash Provided by Operating Activities1,873 893 
Cash Flows From Investing ActivitiesCash Flows From Investing ActivitiesCash Flows From Investing Activities
Capital expendituresCapital expenditures(963) (1,178) Capital expenditures(267)(440)
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(225) (812) Contributions to investments(22)(151)
Distributions from equity investments in excess of cumulative earningsDistributions from equity investments in excess of cumulative earnings86  131  Distributions from equity investments in excess of cumulative earnings18 41 
Other, netOther, net(46) (16) Other, net(12)(22)
Net Cash Used in Investing Activities(241) (1,795) 
Net Cash Provided by Investing ActivitiesNet Cash Provided by Investing Activities130 335 
Cash Flows From Financing ActivitiesCash Flows From Financing ActivitiesCash Flows From Financing Activities
Issuances of debtIssuances of debt2,652  3,042  Issuances of debt3,110 2,125 
Payments of debtPayments of debt(3,037) (4,622) Payments of debt(4,268)(1,969)
Debt issue costsDebt issue costs(11) (6) Debt issue costs(10)(7)
Common stock dividends(1,166) (1,024) 
DividendsDividends(597)(569)
Repurchases of common shares(50) (2) 
Repurchases of sharesRepurchases of shares0 (50)
Contributions from investment partner and noncontrolling interestsContributions from investment partner and noncontrolling interests9  110  Contributions from investment partner and noncontrolling interests3 5 
Distributions to investment partnerDistributions to investment partner(38) —  Distributions to investment partner(23)(18)
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds—  (879) 
Distributions to noncontrolling interests - other(7) (28) 
Distributions to noncontrolling interestsDistributions to noncontrolling interests(2)(3)
Other, netOther, net(1) (4) Other, net(2)(1)
Net Cash Used in Financing ActivitiesNet Cash Used in Financing Activities(1,649) (3,413) Net Cash Used in Financing Activities(1,789)(487)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted DepositsEffect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits(5) 28  Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits0 (8)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits337  (3,082) 
Net Increase in Cash, Cash Equivalents and Restricted DepositsNet Increase in Cash, Cash Equivalents and Restricted Deposits214 733 
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$546  $249  Cash, Cash Equivalents, and Restricted Deposits, end of period$1,423 $942 
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)
Six Months Ended June 30, Three Months Ended March 31,
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 period526  213  Cash and Cash Equivalents, end of period1,377 360 
Restricted Deposits, end of periodRestricted Deposits, end of period20  36  Restricted Deposits, end of period46 582 
Cash, Cash Equivalents, and Restricted Deposits, end of periodCash, Cash Equivalents, and Restricted Deposits, end of period546  249  Cash, Cash Equivalents, and Restricted Deposits, end of period1,423 942 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits$337  $(3,082) 
Net Increase in Cash, Cash Equivalents and Restricted DepositsNet Increase in Cash, Cash Equivalents and Restricted Deposits$214 $733 
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$8  $743  ROU assets and operating lease obligations recognized$7 $14 
Increase in property, plant and equipment from both accruals and contractor retainageIncrease in property, plant and equipment from both accruals and contractor retainage41 
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)891  952  Cash paid during the period for interest (net of capitalized interest)589 661 
Cash paid during the period for income taxes, netCash paid during the period for income taxes, net136  370  Cash paid during the period for income taxes, net1 134 
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 March 31, 20202,261  $23  $41,713  $(8,568) $(62) $33,106  $358  $33,464  
Balance at December 31, 2020Balance at December 31, 20202,264 $23 $41,756 $(9,936)$(407)$31,436 $402 $31,838 
Restricted sharesRestricted shares18  18  18  Restricted shares19 19 19 
Net (loss) income(637) (637) 13  (624) 
Net incomeNet income1,409 1,409 16 1,425 
DistributionsDistributions—  (4) (4) Distributions0 (3)(3)
ContributionsContributions—  4  4  Contributions0 2 2 
Common stock dividends(597) (597) (597) 
DividendsDividends(597)(597)(597)
OtherOther0 (1)(1)
Other comprehensive lossOther comprehensive loss(137) (137) (137) Other comprehensive loss(80)(80)(80)
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 
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, 20192,262  $23  $41,716  $(7,620) $(508) $33,611  $844  $34,455  
Restricted shares18  18  18  
Net income518  518  10  528  
Distributions—  (14) (14) 
Contributions—  1  1  
Common stock dividends(569) (569) (569) 
Other comprehensive income60  60  5  65  
Balance at June 30, 20192,262  $23  $41,734  $(7,671) $(448) $33,638  $846  $34,484  

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 shares36  36  36  
Net (loss) income(943) (943) 28  (915) 
Distributions—  (7) (7) 
Contributions—  6  6  
Common stock 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  
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(5) (5) (5) 
Balance at January 1, 20192,262  23  41,701  (7,721) (330) 33,673  853  34,526  
Repurchases of common shares(2) (2) (2) 
Restricted shares35  35  35  
Net income1,074  1,074  21  1,095  
Distributions—  (28) (28) 
Contributions—  1  1  
Common stock dividends(1,024) (1,024) (1,024) 
Other comprehensive loss(118) (118) (1) (119) 
Balance at June 30, 20192,262  $23  $41,734  $(7,671) $(448) $33,638  $846  $34,484  

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 shares18 18 18 
Net (loss) income(306)(306)15 (291)
Distributions0 (3)(3)
Contributions0 2 2 
Dividends(569)(569)(569)
Other comprehensive income271 271 0271 
Balance at March 31, 20202,261$23 $41,713 $(8,568)$(62)$33,106 $358 $33,464 
The accompanying notes are an integral part of these consolidated financial statements.

109


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-19

The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began in the first quarter of 2020 continued to cause disruptions and volatility in the second quarter of 2020. 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 affected our business in the second quarter, and we expect will continue to do so in the near term. Further, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities.

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

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions as discussed above, we evaluate goodwill for impairment on May 31 of each year. For this purpose, we have 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, 2020 goodwill impairment test.

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


11


Earnings per Share

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

The following table sets forth the allocation of net income (loss) income available to shareholders of Class P shares and participating securities:
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions, except per share amounts)
Net (Loss) Income Available to Common Stockholders$(637) $518  $(943) $1,074  
Participating securities:
   Less: Net Income allocated to restricted stock awards(a)(3) (3) (6) (6) 
Net (Loss) Income Allocated to Class P Stockholders$(640) $515  $(949) $1,068  
Basic Weighted Average Common Shares Outstanding2,261  2,262  2,263  2,262  
Basic (Loss) Earnings Per Common Share$(0.28) $0.23  $(0.42) $0.47  
________
Three Months Ended March 31,
20212020
(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders$1,409 $(306)
Participating securities:
   Less: Net Income allocated to restricted stock awards(a)(7)(3)
Net Income (Loss) Allocated to Class P Stockholders$1,402 $(309)
Basic Weighted Average Shares Outstanding2,264 2,264 
Basic Earnings (Loss) Per Share$0.62 $(0.14)
(a)As of June 30, 2020,March 31, 2021, there were approximately 12 million restricted stock awards outstanding.
10



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 June 30,Six Months Ended June 30,Three Months Ended March 31,
202020192020201920212020
(In millions on a weighted average basis)(In millions on a weighted average basis)
Unvested restricted stock awardsUnvested restricted stock awards12  13  12  13  Unvested restricted stock awards13 12 
Convertible trust preferred securitiesConvertible trust preferred securities3  3  3  3  Convertible trust preferred securities3 3 

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

We recognized the following non-cash pre-tax (gains) losses on divestitures, impairments and other write-downs, net on assets during the three months ended March 31, 2021 and 2020:
Three Months Ended March 31,
20212020
(In millions)
Natural Gas Pipelines
Gain on sale of interest in NGPL Holdings LLC(a)$(206)$0 
Loss on write-down of related party note receivable(a)117 0 
Products Pipelines
Impairment of long-lived and intangible assets0 21 
Terminals
Gain on divestitures of long-lived assets(1)0 
CO2
Impairment of goodwill(a)0 600 
Impairment of long-lived assets(a)0 350 
Other gain on divestitures of long-lived assets(3)0 
Pre-tax (gain) loss on divestitures, impairments and other write-downs, net$(93)$971 
(a)See below for a further discussion of these items.

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 three months ended March 31, 2021. Upon closing, we and Brookfield each hold a 37.5% interest in NGPL Holdings.

Impairments

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

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


We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assets during the three and six months ended June 30, 2020 and 2019:
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions)
Natural Gas Pipelines
Impairment of goodwill$1,000  $—  $1,000  $—  
Gain on divestitures of long-lived assets—  (10) —  (10) 
Products Pipelines
Impairment of long-lived and intangible assets(a)—  —  21  —  
Terminals
Impairment of long-lived and intangible assets(b)5  —  5  —  
CO2
Impairment of long-lived assets—  —  350  —  
Impairment of goodwill—  —  600  —  
Kinder Morgan Canada
Loss on divestiture of long-lived assets—  —  —  2  
Other gain on divestitures of long-lived assets—  —  —  (2) 
Pre-tax loss (gain) on divestitures and impairments, net$1,005  $(10) $1,976  $(10) 
_______
(a)Six months ended June 30, 2020 impairment amount is associated with our Belton terminal.
(b)Three and six months ended June 30, 2020 impairment amount is associated with our Muscatine terminal

Long-lived Assets

As of March 31, 2020, for our CO2 assets, the long lived asset impairment test involved a Step 1 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 six months ended June 30, 2020 are summarized by reporting unit as follows:
Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-Regulated
CO2
Products PipelinesProducts Pipelines TerminalsTerminalsTotal
(in millions)
Goodwill as of December 31, 2019$14,249  $3,343  $1,528  $1,378  $151  $802  $21,451  
Impairments—  (1,000) (600) —  —  —  (1,600) 
Goodwill as of June 30, 2020$14,249  $2,343  $928  $1,378  $151  $802  $19,851  

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

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

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

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

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

•For our March 31, 2020 interim goodwill impairment test of the CO2 reporting unit, we applied an income approach to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertainty and volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.
1411



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.Other Write-downs

The fair value estimates used inDuring the long-lived asset and goodwill test were primarily based on Level 3 inputsfirst 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 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 slowingrecent impairment by Ruby of supply to our pipelines, terminals and otherits assets, which will have an adverse effect onis 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 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.its services.

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. In the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.


15


3. Debt

The following table provides information on the principal amount of our outstanding debt balances:
June 30, 2020December 31, 2019
(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023$—  $—  
Commercial paper notes(a)—  37  
Current portion of senior notes
6.85%, due February 2020(b)—  700  
6.50%, due April 2020(c)—  535  
5.30%, due September 2020600  600  
6.50%, due September 2020349  349  
5.00%, due February 2021750  —  
3.50%, due March 2021750  —  
5.80%, due March 2021400  —  
Trust I preferred securities, 4.75%, due March 2028111  111  
Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d)—  100  
Current portion of other debt46  45  
  Total current portion of debt3,006  2,477  
Long-term debt (excluding current portion)
Senior notes29,267  30,164  
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035373  381  
Trust I preferred securities, 4.75%, due March 2028110  110  
Other226  228  
Total long-term debt29,976  30,883  
Total debt(e)$32,982  $33,360  
_______
March 31, 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 2021500 500 
8.625%, due January 2022260 0 
4.15%, due March 2022375 0 
1.50%, due March 2022(b)880 0 
Trust I preferred securities, 4.75%, due March 2028111 111 
Current portion of other debt47 47 
Total current portion of debt2,173 2,558 
Long-term debt (excluding current portion)
Senior notes29,314 30,141 
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035361 364 
Trust I preferred securities, 4.75%, due March 2028110 110 
Other222 223 
Total long-term debt30,007 30,838 
Total debt(c)$32,180 $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 soldConsists of senior notes denominated in Euros that have been converted to U.S. dollars. The March 31, 2021 balance is reported above at the approximate 25exchange rate of 1.1730 U.S. dollars per Euro. As of March 31, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $65 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as considerationrelated to these notes. The cumulative increase in debt due to the changes in exchange rates for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for1.50% notes due 2022 is offset by a corresponding change in the sale of the Pembina shares, which were used to repay debt that matured in February 2020. The fair value of the Pembina common equity of$925 million as of December 31, 2019 was reported as “Marketable securities at fair value”cross-currency swaps reflected in the accompanying consolidated balance sheet.
(c)In April 2020, we repaid $535 million of maturing senior notes.
(d)In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as“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”).
(e)(c)Excludes our “Debt fair value adjustments” which, as of June 30, 2020March 31, 2021 and December 31, 2019,2020, increased our total debt balances by $1,465$1,054 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 February 24, 2020, TGP, a wholly owned subsidiary,11, 2021, we issued in a private placement $1,000registered offering $750 million aggregate principal amount of its 2.90%3.60% senior notes due 20302051 and received net proceeds of $991$741 million. These notes are guaranteed through the cross guarantee agreement discussed above.

12


Credit Facility

As of June 30, 2020,March 31, 2021, we had 0 borrowings outstanding under our $4.0 billion credit facility, 0 borrowings outstanding under our commercial paper program and $82$81 million in letters of credit. Our availability under our credit facility as of June 30, 2020March 31, 2021 was $3,918$3,919 million. As of June 30, 2020,March 31, 2021, we were in compliance with all required covenants.

16


Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below: 
June 30, 2020December 31, 2019
Carrying
value		Estimated
fair value		Carrying
value		Estimated
fair value
(In millions)
Total debt$34,447  $37,937  $34,392  $38,016  
March 31, 2021December 31, 2020
Carrying
value		Estimated
fair value		Carrying
value		Estimated
fair value
(In millions)
Total debt$33,234 $37,050 $34,689 $39,622 

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both June 30, 2020March 31, 2021 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.

For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2019 Form 10-K.

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 June 30,Six Months Ended June 30,
2020201920202019
Per common share cash dividend declared for the period$0.2625  $0.25  $0.525  $0.50  
Per common share cash dividend paid in the period0.2625  0.25  0.5125  0.45  
Three Months Ended March 31,
20212020
Per share cash dividend declared for the period$0.27 $0.2625 
Per share cash dividend paid in the period0.2625 0.25 

On July 22, 2020,April 21, 2021, our board of directors declared a cash dividend of $0.2625$0.27 per common share for the quarterly period ended June 30, 2020,March 31, 2021, which is payable on AugustMay 17, 20202021 to common shareholders of record as of the close of business on August 3, 2020.April 30, 2021.

1713


Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7) $—  $(326) $(333) 
Other comprehensive gain before reclassifications40  1  16  57  
Loss reclassified from accumulated other comprehensive loss77  —  —  77  
Net current-period change in accumulated other comprehensive (loss) income117  1  16  134  
Balance as of June 30, 2020$110  $1  $(310) $(199) 
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2020$(13)$0 $(394)$(407)
Other comprehensive (loss) gain before reclassifications(156)0 17 (139)
Loss reclassified from accumulated other comprehensive loss59 0 0 59 
Net current-period change in accumulated other comprehensive loss(97)0 17 (80)
Balance as of March 31, 2021$(110)$0 $(377)$(487)
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(152) 24  15  (113) 
Gain reclassified from accumulated other comprehensive loss(5) —  —  (5) 
Net current-period change in accumulated other comprehensive income (loss)(157) 24  15  (118) 
Balance as of June 30, 2019$7  $(67) $(388) $(448) 
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7)$0 $(326)$(333)
Other comprehensive gain before reclassifications222 1 11 234 
Loss reclassified from accumulated other comprehensive loss37 0 0 37 
Net current-period change in accumulated other comprehensive (loss) income259 1 11 271 
Balance as of March 31, 2020$252 $1 $(315)$(62)

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, which was not designated as an accounting hedge. These agreements effectively fixed our LIBOR exposure for a portion of our fixed to floating rate interest rate swaps through 2020.

1814


Energy Commodity Price Risk Management

As of June 30, 2020,March 31, 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(21.5)(16.6)MMBbl
Crude oil basis(4.1)(8.7)MMBbl
Natural gas fixed price(42.9)(35.0)Bcf
Natural gas basis(43.0)(30.5)Bcf
NGL fixed price(1.1)(1.2)MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(3.0)(1.0)MMBbl
Crude oil basis(1.7)(12.6)MMBbl
Natural gas fixed price(10.7)(8.2)Bcf
Natural gas basis16.1 (10.6)Bcf
NGL fixed price(1.7)(1.1)MMBbl

As of June 30, 2020,March 31, 2021, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2024.2025.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of June 30, 2020:March 31, 2021:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)$8,025 7,100 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 contracts2,500 Mark-to-MarketDecember 20202021
_______
(a)The principal amount of hedged senior notes consisted of $1,300$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 June 30, 2020:March 31, 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.
1915



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
June 30,
2020		December 31,
2019		June 30,
2020		December 31,
2019		March 31,
2021		December 31,
2020		March 31,
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)$150  $31  $(17) $(43) Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)$13 $42 $(92)$(33)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)92  17  (2) (8) Deferred charges and other assets/(Other long-term liabilities and deferred credits)6 33 (29)(8)
SubtotalSubtotal242  48  (19) (51) Subtotal19 75 (121)(41)
Interest rate contractsInterest rate contractsFair value of derivative contracts/(Other current liabilities)128  45  (3) —  Interest rate contractsFair value of derivative contracts/(Other current liabilities)126 119 (3)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)690  313  (9) (1) Deferred charges and other assets/(Other long-term liabilities and deferred credits)364 575 (19)(7)
SubtotalSubtotal818  358  (12) (1) Subtotal490 694 (22)(10)
Foreign currency contractsForeign currency contractsFair value of derivative contracts/(Other current liabilities)—  —  (22) (6) Foreign currency contractsFair value of derivative contracts/(Other current liabilities)56 0 (12)(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)22  46  (14) —  Deferred charges and other assets/(Other long-term liabilities and deferred credits)43 138 0 0 
SubtotalSubtotal22  46  (36) (6) Subtotal99 138 (12)(6)
TotalTotal1,082  452  (67) (58) Total608 907 (155)(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)16  8  (5) (7) Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)23 24 (33)(21)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)4  —  (1) —  Deferred charges and other assets/(Other long-term liabilities and deferred credits)0 0 (1)0 
Subtotal20  8  (6) (7) 
Interest rate contractsFair value of derivative contracts/(Other current liabilities)—  —  (6) —  
Subtotal—  —  (6) —  
TotalTotal20  8  (12) (7) Total23 24 (34)(21)
Total derivativesTotal derivatives$1,102  $460  $(79) $(65) Total derivatives$631 $931 $(189)$(78)

20


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

Level 1
Level 2
Level 3		Gross amountContracts available for nettingCash collateral held(b)Net amount
(In millions)
As of June 30, 2020
Energy commodity derivative contracts(a)$12  $250  $—  $262  $(22) $(7) $233  
Interest rate contracts—  818  —  818  (2) —  816  
Foreign currency contracts—  22  —  22  (14) —  8  
As of December 31, 2019
Energy commodity derivative contracts(a)$19  $37  $—  $56  $(19) $(21) $16  
Interest rate contracts—  358  —  358  —  —  358  
Foreign currency contracts—  46  —  46  (6) —  40  
16

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, 2020
Energy commodity derivative contracts(a)$(16) $(9) $—  $(25) $22  $—  $(3) 
Interest rate contracts—  (18) —  (18) 2  —  (16) 
Foreign currency contracts—  (36) —  (36) 14  —  (22) 
As of December 31, 2019
Energy commodity derivative contracts(a)$(3) $(55) $—  $(58) $19  $—  $(39) 
Interest rate contracts—  (1) —  (1) —  —  (1) 
Foreign currency contracts—  (6) —  (6) 6  —  —  

_______
Balance sheet asset fair value measurements by level

Level 1
Level 2
Level 3		Gross amountContracts available for nettingCash collateral held(b)Net amount
(In millions)
As of March 31, 2021
Energy commodity derivative contracts(a)$10 $32 $0 $42 $(37)$0 $5 
Interest rate contracts0 490 0 490 (9)0 481 
Foreign currency contracts0 99 0 99 (12)0 87 
As of December 31, 2020
Energy commodity derivative contracts(a)$6 $93 $0 $99 $(35)$0 $64 
Interest rate contracts0 694 0 694 (2)0 692 
Foreign currency contracts0 138 0 138 (6)0 132 
Balance sheet liability
fair value measurements by level
Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral posted(b)Net amount
(In millions)
As of March 31, 2021
Energy commodity derivative contracts(a)$(12)$(143)$0 $(155)$37 $6 $(112)
Interest rate contracts0 (22)0 (22)9 0 (13)
Foreign currency contracts0 (12)0 (12)12 0 0 
As of December 31, 2020
Energy commodity derivative contracts(a)$(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) income::
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,
2020201920202019
(In millions)
Interest rate contractsInterest, net$26  $208  $459  $336  
Hedged fixed rate debt(a)Interest, net$(28) $(211) $(468) $(349) 
_______
Derivatives in fair value hedging relationshipsLocationGain/(loss) recognized in income
 on derivative and related hedged item
Three Months Ended March 31,
20212020
(In millions)
Interest rate contractsInterest, net$(217)$433 
Hedged fixed rate debt(a)Interest, net$219 $(440)
(a)As of June 30, 2020,March 31, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $827$484 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


21
17


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 June 30,Three Months Ended June 30,
2020201920202019
(In millions)
Energy commodity derivative contracts$(273) $75  Revenues—Commodity sales$(84) $(7) 
Costs of sales(2) 10  
Interest rate contracts(1) (1) Earnings from equity investments(c)—  2  
Foreign currency contracts28  8  Other, net25  19  
Total$(246) $82  Total$(61) $24  

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,
2020201920202019
(In millions)
Energy commodity derivative contracts$114  $(170) Revenues—Commodity sales$(98) $6  
Costs of sales(5) 11  
Interest rate contracts(9) (1) Earnings from equity investments(c)—  2  
Foreign currency contracts(53) (26) Other, net3  (12) 
Total$52  $(197) Total$(100) $7  
_______
Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Three Months Ended March 31,Three Months Ended March 31,
2021202020212020
(In millions)(In millions)
Energy commodity derivative contracts$(158)$379 Revenues—Commodity sales$(20)$(8)
Costs of sales4 (17)
Interest rate contracts1 (8)Earnings from equity investments(c)0 0 
Foreign currency contracts(46)(82)Other, net(61)(23)
Total$(203)$289 Total$(77)$(48)
(a)We expect to reclassify an approximate $116approximately $35 million gainof loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 2020March 31, 2021 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 three months ended June 30, 2019,March 31, 2021 and 2020, we recognized agains of $6 million and $12 million, gainrespectively, 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 June 30,Six Months Ended June 30,
2020201920202019
(In millions)
Foreign currency contracts$—  $(8) $—  $(8) 
Total$—  $(8) $—  $(8) 


22


Derivatives not designated as hedging instrumentsLocationGain/(loss) recognized in income on derivatives
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$149  $14  $266  $24  
Costs of sales2  (1) 6  (3) 
Earnings from equity investments(b)—  2  —  2  
Total(a)$151  $15  $272  $23  
_______
Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Three Months Ended March 31,
20212020
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$(631)$117 
Costs of sales163 4 
Total(a)$(468)$121 
(a)The three and six months ended June 30,March 31, 2021 and 2020 amounts include approximate losses of $448 million and gains of $179$74 million, and $253 million, respectively, and the three and six months ended June 30, 2019 include an approximate loss of $6 million and gain of $2 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.
(b)Amounts represent our share of an equity investee’s income (loss).

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of June 30, 2020March 31, 2021 and December 31, 2019,2020, we had 0 outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2020 and DecemberMarch 31, 2019,2021, we had cash margins of $8$30 million posted by us with our counterparties as collateral and $15reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2020, we had cash margins of $3 million respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets.sheet. The balance at June 30, 2020March 31, 2021 represents the net of our initial margin requirements of $15$24 million offset byand counterparty variation margin requirements of $7$6 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 June 30, 2020,March 31, 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 $67 million of additional collateral.

2318


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 June 30, 2020Three Months Ended March 31, 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)$796  $67  $189  $—  $—  $1,052  Firm services(b)$866 $59 $191 $0 $0 $1,116 
Fee-based servicesFee-based services157  182  95  10  (2) 442  Fee-based services178 221 81 15 0 495 
Total servicesTotal services953  249  284  10  (2) 1,494  Total services1,044 280 272 15 0 1,611 
Commodity salesCommodity salesCommodity sales
Natural gas salesNatural gas sales377  —  —  —  (1) 376  Natural gas sales3,319 0 0 1 (5)3,315 
Product salesProduct sales102  49  3  134  (4) 284  Product sales220 125 5 229 (10)569 
Total commodity salesTotal commodity sales479  49  3  134  (5) 660  Total commodity sales3,539 125 5 230 (15)3,884 
Total revenues from contracts with customersTotal revenues from contracts with customers1,432  298  287  144  (7) 2,154  Total revenues from contracts with customers4,583 405 277 245 (15)5,495 
Other revenues(c)Other revenues(c)Other revenues(c)
Leasing services(d)Leasing services(d)114  42  132  11  —  299  Leasing services(d)119 43 143 12 (1)316 
Derivatives adjustments on commodity salesDerivatives adjustments on commodity sales(11) —  —  75  —  64  Derivatives adjustments on commodity sales(618)0 0 (33)0 (651)
OtherOther36  5  —  2  —  43  Other41 5 0 5 0 51 
Total Other revenues139  47  132  88  —  406  
Total other revenuesTotal other revenues(458)48 143 (16)(1)(284)
Total revenuesTotal revenues$1,571  $345  $419  $232  $(7) $2,560  Total revenues$4,125 $453 $420 $229 $(16)$5,211 

2419



Three Months Ended June 30, 2019
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$889  $84  $279  $—  $(1) $1,251  
Fee-based services187  252  118  15  1  573  
Total services1,076  336  397  15  —  1,824  
Commodity sales
Natural gas sales607  —  —  —  (4) 603  
Product sales197  61  5  291  (10) 544  
Total commodity sales804  61  5  291  (14) 1,147  
Total revenues from contracts with customers1,880  397  402  306  (14) 2,971  
Other revenues(c)
Leasing services55  43  105  13  —  216  
Derivatives adjustments on commodity sales19  —  —  (12) —  7  
Other14  2  —  3  1  20  
Total Other revenues88  45  105  4  1  243  
Total revenues$1,968  $442  $507  $310  $(13) $3,214  

Six 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)$1,661  $146  $378  $—  $—  $2,185  
Fee-based services350  442  216  23  (2) 1,029  
Total services2,011  588  594  23  (2) 3,214  
Commodity sales
Natural gas sales878  —  —  —  (3) 875  
Product sales238  158  6  366  (17) 751  
Total commodity sales1,116  158  6  366  (20) 1,626  
Total revenues from contracts with customers3,127  746  600  389  (22) 4,840  
Other revenues(c)
Leasing services227  84  261  21  —  593  
Derivatives adjustments on commodity sales41  —  —  127  —  168  
Other51  10  —  4  —  65  
Total Other revenues319  94  261  152  —  826  
Total revenues$3,446  $840  $861  $541  $(22) $5,666  

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Six Months Ended June 30, 2019
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$1,819  $164  $529  $—  $(2) $2,510  
Fee-based services379  487  266  31  —  1,163  
Total services2,198  651  795  31  (2) 3,673  
Commodity sales
Natural gas sales1,361  —  —  1  (6) 1,356  
Product sales437  127  7  559  (16) 1,114  
Total commodity sales1,798  127  7  560  (22) 2,470  
Total revenues from contracts with customers3,996  778  802  591  (24) 6,143  
Other revenues(c)
Leasing services110  84  214  26  —  434  
Derivatives adjustments on commodity sales38  —  —  (9) 1  30  
Other25  4  —  7  —  36  
Total Other revenues173  88  214  24  1  500  
Total revenues$4,169  $866  $1,016  $615  $(23) $6,643  
_______
Three Months Ended March 31, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$865 $79 $189 $0 $0 $1,133 
Fee-based services193 260 121 13 0 587 
Total services1,058 339 310 13 0 1,720 
Commodity sales
Natural gas sales501 0 0 0 (2)499 
Product sales136 109 3 232 (13)467 
Total commodity sales637 109 3 232 (15)966 
Total revenues from contracts with customers1,695 448 313 245 (15)2,686 
Other revenues(c)
Leasing services(d)113 42 129 10 0 294 
Derivatives adjustments on commodity sales52 0 0 52 0 104 
Other15 5 0 2 0 22 
Total other revenues180 47 129 64 0 420 
Total revenues$1,875 $495 $442 $309 $(15)$3,106 
(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 above (see note (c) below)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity 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 six months ended June 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 June 30, 2020March 31, 2021 and December 31, 2019,2020, our contract asset balances were $34$31 million and $27$20 million, respectively. Of the contract asset balance at December 31, 2019, $172020, $9 million was transferred to accounts receivable during the sixthree months ended June 30, 2020.March 31, 2021. As of June 30, 2020March 31, 2021 and December 31, 2019,2020, our contract liability balances were $241$243 million and $232$239 million, respectively. Of the contract liability balance at December 31, 2019, $472020, $24 million was recognized as revenue during the sixthree months ended June 30, 2020.March 31, 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 June 30, 2020March 31, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:
YearYearEstimated RevenueYearEstimated Revenue
(In millions)(In millions)
Six months ended December 31, 2020$2,252  
20213,975  
Nine months ended December 31, 2021Nine months ended December 31, 2021$3,276 
202220223,258  20223,626 
202320232,648  20232,924 
202420242,302  20242,508 
202520252,124 
ThereafterThereafter14,722  Thereafter13,585 
TotalTotal$29,157  Total$28,043 

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 June 30,Six Months Ended June 30,Three Months Ended March 31,
202020192020201920212020
(In millions)(In millions)
RevenuesRevenuesRevenues
Natural Gas PipelinesNatural Gas PipelinesNatural Gas Pipelines
Revenues from external customersRevenues from external customers$1,565  $1,956  $3,426  $4,148  Revenues from external customers$4,110 $1,861 
Intersegment revenuesIntersegment revenues6  12  20  21  Intersegment revenues15 14 
Products PipelinesProducts Pipelines345  442  840  866  Products Pipelines453 495 
TerminalsTerminalsTerminals
Revenues from external customersRevenues from external customers418  506  859  1,014  Revenues from external customers419 441 
Intersegment revenuesIntersegment revenues1  1  2  2  Intersegment revenues1 1 
CO2
CO2
232  310  541  615  
CO2
229 309 
Corporate and intersegment eliminationsCorporate and intersegment eliminations(7) (13) (22) (23) Corporate and intersegment eliminations(16)(15)
Total consolidated revenuesTotal consolidated revenues$2,560  $3,214  $5,666  $6,643  Total consolidated revenues$5,211 $3,106 
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Three Months Ended June 30,Six Months Ended June 30,Three Months Ended March 31,
2020201920202019 20212020
(In millions)(In millions)
Segment EBDA(a)Segment EBDA(a)  Segment EBDA(a)
Natural Gas PipelinesNatural Gas Pipelines$(3) $1,088  $1,193  $2,291  Natural Gas Pipelines$2,103 $1,196 
Products PipelinesProducts Pipelines227  307  496  583  Products Pipelines248 269 
TerminalsTerminals229  290  486  589  Terminals227 257 
CO2
CO2
146  196  (609) 394  
CO2
286 (755)
Kinder Morgan Canada—  —  —  (2) 
Total Segment EBDATotal Segment EBDA599  1,881  1,566  3,855  Total Segment EBDA2,864 967 
DD&ADD&A(532) (579) (1,097) (1,172) DD&A(541)(565)
Amortization of excess cost of equity investmentsAmortization of excess cost of equity investments(35) (19) (67) (40) Amortization of excess cost of equity investments(22)(32)
General and administrative and corporate chargesGeneral and administrative and corporate charges(157) (155) (322) (316) General and administrative and corporate charges(148)(165)
Interest, netInterest, net(395) (452) (831) (912) Interest, net(377)(436)
Income tax expenseIncome tax expense(104) (148) (164) (320) Income tax expense(351)(60)
Total consolidated net (loss) income$(624) $528  $(915) $1,095  
Total consolidated net income (loss)Total consolidated net income (loss)$1,425 $(291)
June 30, 2020December 31, 2019
(In millions)
Assets
Natural Gas Pipelines$48,375  $50,310  
Products Pipelines9,258  9,468  
Terminals8,786  8,890  
CO2
2,695  3,523  
Corporate assets(b)2,670  1,966  
Total consolidated assets$71,784  $74,157  
_______
March 31, 2021December 31, 2020
(In millions)
Assets
Natural Gas Pipelines$48,262 $48,597 
Products Pipelines9,152 9,182 
Terminals8,560 8,639 
CO2
2,517 2,478 
Corporate assets(b)2,717 3,077 
Total consolidated assets$71,208 $71,973 
(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, (gain) loss (gain) on impairmentsdivestitures and divestitures,impairments, net, and other income, net.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

8.  Income Taxes

Income tax expense included in our accompanying consolidated statements of operations is as follows:
Three Months Ended June 30,Six Months Ended June 30,Three Months Ended March 31,
202020192020201920212020
(In millions, except percentages)(In millions, except percentages)
Income tax expenseIncome tax expense$104  $148  $164  $320  Income tax expense$351 $60 
Effective tax rateEffective tax rate(20.0)%21.9 %(21.8)%22.6 %Effective tax rate19.8 %(26.0)%

While we would normally expect a federal incomeThe effective tax benefit from our loss before income taxesrate for the three and six months ended June 30, 2020, because these goodwill impairments do not generateMarch 31, 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 tax benefit, we incurred anpartial 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 tax expense for these periods.taxes.

The effective tax rate for the three months ended June 30,March 31, 2020 is “negative” in relation toand lower than the statutory federal rate of 21% primarily due to the $1,000a $600 million Natural Gas Pipelines Non-Regulated reporting unit impairment of non-taxgoodwill, which is a reduction to income but is not deductible goodwill contributing to our loss before income taxes but not providing afor tax benefit, partially offset by the dividend-received deductions from our investments in Citrus Corporation (Citrus) and Plantation Pipe Line Company (Plantation).
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The effective tax rate for the six months ended June 30, 2020 is “negative” in relation to 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,purposes. This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investmentsinvestment in Citrus and Plantation.PPL. While we would normally expect a federal income tax benefit from our loss
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The effective tax ratebefore income taxes for the three and six months ended June 30, 2019March 31, 2020, because a tax benefit is higher thannot allowed on 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.goodwill impairment, we incurred an income tax expense for the period.

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 rate proceedings.
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 (on appeal to the D.C. Circuit Court); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (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 (pending before the FERC for an order on the initial decision); 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
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cases) and/or prospective refunds in protest cases from the date of protest, (IS cases), and SFPP may be required to reduce its rates going forward. 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’ delayed appeal in the 2010 rate case were consolidated. Oral argument was heard by the U.S. Court of Appeals for the D.C. Circuit on March 13, 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 panel delivered its Award, and the panel's ruling 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 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.
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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 are scheduled to be argued toU.S. Supreme Court seeking review of the Delaware Supreme Court on September 9, 2020, and the arbitration proceedingCourt’s decision. This petition remains pending.
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On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in this arbitration is expected bybefore the end of the secondthird quarter of 2021.

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

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

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties).  CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies these claims and will vigorously defend against any action in which they are asserted.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 June 30, 2020March 31, 2021 and December 31, 2019,2020, our total reserve for legal matters was $221$130 million and $203$273 million, respectively.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal,local, state and localfederal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and
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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, could result in substantial costs and liabilities to us.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, will be material.aggregate. We are also currently involved in several governmental proceedings involving groundwater and
31

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 andor 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 June 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 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.
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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. That process was completed December 28, 2020. We anticipate the PRPs, including EPEC Polymers, will engage in further discussions with the EPA during 2021. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until thisthe PRPs engage in discussions with the EPA, the FS is completed, and the RI/FS is finalized, and allocationswe are determined,unable to reasonably estimate the scopeextent of our potential EPA claims forliability. 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 Site and liability therefor are not reasonably estimable.costs of the 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. Plaquemines Parish, along with intervenors, moved to remand the case to state court. 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 and in June 2019,Appeals. On August 10, 2020, the U.S. District Court stayed the remand order pending the outcome of that review.Fifth Circuit affirmed remand.The defendants filed a motion for rehearing which is pending. The case isremains effectively stayed pending resolution of the federal jurisdiction issuea final ruling by the Court of Appeals. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’
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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 23 cases against TGP, 2 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
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banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The 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 U.S. District Court ordered the defendants to pay $1,104 in money damages, and issued a permanent injunction ordering the defendants to restore a total of 9.6 acres of land and maintain certain canals at widths designated by the right of way agreements in effect.  The Court stayed the judgment and the injunction pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. 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. The case is set for trial October 5, 2020. We will continue to vigorously defend thesethe 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, financial position, results of operations or cash flows.business. As of both June 30, 2020March 31, 2021 and December 31, 2019,2020, we have accrued a total reserve for environmental liabilities in the amount of $259$256 million for each respective period.and $250 million, respectively. In addition, as of June 30, 2020both March 31, 2021 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.

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

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ASU No. 2020-06

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

Sale of U.S. Portion of Cochin Pipeline and KMLan Interest in NGPL Holdings LLC

On December 16, 2019,March 8, 2021, we closed on two cross-conditional transactions resulting inand Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of the U.S. portion of the Cochin Pipeline and all the outstanding equity of KML, includinga combined 25% interest in our 70% interest,joint venture, NGPL Holdings LLC (NGPL Holdings), to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”)a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received approximately 25net proceeds of $413 million shares of Pembina common equity 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 three months ended March 31, 2021. Upon closing, we and Brookfield each hold a 37.5% 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.NGPL Holdings.

COVID-19February 2021 Winter Storm

The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began in theOur first quarter of 2020 continued to cause disruptions and volatility in the second quarter of 2020. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wakeearnings reflect impacts of the pandemicFebruary 2021 winter storm that affected our business in the second quarter, and we expect will continue to do so in the near term. Further, significant uncertainty remains regarding the duration and extentTexas, which are largely nonrecurring. See “—Segment Earnings Results” below. Some of the impacttransactions executed during the winter storm remain subject to risks, including counterparty financial risk, potential disputed purchases and sales and potential legislative or regulatory action in response to, or litigation arising out of, the pandemic onunprecedented circumstances of the energy industry, including demandwinter storm, which could adversely affect our future earnings, cash flows and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities.financial condition.

The events as described above resulted in decreases of current2021 Dividends and estimated long-term crude oil and NGL sale prices and volumes we expect to realize and in significant reductions to the market capitalization of many midstream and oil and gas producing companies. These events triggered us to review the carrying value of our long-lived assets and recoverability of goodwill as of March 31, 2020 and impacted our annual goodwill testing performed as of May 31, 2020. Our evaluations resulted in the recognition during the first six months of 2020 of a $350 million impairment for long-lived assets in our CO2 business segment and goodwill impairments of $1,000 million and $600 million to our Natural Gas Pipelines Non-Regulated and CO2 reporting units, respectively. For a further discussion of these impairments and our risk for future impairments, see Note 2, “Impairments.”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 first half of 2020, our incremental employee safety costs associated with COVID-19 mitigation have been less than $10 million, primarily for enhanced cleaning protocols and supplies. 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 4.7 times.

Market conditions$1.05 per share. We also negatively impacted a number of planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. We therefore expect the budgeted $2.4to invest $0.8 billion in expansion projects and contributions to joint ventures for 2020 to be lower by approximately $660 million. With this reduction, DCF less expansion capital expenditures is improved by over $100 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 declared a dividend of $0.2625 per share, or $1.05 per share annualized, for the second quarter of 2020. This represents a 5% increase over the dividend declared for the second quarter of 2019 rather than the previously budgeted dividend of $0.3125, which would have been a 25% increase. We expect that our 2020 dividend payments as well as our 2020 discretionary spending will be funded with internally generated cash flow.
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during 2021.

Considerable uncertainty exists with respect to the future pace and extent of a global economic recovery from the effects of the COVID-19 pandemic.  In addition to the below discussions included in “—Results of Operations—Consolidated Earnings Results” and “—Segment Earnings Results,” the following table provides assumptions and sensitivities for impacts on our business that may be affected by that uncertainty.

Remaining 6 Months
Commodity Volume and Price Assumptions		Sensitivity RangePotential Impact to 2020 Adjusted EBITDA and DCF
(in millions, by segment)
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Total
Natural Gas Gathering and Processing Volumes
3,030 Bbtu/d+/- 5%$14  $14  
Refined Products Volumes (gasoline, diesel and jet fuel)
1,619 MBbl/d for Products Pipelines
(the following apply to both the Products Pipelines and Terminals segments)
+/- 5%$17  $5  $22  
Qtr 3: 11% - 12% reduction from budgeted quarter amount
Qtr 4: 5% reduction from budgeted quarter amount
Crude Oil & Condensate Pipeline Volumes
597 MBbl/d+/- 5%$7  $7  
Crude Oil Production Volumes
44 MBbl/d, gross (31 MBbl/d, net)+/- 5%$11  $11  
Crude Oil Price
$35/bbl+/- $1/bbl WTI$0.1  $0.6  $0.2  $0.9  
NGL to Crude Oil Price Ratio
Natural Gas Pipelines 50% and CO2 35%
+/- 1%$—  $0.2  $0.2  
Potential Impact to 2020 DCF
(in millions)
1-Month/3-Month LIBOR Interest Rates(a)Total
0.24% / 0.35%+/- 10-bp$1.9  
Purpose of Outlook Assumptions and Sensitivity:
The above table provides key assumptions used in our 2020 forecast for the remaining six months of 2020 to incorporate the estimated impact of COVID-19 and commodity price declines. It also provides estimated financial impacts to 2020 Adjusted EBITDA and DCF for potential changes in those assumptions. These sensitivities are general estimates of anticipated impacts on our business segments and overall business of changes relative to our assumptions; the impact of actual changes may vary significantly depending on the affected asset, product and contract.
Notes:
(a)Sensitivity considers a combination of the 1-month and 3-month LIBOR rates. As of June 30, 2020, we had approximately $8.0 billion of fixed-to-floating interest rate swaps on our long-term debt. In March 2020, we fixed the LIBOR component on $2.5 billion of these swaps through the end of 2020 only. As a result, approximately 17% of the principal amount of our debt balance as of June 30, 2020 was 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.

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.

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
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more information.statement. Furthermore, we disclaim any obligation, other than as required by applicable law,plan to publicly update or revise any of our forward-looking statementsprovide updates to reflect future events or developments.these 2021 expectations when we believe previously disclosed expectations no longer have a reasonable basis.

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 (loss) income and net income (loss) income attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA, Net Debt and Net Debt to Adjusted EBITDA.

GAAP Financial Measures

The Consolidated Earnings Results for the three and six months ended June 30,March 31, 2021 and 2020 and 2019 present Segment EBDA net (loss) income and net income (loss) income 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.

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Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP net income (loss) incomeattributable 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 net income (loss) income,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). SeeWe also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) IncomeAttributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below.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.

Adjusted Earnings

Adjusted Earnings is calculated by adjusting net income (loss) income 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 net income (loss) income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings (loss) per common share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting net income (loss) income 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
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financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is net income (loss) income attributable to Kinder Morgan, Inc. DCF per common share is DCF divided by average outstanding common shares, including restricted stock awards that participate in common share dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Income 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 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.

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Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items, our share of unconsolidatedItems. We also include amounts from joint ventureventures for income taxes and DD&A and income tax expense (net of our partners’ share of consolidating joint venture DD&A and income tax expense), and net income attributable to noncontrolling interests that is further adjusted for KML noncontrolling interests (net of its applicable Certain Items) for the periods presented through KML’s sale on December 16, 2019.(see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) income.attributable to Kinder Morgan, Inc. In prior periods Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) IncomeAttributable 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.

Net Debt

Net Debt is calculated, based on amounts as of March 31, 2021, by subtracting the following amounts from our debt balance of $33,234 million: (i) cash and cash equivalents of $1,377 million; (ii) debt fair value adjustments of $1,054 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $109 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. Net Debt is calculated by subtracting from debt (i) cash and cash equivalents; (ii) the preferred interest in the general partner of KMP (which was redeemed in January 2020); (iii) debt fair value adjustments; and (iv) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps. 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 4.5 as of June 30, 2020.

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Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.
Three Months Ended June 30,
20202019Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$(3) $1,088  $(1,091) (100)%
Products Pipelines227  307  (80) (26)%
Terminals229  290  (61) (21)%
CO2
146  196  (50) (26)%
Total Segment EBDA599  1,881  (1,282) (68)%
DD&A(532) (579) 47  8 %
Amortization of excess cost of equity investments(35) (19) (16) (84)%
General and administrative and corporate charges(157) (155) (2) (1)%
Interest, net(395) (452) 57  13 %
(Loss) income before income taxes(520) 676  (1,196) (177)%
Income tax expense(104) (148) 44  30 %
Net (loss) income(624) 528  (1,152) (218)%
Net income attributable to noncontrolling interests(13) (10) (3) (30)%
Net (loss) income attributable to Kinder Morgan, Inc.$(637) $518  $(1,155) (223)%

Six Months Ended June 30,
20202019Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$1,193  $2,291  $(1,098) (48)%
Products Pipelines496  583  (87) (15)%
Terminals486  589  (103) (17)%
CO2
(609) 394  (1,003) (255)%
Kinder Morgan Canada—  (2) 2  100 %
Total Segment EBDA1,566  3,855  (2,289) (59)%
DD&A(1,097) (1,172) 75  6 %
Amortization of excess cost of equity investments(67) (40) (27) (68)%
General and administrative and corporate charges(322) (316) (6) (2)%
Interest, net(831) (912) 81  9 %
(Loss) income before income taxes(751) 1,415  (2,166) (153)%
Income tax expense(164) (320) 156  49 %
Net (loss) income(915) 1,095  (2,010) (184)%
Net income attributable to noncontrolling interests(28) (21) (7) (33)%
Net (loss) income attributable to Kinder Morgan, Inc.$(943) $1,074  $(2,017) (188)%
_______
Three Months Ended March 31,
20212020Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$2,103 $1,196 $907 76 %
Products Pipelines248 269 (21)(8)%
Terminals227 257 (30)(12)%
CO2
286 (755)1,041 138 %
Total Segment EBDA2,864 967 1,897 196 %
DD&A(541)(565)24 4 %
Amortization of excess cost of equity investments(22)(32)10 31 %
General and administrative and corporate charges(148)(165)17 10 %
Interest, net(377)(436)59 14 %
Income (loss) before income taxes1,776 (231)2,007 869 %
Income tax expense(351)(60)(291)(485)%
Net income (loss)1,425 (291)1,716 590 %
Net income attributable to noncontrolling interests(16)(15)(1)(7)%
Net income (loss) attributable to Kinder Morgan, Inc.$1,409 $(306)$1,715 560 %
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss (gain) on impairmentsdivestitures and divestitures,impairments, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
39


(Loss)Net income before income taxes decreased $1,196(loss) attributable to Kinder Morgan, Inc. increased $1,715 million and $2,166 million for the three and six months ended June 30, 2020, respectively, asin 2021 compared to the respective prior year periods.2020. The second quarter decrease was due primarily to a $1 billion non-cash impairment of goodwill associated withincrease in results were impacted by higher earnings from our Natural Gas Pipelines Non-Regulated reporting unit. The year-to-date decrease was dueand CO2 business segments primarily related to $1.95 billionthe February 2021 winter storm and therefore largely nonrecurring, a combined $950 million of non-cash impairments of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting unitsunit and non-cash impairments of certain oil and gas producing assets in our CO2 business segment. The decreases in results were further impacted by lower earnings from all of our business segments primarily attributable to COVID-19-related reduced energy demand and commodity price impacts discussed above, the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and Terminals business segments, partially offset by the benefit of expansion projects in our Natural Gas Pipelines business segment and byrecognized in 2020, lower interest expense and DD&A expense.expense, partially offset by lower earnings from our Terminals and Products Pipelines business segments.

32

Certain Items Affecting Consolidated Earnings Results
Three Months Ended June 30,
20202019
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$(3) $1,019  $1,016  $1,088  $(17) $1,071  $(55) 
Products Pipelines227  —  227  307  —  307  (80) 
Terminals229  —  229  290  —  290  (61) 
CO2
146  10  156  196  (12) 184  (28) 
Total Segment EBDA(a)599  1,029  1,628  1,881  (29) 1,852  (224) 
DD&A and amortization of excess cost of equity investments(567) —  (567) (598) —  (598) 31  
General and administrative and corporate charges(a)(157) —  (157) (155) 3  (152) (5) 
Interest, net(a)(395) (1) (396) (452) (3) (455) 59  
(Loss) income before income taxes(520) 1,028  508  676  (29) 647  (139) 
Income tax expense(b)(104) (10) (114) (148) 5  (143) 29  
Net (loss) income(624) 1,018  394  528  (24) 504  (110) 
Net income attributable to noncontrolling interests(a)(13) —  (13) (10) (1) (11) (2) 
Net (loss) income attributable to Kinder Morgan, Inc.$(637) $1,018  $381  $518  $(25) $493  $(112) 
40

Six Months Ended June 30,
20202019
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts
increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$1,193  $1,002  $2,195  $2,291  $(19) $2,272  $(77) 
Products Pipelines496  4  500  583  17  600  (100) 
Terminals486  —  486  589  —  589  (103) 
CO2
(609) 940  331  394  (21) 373  (42) 
Kinder Morgan Canada—  —  —  (2) 2  —  —  
Total Segment EBDA(a)1,566  1,946  3,512  3,855  (21) 3,834  (322) 
DD&A and amortization of excess cost of equity investments(1,164) —  (1,164) (1,212) —  (1,212) 48  
General and administrative and corporate charges(a)(322) 25  (297) (316) 6  (310) 13  
Interest, net(a)(831) —  (831) (912) (1) (913) 82  
(Loss) income before income taxes(751) 1,971  1,220  1,415  (16) 1,399  (179) 
Income tax expense(b)(164) (106) (270) (320) 7  (313) 43  
Net (loss) income(915) 1,865  950  1,095  (9) 1,086  (136) 
Net income attributable to noncontrolling interests(a)(28) —  (28) (21) (1) (22) (6) 
Net (loss) income attributable to Kinder Morgan, Inc.$(943) $1,865  $922  $1,074  $(10) $1,064  $(142) 
_______
Three Months Ended March 31,
20212020
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$2,103 $(9)$2,094 $1,196 $(17)$1,179 $915 
Products Pipelines248 15 263 269 4 273 (10)
Terminals227 — 227 257 — 257 (30)
CO2
286 5 291 (755)930 175 116 
Total Segment EBDA(a)2,864 11 2,875 967 917 1,884 991 
DD&A and amortization of excess cost of equity investments(563)— (563)(597)— (597)34 
General and administrative and corporate charges(a)(148)— (148)(165)25 (140)(8)
Interest, net(a)(377)(6)(383)(436)1 (435)52 
Income (loss) before income taxes1,776 5 1,781 (231)943 712 1,069 
Income tax expense(b)(351)(40)(391)(60)(96)(156)(235)
Net income (loss)1,425 (35)1,390 (291)847 556 834 
Net income attributable to noncontrolling interests(a)(16)— (16)(15)— (15)(1)
Net income (loss) attributable to Kinder Morgan, Inc.$1,409 $(35)$1,374 $(306)$847 $541 $833 
(a)For a more detailed discussion of these 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 Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

Net income (loss) income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) decreasedincreased by $112$833 million and $142 million for the three and six months ended June 30, 2020, respectively, asin 2021 compared to the respective prior year periods. Decreases2020. The increase in Adjusted Segment EBDA from the prior quarter and year-to-date periods were primarily due to lowerwas impacted by higher earnings from all of our business segments primarily attributable to COVID-19-related reduced energy demand and commodity price impacts discussed above and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and TerminalsCO2 business segments primarily related to the February 2021 winter storm, and therefore largely nonrecurring, and lower interest expense and DD&A expense partially offset by the benefit of expansion projects inlower earnings from our Natural GasTerminals and Products Pipelines business segment.segments.

4133

Non-GAAP Financial Measures

Reconciliation of Net Income (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Three Months Ended June 30,Six Months Ended June 30,Three Months Ended March 31,
202020192020201920212020
(In millions)(In millions)
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)$(637) $518  $(943) $1,074  
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)$1,409 $(306)
Total Certain ItemsTotal Certain Items1,018  (25) 1,865  (10) Total Certain Items(35)847 
Adjusted Earnings(a)Adjusted Earnings(a)381  493  922  1,064  Adjusted Earnings(a)1,374 541 
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)659  691  1,350  1,399  DD&A and amortization of excess cost of equity investments for DCF(b)638 691 
Income tax expense for DCF(a)(b)Income tax expense for DCF(a)(b)132  162  313  357  Income tax expense for DCF(a)(b)419 181 
Cash taxes(c)(b)Cash taxes(c)(b)(5) (51) (8) (64) Cash taxes(c)(b)1 (3)
Sustaining capital expenditures(c)(b)Sustaining capital expenditures(c)(b)(159) (189) (300) (304) Sustaining capital expenditures(c)(b)(107)(141)
Other items(d)(c)Other items(d)(c)(7) 22  (15) 47  Other items(d)(c)4 (8)
DCFDCF$1,001  $1,128  $2,262  $2,499  DCF$2,329 $1,261 

Adjusted Segment EBDA to Adjusted EBITDA to DCF
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions, except per share amounts)
Natural Gas Pipelines$1,016  $1,071  $2,195  $2,272  
Products Pipelines227  307  500  600  
Terminals229  290  486  589  
CO2
156  184  331  373  
Adjusted Segment EBDA(a)1,628  1,852  3,512  3,834  
General and administrative and corporate charges(a)(157) (152) (297) (310) 
KMI’s share of joint venture DD&A and income tax expense(a)(e)110  119  229  245  
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)(13) (2) (28) (5) 
Adjusted EBITDA1,568  1,817  3,416  3,764  
Interest, net(a)(396) (455) (831) (913) 
Cash taxes(c)(5) (51) (8) (64) 
Sustaining capital expenditures(c)(159) (189) (300) (304) 
KML noncontrolling interests DCF adjustments(f)—  (16) —  (31) 
Other items(d)(7) 22  (15) 47  
DCF$1,001  $1,128  $2,262  $2,499  
Adjusted Earnings per common share$0.17  $0.22  $0.40  $0.47  
Weighted average common shares outstanding for dividends(g)2,274  2,275  2,275  2,275  
DCF per common share$0.44  $0.50  $0.99  $1.10  
Declared dividends per common share$0.2625  $0.25  $0.525  $0.50  
_______
Three Months Ended March 31,
20212020
(In millions, except per share amounts)
Natural Gas Pipelines$2,094 $1,179 
Products Pipelines263 273 
Terminals227 257 
CO2
291 175 
Adjusted Segment EBDA(a)2,875 1,884 
General and administrative and corporate charges(a)(148)(140)
Joint venture DD&A and income tax expense(a)(b)103 119 
Net income attributable to noncontrolling interests(a)(16)(15)
Adjusted EBITDA2,814 1,848 
Interest, net(a)(383)(435)
Cash taxes(b)1 (3)
Sustaining capital expenditures(b)(107)(141)
Other items(c)4 (8)
DCF$2,329 $1,261 
Adjusted Earnings per share$0.60 $0.24 
Weighted average shares outstanding for dividends(d)2,277 2,277 
DCF per share$1.02 $0.55 
Declared dividends per share$0.27 $0.2625 
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income (Loss) IncomeAttributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.
(b)Includes KMI’s share ofor represents DD&A, or income tax expense, cash taxes and/or sustaining capital expenditures (as applicable for each item) from joint ventures as applicable. 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 KMI’s share of cash taxes or sustaining capital expenditures from joint ventures, as applicable. See tables included in “—Supplemental Information” below.
(d)Includes non-cash pension expense and non-cash compensation associated with our restricted stock program.
42

(e)KMI’s share of unconsolidated joint venture DD&Aprogram, non-cash pension expense and income tax expense, net of consolidating joint venture partners’ share of DD&A.pension contributions.
(f)2019 amount represents 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.
34

Reconciliation of Net Income (Loss) IncomeAttributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions)
Net (loss) income (GAAP)$(624) $528  $(915) $1,095  
Certain Items:
Fair value amortization(4) (7) (12) (15) 
Legal, environmental and taxes other than income tax reserves—  —  (8) 17  
Change in fair value of derivative contracts(a)32  (18) (4) (8) 
(Gain) loss on impairments and divestitures, net(b)—  (7) 371  (5) 
Loss on impairment of goodwill(c)1,000  —  1,600  —  
Income tax Certain Items(10) 5  (106) 7  
Noncontrolling interests associated with Certain Items—  (1) —  (1) 
Other—  3  24  (5) 
Total Certain Items1,018  (25) 1,865  (10) 
DD&A and amortization of excess cost of equity investments567  598  1,164  1,212  
Income tax expense(d)114  143  270  313  
KMI’s share of joint venture DD&A and income tax expense(d)(e)110  119  229  245  
Interest, net(d)396  455  831  913  
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(d))(13) (1) (28) (4) 
Adjusted EBITDA$1,568  $1,817  $3,416  $3,764  
______
Three Months Ended March 31,
20212020
(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)(a)$1,409 $(306)
Certain Items:
Fair value amortization(4)(8)
Legal, environmental and taxes other than income tax reserves84 (8)
Change in fair value of derivative contracts(b)14 (36)
(Gain) loss on divestitures, impairments and other write-downs, net(c)(89)371 
Loss on impairment of goodwill(d)— 600 
Income tax Certain Items(40)(96)
Other— 24 
Total Certain Items(e)(35)847 
DD&A and amortization of excess cost of equity investments563 597 
Income tax expense(f)391 156 
Joint venture DD&A and income tax expense(f)(g)103 119 
Interest, net(f)383 435 
Adjusted EBITDA$2,814 $1,848 
(a)In prior periods, Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.
(b)Gains or losses are reflected in our DCF when realized.
(b)(c)Six months ended June 30,2021 amount 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. 2020 amount includes: (i)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 priceprices and $21 million for asset impairments in our Products Pipelines business segment, which are reported within “Loss (gain)“(Gain) loss on impairmentsdivestitures and divestitures,impairments, net” on our Consolidated Earnings Results (GAAP) table above.the accompanying consolidated statement of operations.
(c)(d)Three and six months ended June 30, 2020 amounts include a non-cash impairment of goodwill associated with our Natural Gas Pipelines Non-Regulated reporting unit. Six months ended June 30, 2020 also includesamount represents a non-cash impairment of goodwill associated with our CO2reporting unit.
(d)(e)2021 amount includes $117 million and 2020 amount includes less than $1 million reported within “Earnings from equity investments” on our consolidated statements of operations.
(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.
(e)(g)KMI’s share of unconsolidatedRepresents joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.expense. See tables included in “—Supplemental Information” below.


4335

Supplemental Information
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions)
DD&A (GAAP)$532  $579  $1,097  $1,172  
Amortization of excess cost of equity investments (GAAP)35  19  67  40  
DD&A and amortization of excess cost of equity investments567  598  1,164  1,212  
Our share of joint venture DD&A92  98  186  197  
DD&A attributable to KML noncontrolling interests—  (5) —  (10) 
DD&A and amortization of excess cost of equity investments for DCF$659  $691  $1,350  $1,399  
Income tax expense (GAAP)$104  $148  $164  $320  
Certain Items10  (5) 106  (7) 
Income tax expense(a)114  143  270  313  
Our share of taxable joint venture income tax expense(a)18  21  43  48  
Income tax expense attributable to KML noncontrolling interests(a)—  (2) —  (4) 
Income tax expense for DCF(a)$132  $162  $313  $357  
Net income attributable to KML noncontrolling interests$—  $8  $—  $16  
KML noncontrolling interests associated with Certain Items—  1  —  1  
KML noncontrolling interests(a)—  9  —  17  
DD&A attributable to KML noncontrolling interests—  5  —  10  
Income tax expense attributable to KML noncontrolling interests(a)—  2  —  4  
KML noncontrolling interests DCF adjustments(a)$—  $16  $—  $31  
Net income attributable to noncontrolling interests (GAAP)$13  $10  $28  $21  
Less: KML noncontrolling interests(a)—  9  —  17  
Net (loss) income attributable to noncontrolling interests (net of KML noncontrolling interests(a))13  1  28  4  
Noncontrolling interests associated with Certain Items—  1  —  1  
Net (loss) income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)$13  $2  $28  $5  
Additional joint venture information:
Our share of joint venture DD&A$92  $98  $186  $197  
Our share of joint venture income tax expense(a)18  21  43  48  
Our share of joint venture DD&A and income tax expense(a)$110  $119  $229  $245  
Our share of taxable joint venture cash taxes$(6) $(34) $(10) $(34) 
Our share of joint venture sustaining capital expenditures$(26) $(31) $(52) $(50) 
______
Three Months Ended March 31,
20212020
(In millions)
DD&A (GAAP)$541 $565 
Amortization of excess cost of equity investments (GAAP)22 32 
DD&A and amortization of excess cost of equity investments563 597 
Joint venture DD&A75 94 
DD&A and amortization of excess cost of equity investments for DCF$638 $691 
Income tax expense (GAAP)$351 $60 
Certain Items40 96 
Income tax expense(a)391 156 
Unconsolidated joint venture income tax expense(a)(b)28 25 
Income tax expense for DCF(a)$419 $181 
Additional joint venture information
Unconsolidated joint venture DD&A$86 $103 
Less: Consolidated joint venture partners’ DD&A11 9 
Joint venture DD&A75 94 
Unconsolidated joint venture income tax expense(a)(b)28 25 
Joint venture DD&A and income tax expense(a)$103 $119 
Unconsolidated joint venture cash taxes(b)$— $(4)
Unconsolidated joint venture sustaining capital expenditures$(20)$(26)
Less: Consolidated joint venture partners’ sustaining capital expenditures(1)(1)
Joint venture sustaining capital expenditures$(19)$(25)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments.

4436

Segment Earnings Results

Natural Gas Pipelines
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions, except operating statistics)
Revenues$1,571  $1,968  $3,446  $4,169  
Operating expenses(729) (1,030) (1,577) (2,197) 
(Loss) gain on impairments and divestitures, net(1,000) 10  (1,000) 10  
Other income—  1  1  2  
Earnings from equity investments151  131  315  290  
Other, net4  8  8  17  
Segment EBDA(3) 1,088  1,193  2,291  
Certain Items(a)(b)1,019  (17) 1,002  (19) 
Adjusted Segment EBDA$1,016  $1,071  $2,195  $2,272  
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(366) (19)%$(724) (17)%
Adjusted Segment EBDA(55) (5)%(77) (3)%
Volumetric data(c)
Transport volumes (BBtu/d)35,733  34,790  37,414  35,413  
Sales volumes (BBtu/d)2,112  2,323  2,303  2,327  
Gathering volumes (BBtu/d)3,043  3,323  3,202  3,312  
NGLs (MBbl/d)29  32  30  32  
_______
Three Months Ended March 31,
20212020
(In millions, except operating statistics)
Revenues$4,125 $1,875 
Operating expenses(2,270)(848)
Other income1 1 
Earnings from equity investments41 164 
Other, net206 4 
Segment EBDA2,103 1,196 
Certain Items(a)(9)(17)
Adjusted Segment EBDA$2,094 $1,179 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$915 
Volumetric data(b)
Transport volumes (BBtu/d)37,222 38,328 
Sales volumes (BBtu/d)2,260 2,495 
Gathering volumes (BBtu/d)2,509 3,361 
NGLs (MBbl/d)30 30 
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $23$(9) million and $(1)$(17) million for 2021 and 2020, respectively. 2021 amount includes a pre-tax gain of $206 million associated with the threesale 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 six months ended June 30,an increase in expense of $69 million related to a certain litigation matter. 2020 respectively, and $(8)amount includes an increase in revenues of $24 million for the three months ended June 30, 2019 primarily related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales.
(b)Includes non-revenue Certain Item amounts of $996 million and $1,003 million for the three and six months ended June 30, 2020, respectively, and $(9) million and $(19) million for the three and six months ended June 30, 2019, respectively. Three and six month 2020 amounts primarily resulted from a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit. Six month 2019 amount primarily relates tosales partially offset by an increase in earnings for our share ofexpense associated with a certain equity investees’ amortization of regulatory liabilities.EPNG litigation matter.
Other
(c)(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019:2020:

Three Months Ended June 30, 2020March 31, 2021 versus Three Months Ended June 30, 2019March 31, 2020

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues increase/(decrease)Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
MidstreamMidstream$(72) (24)%$(411) (37)%Midstream$901 284%
East RegionEast Region19 3%
West RegionWest Region(15) (6)%(7) (2)%West Region(5)(2)%
East Region32  6 %51  10 %
Intrasegment eliminations—  — %1  25 %
Total Natural Gas PipelinesTotal Natural Gas Pipelines$(55) (5)%$(366) (19)%Total Natural Gas Pipelines$915 78 %
4537

Six Months Ended June 30, 2020 versus Six Months Ended June 30, 2019

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Midstream$(115) (17)%$(825) (34)%
West Region(14) (3)%3  — %
East Region52  5 %96  9 %
Intrasegment eliminations—  — %2  29 %
Total Natural Gas Pipelines$(77) (3)%$(724) (17)%

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 six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019:2020:
•Midstream’s decreases of $72$901 million (24%(284%) and $115 million (17%), respectively, wereincrease in Midstream was primarily due to (i) decreases of $38 million and $72 million, respectively, related to the salehigher sales margins driven by higher commodity prices as a result of the Cochin PipelineFebruary 2021 winter storm on December 16, 2019 to Pembina;our Texas intrastate natural gas pipeline operations; (ii) lower volumeshigher commodity prices as a result of the February 2021 winter storm on KinderHawk, Oklahoma and Hiland Midstream assets; (iii) lower prices onour South Texas assets; and (iv) lower contract rates on our North Texas assets. These decreases were partially offset by (iii) higher equity earnings due to the Gulf Coast ExpressPermian Highway Pipeline being placed in service in September 2019. Overall Midstream’s revenues decreased in both the three and six-month periods primarilyJanuary 2021. These increases were partially offset by lower earnings on (i) our Oklahoma assets due to lowerhigher commodity prices which was largely offset by corresponding decreases in costs of sales;
•West Region’s decreases of $15 million (6%) and $14 million (3%), respectively, were primarily due to decreases in earnings from (i) Ruby Pipeline Company, L.L.C. primarily due to lower transportation revenues and an increase in operating expenses due to the recognition of a credit loss reserve associated with a shipper; (ii) EPNG driven by higher operating expenses; and (iii) Cheyenne Plains Gas Pipeline Company, L.L.C.on certain purchase contracts as a result of the expiration of one shipper’s contract,February 2021 winter storm; and (ii) KinderHawk due to lower volumes. Overall Midstream’s revenues increased primarily due to higher commodity prices which was partially offset by increased earnings from CIG resulting from an expansion projectcorresponding increases in the Denver Julesburg basin;costs of sales; and
•$19 million (3%) increase in the East Region’s increases of $32 million (6%) and $52 million (5%), respectively, wereRegion was primarily due to increasesan increase in earnings from ELC(i) TGP as a result of increased revenues primarily driven by the February 2021 winter storm; and Southern LNG Company, L.L.C.(ii) ELC resulting from six of tenthe liquefaction units (part of the Elba Liquefaction project)project being placed into service in the later partfully operational as of 2019 and first six months ofAugust 2020, partially offset by reduced contributionsequity earnings from TGPFayetteville Express Pipeline LLC primarily due to mild weather in the Northeast and the impactlower revenues as a result of the FERC 501-G rate settlement.contract expirations.
46

Products Pipelines
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions, except operating statistics)
Revenues$345  $442  $840  $866  
Operating expenses(131) (157) (352) (323) 
Loss on impairments and divestitures, net—  —  (21) —  
Earnings from equity investments13  17  28  35  
Other, net—  5  1  5  
Segment EBDA227  307  496  583  
Certain Items(a)—  —  4  17  
Adjusted Segment EBDA$227  $307  $500  $600  
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(97) (22)%$(26) (3)%
Adjusted Segment EBDA(80) (26)%(100) (17)%
Volumetric data(b)
Gasoline(c)762  1,090  862  1,035  
Diesel fuel371  379  365  358  
Jet fuel98  303  196  298  
Total refined product volumes1,231  1,772  1,423  1,691  
Crude and condensate479  651  590  647  
Total delivery volumes (MBbl/d)1,710  2,423  2,013  2,338  
_______
Three Months Ended March 31,
20212020
(In millions, except operating statistics)
Revenues$453 $495 
Operating expenses(219)(221)
Loss on divestitures and impairments, net— (21)
Earnings from equity investments14 15 
Other, net— 1 
Segment EBDA248 269 
Certain Items(a)15 4 
Adjusted Segment EBDA$263 $273 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$(10)
Volumetric data(b)
Gasoline(c)892 961 
Diesel fuel379 358 
Jet fuel175 293 
Total refined product volumes1,446 1,612 
Crude and condensate507 702 
Total delivery volumes (MBbl/d)1,953 2,314 
Certain Items affecting Segment EBDA
(a)Includes non-revenue Certain Item amounts of $15 million and $4 million for 2021 and $172020, respectively. 2021 amount includes an increase in expense of $15 million for the six months ended June 30, 2020 and 2019, respectively. Six monthrelated to an environmental reserve adjustment. 2020 amount 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. Six month 2019 amount is related to an 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.

38

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019.2020:

Three Months Ended June 30, 2020March 31, 2021 versus Three Months Ended June 30, 2019March 31, 2020

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues increase/(decrease)
(In millions, except percentages)
Crude and Condensate$(32) (28)%$(53) (30)%
West Coast Refined Products(30) (24)%(33) (18)%
Southeast Refined Products(18) (27)%(11) (13)%
Total Products Pipelines$(80) (26)%$(97) (22)%
47


Six Months Ended June 30, 2020 versus Six Months Ended June 30, 2019

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$(13)(11)%
Crude and CondensateCrude and Condensate$(49) (21)%$1  — %Crude and Condensate(10)(10)%
West Coast Refined Products(20) (8)%(26) (7)%
Southeast Refined ProductsSoutheast Refined Products(31) (23)%(1) (1)%Southeast Refined Products13 25 %
Total Products Pipelines Total Products Pipelines $(100) (17)%$(26) (3)%Total Products Pipelines$(10)(4)%

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 six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019:2020:
•$13 million (11%) decrease in West Coast Refined Products was primarily due to decreased earnings on Pacific (SFPP) operations driven by lower services revenues as a result of lower volumes and higher operating expense as a result of higher integrity management spending;
•$10 million (10%) decrease in Crude and Condensate’s decreases of $32 million (28%) and $49 million (21%), respectively, wereCondensate was primarily due to decreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s decreased earnings werewas primarily due to lower contracted ratesexpiration of contracts in 2020 and lower volumes.volumes which were exacerbated by temporary supply and demand interruptions from the February 2021 winter storm partially offset by lower operating expense attributable to first quarter 2020 unfavorable inventory valuation adjustments. The Bakken Crude assets decreased earnings were primarily driven by lower volumes. KMCC and Bakken Crude assets year-to-date decreases were also impactedvolumes partially offset by lower operating expense attributable to first quarter 2020 unfavorable inventory valuation adjustments driven by declines in commodity prices during the first quarter of 2020;
•West Coast Refined Products’ decreases of $30 million (24%) and $20 million (8%), respectively, were due to decreased earnings on Pacific (SFPP) operations, Calnev Pipe Line LLC and West Coast terminals driven by lower services revenues as a result of a reduction in volumes due to COVID-19;field operating expenses; and
•$13 million (25%) increase in Southeast Refined Products’ decreases of $18 million (27%) and $31 million (23%), respectively, wereProducts was primarily due to decreased earnings from our South East Terminals 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. Year-to-date decrease was also impacted by lower earnings fromoperating expenses at our Transmix processing operations driven by first quarter 2020 unfavorable inventory adjustments resulting from commodity price declines during the first quarter 2020.adjustments.

Terminals
Three Months Ended June 30,Six Months Ended June 30,Three Months Ended March 31,
202020192020201920212020
(In millions, except operating statistics)(In millions, except operating statistics)
RevenuesRevenues$419  $507  $861  $1,016  Revenues$420 $442 
Operating expensesOperating expenses(193) (221) (385) (437) Operating expenses(197)(192)
Loss on divestitures and impairments, net(5) —  (5) —  
Gain on divestitures and impairments, netGain on divestitures and impairments, net1 — 
Earnings from equity investmentsEarnings from equity investments7  4  12  9  Earnings from equity investments3 5 
Other, netOther, net1  —  3  1  Other, net— 2 
Segment EBDASegment EBDA229  290  486  589  Segment EBDA227 257 
Certain ItemsCertain Items—  —  —  —  Certain Items— — 
Adjusted Segment EBDAAdjusted Segment EBDA$229  $290  $486  $589  Adjusted Segment EBDA$227 $257 
Change from prior periodChange from prior periodIncrease/(Decrease)Change from prior periodIncrease/(Decrease)
Adjusted revenues$(88) (17)%$(155) (15)%
Adjusted Segment EBDAAdjusted Segment EBDA(61) (21)%(103) (17)%Adjusted Segment EBDA$(30)
Volumetric data(a)Volumetric data(a)Volumetric data(a)
Liquids leasable capacity (MMBbl)Liquids leasable capacity (MMBbl)79.4  79.3  79.4  79.3  Liquids leasable capacity (MMBbl)79.9 79.7 
Liquids utilization %(b)Liquids utilization %(b)95.5 %93.4 %95.5 %93.4 %Liquids utilization %(b)94.6 %93.6 %
Bulk transload tonnage (MMtons)Bulk transload tonnage (MMtons)11.1  14.2  24.0  27.9  Bulk transload tonnage (MMtons)11.0 13.0 
4839

Other
(a)Volumes for assets sold are excluded for all periods presented.
(b)The ratio of our tankage capacity in service to tankage capacity available for service.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019.2020:

Three Months Ended June 30, 2020March 31, 2021 versus Three Months Ended June 30, 2019March 31, 2020

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues increase/(decrease)
(In millions, except percentages)
Alberta Canada$(32) (100)%$(48) (100)%
Gulf Liquids(14) (17)%(7) (6)%
Mid Atlantic(7) (37)%(7) (22)%
West Coast(6) (100)%(17) (100)%
All others (including intrasegment eliminations)(2) (1)%(9) (3)%
Total Terminals$(61) (21)%$(88) (17)%

Six Months Ended June 30, 2020 versus Six Months Ended June 30, 2019

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues
increase/(decrease)		Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Alberta Canada$(65) (100)%$(97) (100)%
Gulf CentralGulf Central$(15)(44)%
Marine operationsMarine operations(10)(19)%
Gulf LiquidsGulf Liquids(16) (10)%(6) (3)%Gulf Liquids(5)(6)%
Mid Atlantic(9) (24)%(12) (18)%
West Coast(12) (100)%(33) (100)%
All others (including intrasegment eliminations)All others (including intrasegment eliminations)(1) — %(7) (1)%All others (including intrasegment eliminations)— — %
Total TerminalsTotal Terminals$(103) (17)%$(155) (15)%Total Terminals$(30)(12)%

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 six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019:2020:
•$15 million (44%) decrease in the Sale of KML assetsGulf Central terminals primarily driven by unfavorable petroleum coke volumes due to Pembina on December 16, 2019, which accounted forrefinery outages associated with the decreases on our Alberta Canada terminals and our West Coast terminals;February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC;
•decreases of $14$10 million (17%(19%) decrease in Marine operations was primarily due to lower fleet utilization due to market weakness associated with demand reduction attributable to COVID-19; and $16
•$5 million (10%(6%), respectively, from our decrease in the Gulf Liquids terminals was primarily driven by lower volumes and associated ancillary fees related to both continued demand reduction attributable to COVID-19 as well as tanks being temporarily off-lease as they are transitioned to new customers followingand the termination of a major customer contract; and
•decreases of $7 million (37%) and $9 million (24%), respectively,February 2021 winter storm, which also resulted in higher utility costs. These items were partially offset by additional contributions from our Mid Atlantic terminals primarily due to lower coal volumes at our Pier IX facility driven by coal market weakness largely attributable to demand reduction associated with COVID-19.growth projects placed in service.

4940

CO2
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
(In millions, except operating statistics)
Revenues$232  $310  $541  $615  
Operating expenses(91) (123) (213) (240) 
Loss on impairments and divestitures, net—  —  (950) —  
Earnings from equity investments5  9  13  19  
Segment EBDA146  196  (609) 394  
Certain Items(a)(b)10  (12) 940  (21) 
Adjusted Segment EBDA$156  $184  $331  $373  
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(56) (19)%$(63) (11)%
Adjusted Segment EBDA(28) (15)%(42) (11)%
Volumetric data
SACROC oil production22.0  24.4  22.6  24.4  
Yates oil production6.7  7.3  6.9  7.3  
Katz and Goldsmith oil production2.5  3.8  2.9  4.0  
Tall Cotton oil production1.8  2.4  2.1  2.5  
Total oil production, net (MBbl/d)(c)33.0  37.9  34.5  38.2  
NGL sales volumes, net (MBbl/d)(c)9.4  10.4  9.6  10.2  
CO2 production, net (Bcf/d)
0.4  0.6  0.5  0.6  
Realized weighted average oil price per Bbl$50.31  $49.95  $52.56  $49.31  
Realized weighted average NGL price per Bbl$15.84  $23.58  $17.84  $24.75  
_______
Three Months Ended March 31,
20212020
(In millions, except operating statistics)
Revenues$229 $309 
Operating benefit (expenses)49 (122)
Loss on divestitures and impairments, net— (950)
Earnings from equity investments8 8 
Segment EBDA286 (755)
Certain Items(a)5 930 
Adjusted Segment EBDA$291 $175 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$116 
Volumetric data
SACROC oil production19.4 23.2 
Yates oil production6.1 7.0 
Katz and Goldsmith oil production2.6 3.4 
Tall Cotton oil production0.9 2.4 
Total oil production, net (MBbl/d)(b)29.0 36.0 
NGL sales volumes, net (MBbl/d)(b)8.8 9.8 
CO2 sales volumes, net (Bcf/d)
0.4 0.5 
Realized weighted average oil price ($ per Bbl)$51.05 $54.61 
Realized weighted average NGL price ($ per Bbl)$20.14 $19.74 
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $10$5 million and $(10)$930 million for the three2021 and six months ended June 30, 2020, respectively,respectively. 2020 amount includes (i) a $600 million goodwill impairment on our CO2 reporting unit; (ii) non-cash impairments of $350 million on our oil and $(12)gas producing assets; and (iii) an increase in revenues of $20 million and $(21) million for the three and six months ended June 30, 2019, respectively, related to unrealized (gains) lossesmark-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 six months ended June 30, 2020 resulting from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on most of our oil and gas producing assets.
Other
(c)(b)Net of royalties and outside working interests.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three and six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019.2020:

Three Months Ended June 30, 2020March 31, 2021 versus Three Months Ended June 30, 2019March 31, 2020

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$123 110 %
Source and Transportation activitiesSource and Transportation activities$(24) (33)%$(29) (30)%Source and Transportation activities(7)(10)%
Oil and Gas Producing activities(4) (4)%(32) (16)%
Intrasegment eliminations—  — %5  83 %
Total CO2
Total CO2
$(28) (15)%$(56) (19)%
Total CO2
$116 67 %
5041


Six Months Ended June 30, 2020 versus Six Months Ended June 30, 2019

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Source and Transportation activities$(38) (25)%$(45) (23)%
Oil and Gas Producing activities(4) (2)%(27) (7)%
Intrasegment eliminations—  — %9  69 %
Total CO2 
$(42) (11)%$(63) (11)%

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-monththree-month periods ended June 30, 2020March 31, 2021 and 2019:2020:
•decreases$123 million (110%) increase in Oil and Gas Producing activities primarily due to lower operating expenses of $163 million driven by a benefit for the current period realized from returning power to the grid by curtailing oil production during the February 2021 winter storm partially offset by lower volumes driven in part by the curtailed oil production, which decreased revenues by $24 million (33%and lower realized crude oil prices which decreased revenues by $14 million; and
•$7 million (10%) and $38 million (25%), respectively, from ourdecrease in Source and Transportation activities primarily due to decreasesa decrease of $31$12 million and $49 million, respectively, related to lower CO2 sales volumes partially offset by lower operating expenses of $8 million and $13 million, respectively; and
•decreases of $4 million (4%) and $4 million (2%), respectively, from our Oil and Gas Producing activities primarily due to (i) lower volumes which decreased revenues by $28 million and $35 million, respectively; and (ii) lower NGL prices which decreased revenues by $9 million and $16 million, respectively, offset by (i) higher realized crude oil prices which increased revenues by $5 million and $24 million, respectively; and (ii) lower operating expenses of $23 million and $18 million, respectively.$7 million.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of June 30, 2020.March 31, 2021.

Remaining 20202021202220232024
Crude Oil(a)
Price ($/barrel)$55.84  $53.48  $53.28  $50.14  $43.03  
Volume (barrels per day)30,948  17,400  8,400  5,150  850  
NGLs
Price ($/barrel)$27.62  $24.39  
Volume (barrels per day)6,065  575  
Midland-to-Cushing Basis Spread
Price ($/barrel)$0.14  
Volume (barrels per day)31,100  
_______
Remaining 20212022202320242025
Crude Oil(a)
Price ($ per Bbl)$50.38 $51.03 $49.30 $45.11 $46.89 
Volume (MBbl/d)25.70 13.80 8.65 2.85 0.80 
NGLs
Price ($ per Bbl)$31.75 $44.57 
Volume (MBbl/d)5.36 0.16 
Midland-to-Cushing Basis Spread
Price ($ per Bbl)$0.26 $0.73 
Volume (MBbl/d)24.55 10.25 
(a)Includes West Texas Intermediate hedges.

51

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

Three Months Ended June 30,Earnings
increase/(decrease		Three Months Ended March 31,Earnings
increase/(decrease)
2020201920212020Earnings
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
DD&A (GAAP)DD&A (GAAP)$(541)$(565)$24 4 %
General and administrative (GAAP)General and administrative (GAAP)$(155) $(148) $(7) (5)%General and administrative (GAAP)$(156)$(153)$(3)(2)%
Corporate charges(2) (7) 5  71 %
Corporate benefit (charges)Corporate benefit (charges)8 (12)20 167 %
Certain Items(a)Certain Items(a)—  3  (3) (100)%Certain Items(a)— 25 (25)(100)%
General and administrative and corporate charges(b)General and administrative and corporate charges(b)$(157) $(152) $(5) (3)%General and administrative and corporate charges(b)$(148)$(140)$(8)(6)%
Interest, net (GAAP)Interest, net (GAAP)$(395) $(452) $57  13 %Interest, net (GAAP)$(377)$(436)$59 14 %
Certain Items(c)Certain Items(c)(1) (3) 2  67 %Certain Items(c)(6)1 (7)(700)%
Interest, net(b)Interest, net(b)$(396) $(455) $59  13 %Interest, net(b)$(383)$(435)$52 12 %
Net income attributable to noncontrolling interests (GAAP)Net income attributable to noncontrolling interests (GAAP)$(13) $(10) $(3) (30)%Net income attributable to noncontrolling interests (GAAP)$(16)$(15)$(1)(7)%
Certain Items—  (1) 1  100 %
Certain Items(d)Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)Net income attributable to noncontrolling interests(b)$(13) $(11) $(2) (18)%Net income attributable to noncontrolling interests(b)$(16)$(15)$(1)(7)%
42


Six Months Ended June 30,Earnings
increase/(decrease)
20202019
(In millions, except percentages)
General and administrative (GAAP)$(308) $(302) $(6) (2)%
Corporate charges(14) (14) —  — %
Certain Items(a)25  6  19  317 %
General and administrative and corporate charges(b)$(297) $(310) $13  4 %
Interest, net (GAAP)$(831) $(912) $81  9 %
Certain Items(c)—  (1) 1  100 %
Interest, net(b)$(831) $(913) $82  9 %
Net income attributable to noncontrolling interests (GAAP)$(28) $(21) $(7) (33)%
Certain Items—  (1) 1  100 %
Net income attributable to noncontrolling interests(b)$(28) $(22) $(6) (27)%
Certain items
(a)Six month 2020 amount includes an increase in expense of $23 million associated with the non-cash fair value adjustment and the dividend onaccrual prior to the sale of our investment in Pembina common stock.
(b)Amounts are adjusted for Certain Items.
(c)Three2021 and six month 2020 amounts include (i) decreases in interest expense of $4 million and $12$8 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increasesa decrease and an increase in expense of $3$2 million and $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. Three and six month 2019 amounts include (i) decreases in interest expense of $7 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $3 million and $13$11 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.
(d)2021 and 2020 amounts each include less than $1 million of noncontrolling interests associated with Certain Items.

DD&A expense decreased $24 million in 2021 when compared to 2020 primarily due to non-cash impairments taken in the first quarter 2020 on our oil and gas producing assets.

General and administrative expenses and corporate charges adjusted for Certain Items increased $5$8 million and decreased $13 million for the three and six months ended June 30, 2020, respectively,in 2021 when compared with the respective prior year periods. The second quarter increase wasto 2020 primarily due to lower capitalized costs of $24$16 million reflecting the COVID-19-related cutback onreduced capital projectsspending primarily by our CO2 and Natural Gas Pipelines business segments and our Gulf Coast project being placed in service in September 2019, partially offset by lower pension expenses of $11 million and lower expenses of $6 million due to the sale of KML. The year-to-date decrease was primarily due to lower expenses of $20 million due to the sale
52

of KML, lower pension expenses of $23 million, $7 million lower benefit-related costs and a 2019 project write-off in our Terminals segment partially offset by lower capitalized costs$10 million of $39 million reflecting the COVID-19-related cutback on capital projects by our CO2 and Natural Gas Pipelines business segments and our Gulf Coast project being placed in service in September 2019.cost savings associated with organizational efficiency efforts.

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 six months ended June 30, 2020decreased $52 million in 2021 when compared with the respective prior year periods decreased $59 million and $82 million, respectively,to 2020 primarily due to lower weighted averageLIBOR and long-term debt balances and lower LIBOR rates partially offset by lower capitalized interest.interest rates.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of June 30, 2020March 31, 2021 and December 31, 2019,2020, approximately 17%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 for the three and six months ended June 30, 2020 when compared with the respective prior year periods increased $2 million and $6 million, respectively.

Income Taxes

Our tax expense for the three months ended June 30, 2020March 31, 2021 was approximately $104$351 million as compared with $148$60 million for the same period of 2019.2020. The $44$291 million decreaseincrease in tax expense was due primarily to lowerhigher pre-tax book income in the 2020 period.

Our tax expense for the six months ended June 30, 2020 was approximately $164 million as compared with $320 million for the same2021 period of 2019. The $156 million decrease in tax expense was due primarily to (i) lower pre-tax book income in the 2020 period; (ii) lower foreign income taxes as a result of the KML and U.S. Cochin Sale in 2019; and (iii) the refund of alternative minimum tax sequestration credits in 2020.the 2020 period, offset by the 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.

Liquidity and Capital Resources

General

As of June 30, 2020,March 31, 2021, we had $526$1,377 million of “Cash and cash equivalents,” an increase of $341$193 million from December 31, 2019.2020. Additionally, as of June 30, 2020,March 31, 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 $2,232$1,873 million and $2,098$893 million in the first sixthree 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 expect the negative impact of the decline in commodity pricesbelieve our current cash on hand, our cash flows from operations, and refined product demandour borrowing capacity under our revolving credit facility are more than adequate to continue in the near term, which will negatively affectallow us to manage our operating cash flows;requirements, including maturing debt, through 2021; however, we continue to expect that our short-term liquidity needs will be met through retained cash from operations, short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations.

Due to the significant uncertainty regarding the length and impact of COVID-19 on the energy industry and potential impacts to our business, and to preserve flexibility and to continue strengthening our cash position, we announced a 5% increase in our dividend for each of the first and second quarters of 2020 over the fourth quarter of 2019, a reduction in our planned 25% dividend increase, and a reduction of approximately $660 million in our estimated capital expansion for 2020 as a number of planned expansion projects no longer meet our internal return thresholds. As a result, we continue to be able to fully fund our dividend payments as well as all of our discretionary spending in 2020. We expect tomay access the debt capital
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markets from time to time to refinance our maturing long-term debt. Given our revolver availability relative to debt maturing in the next eighteen months, we have significant flexibility on the timing of refinancing those obligations.

To refinance construction costs
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Our board of its recent expansions,directors declared a quarterly dividend of $0.27 per share for the first quarter of 2021, a 3% increase over the dividend declared for the previous quarter. We expect to fully fund our dividend payments as well as our discretionary spending for 2021 without funding from the capital markets and still have additional flexibility to engage in share repurchases on an opportunistic basis.

On February 24, 2020, TGP, a wholly owned subsidiary,11, 2021, we issued in a private placement $1,000registered offering $750 million aggregate principal amount of its 2.90%3.60% senior notes due 20302051 and received net proceeds of $991 million. We$741 million which were used the proceeds to repay maturing debt. Additionally, 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 June 30, 2020,March 31, 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 June 30, 2020,March 31, 2021, our $3,006$2,173 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. During 2020, we used the proceeds from the sale of the Pembina common equity that we received for the sale of KML to reduce debt. Otherwise, as our debt becomes due, weWe intend to fund our short-term 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 $2,712$884 million and $1,862$1,871 million as of June 30, 2020March 31, 2021 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 $850$987 million unfavorablefavorable change from year-end 20192020 was primarily due to (i) an increasea decrease of approximately $665$385 million in senior notes that mature in the next twelve months; (ii) a $221 million decrease of $925in accrued interest; (iii) a $193 million related to the sale of Pembina common equity in January 2020; partially offset by (i) an increase in cash and cash equivalentsequivalents; (iv) a $150 million decrease in accrued contingencies; and (v) an increase in accounts receivable, net of $341 million; (ii)change in accounts payable, of $85 million, partially offset by a favorable fair value adjustment of $211$186 million on derivative contractsincrease in 2020; and (iii) the $100 million repayment of the preferred interest in Kinder Morgan G.P. Inc.current regulatory liabilities. 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 June 30, 2020March 31, 2021 and December 31, 2019,2020, was $20$29 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 six months ended June 30, 2020. Our outlook as discussed under “—2020 Outlook” takes into account the estimated impact for 2020 attributable to counterparty bankruptcy filings to date. See also our “Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, Part II, Item 1A. Risk Factors —Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.”.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as
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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
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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 sixthree months ended June 30, 2020,March 31, 2021, and the amount we expect to spend for the remainder of 20202021 to sustain and grow our businesses are as follows:
Six Months Ended June 30, 20202020 RemainingTotal 2020(a)
(In millions)
Sustaining capital expenditures(b)(c)$300  $354  $654  
Discretionary capital investments(c)(d)(e)1,024  707  1,731  
_______
Three Months Ended March 31, 20212021 RemainingTotal 2021
(In millions)
Sustaining capital expenditures(a)(b)$107 $757 $864 
Discretionary capital investments(b)(c)(d)132 703 835 
(a)AmountsThree months ended March 31, 2021, 2021 Remaining, and Total 2021 amounts include reductions due to revised outlook, as discussed above$18 million, $86 million, and $104 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “—GeneralNon-GAAP Financial Measures—Supplemental Information..”
(b)SixThree months ended June 30, 2020, 2020 Remaining,March 31, 2021 amount excludes $67 million due to decreases in accrued capital expenditures and Total 2020 amounts include $52 million, $66 million,contractor retainage and $118 million, respectively, for our proportionate share of certain equity investees’ and certain consolidating joint venture subsidiaries’ sustaining capital expenditures.net changes in other.
(c)SixThree months ended June 30, 2020 amount include $4 million of net changes from accrued capital expenditures, contractor retainage, and other.
(d)Six months ended June 30, 2020March 31, 2021 amount includes $305$21 million of our contributions to certain unconsolidated joint ventures for capital investments.
(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 June 30, 2020March 31, 2021 and December 31, 20192020 were $321$182 million and $439$141 million, respectively. The decreaseincrease of $118$41 million was primarily driven by capital commitments related to our Natural Gas Pipelines business segment.

Cash Flows

Operating Activities

Cash provided by operating activities increased $134$980 million in the sixthree months ended June 30, 2020March 31, 2021 compared to the respective 20192020 period primarily due to:

•a $172$1,043 million increase in cash related to accrued taxes driven largely byafter adjusting the $136$1,716 million ofincrease in net income tax paymentsby $673 million for the combined effects of the period-to-period net changes in non-cash items including the 2020 period compared to $370following: (i) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “—Results of Operations”); (ii) (gain) loss on divestitures and impairments, net (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 $63 million ofdecrease in cash associated with net income tax paymentschanges in the 2019 period, whichworking capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by an unfavorable change in both periodsaccounts
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were primarily for foreign income taxes associated withreceivables due to the saletiming of certain Canadian assetscollections from customers, offset by a favorable change due to the timing of trade payables payments in the respective periods. The income tax payments for the 2020 period are net of a $20 million refund related to alternative minimum tax sequestration credits; and
•a $38 million decrease in cash from other operating activities in the 20202021 period compared to the 20192020 period. The decrease was also driven by payments for litigation matters in the 2021 period.

Investing Activities

Cash used inprovided by investing activities decreased $1,554$205 million for the sixthree months ended June 30, 2020March 31, 2021 compared to the respective 20192020 period primarily attributable to:

•an $827a $494 million increasedecrease 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 “Gains and Losses from Divestitures, Impairments and Other Write-downs” to our consolidated financial statements for further information regarding the transaction of the sale of an interest in NGPL Holdings; partially offset by,
•a $587$173 million decrease in capital expenditures reflecting our overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and
•a $129 million decrease in cash used for contributions to equity investmentsinvestees driven by lower contributions to Gulf Coast Express Pipeline LLC, Citrus Corporation, Fayetteville Express Pipeline LLC,SNG and Permian Highway Pipeline LLC in the 20202021 period compared with the 2019 period, partially offset by contributions made to SNG in the 2020 period; and
•a $215 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 cutback of planned capital projects in the wake of COVID-19.period.

Financing Activities

Cash used in financing activities decreased $1,764increased $1,302 million for the sixthree months ended June 30, 2020March 31, 2021 compared to the respective 20192020 period primarily attributable to:

•a $1,190$1,317 million net decreaseincrease in cash used related to debt activity as a result of lower$1,168 million of net debt payments in the 20202021 period compared to the 2019 period; and
•an $879$149 million increase in cash reflecting distribution of the TMPL sale proceeds to the owners of KML restricted voting sharesnet debt issuances in the 2019 period; partially offset by,
•a $142 million increase in dividend payments to our common shareholders; and
•a $101 million decrease in contributions received from investment partner and noncontrolling interests primarily driven by lower contributions received from EIG Global Energy Partners in the 2020 period compared to the 2019 period.

Common Stock Dividends

We expect to declare common stock dividends of $1.05$1.08 per share on our common stock for 2020.2021. The table below reflects our 2020 common stock2021 dividends declared:
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
DecemberMarch 31, 20192021$0.25 0.27 January 22, 2020April 21, 2021February 3, 2020February 18, 2020
March 31, 20200.2625 April 22, 2020May 4, 202030, 2021May 15, 2020
June 30, 20200.2625 July 22, 2020August 3, 2020August 17, 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 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 Reportreport “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of June 30, 2020.March 31, 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 June 30, 2020March 31, 2021 and December 31, 2019,2020, the Obligated Group had $32,140$31,353 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 InformationJune 30, 2020December 31, 2019Summarized Combined Balance Sheet InformationMarch 31, 2021December 31, 2020
(In millions)(In millions)
Current assetsCurrent assets$2,158  $1,918  Current assets$3,465 $2,957 
Current assets - affiliatesCurrent assets - affiliates1,171  1,146  Current assets - affiliates1,197 1,151 
Noncurrent assetsNoncurrent assets62,249  63,298  Noncurrent assets60,648 61,783 
Noncurrent assets - affiliatesNoncurrent assets - affiliates606  441  Noncurrent assets - affiliates506 616 
Total AssetsTotal Assets$66,184  $66,803  Total Assets$65,816 $66,507 
Current liabilitiesCurrent liabilities$4,818  $4,569  Current liabilities$4,295 $4,528 
Current liabilities - affiliatesCurrent liabilities - affiliates1,212  1,139  Current liabilities - affiliates1,223 1,209 
Noncurrent liabilitiesNoncurrent liabilities33,092  33,612  Noncurrent liabilities32,847 33,907 
Noncurrent liabilities - affiliatesNoncurrent liabilities - affiliates1,475  1,325  Noncurrent liabilities - affiliates893 1,078 
Total LiabilitiesTotal Liabilities40,597  40,645  Total Liabilities39,258 40,722 
Redeemable noncontrolling interestRedeemable noncontrolling interest768  803  Redeemable noncontrolling interest705 728 
Kinder Morgan, Inc.’s stockholders’ equityKinder Morgan, Inc.’s stockholders’ equity24,819  25,355  Kinder Morgan, Inc.’s stockholders’ equity25,853 25,057 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ EquityTotal Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$66,184  $66,803  Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$65,816 $66,507 
Summarized Combined Income Statement InformationThree Months Ended June 30, 2020Six Months Ended June 30, 2020
(In millions)
Revenues$2,331  $5,187  
Operating (loss) income(218) 244  
Net loss(497) (350) 
Summarized Combined Income Statement InformationThree Months Ended March 31, 2021
(In millions)
Revenues$4,902 
Operating income1,829 
Net income1,377 

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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 June 30, 2020,March 31, 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 June 30, 2020March 31, 2021 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 June 30, 2020.March 31, 2021.

Item 5.  Other Information.

None.

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Item 6.  Exhibits.
Exhibit
Number                     Description
4.1 
10.1 
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 six months ended June 30, 2020March 31, 2021 and 2019;2020; (ii) our Consolidated Statements of Comprehensive Income (Loss) Income for the three and six months ended June 30, 2020March 31, 2021 and 2019;2020; (iii) our Consolidated Balance Sheets as of June 30, 2020March 31, 2021 and December 31, 2019;2020; (iv) our Consolidated Statements of Cash Flows for the sixthree months ended June 30, 2020March 31, 2021 and 2019;2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2020March 31, 2021 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:July 24, 2020April 23, 2021By:/s/ David P. Michels
David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)
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