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 March 31,September 30, 2020
 
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-20200930_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 April 27,October 22, 2020, the registrant had 2,261,487,0902,263,793,923 Class P shares outstanding.




KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
Page
Number
Number2
2
Information Regarding Forward-Looking Statements
3
Consolidated Statements of Operations - Three and Nine Months Ended March 31,September 30, 2020 and 2019
4
Consolidated Statements of Comprehensive Income (Loss) Income - Three and Nine Months Ended March 31,September 30, 2020 and 2019
5
Consolidated Balance Sheets - as of March 31,September 30, 2020 and December 31, 2019
6
Consolidated Statements of Cash Flows - ThreeNine Months Ended March 31,September 30, 2020 and 2019
7
Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended March 31,September 30, 2020 and 2019
9
Notes to Consolidated Financial Statements
1011
Note 1
1011
Note 2
1112
Note 3
1316
Note 4
1417
Note 5
1518
Note 6
2024
Note 7
2127
Note 8
2228
Note 9
2329
Note 10
2834
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Basis of Presentation
2935
Results of Operations
3136
Overview
3136
Consolidated Earnings Results (GAAP)
3339
Non-GAAP Financial Measures
3442
Segment Earnings Results
3845
General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
4253
Income Taxes
4354
Liquidity and Capital Resources
4354
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
4659
4760
4760
4860
4860
5260
5260
5260
5260
5361
5462

1
KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY


KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY

Company Abbreviations

CIG=Colorado Interstate Gas Company, L.L.C.KMP=Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries
ELC=Elba Liquefaction Company, L.L.C.
EPNG=El Paso Natural Gas Company, L.L.C.SFPP=SFPP, L.P.
KMBT=Kinder Morgan Bulk Terminals, Inc.SNG=Southern Natural Gas Company, L.L.C.
KMI=Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiariesTGP=Tennessee Gas Pipeline Company, L.L.C.
TMEP=TMPL=Trans Mountain Expansion ProjectPipeline System
KML=Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiariesTMPL=Trans Mountain Pipeline System
Trans Mountain=Trans Mountain Pipeline ULC
KMLT=Kinder Morgan Liquid Terminals, LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d=per dayEPA=U.S. Environmental Protection Agency
BBtu=billion British Thermal UnitsFASB=Financial Accounting Standards Board
Bcf=billion cubic feetFERC=Federal Energy Regulatory Commission
CERCLA=Comprehensive Environmental Response, Compensation and Liability ActGAAP=U.S. Generally Accepted Accounting Principles
LLC=LLC=limited liability company
CO2
=
carbon dioxide or our CO2 business segment
LIBOR=London Interbank Offered Rate
COVID-19=Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturnMBbl=thousand barrels
MMBbl=MMBbl=million barrels
DCF=distributable cash flowMMtons=million tons
DD&A=depreciation, depletion and amortizationNGL=natural gas liquids
EBDA=earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investmentsNYMEX=New York Mercantile Exchange
OTC=OTC=over-the-counter
EBITDA=earnings before interest, income taxes, depreciation, depletion and amortization expenses, includingand amortization of excess cost of equity investmentsROU=Right-of-Use
U.S.=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,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict.

Forward-looking statements in this report include statements, express or implied, concerning, without limitation: the long-term demand for our assets and services, the future impact on our business of the global economic consequences of the COVID-19 pandemic, and our expected 2020 outlook, including our expected DCF, Adjusted EBITDA, expectedand Net Debt-to-Adjusted EBITDA ratio and the sensitivity to changes in commodity volume and price assumptions.ratio.

The impacts of COVID-19 and decreases in commodity prices resulting from oversupply and demand weakness are discussed in further detail in Part I, Item 1. “Financial Statements (Unaudited)—Note 1 General—COVID-19;” Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition of Operations—General and Basis of Presentation—COVID-19” and “—2020 Outlook;” Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk;” and Part II, Item 1A. “Risk Factors.Factors,” and in Part II, Item 1A. “Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. In addition to the preceding factors, “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019 (2019 Form 10-K),contain a more detailed description of other factors that may affect the forward-looking statements and should be referenced, except to the extent such other factors are modified or superseded by the descriptions in 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 March 31,
 2020 2019
Revenues   
Services$1,992
 $2,037
Commodity sales1,067
 1,349
Other47
 43
Total Revenues3,106
 3,429
Operating Costs, Expenses and Other   
Costs of sales663
 948
Operations and maintenance620
 598
Depreciation, depletion and amortization565
 593
General and administrative153
 154
Taxes, other than income taxes92
 118
Loss on impairments and divestitures, net (Note 2)971
 —
Other income, net(1) —
Total Operating Costs, Expenses and Other3,063
 2,411
Operating Income43
 1,018
Other Income (Expense)   
Earnings from equity investments192
 192
Amortization of excess cost of equity investments(32) (21)
Interest, net(436) (460)
Other, net2
 10
Total Other Expense(274) (279)
(Loss) Income Before Income Taxes(231) 739
Income Tax Expense(60) (172)
Net (Loss) Income(291) 567
Net Income Attributable to Noncontrolling Interests(15) (11)
Net (Loss) Income Attributable to Kinder Morgan, Inc.$(306) $556
    
Class P Shares   
Basic and Diluted (Loss) Earnings Per Common Share$(0.14) $0.24
Basic and Diluted Weighted Average Common Shares Outstanding2,264
 2,262
    
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts, unaudited)

 Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
Revenues 
Services$1,881 $2,014 $5,664 $6,060 
Commodity sales982 1,154 2,772 3,659 
Other56 46 149 138 
Total Revenues2,919 3,214 8,585 9,857 
Operating Costs, Expenses and Other 
Costs of sales655 762 1,759 2,487 
Operations and maintenance643 668 1,869 1,912 
Depreciation, depletion and amortization539 578 1,636 1,750 
General and administrative153 154 461 456 
Taxes, other than income taxes100 103 295 324 
Loss (gain) on impairments and divestitures, net (Note 2)11 (3)1,987 (13)
Other (income) expense, net(1)1 (2)(1)
Total Operating Costs, Expenses and Other2,100 2,263 8,005 6,915 
Operating Income819 951 580 2,942 
Other Income (Expense) 
Earnings from equity investments194 173 562 526 
Amortization of excess cost of equity investments(32)(21)(99)(61)
Interest, net(383)(447)(1,214)(1,359)
Other, net14 12 32 35 
Total Other Expense(207)(283)(719)(859)
Income (Loss) Before Income Taxes612 668 (139)2,083 
Income Tax Expense(140)(151)(304)(471)
Net Income (Loss)472 517 (443)1,612 
Net Income Attributable to Noncontrolling Interests(17)(11)(45)(32)
Net Income (Loss) Attributable to Kinder Morgan, Inc.$455 $506 $(488)$1,580 
Class P Shares
Basic and Diluted Earnings (Loss) Per Common Share$0.20 $0.22 $(0.22)$0.69 
Basic and Diluted Weighted Average Common Shares Outstanding2,263 2,264 2,263 2,263 
The accompanying notes are an integral part of these consolidated financial statements.
4

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) INCOME
(In Millions, Unaudited)millions, unaudited)
  Three Months Ended March 31,
  2020 2019
Net (loss) income $(291) $567
Other comprehensive income (loss), net of tax    
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(67) and $64, respectively) 222
 (215)
Reclassification of change in fair value of derivatives to net income (net of tax expense of $11 and $4, respectively) 37
 13
Foreign currency translation adjustments (net of tax expense of $- and $5, respectively) 1
 10
Benefit plan adjustments (net of tax expense of $3 and $2, respectively) 11
 8
Total other comprehensive income (loss) 271
 (184)
Comprehensive (loss) income (20) 383
Comprehensive income attributable to noncontrolling interests (15) (5)
Comprehensive (loss) income attributable to Kinder Morgan, Inc. $(35) $378

 Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
Net income (loss)$472 $517 $(443)$1,612 
Other comprehensive (loss) income, net of tax  
Change in fair value of hedge derivatives (net of tax benefit (expense) of $17, $(6), $5, and $39, respectively)(56)20 (16)(132)
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $1, $(13), $(22), and $(11), respectively)(5)40 72 35 
Foreign currency translation adjustments (net of tax benefit (expense) of $0, $2, $0, and $(5), respectively)0 (7)1 16 
Benefit plan adjustments (net of tax expense of $2, $3, $7 and $8, respectively)5 8 21 23 
Total other comprehensive (loss) income(56)61 78 (58)
Comprehensive income (loss)416 578 (365)1,554 
Comprehensive income attributable to noncontrolling interests(17)(8)(45)(28)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.$399 $570 $(410)$1,526 
The accompanying notes are an integral part of these consolidated financial statements.
5

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions, Except Share and Per Share Amounts, Unaudited)
 March 31, 2020 December 31, 2019
ASSETS   
Current Assets   
Cash and cash equivalents$360
 $185
Restricted deposits582
 24
Marketable securities at fair value—
 925
Accounts receivable1,186
 1,379
Fair value of derivative contracts448
 84
Inventories307
 371
Other current assets213
 270
Total current assets3,096
 3,238
Property, plant and equipment, net36,041
 36,419
Investments7,886
 7,759
Goodwill20,851
 21,451
Other intangibles, net2,616
 2,676
Deferred income taxes845
 857
Deferred charges and other assets2,195
 1,757
Total Assets$73,530
 $74,157
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY 
  
Current Liabilities 
  
Current portion of debt$3,540
 $2,477
Accounts payable752
 914
Accrued interest337
 548
Accrued taxes295
 364
Other current liabilities684
 797
Total current liabilities5,608
 5,100
Long-term liabilities and deferred credits 
  
Long-term debt 
  
Outstanding29,955
 30,883
Debt fair value adjustments1,450
 1,032
Total long-term debt31,405
 31,915
Other long-term liabilities and deferred credits2,260
 2,253
Total long-term liabilities and deferred credits33,665
 34,168
Total Liabilities39,273
 39,268
Commitments and contingencies (Notes 3 and 9)


 


Redeemable Noncontrolling Interest793
 803
Stockholders’ Equity 
  
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,261,425,938 and 2,264,936,054 shares, respectively, issued and outstanding
23
 23
Additional paid-in capital41,713
 41,745
Accumulated deficit(8,568) (7,693)
Accumulated other comprehensive loss(62) (333)
Total Kinder Morgan, Inc.’s stockholders’ equity33,106
 33,742
Noncontrolling interests358
 344
Total Stockholders’ Equity33,464
 34,086
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$73,530
 $74,157

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

 September 30, 2020December 31, 2019
ASSETS 
Current Assets 
Cash and cash equivalents$632 $185 
Restricted deposits67 24 
Marketable securities at fair value0 925 
Accounts receivable1,142 1,379 
Fair value of derivative contracts257 84 
Inventories317 371 
Other current assets257 270 
Total current assets2,672 3,238 
Property, plant and equipment, net35,958 36,419 
Investments8,014 7,759 
Goodwill19,851 21,451 
Other intangibles, net2,510 2,676 
Deferred income taxes671 857 
Deferred charges and other assets2,145 1,757 
Total Assets$71,821 $74,157 
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY  
Current Liabilities  
Current portion of debt$2,057 $2,477 
Accounts payable774 914 
Accrued interest351 548 
Accrued taxes335 364 
Accrued contingencies315 89 
Other current liabilities544 708 
Total current liabilities4,376 5,100 
Long-term liabilities and deferred credits  
Long-term debt  
Outstanding31,281 30,883 
Debt fair value adjustments1,379 1,032 
Total long-term debt32,660 31,915 
Other long-term liabilities and deferred credits2,093 2,253 
Total long-term liabilities and deferred credits34,753 34,168 
Total Liabilities39,129 39,268 
Commitments and contingencies (Notes 3 and 9)
Redeemable Noncontrolling Interest747 803 
Stockholders’ Equity  
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,263,749,898 and 2,264,936,054 shares, respectively, issued and outstanding
23 23 
Additional paid-in capital41,736 41,745 
Accumulated deficit(9,945)(7,693)
Accumulated other comprehensive loss(255)(333)
Total Kinder Morgan, Inc.’s stockholders’ equity31,559 33,742 
Noncontrolling interests386 344 
Total Stockholders’ Equity31,945 34,086 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$71,821 $74,157 
The accompanying notes are an integral part of these consolidated financial statements.
6

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
 Nine Months Ended September 30,
 20202019
Cash Flows From Operating Activities 
Net (loss) income$(443)$1,612 
Adjustments to reconcile net (loss) income to net cash provided by operating activities 
Depreciation, depletion and amortization1,636 1,750 
Deferred income taxes164 254 
Amortization of excess cost of equity investments99 61 
Loss (gain) on impairments and divestitures, net (Note 2)1,987 (13)
Earnings from equity investments(562)(526)
Distributions from equity investment earnings487 412 
Changes in components of working capital
Accounts receivable238 224 
Inventories41 (28)
Other current assets14 97 
Accounts payable(107)(266)
Accrued interest, net of interest rate swaps(208)(218)
Accrued taxes(25)(107)
Other current liabilities(111)(136)
Other, net72 5 
Net Cash Provided by Operating Activities3,282 3,121 
Cash Flows From Investing Activities
Capital expenditures(1,351)(1,719)
Proceeds from sales of assets and investments, net of working capital adjustments907 80 
Contributions to investments(365)(1,148)
Distributions from equity investments in excess of cumulative earnings105 207 
Other, net(72)(30)
Net Cash Used in Investing Activities(776)(2,610)
Cash Flows From Financing Activities
Issuances of debt3,888 5,118 
Payments of debt(3,991)(6,303)
Debt issue costs(23)(9)
Common stock dividends(1,764)(1,593)
Repurchases of common shares(50)(2)
Contributions from investment partner and noncontrolling interests11 138 
Distributions to investment partner(60)0 
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds0 (879)
Distributions to noncontrolling interests - other(11)(42)
Other, net(13)(28)
Net Cash Used in Financing Activities(2,013)(3,600)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits(3)26 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits490 (3,063)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period209 3,331 
Cash, Cash Equivalents, and Restricted Deposits, end of period$699 $268 
7

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions, Unaudited)
 Three Months Ended March 31,
 2020 2019
Cash Flows From Operating Activities   
Net (loss) income$(291) $567
Adjustments to reconcile net (loss) income to net cash provided by operating activities   
Depreciation, depletion and amortization565
 593
Deferred income taxes(69) (31)
Amortization of excess cost of equity investments32
 21
Change in fair market value of derivative contracts(36) 10
Loss on impairments and divestitures, net (Note 2)971
 —
Earnings from equity investments(192) (192)
Distributions from equity investment earnings152
 124
Changes in components of working capital   
Accounts receivable222
 193
Inventories59
 (52)
Other current assets50
 128
Accounts payable(200) (189)
Accrued interest, net of interest rate swaps(202) (236)
Accrued taxes(59) (202)
Other current liabilities(126) (149)
Other, net17
 50
Net Cash Provided by Operating Activities893
 635
Cash Flows From Investing Activities   
Capital expenditures(440) (554)
Proceeds from sales of assets and investments, net of working capital adjustments907
 (16)
Contributions to investments(151) (331)
Distributions from equity investments in excess of cumulative earnings41
 81
Other, net(22) 6
Net Cash Provided by (Used in) Investing Activities335
 (814)
Cash Flows From Financing Activities   
Issuances of debt2,125
 1,399
Payments of debt(1,969) (2,990)
Debt issue costs(7) (2)
Common stock dividends(569) (455)
Repurchases of common shares(50) (2)
Contributions from investment partner and noncontrolling interests5
 38
Distributions to investment partner(18) —
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds—
 (879)
Distributions to noncontrolling interests - other(3) (14)
Other, net(1) (3)
Net Cash Used in Financing Activities(487) (2,908)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits(8) 26
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits733
 (3,061)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period209
 3,331
Cash, Cash Equivalents, and Restricted Deposits, end of period$942
 $270
    

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(In Millions, Unaudited)
 Three Months Ended March 31,
 2020 2019
Cash and Cash Equivalents, beginning of period$185
 $3,280
Restricted Deposits, beginning of period24
 51
Cash, Cash Equivalents, and Restricted Deposits, beginning of period209
 3,331
Cash and Cash Equivalents, end of period360
 221
Restricted Deposits, end of period582
 49
Cash, Cash Equivalents, and Restricted Deposits, end of period942
 270
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits$733
 $(3,061)
    
Non-cash Investing and Financing Activities   
ROU assets and operating lease obligations recognized$14
 $701
Increase in property, plant and equipment from both accruals and contractor retainage41
 


Supplemental Disclosures of Cash Flow Information   
Cash paid during the period for interest (net of capitalized interest)661
 690
Cash paid during the period for income taxes, net134
 345

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
 Nine Months Ended September 30,
 20202019
Cash and Cash Equivalents, beginning of period$185 $3,280 
Restricted Deposits, beginning of period24 51 
Cash, Cash Equivalents, and Restricted Deposits, beginning of period209 3,331 
Cash and Cash Equivalents, end of period632 241 
Restricted Deposits, end of period67 27 
Cash, Cash Equivalents, and Restricted Deposits, end of period699 268 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits$490 $(3,063)
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized$15 $764 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,440 1,584 
Cash paid during the period for income taxes, net202 364 
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)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 June 30, 20202,261 $23 $41,731 $(9,802)$(199)$31,753 $371 $32,124 
Restricted shares3 5 5 5 
Net income455 455 17 472 
Distributions0 (4)(4)
Contributions0 2 2 
Common stock dividends(598)(598)(598)
Other comprehensive loss(56)(56)(56)
Balance at September 30, 20202,264 $23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
Common stock
 Issued sharesPar valueAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at June 30, 20192,262 $23 $41,734 $(7,670)$(448)$33,639 $846 $34,485 
Restricted shares3 (7)(7)(7)
Net income506 506 11 517 
Distributions0 (14)(14)
Contributions0 2 2 
Common stock dividends(569)(569)(569)
Other0 (1)(1)
Other comprehensive income (loss)64 64 (3)61 
Balance at September 30, 20192,265 $23 $41,727 $(7,733)$(384)$33,633 $841 $34,474 
 Common stock            
 Issued shares Par value 
Additional
paid-in
capital
 
Accumulated
deficit
 Accumulated
other
comprehensive
loss		 
Stockholders’
equity
attributable
to KMI
 
Non-controlling
interests
 Total
Balance at December 31, 20192,265
 $23
 $41,745
 $(7,693) $(333) $33,742
 $344
 $34,086
Repurchases of common shares(4) 

 (50)     (50)   (50)
Restricted shares  
 18
     18
   18
Net (loss) income      (306)   (306) 15
 (291)
Distributions          —
 (3) (3)
Contributions          —
 2
 2
Common stock dividends      (569)   (569)   (569)
Other comprehensive income        271
 271
 

 271
Balance at March 31, 20202,261
 $23
 $41,713
 $(8,568) $(62) $33,106
 $358
 $33,464

 Common stock            
 Issued shares Par value 
Additional
paid-in
capital
 Accumulated
deficit		 Accumulated
other
comprehensive
loss		 
Stockholders’
equity
attributable
to KMI
 
Non-controlling
interests
 Total
Balance at December 31, 20182,262
 $23
 $41,701
 $(7,716) $(330) $33,678
 $853
 $34,531
Impact of adoption of ASU 2017-12      (4) 


 (4)   (4)
Balance at January 1, 20192,262
 23
 41,701
 (7,720) (330) 33,674
 853
 34,527
Repurchases of common shares
   (2)     (2)   (2)
Restricted shares
   17
     17
   17
Net income      556
   556
 11
 567
Distributions          —
 (14) (14)
Common stock dividends      (455)   (455)   (455)
Other comprehensive loss        (178) (178) (6) (184)
Balance at March 31, 20192,262
 $23
 $41,716
 $(7,619) $(508) $33,612
 $844
 $34,456


The accompanying notes are an integral part of these consolidated financial statements.
9

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

Common stock
 Issued sharesPar valueAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at December 31, 20192,265 $23 $41,745 $(7,693)$(333)$33,742 $344 $34,086 
Repurchases of common shares(4)(50)(50)(50)
Restricted shares3 41 41 41 
Net (loss) income(488)(488)45 (443)
Distributions0 (11)(11)
Contributions0 8 8 
Common stock dividends(1,764)(1,764)(1,764)
Other comprehensive income78 78 78 
Balance at September 30, 20202,264 $23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
Common stock
 Issued sharesPar valueAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at December 31, 20182,262$23 $41,701 $(7,716)$(330)$33,678 $853 $34,531 
Impact of adoption of ASU 2017-12(4)(4)(4)
Balance at January 1, 20192,26223 41,701 (7,720)(330)33,674 853 34,527 
Repurchases of common shares(2)(2)(2)
Restricted shares328 28 28 
Net income1,580 1,580 32 1,612 
Distributions0 (42)(42)
Contributions0 3 3 
Common stock dividends(1,593)(1,593)(1,593)
Other0 (1)(1)
Other comprehensive loss(54)(54)(4)(58)
Balance at September 30, 20192,265$23 $41,727 $(7,733)$(384)$33,633 $841 $34,474 

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

10


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

1. General
1.
General

Organization

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

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2019 Form 10-K.

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

COVID-19

The COVID-19 pandemic-related reduction in energy demand and the sharpdramatic decline in commodity prices relatedthat began to the combined impact of falling demand and recent increasesus in production from Organization of Petroleum Exporting Countries (OPEC) members and other international suppliers have caused significant disruptions and volatility in the global marketplace during the first quarter of 2020. In the first quarter of 2020 we were negativelyhas continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic also affected our business in the second quarter and continues to do so. Further, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and prices for the products handled by theseour pipelines, terminals, shipping vessels and other facilities.

These events, which, among many other inputs,factors, resulted in $950 million of losses from impairments in our CO2 business segment. Thesecertain non-cash impairments arecharges during 2020 as further discussed in Note 2.


Goodwill
There remains
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 continuing significant uncertainty regarding the length and impact of COVID-19 and decreased commodity prices on the energy industry and potential future impacts to our business.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) available to shareholders of Class P shares and participating securities (in millions):securities:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except per share amounts)
Net Income (Loss) Available to Common Stockholders$455 $506 $(488)$1,580 
Participating securities:
   Less: Net Income allocated to restricted stock awards(a)(3)(3)(9)(9)
Net Income (Loss) Allocated to Class P Stockholders$452 $503 $(497)$1,571 
Basic Weighted Average Common Shares Outstanding2,263 2,264 2,263 2,263 
Basic Earnings (Loss) Per Common Share$0.20 $0.22 $(0.22)$0.69 
 Three Months Ended March 31,

2020 2019
Net (Loss) Income Available to Common Stockholders$(306) $556
Participating securities:   
   Less: Net Income allocated to restricted stock awards(a)(3) (3)
Net (Loss) Income Allocated to Class P Stockholders$(309) $553
    
Basic Weighted Average Common Shares Outstanding2,264
 2,262
Basic (Loss) Earnings Per Common Share$(0.14) $0.24
________
(a)As of September 30, 2020, there were approximately 13 million restricted stock awards outstanding.

________
(a)As of March 31, 2020, there were approximately 12 million restricted stock awards outstanding.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share (in millions on a weighted-average basis):share:
Three Months Ended September 30,Nine Months Ended September 30,
Three Months Ended March 31,2020201920202019
2020 2019(In millions on a weighted average basis)
Unvested restricted stock awards12
 13
Unvested restricted stock awards13 13 13 13 
Convertible trust preferred securities3
 3
Convertible trust preferred securities3 3 3 3 


2. Impairments

During the first quarter of 2020, the decrease in the worldwideenergy production and demand for crude oil primarily duefactors related to COVID-19 and the sharp decline in commodity prices related to the combined impact of falling demand and recent increases in production from OPEC members and other international suppliers resulted in decreases in current and expected long-term crude oil and NGL sale prices, along with reductions to the market capitalization of peer companies in the energy industry. We determined that these conditions represented a triggering eventevents that required us to perform impairment testing ofon certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business 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 CO2 business segment during the three months ended March 31, 2020.

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


We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assets during the nine months ended September 30, 2020 and 2019:
Nine Months Ended September 30,
20202019
(In millions)
Natural Gas Pipelines
Impairment of goodwill$1,000 $0 
Impairments of inventory11 0 
Gain on divestitures of long-lived assets0 (10)
Products Pipelines
Impairment of long-lived and intangible assets21 0 
Terminals
Impairment of long-lived and intangible assets5 0 
Gain on divestitures of long-lived assets0 (3)
CO2
Impairment of goodwill600 0 
Impairment of long-lived assets350 0 
Kinder Morgan Canada
Loss on divestiture of long-lived assets0 2 
Other gain on divestitures of long-lived assets0 (2)
Pre-tax loss (gain) on divestitures and impairments, net$1,987 $(13)

Long-lived Assets

ForAs of March 31, 2020, for our CO2 assets, the long lived asset impairment test involved a Step 1an 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.

2 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 representsrepresented the estimated weighted average cost of capital of a

theoretical market participant. Based on step two of our long lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.

13


Goodwill

Changes in the amounts of our goodwill for the nine months ended September 30, 2020 are summarized by reporting unit as follows:
Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-Regulated
CO2
Products PipelinesProducts Pipelines TerminalsTerminalsTotal
(In millions)
Goodwill as of December 31, 2019$14,249 $3,343 $1,528 $1,378 $151 $802 $21,451 
Impairments0 (1,000)(600)0 0 0 (1,600)
Goodwill as of September 30, 2020$14,249 $2,343 $928 $1,378 $151 $802 $19,851 
The following
•Our May 31, 2020 goodwill impairment testtests 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 units reflectsunit. For 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 theMay 31, 2020 goodwill impairment test by removing Step 2 of the CO2 reporting unit we used the income approach with assumptions similar to those used for its March 31, 2020 goodwill impairment test, which required a hypothetical purchase price allocation.test.

For our CO•2 and Natural Gas Pipelines Non-Regulated reporting units, we applied an income approachIn regards to evaluate the fair value of these reporting units based on the present value of cash flows these reporting units are expected to generate in the future. Due to the uncertainty and volatility in market conditions within our peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.

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

For 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 66.5 years of projections and application of a year 6an 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, including,and as applicable current commodity prices. applied to our existing contracts and expected future customer demand for such commodities. The fair value based on a weighting of the market and income approaches resulted in an implied EV to 2020 EBITDA multiple valuation of approximately 11x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium at the reporting unit level.

The results of our impairment analysis for ourthe Natural Gas Pipelines Non-Regulated reporting unit did not indicate angoodwill impairment analysis was a partial impairment of goodwill withof approximately $1,000 million as of May 31, 2020.

•For our March 31, 2020 interim goodwill impairment test of the CO2 reporting unit’sunit, we applied an income approach to evaluate its fair value in excessbased on the present value of its carryingcash 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 by less than 10% as of March 31, 2020.
14

We consider

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

The fair value estimates used in the long-lived asset and goodwill impairment calculations to betest were primarily based on Level 3 inputs inof the fair value hierarchy.
We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets (in millions):
 Three Months Ended March 31,
 2020 2019
Products Pipelines   
Impairments of long-lived and intangible assets(a)$21
 $—
CO2
   
Impairments of long-lived assets350
 —
Impairment of goodwill600
 —
Kinder Morgan Canada   
Losses on divestiture of long-lived assets—
 2
Other gains on divestitures of long-lived assets—
 (2)
Pre-tax losses on divestitures and impairments, net$971
 $—
_______
(a)2020 impairment amount is associated with our Belton terminal.

Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us. In addition, the revenues, cash flows, profitability and future growth of some of our

businesses depend to a large degree on prevailing crude oil, NGL and natural gas prices. Our CO2 business segment (and the carrying value of our crude oil, NGL and natural gas producing properties) and certain midstream businesses within our Natural Gas Pipelines business segment depend to a large degree, and certain businesses within our Product Pipelines business segment depend to a lesser degree, on prevailing crude oil, NGL and natural gas prices.

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. InAlthough we did not identify additional triggering events during the third quarter of 2020, in the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. In addition, we are required to perform our annual goodwill impairment test on May 31st. 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 (in millions):balances:
September 30, 2020December 31, 2019
March 31, 2020 December 31, 2019(In millions, unless otherwise stated)
Current portion of debt   Current portion of debt
$4 billion credit facility due November 16, 2023$—
 $—
$4 billion credit facility due November 16, 2023$0 $0 
Commercial paper notes(a)—
 37
Commercial paper notes(a)0 37 
Current portion of senior notes   Current portion of senior notes
6.85%, due February 2020(b)—
 700
6.85%, due February 2020(b)0 700 
6.50%, due April 2020(c)535
 535
6.50%, due April 2020(c)0 535 
5.30%, due September 2020600
 600
6.50%, due September 2020349
 349
5.30%, due September 2020(d)5.30%, due September 2020(d)0 600 
6.50%, due September 2020(d)6.50%, due September 2020(d)0 349 
5.00%, due February 2021750
 —
5.00%, due February 2021750 0 
3.50%, due March 2021750
 —
3.50%, due March 2021750 0 
5.80%, due March 2021400
 —
5.80%, due March 2021400 0 
Trust I preferred securities, 4.75%, due March 2028111
 111
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
Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e)Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e)0 100 
Current portion of other debt45
 45
Current portion of other debt46 45 
Total current portion of debt3,540
 2,477
 Total current portion of debt2,057 2,477 
   
Long-term debt (excluding current portion)   Long-term debt (excluding current portion)
Senior notes29,242
 30,164
Senior notes30,578 30,164 
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035377
 381
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035369 381 
Trust I preferred securities, 4.75%, due March 2028110
 110
Trust I preferred securities, 4.75%, due March 2028110 110 
Other226
 228
Other224 228 
Total long-term debt29,955
 30,883
Total long-term debt31,281 30,883 
Total debt(e)$33,495
 $33,360
Total debt(f)Total debt(f)$33,338 $33,360 
_______
(a)Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.
(b)On January 9, 2020, we sold the approximate 25 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to repay debt that matured in February 2020. The fair value of the Pembina common equity of$925 million as of December 31, 2019 was reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet.
(c)As of March 31, 2020, funds for the repayment of these maturing notes, and associated accrued interest, were held in escrow and included in the accompanying consolidated balance sheet within “Restricted deposits.”
(a)Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.
(b)On January 9, 2020, we sold the approximate 25 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to partially repay debt that matured in February 2020. The fair value of the Pembina common equity of $925 million as of December 31, 2019 was reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet.
(c)In April 2020, we repaid $535 million of maturing senior notes.
(d)In September 2020, we repaid a combined $949 million of maturing senior notes using proceeds from our newly issued senior notes.
(e)In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020.
(f)Excludes our “Debt fair value adjustments” which, as of September 30, 2020 and December 31, 2019, increased our total debt balances by $1,379 million and $1,032 million, respectively.

(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 current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020.
(e)Excludes our “Debt fair value adjustments” which, as of March 31, 2020 and December 31, 2019, increased our total debt balances by $1,450 million and $1,032 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements.

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

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

On February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $994$991 million. These

The senior notes issued in August 2020 and February 2020 are guaranteed through the cross guarantee agreement discussed above.
16



Credit Facility

As of March 31,September 30, 2020, we had 0 borrowings outstanding under our $4.0 billion credit facility, 0 borrowings outstanding under our commercial paper program and $83$81 million in letters of credit. Our availability under our credit facility as of March 31,September 30, 2020 was $3,917$3,919 million. As of March 31,September 30, 2020, we were in compliance with all required covenants.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):below: 
September 30, 2020December 31, 2019
Carrying
value		Estimated
fair value		Carrying
value		Estimated
fair value
(In millions)
Total debt$34,717 $38,253 $34,392 $38,016 
 March 31, 2020 December 31, 2019
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
Total debt$34,945
 $34,198
 $34,392
 $38,016

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31,September 30, 2020 and December 31, 2019.

4. Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the three months endedIn March 31, 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 September 30,Nine Months Ended September 30,
2020201920202019
Per common share cash dividend declared for the period$0.2625 $0.25 $0.7875 $0.75 
Per common share cash dividend paid in the period0.2625 0.25 0.775 0.70 
 Three Months Ended March 31,
 2020 2019
Per common share cash dividend declared for the period$0.2625
 $0.25
Per common share cash dividend paid in the period0.25
 0.20



On April 22,October 21, 2020, our board of directors declared a cash dividend of $0.2625 per common share for the quarterly period ended March 31,September 30, 2020, which is payable on May 15,November 16, 2020 to common shareholders of record as of the close of business on May 4,November 2, 2020.

17


Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):follows:
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7)$0 $(326)$(333)
Other comprehensive (loss) gain before reclassifications(16)1 21 6 
Loss reclassified from accumulated other comprehensive loss72 0 0 72 
Net current-period change in accumulated other comprehensive (loss) income56 1 21 78 
Balance as of September 30, 2020$49 $1 $(305)$(255)
 
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
 
Foreign
currency
translation
adjustments
 
Pension and
other
postretirement
liability adjustments
 
Total
accumulated other
comprehensive loss
Balance as of December 31, 2019$(7) $—
 $(326) $(333)
Other comprehensive gain before reclassifications222
 1
 11
 234
Loss reclassified from accumulated other comprehensive loss37
 —
 —
 37
Net current-period change in accumulated other comprehensive (loss) income259
 1
 11
 271
Balance as of March 31, 2020$252
 $1
 $(315) $(62)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2018$164 $(91)$(403)$(330)
Other comprehensive (loss) gain before reclassifications(132)20 23 (89)
Loss reclassified from accumulated other comprehensive loss35 0 0 35 
Net current-period change in accumulated other comprehensive income (loss)(97)20 23 (54)
Balance as of September 30, 2019$67 $(71)$(380)$(384)

 
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
 
Foreign
currency
translation
adjustments
 
Pension and
other
postretirement
liability adjustments
 
Total
accumulated other
comprehensive loss
Balance as of December 31, 2018$164
 $(91) $(403) $(330)
Other comprehensive (loss) gain before reclassifications(215) 16
 8
 (191)
Loss reclassified from accumulated other comprehensive loss13
 —
 —
 13
Net current-period change in accumulated other comprehensive income (loss)(202) 16
 8
 (178)
Balance as of March 31, 2019$(38) $(75) $(395) $(508)


5.  Risk Management
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 wasmillion. During the three months ended September 30, 2020, we entered into an additional floating-to-fixed interest rate swap agreement with a notional principal amount of $1,000 million. These agreements were not designated as an accounting hedge. These agreementshedges and effectively fixed our LIBOR exposure for a portion of our fixed to floating rate interest rate swaps for 2020. As of March 31, 2020, the maximum length of time over which we have hedged a portion of our exposure to the variability in future interest payments is through December 31, 2020.2021.

18


Energy Commodity Price Risk Management

As of March 31,September 30, 2020, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price(18.9(20.2))MMBbl
Crude oil basis(6.2(2.6))MMBbl
Natural gas fixed price(35.7(34.8))Bcf
Natural gas basis(31.3(34.8))Bcf
NGL fixed price(1.2(1.2))MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(0.7(2.4))MMBbl
Crude oil basis(2.4(0.9))MMBbl
Natural gas fixed price(17.3(9.7))Bcf
Natural gas basis23.42.2 
Bcf
NGL fixed price(1.7(1.4))MMBbl


As of March 31,September 30, 2020, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2023.2024.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of March 31, 2020 (in millions):
September 30, 2020:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)$7,625 Fair value hedgeMarch 2035
Variable-to-fixed interest rate contracts250 Cash flow hedgeJanuary 2023
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts3,500 Mark-to-MarketDecember 2021
Notional amountAccounting treatmentMaximum term
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)$8,025Fair value hedgeMarch 2035
Variable-to-fixed interest rate contracts$250Cash flow hedgeJanuary 2023
Variable-to-fixed interest rate contracts$2,500Mark-to-MarketDecember 2020
_______
(a)The principal amount of hedged senior notes consisted of $1,300 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet.
(a)The principal amount of hedged senior notes consisted of $900 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of March 31, 2020 (in millions):
September 30, 2020:
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
Notional amountAccounting treatmentMaximum term
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$1,358Cash flow hedgeMarch 2027
_______
(a) These sThesewaps swaps eliminate the foreign currency risk associated with all of our Euro-denominated debt.
19



The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):sheets:
Fair Value of Derivative Contracts
Derivatives AssetDerivatives Liability
September 30,
2020		December 31,
2019		September 30,
2020		December 31,
2019
LocationFair valueFair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)$103 $31 $(25)$(43)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)59 17 (4)(8)
Subtotal162 48 (29)(51)
Interest rate contractsFair value of derivative contracts/(Other current liabilities)134 45 (3)0 
Deferred charges and other assets/(Other long-term liabilities and deferred credits)634 313 (8)(1)
Subtotal768 358 (11)(1)
Foreign currency contractsFair value of derivative contracts/(Other current liabilities)0 0 (14)(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)70 46 0 0 
Subtotal70 46 (14)(6)
Total1,000 452 (54)(58)
Derivatives not designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Other current liabilities)19 8 (10)(7)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)6 0 (1)0 
Subtotal25 8 (11)(7)
Interest rate contractsFair value of derivative contracts/(Other current liabilities)0 0 (3)0 
Subtotal0 0 (3)0 
Total25 8 (14)(7)
Total derivatives$1,025 $460 $(68)$(65)
Fair Value of Derivative Contracts
    Derivatives Asset Derivatives Liability
    March 31,
2020		 December 31,
2019		 March 31,
2020		 December 31,
2019
  Location Fair value Fair value
Derivatives designated as hedging instruments          
Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $279
 $31
 $(7) $(43)
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 135
 17
 —
 (8)
Subtotal   414
 48
 (7) (51)
Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 126
 45
 (2) —
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 666
 313
 (9) (1)
Subtotal   792
 358
 (11) (1)
Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) —
 —
 (30) (6)
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 11
 46
 (24) —
Subtotal   11
 46
 (54) (6)
Total   1,217
 452
 (72) (58)
           
Derivatives not designated as hedging instruments    
    
  
Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 43
 8
 (2) (7)
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 4
 —
 —
 —
Subtotal   47
 8
 (2) (7)
Interest rate contracts Fair value of derivative contracts/(Other current liabilities) —
 —
 (4) —
Subtotal   —
 —
 (4) —
Total   47
 8
 (6) (7)
Total derivatives   $1,264
 $460
 $(78) $(65)

20


The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC (in millions).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 September 30, 2020
Energy commodity derivative contracts(a)$3 $184 $0 $187 $(28)$0 $159 
Interest rate contracts0 768 0 768 (2)0 766 
Foreign currency contracts0 70 0 70 (14)0 56 
As of December 31, 2019
Energy commodity derivative contracts(a)$19 $37 $0 $56 $(19)$(21)$16 
Interest rate contracts0 358 0 358 0 0 358 
Foreign currency contracts0 46 0 46 (6)0 40 
 Balance sheet asset fair value measurements by level    
 

Level 1
 

Level 2
 

Level 3
 Gross amount Contracts available for netting Cash collateral held(b) Net amount
As of March 31, 2020             
Energy commodity derivative contracts(a)$6
 $455
 $—
 $461
 $(9) $(25) $427
Interest rate contracts—
 792
 —
 792
 (2) —
 790
Foreign currency contracts—
 11
 —
 11
 (11) —
 —
As of December 31, 2019 
  
  
        
Energy commodity derivative contracts(a)$19
 $37
 $—
 $56
 $(19) $(21) $16
Interest rate contracts—
 358
 —
 358
 —
 —
 358
Foreign currency contracts—
 46
 —
 46
 (6) —
 40

Balance sheet liability
fair value measurements by level
Balance sheet liability
fair value measurements by level
    Level 1Level 2Level 3Gross amountContracts available for nettingCash collateral posted(b)Net amount
Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(b) Net amount(In millions)
As of March 31, 2020             
As of September 30, 2020As of September 30, 2020
Energy commodity derivative contracts(a)$(7) $(2) $—
 $(9) $9
 $—
 $—
Energy commodity derivative contracts(a)$(29)$(11)$0 $(40)$28 $8 $(4)
Interest rate contracts—
 (15) —
 (15) 2
 —
 (13)Interest rate contracts0 (14)0 (14)2 0 (12)
Foreign currency contracts—
 (54) —
 (54) 11
 —
 (43)Foreign currency contracts0 (14)0 (14)14 0 0 
As of December 31, 2019             As of December 31, 2019
Energy commodity derivative contracts(a)$(3) $(55) $—
 $(58) $19
 $—
 $(39)Energy commodity derivative contracts(a)$(3)$(55)$0 $(58)$19 $0 $(39)
Interest rate contracts—
 (1) —
 (1) —
 —
 (1)Interest rate contracts0 (1)0 (1)0 0 (1)
Foreign currency contracts—
 (6) —
 (6) 6
 —
 —
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.
(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 (loss) income (in millions)(loss):
Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income
on derivative and related hedged item		Derivatives in fair value hedging relationshipsLocationGain/(loss) recognized in income
on derivative and related hedged item
 Three Months Ended March 31,Three Months Ended September 30,Nine Months Ended September 30,
 2020 20192020201920202019
    (In millions)
Interest rate contracts Interest, net $433
 $128
Interest rate contractsInterest, net$(50)$117 $409 $453 
    
Hedged fixed rate debt(a) Interest, net $(440) $(138)Hedged fixed rate debt(a)Interest, net$50 $(119)$(418)$(468)
_______
(a)As of March 31, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $799 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

(a)As of September 30, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $777 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

Derivatives in cash flow hedging relationships 
Gain/(loss)
recognized in OCI on derivative(a)
 Location 
Gain/(loss) reclassified from Accumulated OCI
into income(b)
  Three Months Ended March 31,   Three Months Ended March 31,
  2020 2019   2020 2019
Energy commodity derivative contracts $379
 $(245) Revenues—Commodity sales $(8) $13
Interest rate contracts (8) —
 Costs of sales (17) 1
Foreign currency contracts (82) (34) Other, net (23) (31)
Total $289
 $(279) Total $(48) $(17)
_______
(a)We expect to reclassify an approximate $257 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of March 31, 2020 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. 
(b)Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
Derivatives in net investment hedging relationships 
Gain/(loss)
recognized in OCI on derivative
  Three Months Ended March 31,
  2020 2019
Foreign currency contracts $—
 $(8)
Total $—
 $(8)

Derivatives not designated as hedging instruments Location Gain/(loss) recognized in income on derivatives
    Three Months Ended March 31,
    2020 2019
Energy commodity derivative contracts Revenues—Commodity sales $117
 $10
  Costs of sales 4
 (2)
Total(a)   $121
 $8

21


Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Three Months Ended September 30,Three Months Ended September 30,
2020201920202019
(In millions)(In millions)
Energy commodity derivative contracts$(143)$96 Revenues—Commodity sales$(47)$9 
Costs of sales(7)(3)
Interest rate contracts0 (1)Earnings from equity investments(c)(1)0 
Foreign currency contracts70 (69)Other, net61 (59)
Total$(73)$26 Total$6 $(53)

Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)(In millions)
Energy commodity derivative contracts$(29)$(74)Revenues—Commodity sales$(145)$15 
Costs of sales(12)8 
Interest rate contracts(9)(2)Earnings from equity investments(c)(1)2 
Foreign currency contracts17 (95)Other, net64 (71)
Total$(21)$(171)Total$(94)$(46)
_______
(a)The three months ended March 31, 2020 and 2019 amounts include approximate gains of $74 million and $8 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.
(a)We expect to reclassify an approximate $68 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2020 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. 
(b)During the nine months ended September 30, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).

Derivatives in net investment hedging relationshipsGain/(loss)
recognized in OCI on derivative
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Foreign currency contracts$0 $0 $0 $(8)
Total$0 $0 $0 $(8)


22


Derivatives not designated as hedging instrumentsLocationGain/(loss) recognized in income on derivatives
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$87 $12 $353 $36 
Costs of sales12 0 18 (3)
Earnings from equity investments(b)0 0 0 2 
Total(a)$99 $12 $371 $35 
_______
(a)The three and nine months ended September 30, 2020 include approximate gains of $96 million and $349 million, respectively, and the three and nine months ended September 30, 2019 include an approximate loss of $4 million and $2 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.
(b)Amounts represent our share of an equity investee’s income (loss).

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of March 31,September 30, 2020 and December 31, 2019, we had 0 outstanding letters of credit supporting our commodity price risk management program. As of March 31,September 30, 2020, we had cash margins of $32 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. As of December 31, 2019, we had cash margins of $19 million and $15 million respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at March 31,September 30, 2020 represents the net of our initial margin requirements of $6$24 million offset byand counterparty variation margin requirements of $25$8 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of March 31,September 30, 2020, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post additional collateral.

23


6. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source (in millions):source:
Three Months Ended September 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$818 $69 $185 $1 $(2)$1,071 
Fee-based services173 228 91 8 3 503 
Total services991 297 276 9 1 1,574 
Commodity sales
Natural gas sales507 0 0 1 (2)506 
Product sales158 97 5 180 (5)435 
Total commodity sales665 97 5 181 (7)941 
Total revenues from contracts with customers1,656 394 281 190 (6)2,515 
Other revenues(c)
Leasing services119 42 143 13 0 317 
Derivatives adjustments on commodity sales(6)0 0 46 0 40 
Other40 6 0 2 (1)47 
Total Other revenues153 48 143 61 (1)404 
Total revenues$1,809 $442 $424 $251 $(7)$2,919 
24


  Three Months Ended March 31, 2020
  Natural Gas Pipelines Products Pipelines Terminals 
CO2
 Corporate and Eliminations Total
Revenues from contracts with customers(a)            
Services            
Firm services(b) $865
 $79
 $189
 $—
 $—
 $1,133
Fee-based services 193
 260
 121
 13
 —
 587
Total services 1,058
 339
 310
 13
 —
 1,720
Commodity sales            
Natural gas sales 501
 —
 —
 —
 (2) 499
Product sales 136
 109
 3
 232
 (13) 467
Total commodity sales 637
 109
 3
 232
 (15) 966
Total revenues from contracts with customers 1,695
 448
 313
 245
 (15) 2,686
Other revenues(c) 180
 47
 129
 64
 —
 420
Total revenues $1,875
 $495
 $442
 $309
 $(15) $3,106

Three Months Ended September 30, 2019
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$882 $89 $256 $1 $(1)$1,227 
Fee-based services182 265 132 14 0 593 
Total services1,064 354 388 15 (1)1,820 
Commodity sales
Natural gas sales618 0 0 0 (1)617 
Product sales162 84 9 268 (7)516 
Total commodity sales780 84 9 268 (8)1,133 
Total revenues from contracts with customers1,844 438 397 283 (9)2,953 
Other revenues(c)
Leasing services57 45 111 13 0 226 
Derivatives adjustments on commodity sales23 0 0 (1)(1)21 
Other10 1 0 3 0 14 
Total Other revenues90 46 111 15 (1)261 
Total revenues$1,934 $484 $508 $298 $(10)$3,214 

Nine Months Ended September 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$2,479 $215 $563 $1 $(2)$3,256 
Fee-based services523 670 307 31 1 1,532 
Total services3,002 885 870 32 (1)4,788 
Commodity sales
Natural gas sales1,385 0 0 1 (5)1,381 
Product sales396 255 11 546 (22)1,186 
Total commodity sales1,781 255 11 547 (27)2,567 
Total revenues from contracts with customers4,783 1,140 881 579 (28)7,355 
Other revenues(c)
Leasing services346 126 404 34 0 910 
Derivatives adjustments on commodity sales35 0 0 173 0 208 
Other91 16 0 6 (1)112 
Total Other revenues472 142 404 213 (1)1,230 
Total revenues$5,255 $1,282 $1,285 $792 $(29)$8,585 

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Nine Months Ended September 30, 2019
 Three Months Ended March 31, 2019Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
 Natural Gas Pipelines Products Pipelines Terminals 
CO2
 Corporate and Eliminations Total(In millions)
Revenues from contracts with customers(a)            Revenues from contracts with customers(a)
Services            Services
Firm services(b) $930
 $80
 $250
 $—
 $(1) $1,259
Firm services(b)$2,701 $253 $785 $1 $(3)$3,737 
Fee-based services 192
 235
 148
 16
 (1) 590
Fee-based services561 752 398 45 0 1,756 
Total services 1,122
 315
 398
 16
 (2) 1,849
Total services3,262 1,005 1,183 46 (3)5,493 
Commodity sales            Commodity sales
Natural gas sales 754
 —
 —
 1
 (2) 753
Natural gas sales1,979 0 0 1 (7)1,973 
Product sales 240
 66
 2
 268
 (6) 570
Product sales599 211 16 827 (23)1,630 
Total commodity sales 994
 66
 2
 269
 (8) 1,323
Total commodity sales2,578 211 16 828 (30)3,603 
Total revenues from contracts with customers 2,116
 381
 400
 285
 (10) 3,172
Total revenues from contracts with customers5,840 1,216 1,199 874 (33)9,096 
Other revenues(c) 85
 43
 109
 20
 —
 257
Other revenues(c)
Leasing servicesLeasing services167 129 325 39 0 660 
Derivatives adjustments on commodity salesDerivatives adjustments on commodity sales61 0 0 (10)0 51 
OtherOther35 5 0 10 0 50 
Total Other revenuesTotal Other revenues263 134 325 39 0 761 
Total revenues $2,201
 $424
 $509
 $305
 $(10) $3,429
Total revenues$6,103 $1,350 $1,524 $913 $(33)$9,857 
_______
(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c) below)
(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
(c)
Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 and primarily include leases of $294 million and $218 million and derivative contracts of $104 million and $23 million for the three months ended March 31, 2020 and 2019, respectively. See Note 5 for additional information related to our derivative contracts.

(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
(c)For the three and nine months ended September 30, 2020 and 2019, amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.

Contract Balances

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

As of March 31,September 30, 2020 and December 31, 2019, our contract asset balances were $32$44 million and $27 million, respectively. Of the contract asset balance at December 31, 2019, $10$21 million was transferred to accounts receivable during the threenine months ended March 31,September 30, 2020. As of March 31,September 30, 2020 and December 31, 2019, our contract liability balances were $257$237 million and $232 million, respectively. Of the contract liability balance at December 31, 2019, $32$57 million was recognized as revenue during the threenine months ended March 31,September 30, 2020.
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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 March 31,September 30, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):periods:
YearEstimated Revenue
(In millions)
Three months ended December 31, 2020$1,152 
20214,102 
20223,344 
20232,715 
20242,361 
Thereafter14,722 
Total$28,396 
Year Estimated Revenue
Nine months ended December 31, 2020 $3,309
2021 3,845
2022 3,121
2023 2,529
2024 2,206
Thereafter 13,988
Total $28,998


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

7.  Reportable Segments
7.  
Reportable Segments

Financial information by segment follows (in millions):follows:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers$1,803 $1,925 $5,229 $6,073 
Intersegment revenues6 9 26 30 
Products Pipelines442 484 1,282 1,350 
Terminals
Revenues from external customers423 507 1,282 1,521 
Intersegment revenues1 1 3 3 
CO2
251 298 792 913 
Corporate and intersegment eliminations(7)(10)(29)(33)
Total consolidated revenues$2,919 $3,214 $8,585 $9,857 
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 Three Months Ended March 31,
 2020 2019
Revenues   
Natural Gas Pipelines   
Revenues from external customers$1,861
 $2,192
Intersegment revenues14
 9
Products Pipelines495
 424
Terminals   
Revenues from external customers441
 508
Intersegment revenues1
 1
CO2
309
 305
Corporate and intersegment eliminations(15) (10)
Total consolidated revenues$3,106
 $3,429
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
(In millions)
Segment EBDA(a)  
Natural Gas Pipelines$1,091 $1,092 $2,284 $3,383 
Products Pipelines223 325 719 908 
Terminals246 295 732 884 
CO2
156 164 (453)558 
Kinder Morgan Canada0 0 0 (2)
Total Segment EBDA1,716 1,876 3,282 5,731 
DD&A(539)(578)(1,636)(1,750)
Amortization of excess cost of equity investments(32)(21)(99)(61)
General and administrative and corporate charges(150)(162)(472)(478)
Interest, net(383)(447)(1,214)(1,359)
Income tax expense(140)(151)(304)(471)
Total consolidated net income (loss)$472 $517 $(443)$1,612 

 Three Months Ended March 31,
 2020 2019
Segment EBDA(a)   
Natural Gas Pipelines$1,196
 $1,203
Products Pipelines269
 276
Terminals257
 299
CO2
(755)
 198
Kinder Morgan Canada—
 (2)
Total Segment EBDA967
 1,974
DD&A(565) (593)
Amortization of excess cost of equity investments(32) (21)
General and administrative and corporate charges(165) (161)
Interest, net(436) (460)
Income tax expense(60) (172)
Total consolidated net (loss) income$(291) $567
September 30, 2020December 31, 2019
March 31, 2020 December 31, 2019(In millions)
Assets   Assets
Natural Gas Pipelines$49,393
 $50,310
Natural Gas Pipelines$48,522 $50,310 
Products Pipelines9,310
 9,468
Products Pipelines9,216 9,468 
Terminals8,840
 8,890
Terminals8,808 8,890 
CO2
2,926
 3,523
CO2
2,589 3,523 
Corporate assets(b)3,061
 1,966
Corporate assets(b)2,686 1,966 
Total consolidated assets$73,530
 $74,157
Total consolidated assets$71,821 $74,157 
_______
(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, 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.

(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other (income) expense, net.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

8.  Income Taxes

Income tax expense included in our accompanying consolidated statements of operations areis as follows (in millions, except percentages): follows:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except percentages)
Income tax expense$140 $151 $304 $471 
Effective tax rate22.9 %22.6 %(218.7)%22.6 %
 Three Months Ended March 31,
 2020 2019
Income tax expense$60
 $172
Effective tax rate(26.0)% 23.3%


Total tax expense for the three months ended March 31, 2020 is approximately $60 million resulting in an effective tax rate of (26.0)%, as compared with $172 million tax expense and an effective tax rate of 23.3%, for the same period of 2019.

The effective tax rate for the three months ended March 31,September 30, 2020 is higher than the statutory federal rate of 21% primarily due to state income taxes.

The effective tax rate for the nine months ended September 30, 2020 is “negative” in relation toand lower than the statutory federal rate of 21% primarily due to the $600$1,600 million CO2 and Natural Gas Pipelines Non-Regulated reporting unitunits’ impairment of non taxnon-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit. While we would normally expect a federal income tax benefit from our loss before income taxes, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period, partially offset by the refund of alternative minimum tax
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sequestration credits and dividend-received deductions from our investments in Citrus Corporation (Citrus) and Plantation Pipe Line Company (Plantation). While we would normally expect a federal income tax benefit from our loss before income taxes for the three months ended March 31, 2020, because the tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period.

The effective tax rate for the three and nine months ended March 31,September 30, 2019 is higher than the statutory federal rate of 21% primarily due to state and foreign taxes. These increases weretaxes, partially offset by dividend-received deductions from our investments in Citrus, NGPL Holdings LLC and Plantation.


9.   Litigation and Environmental
9.   
Litigation, Environmental and Other Contingencies
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

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

On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI sought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC and there is no deadline or requirement forFERC. 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 take actionnatural 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 this matter.a pipeline-by-pipeline, case-by-case basis. The Policy Statement does not result in any immediate changes to any existing rates or ROEs for any of our pipelines, and any future changes to rates or ROEs for a pipeline will depend on a variety of factors that remain to be determined when they are raised and argued in connection with future or existing rate proceedings, including the OR16-6 proceeding referenced in “SFPP FERC Proceedings” below.

SFPP FERC Proceedings

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

date of protest (IS cases), and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.

SFPP paid refunds to shippers in May 2019, in the IS08-390 proceeding as ordered by the FERC based on its denial of an income tax allowance. With respect to the various SFPP related complaints and protest proceedings at the FERC (including IS08-390), we estimate that the shippers are seeking approximately $50 million in annual rate reductions and approximately $400$425 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, as well as the compliance filing methodology recently approved by the FERC to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.

EPNG FERC Proceedings

The tariffs and rates charged by EPNG are subject to 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) 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 theThe U.S. Court of Appeals for the D.C. Circuit denied all petitions for review on March 13,July 24, 2020.

Gulf LNG Facility Disputes

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

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

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seeks to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. The Delaware cross appeals andwere argued to the Delaware Supreme Court on September 9, 2020. The arbitration proceeding remain pending.remains pending, but has been stayed by agreement pending the Delaware Supreme Court’s decision.
30


On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement.  ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in this arbitration is expected by the end of the second quarter of 2021.

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

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

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties).  CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland

Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies 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 March 31,September 30, 2020 and December 31, 2019, our total reserve for legal matters was $243$280 million and $203 million, respectively. In addition, as of March 31, 2020 and December 31, 2019, we have recorded a receivable of $31 million and $2 million, respectively, for expected cost recoveries that have been deemed probable.

Environmental Matters

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

We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material, individually or in the aggregate, will be material.aggregate. We are also currently involved in several governmental proceedings involving groundwater
31

and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the remediation.

In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas 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 $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of 2 facilities acquired from GATX Terminals Corporation) 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���sKMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required

by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.

Uranium Mines in Vicinity of Cameron, Arizona

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

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

EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
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On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower 8 miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower 8 miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins. On June 30, 2018 and July 13, 2018, respectively, OCC filed 2 separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018.

In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower 8 miles of the Site. We anticipate that process will be completed by December 31, 2020. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in

the upper nine miles of the Site. Until thisthe allocation process and FS isare completed, and the RI/FS is finalized, and allocationswe are determined,unable to reasonably estimate the scopeextent of our potential EPA claims for the Site and liability therefor are not reasonably estimable.liability.

Louisiana Governmental Coastal Zone Erosion Litigation

Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA). The Plaintiffs allege the defendants’ and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands, including marsh (Coastal Zone). The alleged damages include erosion of property within the Coastal Zone, and discharge of pollutants that are alleged to have adversely impacted the Coastal Zone, including plants and wildlife.lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected Coastal Zone to its original condition. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) routinely intervene in these cases, and we expect the LDNR and LAG to intervene in any additional cases that may be filed.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 that those operations caused substantial damage to the Coastal Zone.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 Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. In 2016, the LAG and LDNR intervened in the lawsuit.areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana on several grounds including federal officer liability. Plaquemines Parish, along with the intervenors, moved to remand the case to the state district court. OnLouisiana. In May 28, 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified thea federal officer liability jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals and on June 11, 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 officer liability 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’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the Coastal Zone.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 Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. Onareas. In April 5, 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. OnIn May 28, 2019, Orleans moved to remand the case to the state district court. OnIn January 30, 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 2 cases against TGP, 2 cases against SNG, and 2 cases against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The plaintiffs allege that the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorneys’attorney fees,
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interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The plaintiffs allege that the defendants are obligated to restore and remediate the affected property without regard to the value of the property. The plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. In one caseOne of these cases filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant that was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana,

$80 million was sought in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands.Louisiana. On May 4, 2018, the U.S. District Court entered a judgment dismissing the tort and negligence claims against all of the defendants, and dismissing certain of the contract claims against TGP.  In ruling in favor of the plaintiffs on the remainingcertain of their contract claims, the District Court ordered the defendants to pay $1,104 in money damages, and issued a permanent injunction ordering the defendants to restore a total of 9.6 acres of land and maintain certain canals at widths designated by the right of way agreements in effect.claims. The Court stayed the judgment and the injunction pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. On September 13,In October 2018, the third-party defendant filed a motion to vacate the judgment and dismiss allCourt of Appeals dismissed the appeals for lack of subject matter jurisdiction. On October 2, 2018 the Court of Appeals dismissed the appeals and onIn April 17, 2019, the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. TheOn October 2, 2020, the case was settled for an amount which is set for trial July 27, 2020.not material to our business. 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 March 31,September 30, 2020 and December 31, 2019, we have accrued a total reserve for environmental liabilities in the amount of $256$253 million and $259 million, respectively. In addition, as of March 31,September 30, 2020 and December 31, 2019, we have recorded a receivable of $12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable.

10. Recent Accounting Pronouncements

ASU No. 2018-14

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

ASU No. 2020-04

On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.”  This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate.  Entities can elect not to apply certain modification accounting requirements to contracts affected by this reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2020-06

On August 5, 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year ending December 31, 2021, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

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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 and (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2019 Form 10-K.

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

On December 16, 2019, we closed on two cross-conditional transactions resulting in the sale of the U.S. portion of the Cochin Pipeline and all the outstanding equity of KML, including our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”). We received approximately 25 million shares of Pembina common equity for our interest in KML. On January 9, 2020, we sold our Pembina shares and received proceeds of approximately $907 million ($764 million after tax) which were used to repay maturing debt. The assets sold were part of our Natural Gas Pipelines and Terminals business segments.

COVID-19

The COVID-19 pandemic-related reduction in energy demand and the sharpdramatic decline in commodity prices relatedthat began to the combined impact of falling demand and recent increasesus in production from Organization of Petroleum Exporting Countries (OPEC) members and other international suppliers has caused significant disruptions and volatility in the global marketplace during the first quarter of 2020 which have adverselycontinued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic also affected our business.  In responsebusiness in the second quarter and continues to COVID-19, governments arounddo so. Further, significant uncertainty remains regarding the world have implemented increasingly stringent measures to help reduce the spreadduration and extent of the virus, including stay-at-home and shelter-in-place orders, travel restrictions and other measures.  These measures have adversely affected the economies and financial marketsimpact of the U.S. and many other countries, resulting in an economic downturn that has negatively impacted globalpandemic on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. There is significant uncertainty regarding the length and impact of the virus on the energy industry and potential impacts to our business. For further discussion, see Part II, Item 1A. “Risk Factors.”

Events
The events as described above resulted in decreases of current and expectedestimated long-term crude oil and NGL sale prices and volumes we expect to realize along withand 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 of our CO2 business segment and conduct interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020 and impacted our annual goodwill testing performed as of May 31, 2020. Our evaluationevaluations 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 a goodwill impairmentimpairments of $1,000 million and $600 million.million to our Natural Gas Pipelines Non-Regulated and CO2 reporting units, respectively. For a further discussion of these impairments and our risk for future impairments, see Note 2, “Impairments.”

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

2020 Outlook

In December 2019, weAs previously announced, for 2020 our 2020original budget guidance in which we expected to declare dividendscontemplated DCF of $1.25 per share, a 25% increase from the 2019 declared dividends of $1.00 per share, and to generate approximately $5.1 billion ($2.24 per common share) and Adjusted EBITDA of DCF, or $2.24 of DCF per share, andapproximately $7.6 billion of Adjusted EBITDA. On April 22, 2020, we announced an update to our outlook for 2020 to include estimated impacts of the economic downturn resulting from COVID-19 and unfavorable commodity demand and prices. Because of the current environment, webillion. We now expect DCF to be below budgetplan by approximatelyslightly more than 10% and Adjusted EBITDA to be below budgetplan by approximatelyslightly more than 8%. As a result, we now expect to end 2020 with a Net Debt-to-Adjusted EBITDA ratio of approximately 4.6 times, consistent with our long-term objective of around 4.5 times.

In addition, marketMarket conditions have resulted inalso negatively impacted a number of planned expansion projects such that they are not needed at this time or no longer meetingmeet our internal return thresholds, and wethresholds. We therefore reduced our budget ofexpect the budgeted $2.4 billion expansion projects and contributions to joint ventures for 2020 to be lower by approximately $700$680 million. With this reduction, DCF less expansion capital expenditures is improved by approximately $200$135 million compared to budget, helping to keep our balance sheet strong. In addition, to help preserve flexibility and maintain balance sheet strength, our board of directors has maintained the dividend level and declared a dividend of $0.2625 per share, or $1.05 per share annualized.annualized, for the third quarter of 2020. This represents a 5% increase over lastthe dividend declared for the third quarter of 2019 rather than the previously budgeted dividend of $0.3125,
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which would have been a 25% increase. We expect that our 2020 dividend payments as well as our 2020 discretionary spending will be fully funded with internally generated cash flow.

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 9 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     
3,325 Bbtu/d+/- 5%$23
   $23
Refined Products Volumes (gasoline, diesel and jet fuel)      
1,452 MBbl/d for Products Pipelines
(the following apply to both the Products Pipelines and Terminals segments)(a)		+/- 5% $26
$12
 $38
Qtr 2: 40% - 45% reduction from budgeted quarter amount      
Qtr 3: 10% - 12% reduction from budgeted quarter amount      
Qtr 4: 5% - 6% reduction from budgeted quarter amount      
Crude Oil & Condensate Pipeline Volumes      
587 MBbl/d+/- 5% $11
  $11
Crude Oil Production Volumes      
46 MBbl/d, gross (33 MBbl/d, net)+/- 5%   $12
$12
Crude Oil Price      
$30/bbl+/- $1/bbl WTI$0.2
$0.9
 $0.5
$1.6
NGL to Crude Oil Price Ratio      
Natural Gas Pipelines 49% and CO2 25%
+/- 1%$0.1
  $0.4
$0.5
     Potential Impact to 2020 DCF
(in millions)
3-Month LIBOR Interest Rate(b)    Total
0.64%+/- 10-bp   $2.4 
       
Purpose of Outlook Assumptions and Sensitivity:     
The above table provides key assumptions used in our 2020 forecast for the remaining 9 months of 2020 to incorporate the estimated impact of COVID-19 and oil price decline. 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)Potential impact to 2020 Adjusted EBITDA for Terminals includes sensitivity to changes in petroleum coke volume.
(b)As of March 31, 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 March 31, 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 common stockholdersKinder 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”Measures” below.

Considerable uncertainty exists with respect to the future pace and extent of a global economic recovery from the effects of the COVID-19 pandemic. Our updated expectations for 2020 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statements. Please read Part II, Item 1A. ““Risk Factors”Factors” below and ““Information Regarding Forward-Looking Statements”Statements” at the beginning of this report for more information. Furthermore, we disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.


Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 7, “Reportable Segments”), net income (loss) 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 nine months ended March 31,September 30, 2020 and 2019 present Segment EBDA, net income (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.

Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP net income (loss) income 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,, 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) Income (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 “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

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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’s 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 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 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.

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 15, 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.. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income (Loss) Income (GAAP) to Adjusted EBITDA” below.

Amounts from Joint Ventures

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

Net Debt is 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 (which, as of March 31, 2020, the cash and cash equivalents component of Net Debt includes “Restricted deposits” held in escrow that were used on April 1, 2020 for the repayment of senior notes plus associated accrued interest);equivalents; (ii) the preferred interest in the general partner of KMP (which was redeemed in January 2020); (iii) debt fair value adjustments; and (iv) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents. Our Net Debt-to-Adjusted EBITDA ratio was 4.34.6 as of March 31,September 30, 2020.

38

Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.
Three Months Ended September 30,
20202019Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$1,091 $1,092 $(1)— %
Products Pipelines223 325 (102)(31)%
Terminals246 295 (49)(17)%
CO2
156 164 (8)(5)%
Total Segment EBDA1,716 1,876 (160)(9)%
DD&A(539)(578)39 7 %
Amortization of excess cost of equity investments(32)(21)(11)(52)%
General and administrative and corporate charges(150)(162)12 7 %
Interest, net(383)(447)64 14 %
Income before income taxes612 668 (56)(8)%
Income tax expense(140)(151)11 7 %
Net income472 517 (45)(9)%
Net income attributable to noncontrolling interests(17)(11)(6)(55)%
Net income attributable to Kinder Morgan, Inc.$455 $506 $(51)(10)%
 Three Months Ended March 31,  
 2020 2019 Earnings
increase/(decrease)
 (In millions, except percentages)
Segment EBDA(a)       
Natural Gas Pipelines$1,196
 $1,203
 $(7) (1)%
Products Pipelines269
 276
 (7) (3)%
Terminals257
 299
 (42) (14)%
CO2
(755) 198
 (953) (481)%
Kinder Morgan Canada(b)—
 (2) 2
 100 %
Total Segment EBDA967
 1,974
 (1,007) (51)%
DD&A(565) (593) 28
 5 %
Amortization of excess cost of equity investments(32) (21) (11) (52)%
General and administrative and corporate charges(165) (161) (4) (2)%
Interest, net(436) (460) 24
 5 %
(Loss) income before income taxes(231) 739
 (970) (131)%
Income tax expense(60) (172) 112
 65 %
Net (loss) income(291) 567
 (858) (151)%
Net income attributable to noncontrolling interests(15) (11) (4) (36)%
Net (loss) income attributable to Kinder Morgan, Inc.(306) 556
 (862) (155)%

Nine Months Ended September 30,
20202019Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$2,284 $3,383 $(1,099)(32)%
Products Pipelines719 908 (189)(21)%
Terminals732 884 (152)(17)%
CO2
(453)558 (1,011)(181)%
Kinder Morgan Canada— (2)2 100 %
Total Segment EBDA3,282 5,731 (2,449)(43)%
DD&A(1,636)(1,750)114 7 %
Amortization of excess cost of equity investments(99)(61)(38)(62)%
General and administrative and corporate charges(472)(478)6 1 %
Interest, net(1,214)(1,359)145 11 %
(Loss) income before income taxes(139)2,083 (2,222)(107)%
Income tax expense(304)(471)167 35 %
Net (loss) income(443)1,612 (2,055)(127)%
Net income attributable to noncontrolling interests(45)(32)(13)(41)%
Net (loss) income attributable to Kinder Morgan, Inc.$(488)$1,580 $(2,068)(131)%
_______
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)2019 amount represents a final working capital adjustment on the TMPL sale.
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other (income) expense, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
39

(Loss) income
Income (loss) before income taxes decreased $970$56 million inand $2,222 million for the three and nine months ended September 30, 2020, respectively, as compared to 2019.the respective prior year periods. The decrease was due primarily to a non-cash impairment of goodwill associated with our CO2 reporting unit and non-cash impairments of certain oil and gas producing assetsdecreases in our CO2 business segment, and to a much lesser extent, assets inresults were impacted by lower earnings from our Products Pipelines business segment. The decrease was further impacted by lower earningsand Terminals in the comparative three-month periods and from all of our business segments in the comparative nine-month periods primarily attributable to COVID-19-related reduced energy demand and commodity price impacts and the impact of of the KML and U.S. Cochin Sale in the fourth quarter of 2019 as well as sharp declines in commodity prices impacting the Productson our Natural Gas Pipelines and Terminals business segment,segments, partially offset by the benefit of completed expansion projects in our Natural Gas Pipelines business segment and by lower interest expense and DD&A expense. The year-to-date decrease also included a combined $1.95 billion of non-cash impairments of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash impairments of certain oil and gas producing assets in our CO2 business segment.


Certain Items Affecting Consolidated Earnings Results
Three Months Ended September 30,
20202019
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$1,091 $(9)$1,082 $1,092 $(2)$1,090 $(8)
Products Pipelines223 46 269 325 11 336 (67)
Terminals246 — 246 295 — 295 (49)
CO2
156 (2)154 164 (15)149 5 
Total Segment EBDA(a)1,716 35 1,751 1,876 (6)1,870 (119)
DD&A and amortization of excess cost of equity investments(571)— (571)(599)— (599)28 
General and administrative and corporate charges(a)(150)11 (139)(162)5 (157)18 
Interest, net(a)(383)(8)(391)(447)(5)(452)61 
Income before income taxes612 38 650 668 (6)662 (12)
Income tax expense(b)(140)(8)(148)(151)8 (143)(5)
Net income472 30 502 517 2 519 (17)
Net income attributable to noncontrolling interests(a)(17)— (17)(11)— (11)(6)
Net income attributable to Kinder Morgan, Inc.$455 $30 $485 $506 $2 $508 $(23)
40

Three Months Ended March 31,  Nine Months Ended September 30,
2020 2019  20202019
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts
increase/(decrease) to earnings		GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts
increase/(decrease) to earnings
(In millions)(In millions)
Segment EBDA             Segment EBDA
Natural Gas Pipelines$1,196
 $(17) $1,179
 $1,203
 $(2) $1,201
 $(22)Natural Gas Pipelines$2,284 $993 $3,277 $3,383 $(21)$3,362 $(85)
Products Pipelines269
 4
 273
 276
 17
 293
 (20)Products Pipelines719 50 769 908 28 936 (167)
Terminals257
 —
 257
 299
 —
 299
 (42)Terminals732 — 732 884 — 884 (152)
CO2
(755) 930
 175
 198
 (9) 189
 (14)
CO2
(453)938 485 558 (36)522 (37)
Kinder Morgan Canada—
 —
 —
 (2) 2
 —
 —
Kinder Morgan Canada— — — (2)2 — — 
Total Segment EBDA(a)967
 917
 1,884
 1,974
 8
 1,982
 (98)Total Segment EBDA(a)3,282 1,981 5,263 5,731 (27)5,704 (441)
DD&A and amortization of excess cost of equity investments(597) —
 (597) (614) —
 (614) 17
DD&A and amortization of excess cost of equity investments(1,735)— (1,735)(1,811)— (1,811)76 
General and administrative and corporate charges(a)(165) 25
 (140) (161) 3
 (158) 18
General and administrative and corporate charges(a)(472)36 (436)(478)11 (467)31 
Interest, net(a)(436) 1
 (435) (460) 2
 (458) 23
Interest, net(a)(1,214)(8)(1,222)(1,359)(6)(1,365)143 
(Loss) income before income taxes(231) 943
 712
 739
 13
 752
 (40)(Loss) income before income taxes(139)2,009 1,870 2,083 (22)2,061 (191)
Income tax expense(b)(60) (96) (156) (172) 2
 (170) 14
Income tax expense(b)(304)(114)(418)(471)15 (456)38 
Net (loss) income(291) 847
 556
 567
 15
 582
 (26)Net (loss) income(443)1,895 1,452 1,612 (7)1,605 (153)
Net income attributable to noncontrolling interests(a)(15) —
 (15) (11) —
 (11) (4)Net income attributable to noncontrolling interests(a)(45)— (45)(32)(1)(33)(12)
Net (loss) income attributable to Kinder Morgan, Inc.$(306) $847
 $541
 $556
 $15
 $571
 $(30)Net (loss) income attributable to Kinder Morgan, Inc.$(488)$1,895 $1,407 $1,580 $(8)$1,572 $(165)
_______
(a)
(a)For a more detailed discussion of these Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(b)The combined net effect of the Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

“—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(b)The combined net effect of the Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

Net income (loss) income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) decreased by $30$23 million inand $165 million for the three and nine months ended September 30, 2020, respectively, as compared to 2019.the respective prior year periods. Decreases in Adjusted Segment EBDA was negatively impacted byfrom the prior quarter and year-to-date periods were primarily due to lower earnings from our Products Pipelines, Terminals and Natural Gas Pipelines business segments primarily attributable to COVID-19-related reduced energy demand and commodity price impacts discussed above and the impact of the KML and U.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and sharp declines in commodity prices impacting our Products PipelinesTerminals business segment,segments, partially offset by earnings fromthe benefit of completed expansion projects in our Natural Gas Pipelines business segment. Reduced DD&A, general and administrative and corporate charges, interest and income tax expense partially offset the decrease in Adjusted Segment EBDA. Reduced general and administrative and corporate charges and interest expense were primarily due to the KML and Cochin Sale.

41

Non-GAAP Financial Measures

Reconciliation of Net Income (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)$455 $506 $(488)$1,580 
Total Certain Items30 2 1,895 (8)
Adjusted Earnings(a)485 508 1,407 1,572 
DD&A and amortization of excess cost of equity investments for DCF(b)662 694 2,012 2,093 
Income tax expense for DCF(a)(b)171 164 484 521 
Cash taxes(c)(49)(12)(57)(76)
Sustaining capital expenditures(c)(177)(173)(477)(477)
Other items(d)(7)(41)(22)6 
DCF$1,085 $1,140 $3,347 $3,639 
 Three Months Ended March 31,
 2020 2019
 (In millions)
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)$(306) $556
Total Certain Items847
 15
Adjusted Earnings(a)541
 571
DD&A and amortization of excess cost of equity investments for DCF(b)691
 708
Income tax expense for DCF(a)(b)181
 195
Cash taxes(c)(3) (13)
Sustaining capital expenditures(c)(141) (115)
Other items(d)(8) 25
DCF$1,261
 $1,371


Adjusted Segment EBDA to Adjusted EBITDA to DCF
Three Months Ended March 31,Three Months Ended September 30,Nine Months Ended September 30,
2020 20192020201920202019
(In millions, except per share amounts)(In millions, except per share amounts)
Natural Gas Pipelines$1,179
 $1,201
Natural Gas Pipelines$1,082 $1,090 $3,277 $3,362 
Products Pipelines273
 293
Products Pipelines269 336 769 936 
Terminals257
 299
Terminals246 295 732 884 
CO2
175
 189
CO2
154 149 485 522 
Adjusted Segment EBDA(a)1,884
 1,982
Adjusted Segment EBDA(a)1,751 1,870 5,263 5,704 
General and administrative and corporate charges(a)(140) (158)General and administrative and corporate charges(a)(139)(157)(436)(467)
KMI’s share of joint venture DD&A and income tax expense(a)(e)119
 126
Joint venture DD&A and income tax expense(a)(e)Joint venture DD&A and income tax expense(a)(e)114 123 343 368 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)(15) (3)Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)(17)(2)(45)(7)
Adjusted EBITDA1,848
 1,947
Adjusted EBITDA1,709 1,834 5,125 5,598 
Interest, net(a)(435) (458)Interest, net(a)(391)(452)(1,222)(1,365)
Cash taxes(c)(3) (13)Cash taxes(c)(49)(12)(57)(76)
Sustaining capital expenditures(c)(141) (115)Sustaining capital expenditures(c)(177)(173)(477)(477)
KML noncontrolling interests DCF adjustments(f)—
 (15)KML noncontrolling interests DCF adjustments(f)— (16)— (47)
Other items(d)(8) 25
Other items(d)(7)(41)(22)6 
DCF$1,261
 $1,371
DCF$1,085 $1,140 $3,347 $3,639 
   
Adjusted Earnings per common share$0.24
 $0.25
Adjusted Earnings per common share$0.21 $0.22 $0.62 $0.69 
Weighted average common shares outstanding for dividends(g)2,277
 2,275
Weighted average common shares outstanding for dividends(g)2,276 2,277 2,276 2,276 
DCF per common share$0.55
 $0.60
DCF per common share$0.48 $0.50 $1.47 $1.60 
Declared dividends per common share$0.2625
 $0.25
Declared dividends per common share$0.2625 $0.25 $0.7875 $0.75 
_______
(a)
(a)Amounts are adjusted for Certain Items.
(b)
Includes KMI’s share of DD&A or income tax expense from joint ventures as applicable. 2019 amounts are also net of DD&A or income tax expense attributable to KML noncontrolling interests. See tables included in “—Reconciliation of Net Income (Loss) (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.
(c)
Includes KMI’s share of cash taxes or sustaining capital expenditures from joint ventures, as applicable. See tables included in “—Supplemental Information” below.
(d)Includes non-cash pension expense and non-cash compensation associated with our restricted stock program.
(e)KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.
(f)
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)Includes restricted stock awards that participate in common share dividends.

(b)Includes DD&A or income tax expense, as applicable, from unconsolidated joint ventures, reduced by consolidated joint venture partners’ DD&A. 2019 amounts are also net of DD&A or income tax expense attributable to KML noncontrolling interests. See tables included in “—Supplemental Information” below.
(c)Includes cash taxes or sustaining capital expenditures, as applicable, from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “—Supplemental Information” below.
42

(d)Includes non-cash pension expense and non-cash compensation associated with our restricted stock program.
(e)Represents unconsolidated joint venture DD&A and income tax expense, reduced by consolidated joint venture partners’ DD&A. See tables included in “—Supplemental Information” below.
(f)2019 amounts represent the combined net income, DD&A and income tax expense adjusted for Certain Items, as applicable, attributable to KML noncontrolling interests. See table included in “—Supplemental Information” below.
(g)Includes restricted stock awards that participate in common share dividends.

Reconciliation of Net Income (Loss) Income (GAAP) to Adjusted EBITDA
Three Months Ended September 30,Nine Months Ended September 30,
Three Months Ended March 31,2020201920202019
2020 2019(In millions)
(In millions)
Net (loss) income (GAAP)$(291) $567
Net income (loss) (GAAP)Net income (loss) (GAAP)$472 $517 $(443)$1,612 
Certain Items:   Certain Items:
Fair value amortization(8) (8)Fair value amortization(5)(7)(17)(22)
Legal, environmental and taxes other than income tax reserves(8) 17
Legal, environmental and taxes other than income tax reserves46 11 38 28 
Change in fair value of derivative contracts(a)(36) 10
Change in fair value of derivative contracts(a)(6)(14)(10)(22)
Loss on impairments and divestitures, net(b)371
 2
Loss (gain) on impairments and divestitures, net(b)Loss (gain) on impairments and divestitures, net(b)11 — 382 (5)
Loss on impairment of goodwill(c)600
 —
Loss on impairment of goodwill(c)— — 1,600 — 
COVID-19 costsCOVID-19 costs11 — 11 — 
Income tax Certain Items(96) 2
Income tax Certain Items(8)8 (114)15 
Noncontrolling interests associated with Certain ItemsNoncontrolling interests associated with Certain Items— — — (1)
Other24
 (8)Other(19)4 5 (1)
Total Certain Items847
 15
Total Certain Items(d)Total Certain Items(d)30 2 1,895 (8)
DD&A and amortization of excess cost of equity investments597
 614
DD&A and amortization of excess cost of equity investments571 599 1,735 1,811 
Income tax expense(d)156
 170
KMI’s share of joint venture DD&A and income tax expense(d)(e)119
 126
Interest, net(d)435
 458
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(d))(15) (3)
Income tax expense(e)Income tax expense(e)148 143 418 456 
Joint venture DD&A and income tax expense(e)(f)Joint venture DD&A and income tax expense(e)(f)114 123 343 368 
Interest, net(e)Interest, net(e)391 452 1,222 1,365 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(e))Net income attributable to noncontrolling interests (net of KML noncontrolling interests(e))(17)(2)(45)(6)
Adjusted EBITDA$1,848
 $1,947
Adjusted EBITDA$1,709 $1,834 $5,125 $5,598 
______
(a)
(a)Gains or losses are reflected in our DCF when realized.
(b)
2020 amount primarily includes: (i) pre-tax non-cash losses are reflected in our DCF when realized.
(b)Nine months ended September 30, 2020 amount includes a pre-tax non-cash impairment loss of $350 million and $21 million for asset impairments related to oil and gas producing assets in our CO2 business segment driven by low oil price and assets in our Products Pipelines business segment, respectively, and gas producing assets in our CO2 business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment which are reported within “Loss (gain) on impairments and divestitures, net” on our Consolidated Earnings Results (GAAP) table above.
(c)Nine months ended September 30, 2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, respectively.
(d)Three months ended September 30, 2020 and 2019 amounts include $(4) million and $(2) million, respectively, and nine months ended September 30, 2020 and 2019 amounts include $(4) million and $(15) million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.
(e)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
(f)Represents unconsolidated joint venture DD&A and income tax expense, reduced by consolidated joint venture partners’ DD&A. See table included in “—Supplemental Information” below.


43

(c)
2020 amount represents a non-cash impairment of goodwill associated with our CO2 reporting unit.
(d)
Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
(e)KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.

Supplemental Information
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
DD&A (GAAP)$539 $578 $1,636 $1,750 
Amortization of excess cost of equity investments (GAAP)32 21 99 61 
DD&A and amortization of excess cost of equity investments571 599 1,735 1,811 
Joint venture DD&A91 100 277 297 
DD&A attributable to KML noncontrolling interests— (5)— (15)
DD&A and amortization of excess cost of equity investments for DCF$662 $694 $2,012 $2,093 
Income tax expense (GAAP)$140 $151 $304 $471 
Certain Items8 (8)114 (15)
Income tax expense(a)148 143 418 456 
Unconsolidated joint venture income tax expense(a)23 23 66 71 
Income tax expense attributable to KML noncontrolling interests(a)— (2)— (6)
Income tax expense for DCF(a)$171 $164 $484 $521 
KML activities prior to December 16, 2019
Net income attributable to KML noncontrolling interests$— $9 $— $25 
KML noncontrolling interests associated with Certain Items— — — 1 
KML noncontrolling interests(a)— 9 — 26 
DD&A attributable to KML noncontrolling interests— 5 — 15 
Income tax expense attributable to KML noncontrolling interests(a)— 2 — 6 
KML noncontrolling interests DCF adjustments(a)$— $16 $— $47 
Net income attributable to noncontrolling interests (GAAP)$17 $11 $45 $32 
Less: KML noncontrolling interests(a)— 9 — 26 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))17 2 45 6 
Noncontrolling interests associated with Certain Items— — — 1 
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)$17 $2 $45 $7 
 Three Months Ended March 31,
 2020 2019
 (In millions)
DD&A (GAAP)$565
 $593
Amortization of excess cost of equity investments (GAAP)32
 21
DD&A and amortization of excess cost of equity investments597
 614
Our share of joint venture DD&A94
 99
DD&A attributable to KML noncontrolling interests—
 (5)
DD&A and amortization of excess cost of equity investments for DCF$691
 $708
    
Income tax expense (GAAP)$60
 $172
Certain Items96
 (2)
Income tax expense(a)156
 170
Our share of taxable joint venture income tax expense(a)25
 27
Income tax expense attributable to KML noncontrolling interests(a)—
 (2)
Income tax expense for DCF(a)$181
 $195
    
Net income attributable to KML noncontrolling interests$—
 $8
KML noncontrolling interests associated with Certain Items—
 —
KML noncontrolling interests(a)—
 8
DD&A attributable to KML noncontrolling interests—
 5
Income tax expense attributable to KML noncontrolling interests(a)—
 2
KML noncontrolling interests DCF adjustments(a)$—
 $15
    
Net income attributable to noncontrolling interests (GAAP)$15
 $11
Less: KML noncontrolling interests(a)—
 8
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))15
 3
Noncontrolling interests associated with Certain Items—
 —
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)$15
 $3
    
Additional joint venture information:   
Our share of joint venture DD&A$94
 $99
Our share of joint venture income tax expense(a)25
 27
Our share of joint venture DD&A and income tax expense(a)$119
 $126
    
Our share of taxable joint venture cash taxes$(4) $—
    
Our share of joint venture sustaining capital expenditures$(26) $(19)
44
______
(a)Amounts are adjusted for Certain Items.

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions)
Additional joint venture information
Unconsolidated joint venture DD&A$101 $104 $306 $308 
Consolidated joint venture partners’ DD&A(10)(4)(29)(11)
Joint venture DD&A91 100 277 297 
Unconsolidated joint venture income tax expense(a)23 23 66 71 
Joint venture DD&A and income tax expense(a)$114 $123 $343 $368 
Unconsolidated joint venture cash taxes(b)$(41)$(16)$(51)$(50)
Unconsolidated joint venture sustaining capital expenditures$(32)$(35)$(84)$(85)
Consolidated joint venture partners’ sustaining capital expenditures2 2 4 5 
Joint venture sustaining capital expenditures$(30)$(33)$(80)$(80)
______
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and Plantation Pipe Line equity investments.

Segment Earnings Results

Natural Gas Pipelines
Three Months Ended March 31,Three Months Ended September 30,Nine Months Ended September 30,
2020 20192020201920202019
(In millions, except operating statistics)(In millions, except operating statistics)
Revenues$1,875
 $2,201
Revenues$1,809 $1,934 $5,255 $6,103 
Operating expenses(848) (1,167)Operating expenses(878)(993)(2,455)(3,190)
(Loss) gain on impairments and divestitures, net(Loss) gain on impairments and divestitures, net(11)— (1,011)10 
Other income1
 1
Other income— — 1 2 
Earnings from equity investments164
 159
Earnings from equity investments169 141 484 431 
Other, net4
 9
Other, net2 10 10 27 
Segment EBDA1,196
 1,203
Segment EBDA1,091 1,092 2,284 3,383 
Certain Items(a)(b)(17)
 (2)Certain Items(a)(b)(9)(2)993 (21)
Adjusted Segment EBDA$1,179
 $1,201
Adjusted Segment EBDA$1,082 $1,090 $3,277 $3,362 
   
Change from prior periodIncrease/(Decrease)Change from prior periodIncrease/(Decrease)
Adjusted revenues$(358) (16)%Adjusted revenues$(128)(7)%$(852)(14)%
Adjusted Segment EBDA(22) (2)%Adjusted Segment EBDA(8)(1)%(85)(3)%
   
Volumetric data(c)   Volumetric data(c)
Transport volumes (BBtu/d)39,095
 36,044
Transport volumes (BBtu/d)36,453 37,028 37,091 35,958 
Sales volumes (BBtu/d)2,495
 2,332
Sales volumes (BBtu/d)2,382 2,647 2,330 2,435 
Gathering volumes (BBtu/d)3,361
 3,301
Gathering volumes (BBtu/d)2,925 3,380 3,109 3,335 
NGLs (MBbl/d)30
 32
NGLs (MBbl/d)22 33 27 32 
_______
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $(24) million and $8 million for 2020 and 2019, respectively. These Certain Item amounts are primarily related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales in the 2020 and 2019 periods.
(b)Includes non-revenue Certain Item amounts of $7 million and $(10) million for 2020 and 2019, respectively. 2020 amount is primarily related to increase in expense associated with a certain EPNG litigation matter. 2019 amount is primarily related to an increase in earnings for our share of certain equity investees’ amortization of regulatory liabilities.
(a)Includes revenue Certain Item amounts of $(4) million and $(5) million for the three and nine months ended September 30, 2020, respectively, and $(1) million for both three and nine months ended September 30, 2019 which includes $(14) million of amortization of
45

regulatory liabilities (three and nine months 2020), partially offset by non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales (all periods).
(b)Includes non-revenue Certain Item amounts of $(5) million and $998 million for the three and nine months ended September 30, 2020, respectively, and $(1) million and $(20) million for the three and nine months ended September 30, 2019, respectively. Nine-month 2020 amount primarily resulted from a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit. Nine-month 2019 amounts are primarily related to an increase in earnings from certain equity investees’ amortization of regulatory liabilities.
Other
(c)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.
(c)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.

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

Three Months Ended March 31,September 30, 2020 versus Three Months Ended March 31,September 30, 2019

Adjusted Segment EBDA
increase/(decrease)
 
Adjusted revenues
increase/(decrease)
Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Midstream$(43) (12)% $(449) (33)%Midstream$(68)(21)%$(208)(19)%
West RegionWest Region(5)(2)%1 — %
East Region20
 4 % 45
 8 %East Region65 13 %77 15 %
West Region1
 — % 10
 3 %
Intrasegment eliminations—
 — % 36
 95 %Intrasegment eliminations— — %2 40 %
Total Natural Gas Pipelines$(22) (2)% $(358) (16)%Total Natural Gas Pipelines$(8)(1)%$(128)(7)%

Nine Months Ended September 30, 2020 versus Nine Months Ended September 30, 2019

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Midstream$(183)(18)%$(1,033)(29)%
West Region(19)(2)%4 — %
East Region117 7 %173 11 %
Intrasegment eliminations— — %4 33 %
Total Natural Gas Pipelines$(85)(3)%$(852)(14)%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three-monththree and nine-month periods ended March 31,September 30, 2020 and 2019:
•Midstream’s decreasedecreases of $43$68 million (12%(21%) wasand $183 million (18%), respectively, were primarily due to (i) decreases of $40 million and $112 million, respectively, related to the sale of the Cochin Pipeline on December 16, 2019 to Pembina,Pembina; (ii) lower prices and quarter-to-date volumes on South Texas assets; (iii) lower volumes on KinderHawk Field Services and Oklahoma assets,KinderHawk; (iv) lower contract rates on our North Texas assetsassets; and (v) lower sales margins partially offset by higher transportation revenues driven by new customer contracts on our Texas intrastate natural gas pipeline operations. TheseThese decreases were partially offset by higher volumes on

the Hiland Midstream assets and higher equity earnings due to the Gulf Coast Express Pipeline (Gulf Coast) being placed in service in September 2019. Overall Midstream’s revenues decreased in both the three and nine-month periods primarily due to lower commodity prices and volumes which was largely offset by corresponding decreases in costs of sales;
•West Region’s decreases of $5 million (2%) and $19 million (2%), respectively, were primarily due to decreases in earnings from (i) Ruby Pipeline Company, L.L.C. primarily due to lower transportation revenues and an increase in operating expenses due to the recognition of a credit loss reserve associated with a shipper; (ii) Cheyenne Plains Gas Pipeline Company, L.L.C. as a result of the expiration of one shipper’s contract; and (iii) EPNG driven by higher operating expenses, partially offset by increased earnings from CIG resulting from an expansion project in the Denver Julesburg basin; and
•East Region’s increaseincreases of $20$65 million (4%(13%) wasand $117 million (7%), respectively, were primarily due to increases in earnings from ELC and Southern LNG Company, L.L.C. resulting from five of tenthe liquefaction units (part of the Elba Liquefaction project)project being placed into service in the later part of 2019 and through the first quartereight months of 2020 partially offsetand increased equity
46

earnings from Citrus Corporation (Citrus) as a result of lower operating expenses and interest expense and higher transportation revenues. The year-to-date increase was also impacted by reduced contributions from TGP due to historically mild weather in the Northeast and the impact of the FERC 501-G rate settlement; and
•
West Region’s increase of $1 million (—%) was primarily due to increases in earnings from EPNG and CIG driven by increased revenues due to expansion in the Permian Basin and the Denver Julesburg basin, respectively, partially offset by decreased equity earnings from Ruby Pipeline Company due to lower transportation revenues.

settlement.

Products Pipelines
 Three Months Ended March 31,
 2020 2019
 (In millions, except operating statistics)
Revenues$495
 $424
Operating expenses(221) (166)
Loss on impairments and divestitures, net(21) —
Earnings from equity investments15
 18
Other, net1
 —
Segment EBDA269
 276
Certain Items(a)4
 17
Adjusted Segment EBDA$273
 $293
    
Change from prior periodIncrease/(Decrease)
Adjusted revenues$71
 17 %
Adjusted Segment EBDA(20) (7)%
    
Volumetric data(b)   
Gasoline(c)961
 980
Diesel fuel358
 337
Jet fuel293
 294
Total refined product volumes1,612
 1,611
Crude and condensate702
 643
Total delivery volumes (MBbl/d)2,314
 2,254
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except operating statistics)
Revenues$442 $484 $1,282 $1,350 
Operating expenses(233)(177)(585)(500)
Loss on impairments and divestitures, net— — (21)— 
Earnings from equity investments14 17 42 52 
Other, net— 1 1 6 
Segment EBDA223 325 719 908 
Certain Items(a)46 11 50 28 
Adjusted Segment EBDA$269 $336 $769 $936 
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(42)(9)%$(68)(5)%
Adjusted Segment EBDA(67)(20)%(167)(18)%
Volumetric data(b)
Gasoline(c)941 1,066 888 1,045 
Diesel fuel383 393 371 370 
Jet fuel160 318 184 305 
Total refined product volumes1,484 1,777 1,443 1,720 
Crude and condensate530 639 570 644 
Total delivery volumes (MBbl/d)2,014 2,416 2,013 2,364 
_______
Certain Items affecting Segment EBDA
(a)Includes non-revenue Certain Item amounts of $4 million and $17 million for 2020 and 2019, respectively. 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. 2019 amount is related to an unfavorable adjustment of tax reserves, other than income taxes.
(a)Includes non-revenue Certain Item amounts of $46 million and $50 million for the three and nine months ended September 30, 2020, respectively, and $11 million and $28 million for the three and nine months ended September 30, 2019, respectively. Three and nine-month 2020 amounts both include a $46 million unfavorable rate case reserve adjustment. Nine-month 2020 amount also includes a non-cash loss on impairment of our Belton Terminal of $21 million and a $17 million favorable adjustment for tax reserves, other than income taxes. Three and nine-month 2019 amounts include an unfavorable environmental reserve adjustment. Nine-month 2019 amount also includes a $17 million unfavorable adjustment of tax reserves, other than income taxes.
Other
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

47

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three-monththree and nine-month periods ended March 31,September 30, 2020 and 2019.

Three Months Ended March 31,September 30, 2020 versus Three Months Ended March 31,September 30, 2019


Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues increase/(decrease)
(In millions, except percentages)
West Coast Refined Products$(31)(21)%$(19)(10)%
Crude and Condensate(27)(22)%1 1 %
Southeast Refined Products(9)(13)%(24)(22)%
Total Products Pipelines$(67)(20)%$(42)(9)%

 
Adjusted Segment EBDA
increase/(decrease)
 
Adjusted revenues
increase/(decrease)
 (In millions, except percentages)
Crude and Condensate$(17) (15)% $54
 34%
Southeast Refined Products(13) (20)% 10
 10%
West Coast Refined Products10
 9 % 7
 4%
Total Products Pipelines $(20) (7)% $71
 17%
Nine Months Ended September 30, 2020 versus Nine Months Ended September 30, 2019

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues
increase/(decrease)
(In millions, except percentages)
West Coast Refined Products$(51)(13)%$(45)(8)%
Crude and Condensate(76)(21)%2 — %
Southeast Refined Products(40)(20)%(25)(8)%
Total Products Pipelines $(167)(18)%$(68)(5)%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three-monththree and nine-month periods ended March 31,September 30, 2020 and 2019:
•West Coast Refined Products’ decreases of $31 million (21%) and $51 million (13%), respectively, were due to decreased earnings on Pacific (SFPP) operations, Calnev Pipe Line LLC and West Coast terminals driven by lower services revenues as a result of a reduction in volumes due to COVID-19;
•Crude and Condensate’s decreasedecreases of $17$27 million (15%(22%) wasand $76 million (21%), respectively, were primarily due to decreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s decreased earnings were due to lower contracted rates and lower volumes. The Bakken Crude assets as a result ofdecreased earnings were primarily driven by lower volumes and reduced re-contracted rates. KMCC and Bakken Crude assets year-to-date decreases were also impacted by unfavorable inventory valuation adjustments driven by declines in commodity prices during the first quarter of 2020. KMCC’s2020; and
•Southeast Refined Products’ decreases of $9 million (13%) and $40 million (20%), respectively, were primarily due to decreased earnings werefrom our South East Terminals and Central Florida Pipeline and a decrease in equity earnings from Plantation Pipe Line as a result of decreased transportation revenues driven by lower volumes and prices due to COVID-19. The year-to-date decrease was also impacted by lower contracted rates partially offset by higher volumes. These decreases were partially offset by increased earnings from KMCC - Splitter primarily due to higher volumes driven by the Desalter project which was placed into service in May 2019 and associated processing fees. Overall Crude and Condensate revenues increased primarily due to increased volumes which were largely offset by a corresponding increase in costs of sales;
Southeast Refined Products’ decrease of $13 million (20%) was primarily due to decreased earnings from our Transmix processing operations driven by unfavorable inventory adjustments driven byresulting from commodity price declines during the first quarter 2020. The increase in revenues was primarily due to higher commodity sales revenues driven by a new customer contract which was offset by a corresponding increase in costs of sales; and
West Coast Refined Products’ increase of $10 million (9%) was primarily due to increased earnings on Pacific (SFPP) operations driven by an increase in services revenues as a result of higher tariff rates.

48

Terminals
 Three Months Ended March 31,
 2020 2019
 (In millions, except operating statistics)
Revenues$442
 $509
Operating expenses(192) (216)
Earnings from equity investments5
 5
Other, net2
 1
Segment EBDA257
 299
Certain Items—
 —
Adjusted Segment EBDA$257
 $299
    
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(67) (13)%
Adjusted Segment EBDA(42) (14)%
    
Volumetric data(a)   
Liquids tankage capacity available for service (MMBbl)79.5
 79.3
Liquids utilization %(b)93.7% 94.0 %
Bulk transload tonnage (MMtons)13.0
 13.6
_______
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except operating statistics)
Revenues$424 $508 $1,285 $1,524 
Operating expenses(185)(223)(570)(660)
Gain (loss) on divestitures and impairments, net— 3 (5)3 
Earnings from equity investments7 6 19 15 
Other, net— 1 3 2 
Segment EBDA246 295 732 884 
Certain Items— — — — 
Adjusted Segment EBDA$246 $295 $732 $884 
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(84)(17)%$(239)(16)%
Adjusted Segment EBDA(49)(17)%(152)(17)%
Volumetric data(a)
Liquids leasable capacity (MMBbl)79.4 79.5 79.4 79.5 
Liquids utilization %(b)96.2 %94.4 %96.2 %94.4 %
Bulk transload tonnage (MMtons)11.3 14.1 35.4 42.0 
Other
(a)Volumes for assets sold are excluded for all periods presented.
(b)The ratio of our tankage capacity in service to tankage capacity available for service.

(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-monththree and nine-month periods ended March 31,September 30, 2020 and 2019.

Three Months Ended March 31,September 30, 2020 versus Three Months Ended March 31,September 30, 2019

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

 
Adjusted Segment EBDA
increase/(decrease)
 
Adjusted revenues
increase/(decrease)
 (In millions, except percentages)
Alberta Canada$(33) (100)% $(49) (100)%
West Coast(6) (100)% (16) (100)%
All others (including intrasegment eliminations)(3) (1)% (2) — %
Total Terminals$(42) (14)% $(67) (13)%

Nine Months Ended September 30, 2020 versus Nine Months Ended September 30, 2019

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

The changes in Segment EBDA for our Terminals business segment duringare further explained by the three-monthfollowing discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended March 31,September 30, 2020 and 2019 are explained by2019:
•combined decreases of $36 million and $113 million, respectively, associated with our Alberta Canada terminals and our West Coast terminals due to the sale of KML assets to Pembina on December 16, 2019, which accounted for2019;
•decreases of $5 million (6%) and $21 million (9%), respectively, from our Gulf Liquids terminals primarily driven by lower volumes and associated ancillary fees related to demand reduction attributable to COVID-19. Year-to-date decrease was also impacted by tanks being temporarily off-lease as they are transitioned to new customers following the decrease ontermination of a major customer contract;
•decreases of $4 million (27%) and $4 million (8%), respectively, from our Alberta CanadaGulf Bulk terminals primarily due to lower revenues driven by lower refinery petroleum coke production and onthe expiration of a customer contract in January 2020; and
•decreases of $3 million (23%) and $12 million (24%), respectively, from our West Coast terminals.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.

50

CO2
Three Months Ended March 31,Three Months Ended September 30,Nine Months Ended September 30,
2020 20192020201920202019
(In millions, except operating statistics)(In millions, except operating statistics)
Revenues$309
 $305
Revenues$251 $298 $792 $913 
Operating expenses(122) (117)Operating expenses(99)(143)(312)(383)
Loss on impairments and divestitures, net(950) —
Loss on impairments and divestitures, net— — (950)— 
Earnings from equity investments8
 10
Earnings from equity investments4 9 17 28 
Segment EBDA(755) 198
Segment EBDA156 164 (453)558 
Certain Items(a)(b)930
 (9)Certain Items(a)(b)(2)(15)938 (36)
Adjusted Segment EBDA$175
 $189
Adjusted Segment EBDA$154 $149 $485 $522 
   
Change from prior periodIncrease/(Decrease)Change from prior periodIncrease/(Decrease)
Adjusted revenues$(7) (2)%Adjusted revenues$(34)(12)%$(97)(11)%
Adjusted Segment EBDA(14) (7)%Adjusted Segment EBDA5 3 %(37)(7)%
   
Volumetric data   Volumetric data
SACROC oil production23.2
 24.4
SACROC oil production21.2 23.2 22.1 24.0 
Yates oil production7.0
 7.3
Yates oil production6.4 6.8 6.7 7.1 
Katz and Goldsmith oil production3.4
 4.1
Katz and Goldsmith oil production2.6 3.6 2.8 3.8 
Tall Cotton oil production2.4
 2.6
Tall Cotton oil production1.4 2.1 1.9 2.4 
Total oil production, net (MBbl/d)(c)36.0
 38.4
Total oil production, net (MBbl/d)(c)31.6 35.7 33.5 37.3 
NGL sales volumes, net (MBbl/d)(c)9.8
 10.1
NGL sales volumes, net (MBbl/d)(c)9.1 10.2 9.4 10.2 
CO2 production, net (Bcf/d)
0.5
 0.6
Realized weighted-average oil price per Bbl$54.61
 $48.67
Realized weighted-average NGL price per Bbl$19.74
 $25.98
CO2 sales volumes, net (Bcf/d)
CO2 sales volumes, net (Bcf/d)
0.4 0.6 0.5 0.6 
Realized weighted average oil price per BblRealized weighted average oil price per Bbl$54.83 $49.45 $53.28 $49.36 
Realized weighted average NGL price per BblRealized weighted average NGL price per Bbl$17.65 $21.12 $17.77 $23.54 
_______
Certain Items affecting Segment EBDA
(a)Includes revenue Certain Item amounts of $(20) million and $(9) million for 2020 and 2019, respectively, related to unrealized gains associated with derivative contracts used to hedge forecasted commodity sales.
(b)
(a)Includes revenue Certain Item amounts of $(2) million and $(12) million for the three and nine months ended September 30, 2020, respectively, and $(15) million and $(36) million for the three and nine months ended September 30, 2019, respectively, related to mark-to-market gains associated with derivative contracts used to hedge forecasted commodity sales.
(b)Includes non-revenue Certain Item amount of $950 million for the nine months ended September 30, 2020 resulting from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on most of our oil and gas producing assets.
Other
(c)Net of royalties and outside working interests.

(c)Net of royalties and outside working interests.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three-monththree and nine-month periods ended March 31,September 30, 2020 and 2019.

Three Months Ended March 31,September 30, 2020 versus Three Months Ended March 31,September 30, 2019

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$27 35 %$(10)(5)%
Source and Transportation activities(22)(31)%(28)(29)%
Intrasegment eliminations— — %4 80 %
Total CO2
$5 3 %$(34)(12)%
51

 
Adjusted Segment EBDA
increase/(decrease)
 
Adjusted revenues
increase/(decrease)
 (In millions, except percentages)
Source and Transportation activities$(14) (18)% $(16) (16)%
Oil and Gas Producing activities—
 — % 5
 2 %
Intrasegment eliminations—
 — % 4
 57 %
Total CO2 
$(14) (7)% $(7) (2)%

Nine Months Ended September 30, 2020 versus Nine Months Ended September 30, 2019

Adjusted Segment EBDA
increase/(decrease)		Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$23 8 %$(37)(6)%
Source and Transportation activities(60)(27)%(73)(25)%
Intrasegment eliminations— — %13 72 %
Total CO2 
$(37)(7)%$(97)(11)%

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three-monththree and nine-month periods ended March 31,September 30, 2020 and 2019:
•
decrease of $14 million (18%
•increases of $27 million (35%) from our Source and Transportation activities primarily due to a decrease of $19 million related to lower CO2 sales volumes partially offset by higher CO2 sales driven by higher contract sales prices and lower operating expenses; and $23 million (8%), respectively, from our Oil and Gas Producing activities primarily due to (i) lower operating expenses of $32 million and $50 million, respectively; and (ii) higher realized crude oil prices which increased revenues by $18 million and $42 million, respectively, offset by (i) lower volumes which decreased revenues by $25 million and $61 million, respectively; and (ii) lower NGL prices which decreased revenues by $3 million and $19 million, respectively; and
•decreases of $22 million (31%) and $60 million (27%), respectively, from our Source and Transportation activities primarily due to decreases of $28 million and $77 million, respectively, related to lower CO2 sales volumes partially offset by lower operating expenses of $9 million and $22 million, respectively.

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

Remaining 20202021202220232024
Crude Oil(a)
Price ($/barrel)$56.07 $52.00 $53.05 $50.14 $43.40 
Volume (barrels per day)30,684 20,300 8,600 5,150 950 
NGLs
Price ($/barrel)$28.17 $26.61 
Volume (barrels per day)6,315 2,474 
Midland-to-Cushing Basis Spread
Price ($/barrel)$0.14 $0.40 
Volume (barrels per day)31,100 1,500 
_______
(a)Includes West Texas Intermediate hedges.

52

•
flat (—%) from our Oil and Gas Producing activities due to increased revenues of $5 million driven by higher realized crude oil prices which increased revenues by $13 million and was offset by lower volumes which reduced revenues by $8 million, and higher operating expenses of $5 million.

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

Three Months Ended September 30,Earnings
increase/(decrease)
20202019
(In millions, except percentages)
General and administrative (GAAP)$(153)$(154)$1 1 %
Corporate benefit (charges)3 (8)11 138 %
Certain Items(a)11 5 6 120 %
General and administrative and corporate charges(b)$(139)$(157)$18 11 %
Interest, net (GAAP)$(383)$(447)$64 14 %
Certain Items(c)(8)(5)(3)(60)%
Interest, net(b)$(391)$(452)$61 13 %
Net income attributable to noncontrolling interests (GAAP)$(17)$(11)$(6)(55)%
Certain Items— — — — %
Net income attributable to noncontrolling interests(b)$(17)$(11)$(6)(55)%
 Three Months Ended March 31, 
Earnings
increase/(decrease)
 2020 2019 
 (In millions, except percentages)
General and administrative (GAAP)$(153) $(154) $1
 1 %
Corporate charges(12) (7) (5) (71)%
Certain Items(a)25
 3
 22
 733 %
General and administrative and corporate charges(b)$(140) $(158) $18
 11 %
        
Interest, net (GAAP)$(436) $(460) $24
 5 %
Certain Items(c)1
 2
 (1) (50)%
Interest, net(b)$(435) $(458) $23
 5 %
        
Net income attributable to noncontrolling interests (GAAP)$(15) $(11) $(4) (36)%


Nine Months Ended September 30,Earnings
increase/(decrease)
20202019
(In millions, except percentages)
General and administrative (GAAP)$(461)$(456)$(5)(1)%
Corporate charges(11)(22)11 50 %
Certain Items(a)36 11 25 227 %
General and administrative and corporate charges(b)$(436)$(467)$31 7 %
Interest, net (GAAP)$(1,214)$(1,359)$145 11 %
Certain Items(c)(8)(6)(2)(33)%
Interest, net(b)$(1,222)$(1,365)$143 10 %
Net income attributable to noncontrolling interests (GAAP)$(45)$(32)$(13)(41)%
Certain Items— (1)1 100 %
Net income attributable to noncontrolling interests(b)$(45)$(33)$(12)(36)%
Certain items
(a)2020 amount includes an increase in expense of $23 million associated with the non-cash fair value adjustment and the dividend accrual on the Pembina common stock.
(b)Amounts are adjusted for Certain Items.
(c)2020 and 2019 amounts include (i) decreases in interest expense of $8 million for each period related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $11 million and $10 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.
(a)Three and nine-month 2020 amounts both include an increase in expense of $11 million related to costs incurred associated with COVID-19 mitigation. Nine-month 2020 amount also includes an increase in expense of $23 million associated with the non-cash fair value adjustment and the dividend on the Pembina common stock.
(b)Amounts are adjusted for Certain Items.
(c)Three and nine-month 2020 amounts include (i) decreases in interest expense of $5 million and $17 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) a decrease in expense of $3 million and an increase in expense of $11 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt. Three and nine-month 2019 amounts include (i) decreases in interest expense of $7 million and $22 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $2 million and $15 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.

General and administrative expenses and corporate charges adjusted for Certain Items decreased $18 million inand $31 million for the three and nine months ended September 30, 2020, respectively, when compared to 2019with the respective prior year periods primarily due to lower non-cash pension expenses of $14$11 million and $34 million, respectively, lower expenses of $6 million and $27 million, respectively, due to the sale of KML lower pension costs ofand U.S. Cochin Sale, $7 million and $12 million, a $4 million project write-off in 2019 and lower benefit-related costs in our Terminals segment,respectively, of cost
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savings associated with reduced business activity during the pandemic, partially offset by lower capitalized costs of $15$4 million and $43 million, respectively, reflecting the COVID-19-related cutback on capital projects primarily due toby our CO2 and Natural Gas Pipelines business segments and our Gulf Coast project being placed in service in September 2019. The year-to-date decrease was also impacted by $8 million for a reduction in other benefit-related costs and a 2019 andproject write-off in our Elba Liquefaction project which was partially placed in service in later part of 2019 and during first quarter 2020.Terminals segment.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our consolidated interest expense, net of interest

income adjusted for Certain Items decreased $23 million infor the three and nine months ended September 30, 2020 when compared to 2019with the respective prior year periods decreased $61 million and $143 million, respectively, primarily due to lower weighted average long-term debt balances and lower LIBOR rates partially offset by lower capitalized interest and interest income.interest.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of March 31,September 30, 2020 and December 31, 2019, approximately 17%16% and 27%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2020 when compared to 2019with the respective prior year periods increased $4 million.$6 million and $12 million, respectively.

Income Taxes

Our tax expense for the three months ended March 31,September 30, 2020 was approximately $60$140 million as compared with $172$151 million for the same period of 2019. The $112$11 million decrease in tax expense was due primarily due to lower pre-tax book income in the 2020 period.

Our tax expense for the nine months ended September 30, 2020 was approximately $304 million as compared with $471 million for the same period of 2019. The $167 million decrease in tax expense was due primarily to (i) lower pre-tax book income in the 2020 as a result of the impairment of certain CO2 business segment assets,period; (ii) lower foreign income taxes as a result of the KML and U.S. Cochin Sale in 2019,2019; and (iii) the refund of alternative minimum tax sequestration credits in 2020.


Liquidity and Capital Resources

General

As of March 31,September 30, 2020, we had $360$632 million of “Cash and cash equivalents,” an increase of $175$447 million (95%) from December 31, 2019. As of March 31, 2020, our “Restricted deposits” includes $535 million held in escrow for maturing senior notes that matured on April 1, 2020.2019. Additionally, as of March 31,September 30, 2020, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flow from operations, providing a source of funds of $893$3,282 million and $635$3,121 million in the first threenine months of 2020 and 2019, respectively. The period-to-period increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures. We expect the negative impact of the decline in commodity prices and refined product demand to continue in the near term, which will negatively affectbelieve our operatingcurrent cash flows; however, we continue to expect thaton hand, our short-term liquidity needs will be met through retained cash from operations, short-term borrowings or by issuing new long-termand our borrowing capacity under our revolving credit facility are more than adequate to allow us to manage our cash requirements, including maturing debt, through 2021; however, we may access the debt capital markets from time to time to refinance certain of our maturing long-term debt obligations.debt.

Due toOur board of directors declared a quarterly dividend of $0.2625 per share for the significant uncertainty regardingthird quarter of 2020, unchanged from the length and impact of the virus on the energy industry and potential impacts to our business, and to preserve flexibility and to continue strengthening our cash position, on April 22, 2020, we announcedprevious quarter. This represents a 5% increase in ourover the dividend declared for the firstthird quarter of 2020 over the fourth quarter of 2019, a reduction in our planned 25% growth, and a reduction of approximately $700 million in our estimated capital expansion for 2020 as2019. As previously announced, market conditions have negatively impacted a number of our current year and future planned expansion projects such that they are not needed at this time or no longer meet our internal return thresholds. As a result, we do notour estimated capital expenditures for expansion projects and contributions to joint ventures will be almost 30% below our 2020 budget. We
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continue to expect the need to accessfully fund our dividend payments as well as our discretionary spending for 2020 without funding from the capital marketsmarkets.

On August 5, 2020, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% senior notes due 2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million. We used a portion of the proceeds to fund our growth projects for 2020. At some point we would expect to access the debt capital markets to refinancerepay maturing long-term debt, but given our revolver availability relative to debt maturing in the next eighteen months, we have significant flexibility on that timing.debt.

To refinance construction costs of its recent expansions, on February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $994$991 million. We used the proceeds to repay maturing debt. Additionally, during the first quarter of

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


Short-term Liquidity

As of March 31,September 30, 2020, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $4.0 billion revolving credit facility and associated commercial paper program. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and additionally for us, 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 March 31,September 30, 2020, our $3,540$2,057 million of short-term debt consisted primarily of senior notes that mature in the next twelve months, including $535 million that was repaid on April 1, 2020 with cash held in escrow as of March 31, 2020 and reported within “Restricted deposits” in the accompanying consolidated balance sheet. During 2020,months. Although we used the proceeds from the sale of the Pembina common equity that we received for the sale of KML to reduce debt. Otherwise, as our debt becomes due,during 2020, we generally intend to fund our short-term debt, as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2019 was $2,477 million.

We had working capital (defined as current assets less current liabilities) deficits of $2,512$1,704 million and $1,862 million as of March 31,September 30, 2020 and December 31, 2019, respectively.  Our current liabilities may include short-term borrowings, which we may periodically replace with long-term financing and/or pay down using cash from operations. The overall $650$158 million (35%) unfavorablefavorable change from year-end 2019 was primarily due to (i) an increase in cash and cash equivalents of $447 million; (ii) a decrease of approximately $1,100$284 million in senior notes that mature in the next twelve months; (iii) a favorable asset fair value adjustment of $173 million on derivative contracts in 2020; and (ii)(iv) the $100 million repayment of the preferred interest in Kinder Morgan G.P. Inc.; partially offset by a decrease of $925 million related to the sale of Pembina common equity in January 2020; partially offset by (i) an increase in restricted deposits primarily related to cash held in escrow of $535 million for debt that matured on April 1, 2020 discussed above; (ii) an increase in cash and cash equivalents of $175 million; (iii) a favorable fair value adjustment of $364 million on derivative contracts in 2020; (iv) net repayments of short-term debt of $37 million; and (v) a net decrease in accounts payable, accrued interest and accrued taxes.2020. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

Counterparty Creditworthiness

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

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

Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet

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

Our capital expenditures for the threenine months ended March 31,September 30, 2020, and the amount we expect to spend for the remainder of 2020 to sustain and grow our businesses are as follows:
Three Months Ended March 31, 2020 2020 Remaining Total 2020(a)Nine Months Ended September 30, 20202020 RemainingTotal 2020(a)
(In millions)(In millions)
Sustaining capital expenditures(b)(c)$141
 $524
 $665
Sustaining capital expenditures(b)(c)$477 $181 $658 
Discretionary capital investments(c)(d)(e)542
 1,151
 1,693
Discretionary capital investments(c)(d)(e)1,397 321 1,718 
_______
(a)
(a)Amounts include reductions due to revised outlook, as discussed above in “—General.”
(b)Nine months ended September 30, 2020, 2020 Remaining, and Total 2020 amounts include $80 million, $35 million, and $115 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “Non-GAAP Financial Measures—Supplemental Information.”
(c)Nine months ended September 30, 2020 amount includes $1 million of net changes from accrued capital expenditures, contractor retainage, and other.
(d)Nine months ended September 30, 2020 amount includes $442 million of our contributions to certain unconsolidated joint ventures for capital investments.
(e)Amounts include our actual or estimated contributions to certain equity investees, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

—General.”
(b)
Three months ended March 31, 2020, 2020 Remaining, and Total 2020 amounts include $26 million, $89 million, and $115 million, respectively, for our proportionate share of certain equity investees’ and certain consolidating joint venture subsidiaries’ sustaining capital expenditures.
(c)Three months ended March 31, 2020 amount include $43 million of net changes from accrued capital expenditures, contractor retainage, and other.
(d)Three months ended March 31, 2020 amount includes $174 million of our contributions to certain unconsolidated joint ventures for capital investments.
(e)Amounts include our actual or estimated contributions to certain equity investees, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2019 in our 2019 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2020 and December 31, 2019 were $192 million and $439 million, respectively. The decrease of $247 million was primarily driven by capital commitments related to our Natural Gas Pipelines business segment.

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Cash Flows

Operating Activities

Cash provided by operating activities increased $258$161 million in the threenine months ended March 31,September 30, 2020 compared to the respective 2019 period primarily due to:
•a $211$161 million increase in cash primarily resulting from $134$202 million of net income tax payments in the 2020 period compared to $345$364 million of net income tax payments in the 2019 period, which in both periods were primarily for foreign income taxes mostly associated with the TMPL sale.sale of certain Canadian assets. The income tax paymentpayments for the 2020 period also includedare net of a $20 million refund received related to alternative minimum tax sequestration credits; andcredits.
a $47 million increase in cash from other operating activities in the 2020 period compared to the 2019 period.

Investing Activities

Cash provided byused in investing activities increased $1,149decreased $1,834 million for the threenine months ended March 31,September 30, 2020 compared to the respective 2019 period primarily attributable to:

a $923•an $827 million increase in cash primarily due to $907 million of proceeds received from the sale of the Pembina shares in the 2020 period;

•a $180$783 million decrease in cash used for contributions to equity investments driven by lower contributions to Gulf Coast Express Pipeline LLC, Midcontinent Express Pipeline LLC, Citrus, and Permian HighwayFayetteville Express Pipeline LLC in the 2020 period compared with the 2019 period, partially offset by contributions made to SNG in the 2020 period; and
•a $114$368 million decrease in capital expenditures in the 2020 period over the comparative 2019 period primarily due to lower expenditures on the Elba Liquefaction expansion.expansion and also reflecting our reduction of expansion capital projects in the wake of COVID-19; partially offset by,
•a $102 million decrease in distributions received from equity investments in excess of cumulative earnings primarily from Ruby Pipeline Holding Company L.L.C. and Fayetteville Express Pipeline LLC in the 2020 period over the comparative 2019 period.

Financing Activities

Cash used byin financing activities decreased $2,421$1,587 million for the threenine months ended March 31,September 30, 2020 compared to the respective 2019 period primarily attributable to:

•a $1,742$1,068 million net decrease in cash used related to debt activity as a result of $149 million oflower net debt issuancespayments in the 2020 period compared to $1,593 million of net debt payments in the 2019 period. See Note 3 “Debt” for further information regarding our debt activity;period; and
•an $879 million increase in cash reflecting the distribution of the TMPL sale proceeds to the owners of KML restricted voting shares in the 2019 period; partially offset by,
•a $114$171 million increase in dividend payments to our common shareholders; and
•a $48$127 million increasedecrease in cash used due to an increase in common shares repurchased under our common share buy-back programcontributions received from investment partner and noncontrolling interests primarily driven by lower contributions received from EIG Global Energy Partners in the 2020 period compared to the 2019 period.

Common Stock Dividends

We expect to declare common stock dividends of $1.05 per share on our common stock for 2020. The table below reflects our 2020 common stock dividends declared:
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
December 31, 2019$0.25 January 22, 2020February 3, 2020February 18, 2020
March 31, 20200.2625 April 22, 2020May 4, 2020May 15, 2020
June 30, 20200.2625 July 22, 2020August 3, 2020August 17, 2020
September 30, 20200.2625 October 21, 2020November 2, 2020November 16, 2020
Three months ended Total quarterly dividend per share for the period Date of declaration Date of record Date of dividend
December 31, 2019 $0.25
 January 22, 2020 February 3, 2020 February 18, 2020
March 31, 2020 0.2625
 April 22, 2020 May 4, 2020 May 15, 2020

The actual amount of common stock dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide
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for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2019 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.

Our common stock dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our common stock dividends generally are expected to be paid on or about the 15th day of each February, May, August and November.

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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.  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 March 31,September 30, 2020.”

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

Excluding fair value adjustments, as of March 31,September 30, 2020 and December 31, 2019, the Obligated Group had $32,649$32,502 million and $32,409 million, respectively, of Guaranteed Notes outstanding.  

Summarized combined Balance Sheetbalance sheet and Income Statementincome statement information for the Obligated Group follows (in millions):follows:
Summarized Combined Balance Sheet InformationSeptember 30, 2020December 31, 2019
(In millions)
Current assets$2,418 $1,918 
Current assets - affiliates1,073 1,146 
Noncurrent assets62,131 63,298 
Noncurrent assets - affiliates615 441 
Total Assets$66,237 $66,803 
Current liabilities$3,810 $4,569 
Current liabilities - affiliates1,118 1,139 
Noncurrent liabilities34,320 33,612 
Noncurrent liabilities - affiliates1,057 1,325 
Total Liabilities40,305 40,645 
Redeemable noncontrolling interest747 803 
Kinder Morgan, Inc.’s stockholders’ equity25,185 25,355 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$66,237 $66,803 
Summarized Combined Income Statement InformationThree Months Ended September 30, 2020Nine Months Ended September 30, 2020
(In millions)
Revenues$2,653 $7,840 
Operating income788 1,032 
Net income463 113 

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Summarized Combined Balance Sheet InformationMarch 31, 2020 December 31, 2019
ASSETS   
Current assets$2,762
 $1,918
Current assets - affiliates1,288
 1,146
Noncurrent assets63,206
 63,298
Noncurrent assets - affiliates449
 441
Total Assets$67,705
 $66,803
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY 
  
Current liabilities$5,210
 $4,569
Current liabilities - affiliates1,175
 1,139
Noncurrent liabilities33,105
 33,612
Noncurrent liabilities - affiliates1,429
 1,325
Total Liabilities40,919
 40,645
Redeemable Noncontrolling Interest793
 803
Kinder Morgan, Inc.’s stockholders’ equity25,993
 25,355
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$67,705
 $66,803

Summarized Combined Income Statement InformationThree Months Ended March 31, 2020
Revenues$2,856
Operating income462
Net income147

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

For a discussion of changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2019,, in Item 7A in our 2019 Form 10-K, see Item 2, “Management's Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook” and Item 1, Note 5 “Risk Management” to our consolidated financial statements for more information on our risk management activities, both of which are incorporated in this item by reference.

Item 4.  Controls and Procedures.

As of March 31,September 30, 2020, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.

Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended March 31,September 30, 2020 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation Environmental and Other Contingencies”Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

Other than the following risk factors regarding COVID-19 and the following updated risk factors, thereThere have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2019 Form 10-K.

The COVID-19 pandemic has adversely affected,10-K and could continue to adversely affect, our business.

The ongoing pandemic involving COVID-19, a highly transmissible and pathogenic coronavirus, has negatively impacted the global economy and in turn reduced demand and pricing for crude oil, natural gas, NGL, refined petroleum products, CO2, steel, chemicals and other products that we handle, which has adversely affected our business. In response to COVID-19, governments around the world have implemented increasingly stringent measures to help reduce the spread of the virus, including stay-at-home and shelter-in-place orders, travel restrictions and other measures. These measures have adversely affected the economies and financial markets of the U.S. and many other countries, resulting in an economic downturn that has negatively impacted global demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. Continuing uncertainty regarding the global impact of COVID-19 is likely to result in continued weakness in demand and prices for the products on which our business depends.

If the COVID-19 outbreak should worsen, we may also experience further disruptions to commodities markets, supply chains and the availability and efficiency of our workforce, which could adversely affect our ability to conduct our business and operations and limit our ability to execute on our business plan. In addition, measures taken by regulatory authorities attempting to mitigate the economic consequences of COVID-19 may not be effective or may have unintended harmful consequences. For example, the Texas Railroad Commission recently held a hearing to consider the possibility of requiring Texas producers to cut crude oil production to balance supply and demand for crude oil. Although no action was taken, we cannot predict whether regulatory authorities will decide to implement crude oil production cuts or other measures, or how such measures will affect our business. There are still too many variables and uncertainties regarding COVID-19 — including the ultimate geographic spread of the virus, the duration and severity of the outbreak and the extent of travel restrictions and business closures imposed in affected countries — to reasonably predict the potential impact of COVID-19 on our business and operations. COVID-19 may materially adversely affect our business, results of operations, financial condition and cash flows. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to the global economic recession that is likely to result from the measures taken to combat the virus.

Our businesses are dependent on the supply of and demand for the products that we handle.

Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO2, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. For example, without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may reduce or shut down production during times of lower product prices or higher production costs to the extent they become uneconomic. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput.

Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Additionally, demand for such products can decline due to situations over which we have no control, such as the COVID-19 pandemic and various measures that federal, state and local authorities have implemented in order to prevent further spread of COVID-19, including stay-at-home orders, or to respond to the economic consequences of COVID-19. See “—The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.”

In addition to economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as declining or sustained low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets. Also, sustained lower demand for hydrocarbons, or changes in the regulatory environment or applicable governmental policies, including in relation to climate change or other environmental concerns, may have a negative impact on the supply of crude oil and other products. In recent years, a number of initiatives and regulatory changes relating to reducing greenhouse gas emissions have been undertaken by federal, state and municipal governments and crude oil and gas industry participants. In addition, public sentiment surrounding the potential risks posed by climate change and emerging technologies have resulted in an increased demand for energy efficiency and a transition to energy provided from renewable energy sources, rather than fossil fuels, and fuel-efficient alternatives such as hybrid and electric vehicles. These factors could result in not only increased costs for producers of hydrocarbons but also an overall decrease in the demand for hydrocarbons. Each of the foregoing could negatively impact our business directly as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. Furthermore, such unfavorable conditions may compound the adverse effects of larger disruptions such as COVID-19. See “—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 productsor services we provide or otherwise fulfill their obligations to us” below.

We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle. In addition, irrespective of supply of or demand for products we handle, implementation of new regulations or changes to existing regulations affecting the energy industry could have a material adverse effect on us.

The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.

The revenues, cash flows, profitability and future growth of some of our businesses (and the carrying values of certain of their respective assets, which include related goodwill) depend to a large degree on prevailing crude oil, NGL and natural gas prices. Our CO2 business segment and certain midstream businesses within our Natural Gas Pipelines business segment depend to a large degree, and certain businesses within our Product Pipelines business segment depend to a lesser degree, on prevailing crude oil, NGL and natural gas prices. For the estimated impacts from sensitivities to changes in commodity prices to Adjusted EBITDA and DCF for the remainder of 2020, please refer to Part I, Item 2.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook.”

Prices for crude oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) domestic and global economic conditions; (iii) the activities of the OPEC and other countries that are significant producers of crude oil; (iv) governmental regulation; (v) political instability in crude oil producing countries; (vi) the foreign supply of and demand for crude oil and natural gas; (vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and prices of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. We are also subject, indirectly, to volatility of commodity prices, through many of our customers’ direct exposure to such volatility. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.”

As COVID-19 spread internationally and global economic activity slowed, future economic activity was forecasted to slow with a resulting forecast of a decline in crude oil and gas demand. In an attempt to stabilize the market, OPEC proposed production cuts in early March 2020; however, member producers failed to agree and some producers instead announced planned production increases, after which crude oil prices declined sharply. By mid-March 2020, crude oil prices had declined to less than $25 per barrel, the lowest price since April 1999. Member producers reached agreement on production cuts by

mid-April; however, crude oil prices continued to decline following announcement of the agreement. Producers in the U.S. and globally have not reduced crude oil production at a rate sufficient to match the sharp slowdown in economic activity caused by measures to control the spread of COVID-19, resulting in an oversupply of crude oil that recently caused crude oil prices per barrel to fall below zero. Sharp declines in the prices of crude oil, NGL or natural gas, or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

In recent decades, there have been periods worldwide of both overproduction and underproduction of hydrocarbons, and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The cycles of excess or short supply of crude oil or natural gas have placed pressures on prices and resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk.” For estimated impacts from sensitivities to changes in commodity prices to Adjusted EBITDA and DCF for the remainder of 2020, please refer to Part I, Item 2.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook.”

Our operating results may be adversely affected by unfavorable economic and market conditions.

As described above, COVID-19’s global spread and the measures that governments have implemented to control the spread of the virus have resulted in a downturn of economic activity on a global scale. Such slowdowns are affecting numerous industries, including the crude oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. In addition, uncertain or changing economic conditions within one or more geographic regions may affect our operating results within the affected regions. Sustained unfavorable commodity prices, volatility in commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers, which could impair their ability to meet their obligations to us. See “—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.” In addition, decreases in the prices of crude oil, NGL and natural gas are likely to have a negative impact on our operating results and cash flow. See “—The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.”

If economic and market conditions (including volatility in commodity markets) globally, in the U.S. or in other key markets become more volatile or continue to deteriorate, we may experience material impacts on our business, financial condition and results of operations.

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.

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. The global economic slowdown caused by COVID-19’s spread, combined with the recent extreme drop in crude oil prices, has significantly impacted the financial condition of many companies, particularly exploration and production companies, including some of our customers or counterparties. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and may not be able to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Crude oil, NGL and natural gas prices were all lower on average in 2019 compared to 2018, and natural gas prices have continued to decline so far in 2020. Further deterioration in crude oil prices, or a continuation of the existing low natural gas or NGL price environment, would likely cause severe financial distress to some of our customers with direct commodity price exposure and may result in additional customer bankruptcies. Further, the security that is permitted to be obtained from such customers may be limited by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us.

Furthermore, financially distressed customers might be forced to reduce or curtail their future use of our products and services, which also could have a material adverse effect on our results of operations, financial condition, and cash flows.

We cannot provide any assurance that such customers and key counterparties will not become financially distressed or that such financially distressed customers or counterparties will not default on their obligations to us or file for bankruptcy protection. If one of such customers or counterparties files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion, of amounts owed to us. Similarly, our contracts with such customers may be renegotiated at lower rates or terminated altogether. Significant customer and other counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash flows.

Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.

We engage in hedging arrangements to reduce our direct exposure to fluctuations in the prices of crude oil, natural gas and NGL, including differentials between regional markets. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for crude oil, natural gas and NGL. Furthermore, our hedging arrangements cannot hedge against any decrease in the volumes of products we handle. See “—Our businesses are dependent on the supply of and demand for the products that we handle.”

The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets. As our existing hedges expire, we will seek to replace them with new hedging arrangements. To the extent then-existing underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those consolidated financial statements. In addition, it may not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Part II, Item 7,1A. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging ActivitiesRisk Factors” of our 2019Quarterly Report on Form 10-K and Note 5 “Risk Management” to our consolidated financial statements included in Part I of this Form 10-Q.10-Q for the quarter ended March 31, 2020.

A breach of information security or failure of one or more key information technology or operational (IT) systems, or those of third parties, may adversely affect our business, results of operations or business reputation.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. Some of the operational systems we use are owned or operated by independent third-party vendors. The various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals with industrial control systems, collecting and storing information and data, processing transactions, and handling other processing necessary to manage our business.

While we have implemented and maintain a cybersecurity program designed to protect our IT and data systems from such attacks, we can provide no assurance that our cybersecurity program will be effective. In compliance with state and local stay-at-home orders issued in connection with COVID-19, a number of our employees have transitioned to working from home. As a result, more of our employees are working from locations where our cybersecurity program may be less effective and IT security may be less robust. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, through an act of terrorism or cyber sabotage event has increased as attempted attacks have advanced in sophistication and number around the world.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to

perform critical functions, which could adversely affect our business and results of operations. A significant failure, compromise, breach or interruption in our systems, which may result from problems such as malware, computer viruses, hacking attempts or third-party error or malfeasance, could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and maintain security measures, including malware and anti-virus software and controls, may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. In the future, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

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

None. 

Our Purchases of Our Class P Shares
Period Total number of securities purchased(a) Average price paid per security(b) Total number of securities purchased as part of publicly announced plans(a) Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs
January 1 to January 31, 2020 —
 $—
 —
 $1,474,909,370
February 1 to February 29, 2020 —
 $—
 —
 $1,474,909,370
March 1 to March 31, 2020 3,588,486
 $13.93
 3,588,486
 $1,424,909,386
         
Total 3,588,486
 $13.93
 3,588,486
 $1,424,909,386
_______
(a)On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. After repurchase, the shares are canceled and no longer outstanding.
(b)Amount excludes any commission or other costs to repurchase shares.

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 March 31,September 30, 2020.

Item 5.  Other Information.

None.

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



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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:April 28,KINDER MORGAN, INC.
Registrant
Date:October 23, 2020By:/s/ David P. Michels
David P. Michels

Vice President and Chief Financial Officer

(principal financial and accounting officer)

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