UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549

F O R M  10-Q

þ☑QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIESEXCHANGEACT OF 1934

For the quarterly period ended September 30, 20172022

or

o☐TRANSITIONREPORT 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-20220930_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
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 o☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).  Yes þ No o☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer”filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o☐ Non-accelerated filer o☐ Smaller reporting company o☐ Emerging Growth Company ogrowth company ☐


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


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o☐ No þ

As of October 19, 2017,20, 2022, the registrant had 2,233,239,5742,247,742,071 shares of Class P sharescommon stock outstanding.





KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS

Page
Number
Number2
2
Information Regarding Forward-Looking Statements
3
Consolidated Statements of Income - ThreeThree and Nine Months Ended September 30, 20172022 and 20162021
4
Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 20172022 and 20162021
5
Consolidated Balance Sheets - as of September 30, 20172022 and December 31, 20162021
6
Consolidated Statements of Cash Flows - Nine Months Ended SeptemberSeptember 30, 20172022 and 20162021
7
Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 30, 20172022 and 20162021
89
Notes to Consolidated Financial Statements
910
Note 1.
10
Note 2.
11
Note 3.
13
Note 4.
14
Note 5.
15
Note 6.
16
Note 7.
21
Note 8.
24
Note 9.
25
Note 10.
26
Note 11.
30
General and Basis of Presentation
4332
Results of Operations
4332
Overview
32
Consolidated Earnings Results (GAAP)
35
Non-GAAP Financial Measures
38
Segment Earnings Results
41
DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
49
Income Taxes
51
Liquidity and Capital Resources
5751
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
55
6256
6256
6356
56
Risk Factors
63
Item 2.
6356
6356
6357
57
6358
Exhibits59
64
Signature
65

1
KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY



KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY

Company Abbreviations

EPNG=El Paso Natural Gas Company, L.L.C.Ruby=Ruby Pipeline Holding Company, L.L.C.
KMBT=Kinder Morgan Bulk Terminals, Inc.SFPP=SFPP, L.P.
KMI=Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiariesSNG=Southern Natural Gas Company, L.L.C.
TGP=Tennessee Gas Pipeline Company, L.L.C.
KMLT=Kinder Morgan Liquid Terminals, LLC
CIG=Colorado Interstate Gas Company, L.L.C.KML=Kinder Morgan Canada Limited and its majority-
Copano=Copano Energy, L.L.C.owned and/or controlled subsidiaries
Elba Express=Elba Express Company, L.L.C.KMLT=Kinder Morgan Liquid Terminals, LLC
EPB=El Paso Pipeline Partners, L.P. and its majority-KMP=Kinder Morgan Energy Partners, L.P. and its
owned and/or controlled subsidiariesmajority-owned and/or controlled subsidiaries
EPNG=El Paso Natural Gas Company, L.L.C.KMR=Kinder Morgan Management, LLC
Hiland=Hiland Partners, LPSFPP=SFPP, L.P.
KMBT=Kinder Morgan Bulk Terminals, Inc.SLNG=Southern LNG Company, L.L.C.
KMEP=Kinder Morgan Energy Partners, L.P.SNG=Southern Natural Gas Company, L.L.C.
KMGP=Kinder Morgan G.P., Inc.TGP=Tennessee Gas Pipeline Company, L.L.C.
KMI=Kinder Morgan, Inc. and its majority-owned and/or
controlled subsidiaries
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the company”Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d=per dayEPAFERC=United States Environmental Protection AgencyFederal Energy Regulatory Commission
BBtuBbl=barrelsGAAP=U.S. Generally Accepted Accounting Principles
BBtu=billion British Thermal UnitsFASBLLC=Financial Accounting Standards Boardlimited liability company
Bcf=billion cubic feetFERCLIBOR=Federal Energy Regulatory CommissionLondon Interbank Offered Rate
CERCLA=Comprehensive Environmental Response,GAAP=United States Generally Accepted Accounting
Compensation and Liability ActMBbl=Principlesthousand barrels
C$MMBbl=Canadian dollarsIPO=Initial Public Offeringmillion barrels
CO2
=
carbon dioxide or our CO2 business segment
LLCMMtons=limited liability companymillion tons
DCF=distributable cash flowMBblNGL=thousand barrelsnatural gas liquids
DD&A=depreciation, depletion and amortizationMMBblNYMEX=million barrelsNew York Mercantile Exchange
EBDA=earnings before depreciation, depletion andNGL=natural gas liquids
amortization expenses, including amortization ofOTC=over-the-counter
excess cost of equity investmentsOTC=over-the-counter
PHMSA=Pipeline and Hazardous Materials Safety Administration
EBITDA=earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investmentsROU=Right-of-Use
U.S.=United States of America
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.EPA=U.S. Environmental Protection AgencyWTI=West Texas Intermediate
FASB=Financial Accounting Standards Board





2


Information Regarding Forward-Looking Statements


This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,“outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or to pay dividends, are forward-looking statements. Forward-looking statements are not guaranteesin this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, our anticipated dividends and capital projects, including expected completion timing and benefits of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and futurethose projects.

Important factors that could cause actual results of operations mayto differ materially from those expressed in theseor implied by the forward-looking statements. Manystatements in this report include: the timing and extent of changes in the factors that will determine these results are beyond our ability to control or predict.

See “Informationsupply of and demand for the products we transport and handle; commodity prices; and the other risks and uncertainties described in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” in this report, as well as “Information Regarding Forward-Looking Statements”Statements” and Part I, Item 1A. “Risk Factors”“Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K) for a more detailed description of factors that may affect2021 (except to the forward-looking statements. extent such information is modified or superseded by information in 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 plandisclaim any obligation, other than as required by applicable law, to provide updatespublicly update or revise any of our forward-looking statements to projections included in this report when we believe previously disclosed projections no longer have a reasonable basis.reflect future events or developments.



3

PART I.  FINANCIAL INFORMATION


Item 1.  Financial Statements.



KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions, Except Per Share Amounts)
(Unaudited)
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Revenues       
Natural gas sales$714
 $719
 $2,281
 $1,740
Services1,938
 2,006
 5,855
 6,154
Product sales and other629
 605
 1,937
 1,775
Total Revenues3,281
 3,330
 10,073
 9,669
        
Operating Costs, Expenses and Other     
  
Costs of sales1,029
 971
 3,200
 2,454
Operations and maintenance587
 576
 1,636
 1,744
Depreciation, depletion and amortization562
 549
 1,697
 1,652
General and administrative164
 171
 498
 550
Taxes, other than income taxes102
 106
 297
 324
Loss on impairments and divestitures, net7
 76
 13
 307
Other income, net—
 (1) —
 —
Total Operating Costs, Expenses and Other2,451
 2,448
 7,341
 7,031
        
Operating Income830
 882
 2,732
 2,638
        
Other Income (Expense)     
  
Earnings from equity investments167
 137
 477
 343
Loss on impairments and divestitures of equity investments, net—
 (350) —
 (344)
Amortization of excess cost of equity investments(15) (15) (45) (45)
Interest, net(459) (472) (1,387) (1,384)
Other, net24
 12
 60
 42
Total Other Expense(283) (688) (895) (1,388)
        
Income Before Income Taxes547
 194
 1,837
 1,250
        
Income Tax Expense(160) (377) (622) (744)
        
Net Income (Loss)387
 (183) 1,215
 506
        
Net Income Attributable to Noncontrolling Interests(14) (5) (26) (7)
        
Net Income (Loss) Attributable to Kinder Morgan, Inc.373
 (188) 1,189
 499
        
Preferred Stock Dividends(39) (39) (117) (117)
 

 

    
Net Income (Loss) Available to Common Stockholders$334
 $(227) $1,072
 $382
        
Class P Shares       
Basic Earnings (Loss) Per Common Share$0.15
 $(0.10) $0.48
 $0.17
        
Basic Weighted Average Common Shares Outstanding2,231
 2,230
 2,230
 2,229
        
Diluted Earnings (Loss) Per Common Share$0.15
 $(0.10) $0.48
 $0.17
        
Diluted Weighted Average Common Shares Outstanding2,231
 2,230
 2,230
 2,229
        
Dividends Per Common Share Declared for the Period$0.125
 $0.125
 $0.375
 $0.375
KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts, unaudited)

Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Revenues 
Services$2,028 $1,928 $6,089 $5,734 
Commodity sales3,108 1,868 8,416 6,343 
Other41 28 116 108 
Total Revenues5,177 3,824 14,621 12,185 
Operating Costs, Expenses and Other 
Costs of sales2,717 1,559 7,294 4,504 
Operations and maintenance712 614 1,960 1,710 
Depreciation, depletion and amortization551 526 1,632 1,595 
General and administrative162 174 470 490 
Taxes, other than income taxes113 106 340 324 
(Gain) loss on divestitures and impairments, net(9)4 (30)1,602 
Other income, net— (3)(6)(6)
Total Operating Costs, Expenses and Other4,246 2,980 11,660 10,219 
Operating Income931 844 2,961 1,966 
Other Income (Expense) 
Earnings from equity investments195 169 564 392 
Amortization of excess cost of equity investments(19)(21)(57)(56)
Interest, net(399)(368)(1,087)(1,122)
Other, net (Note 2)21 21 63 264 
Total Other Expense(202)(199)(517)(522)
Income Before Income Taxes729 645 2,444 1,444 
Income Tax Expense(134)(134)(512)(248)
Net Income595 511 1,932 1,196 
Net Income Attributable to Noncontrolling Interests(19)(16)(54)(49)
Net Income Attributable to Kinder Morgan, Inc.$576 $495 $1,878 $1,147 
Class P Common Stock
Basic and Diluted Earnings Per Share$0.25 $0.22 $0.83 $0.50 
Basic and Diluted Weighted Average Shares Outstanding2,253 2,267 2,262 2,265 
The accompanying notes are an integral part of these consolidated financial statements.

4


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Millions)millions, unaudited)
(Unaudited)
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
        
Net income (loss)$387
 $(183) $1,215
 $506
Other comprehensive income (loss), net of tax 
  
    
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(3), $(29), $(105) and $11, respectively)7
 50
 185
 (19)
Reclassification of change in fair value of derivatives to net income (net of tax benefit of $27, $23, $82 and $92, respectively)(48) (39) (144) (158)
Foreign currency translation adjustments (net of tax (expense) benefit of $(28), $11, $(45) and $(38), respectively)78
 (20) 129
 65
Benefit plan adjustments (net of tax expense of $(8), $(3), $(17) and $(9), respectively)7
 6
 20
 16
Total other comprehensive income (loss)44
 (3) 190
 (96)
        
Comprehensive income (loss)431
 (186) 1,405
 410
Comprehensive income attributable to noncontrolling interests(44) (5) (75) (7)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.$387
 $(191) $1,330
 $403

Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Net income$595 $511 $1,932 $1,196 
Other comprehensive income (loss), net of tax  
Net unrealized gain (loss) from derivative instruments (net of taxes of $(40), $41, $109 and $135, respectively)123 (131)(366)(444)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $(29), $(28), $(118), and $(55), respectively)104 92 396 181 
Benefit plan adjustments (net of taxes of $(1), $(2), $(6) and $(7), respectively)2 6 18 28 
Total other comprehensive income (loss)229 (33)48 (235)
Comprehensive income824 478 1,980 961 
Comprehensive income attributable to noncontrolling interests(19)(16)(54)(49)
Comprehensive income attributable to KMI$805 $462 $1,926 $912 
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)
 September 30, 2017 December 31, 2016
 (Unaudited)  
ASSETS   
Current Assets   
Cash and cash equivalents$539
 $684
Restricted deposits81
 103
Accounts receivable, net1,194
 1,370
Fair value of derivative contracts175
 198
Inventories428
 357
Income tax receivable20
 180
Other current assets176
 337
Total current assets2,613
 3,229
    
Property, plant and equipment, net39,867
 38,705
Investments7,484
 7,027
Goodwill22,164
 22,152
Other intangibles, net3,153
 3,318
Deferred income taxes3,432
 4,352
Deferred charges and other assets1,638
 1,522
Total Assets$80,351
 $80,305
    
LIABILITIES AND STOCKHOLDERS’ EQUITY 
  
Current Liabilities 
  
Current portion of debt$3,156
 $2,696
Accounts payable1,358
 1,257
Accrued interest442
 625
Accrued contingencies277
 261
Other current liabilities941
 1,085
Total current liabilities6,174
 5,924
Long-term liabilities and deferred credits 
  
Long-term debt 
  
Outstanding33,969
 36,105
Preferred interest in general partner of KMP100
 100
Debt fair value adjustments1,047
 1,149
Total long-term debt35,116
 37,354
Other long-term liabilities and deferred credits2,537
 2,225
Total long-term liabilities and deferred credits37,653
 39,579
Total Liabilities43,827
 45,503
Commitments and contingencies (Notes 3 and 9)

 

Stockholders’ Equity 
  
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,231,147,804 and 2,230,102,384 shares, respectively, issued and outstanding
22
 22
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding—
 —
Additional paid-in capital42,101
 41,739
Retained deficit(6,429) (6,669)
Accumulated other comprehensive loss(469) (661)
Total Kinder Morgan, Inc.’s stockholders’ equity35,225
 34,431
Noncontrolling interests1,299
 371
Total Stockholders’ Equity36,524
 34,802
Total Liabilities and Stockholders’ Equity$80,351
 $80,305



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

September 30, 2022December 31, 2021
ASSETS
Current Assets
Cash and cash equivalents$483 $1,140 
Restricted deposits240 7 
Accounts receivable1,873 1,611 
Fair value of derivative contracts194 220 
Inventories715 562 
Other current assets314 289 
Total current assets3,819 3,829 
Property, plant and equipment, net35,534 35,653 
Investments7,465 7,578 
Goodwill19,965 19,914 
Other intangibles, net1,875 1,678 
Deferred income taxes— 115 
Deferred charges and other assets1,334 1,649 
Total Assets$69,992 $70,416 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt$2,634 $2,646 
Accounts payable1,579 1,259 
Accrued interest327 504 
Accrued taxes297 270 
Fair value of derivative contracts501 178 
Other current liabilities810 964 
Total current liabilities6,148 5,821 
Long-term liabilities and deferred credits
Long-term debt
Outstanding29,000 29,772 
Debt fair value adjustments107 902 
Total long-term debt29,107 30,674 
Deferred income taxes442 — 
Other long-term liabilities and deferred credits2,160 2,000 
Total long-term liabilities and deferred credits31,709 32,674 
Total Liabilities37,857 38,495 
Commitments and contingencies (Notes 4 and 10)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,249,727,830 and 2,267,391,527 shares, respectively, issued and outstanding
23 23 
Additional paid-in capital41,689 41,806 
Accumulated deficit(10,593)(10,595)
Accumulated other comprehensive loss(363)(411)
Total Kinder Morgan, Inc.’s stockholders’ equity30,756 30,823 
Noncontrolling interests1,379 1,098 
Total Stockholders’ Equity32,135 31,921 
Total Liabilities and Stockholders’ Equity$69,992 $70,416 
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,
20222021
Cash Flows From Operating Activities
Net income$1,932 $1,196 
Adjustments to reconcile net income to net cash provided by operating activities 
Depreciation, depletion and amortization1,632 1,595 
Deferred income taxes499 236 
Amortization of excess cost of equity investments57 56 
Change in fair market value of derivative contracts45 60 
(Gain) loss on divestitures and impairments, net(30)1,602 
Gain on sale of interest in equity investment (Note 2)— (206)
Earnings from equity investments(564)(392)
Distributions from equity investment earnings548 535 
Changes in components of working capital
Accounts receivable(260)(119)
Inventories(165)(89)
Other current assets(60)(90)
Accounts payable347 362 
Accrued interest, net of interest rate swaps(160)(177)
Accrued taxes27 15 
Other current liabilities2 71 
Rate reparations, refunds and other litigation reserve adjustments(189)(97)
Other, net(98)(118)
Net Cash Provided by Operating Activities3,563 4,440 
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 2)(488)(1,518)
Capital expenditures(1,144)(894)
Proceeds from sales of investments (Note 2)4 417 
Contributions to investments(60)(36)
Distributions from equity investments in excess of cumulative earnings126 121 
Other, net17 (1)
Net Cash Used in Investing Activities(1,545)(1,911)
Cash Flows From Financing Activities
Issuances of debt8,898 4,950 
Payments of debt(9,569)(6,459)
Debt issue costs(21)(20)
Dividends(1,876)(1,828)
Repurchases of shares(333)— 
Proceeds from sale of noncontrolling interests (Note 2)557 — 
Contributions from noncontrolling interests1 4 
Distributions to investment partner— (67)
Distributions to noncontrolling interests(85)(14)
Other, net(14)(25)
Net Cash Used in Financing Activities(2,442)(3,459)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits(424)(930)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,147 1,209 
Cash, Cash Equivalents, and Restricted Deposits, end of period$723 $279 
Cash and Cash Equivalents, beginning of period$1,140 $1,184 
Restricted Deposits, beginning of period7 25 
Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,147 1,209 
7

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
(Unaudited)
 Nine Months Ended September 30,
 2017 2016
Cash Flows From Operating Activities   
Net income$1,215
 $506
Adjustments to reconcile net income to net cash provided by operating activities   
Depreciation, depletion and amortization1,697
 1,652
Deferred income taxes624
 767
Amortization of excess cost of equity investments45
 45
Change in fair market value of derivative contracts28
 15
Loss on impairments and divestitures, net13
 307
Loss on impairments and divestitures of equity investments, net—
 344
Earnings from equity investments(477) (343)
Distributions from equity investment earnings370
 321
Changes in components of working capital, net of the effects of acquisitions and dispositions   
Accounts receivable, net174
 26
Income tax receivable144
 —
Inventories(86) 68
Other current assets(2) (20)
Accounts payable(62) (46)
Accrued interest, net of interest rate swaps(158) (158)
Accrued contingencies and other current liabilities(23) 148
Rate reparations, refunds and other litigation reserve adjustments(100) 31
Other, net(95) (160)
Net Cash Provided by Operating Activities3,307
 3,503
    
Cash Flows From Investing Activities   
Acquisitions of assets and investments, net of cash acquired(4) (333)
Capital expenditures(2,231) (2,109)
Proceeds from sale of equity interests in subsidiaries, net—
 1,402
Sales of property, plant and equipment, and other net assets, net of removal costs118
 250
Contributions to investments(631) (389)
Distributions from equity investments in excess of cumulative earnings252
 158
Other, net10
 (26)
Net Cash Used in Investing Activities(2,486) (1,047)
    
Cash Flows From Financing Activities   
Issuances of debt7,790
 8,485
Payments of debt(9,654) (9,135)
Restricted cash held in escrow for debt repayment—
 (776)
Debt issue costs(69) (15)
Cash dividends - common shares(840) (839)
Cash dividends - preferred shares(117) (115)
Contributions from investment partner444
 —
Contributions from noncontrolling interests - net proceeds from KML IPO1,245
 —
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance230
 —
Contributions from noncontrolling interests - other12
 88
Distributions to noncontrolling interests(26) (17)
Other, net(9) (8)
Net Cash Used in Financing Activities(994) (2,332)
    
Effect of Exchange Rate Changes on Cash and Cash Equivalents28
 4
    
Net (decrease) increase in Cash and Cash Equivalents(145) 128
Cash and Cash Equivalents, beginning of period684
 229
Cash and Cash Equivalents, end of period$539
 $357
 
Non-cash Investing and Financing Activities   
Increase in property, plant and equipment from both accruals and contractor retainage$167
  
Assets acquired by the assumption or incurrence of liabilities—
 $43
Net assets contributed to equity investments—
 37
Supplemental Disclosures of Cash Flow Information   
Cash paid during the period for interest (net of capitalized interest)$1,566
 $1,598
Cash (refund) paid during the period for income taxes, net(144) 4

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
20222021
Cash and Cash Equivalents, end of period483 102 
Restricted Deposits, end of period240 177 
Cash, Cash Equivalents, and Restricted Deposits, end of period723 279 
Net Decrease in Cash, Cash Equivalents and Restricted Deposits$(424)$(930)
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments$19 $35 
Increase in property, plant and equipment from both accruals and contractor retainage23 4 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,278 1,313 
Cash paid during the period for income taxes, net12 8 
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)millions, unaudited)
(Unaudited)
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at June 30, 20222,257 $23 $41,654 $(10,540)$(592)$30,545 $1,080 $31,625 
Repurchases of shares(9)(160)(160)(160)
Restricted shares2 5 5 5 
Net income576 576 19 595 
Distributions— (32)(32)
Contributions— 1 1 
Impact of change in ownership interest in subsidiary190 190 311 501 
Dividends(629)(629)(629)
Other comprehensive income229 229 229 
Balance at September 30, 20222,250 $23 $41,689 $(10,593)$(363)$30,756 $1,379 $32,135 
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at June 30, 20212,265$23 $41,793 $(10,496)$(609)$30,711 $429 $31,140 
Restricted shares2(5)(5)(5)
Net income495 495 16 511 
Distributions— (6)(6)
Contributions— 1 1 
Dividends(616)(616)(616)
Other comprehensive loss(33)(33)(33)
Balance at September 30, 20212,267$23 $41,788 $(10,617)$(642)$30,552 $440 $30,992 
 Common stock Preferred stock            
 Issued shares Par value Issued shares Par value 
Additional
paid-in
capital
 
Retained
deficit
 
Accumulated
other
comprehensive
loss
 
Stockholders’
equity
attributable
to KMI
 
Non-controlling
interests
 Total
Balance at December 31, 20162,230
 $22
 2
 $—
 $41,739
 $(6,669) $(661) $34,431
 $371
 $34,802
Restricted shares1
       46
     46
   46
Net income          1,189
   1,189
 26
 1,215
KML IPO        314
   51
 365
 684
 1,049
KML preferred share issuance              —
 230
 230
Distributions              —
 (27) (27)
Contributions              —
 13
 13
Preferred stock dividends          (117)   (117)   (117)
Common stock dividends          (840)   (840)   (840)
Impact of adoption of ASU 2016-09 (See Note 8)          8
   8
   8
Sale and deconsolidation of interest in Deeprock Development, LLC              —
 (30) (30)
Other        2
     2
 (17) (15)
Other comprehensive income            141
 141
 49
 190
Balance at September 30, 20172,231
 $22
 2
 $—
 $42,101
 $(6,429) $(469) $35,225
 $1,299
 $36,524
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at December 31, 20212,267 $23 $41,806 $(10,595)$(411)$30,823 $1,098 $31,921 
Impact of adoption of ASU 2020-06 (Note 5)(11)(11)(11)
Balance at January 1, 20222,267 23 41,795 (10,595)(411)30,812 1,098 31,910 
Repurchases of shares(19)(333)(333)(333)
EP Trust I Preferred security conversions1 1 1 
Restricted shares2 36 36 36 
Net income1,878 1,878 54 1,932 
Distributions— (85)(85)
Contributions— 1 1 
Impact of change in ownership interest in subsidiary190 190 311 501 
Dividends(1,876)(1,876)(1,876)
Other comprehensive income48 48 48 
Balance at September 30, 20222,250 $23 $41,689 $(10,593)$(363)$30,756 $1,379 $32,135 

Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at December 31, 2020Balance at December 31, 20202,264$23 $41,756 $(9,936)$(407)$31,436 $402 $31,838 
Common stock Preferred stock            
Issued shares Par value Issued shares Par value 
Additional
paid-in
capital
 
Retained
deficit
 
Accumulated
other
comprehensive
loss
 
Stockholders’
equity
attributable
to KMI
 
Non-controlling
interests
 Total
Balance at December 31, 20152,229
 $22
 2
 $—
 $41,661
 $(6,103) $(461) $35,119
 $284
 $35,403
Restricted shares1
       47
     47
   47
Restricted shares332 32 32 
Net income          499
   499
 7
 506
Net income1,147 1,147 49 1,196 
Distributions              —
 (17) (17)Distributions— (14)(14)
Contributions              —
 88
 88
Contributions— 4 4 
Preferred stock dividends          (117)   (117)   (117)
Common stock dividends          (839)   (839)   (839)
DividendsDividends(1,828)(1,828)(1,828)
Other        (7)     (7)   (7)Other— (1)(1)
Other comprehensive loss            (96) (96)   (96)Other comprehensive loss(235)(235)(235)
Balance at September 30, 20162,230
 $22
 2
 $—
 $41,701
 $(6,560) $(557) $34,606
 $362
 $34,968
Balance at September 30, 2021Balance at September 30, 20212,267$23 $41,788 $(10,617)$(642)$30,552 $440 $30,992 
The accompanying notes are an integral part of these consolidated financial statements.

9


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


1. General

Organization


We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 84,00083,000 miles of pipelines, 141 terminals, 700 Bcf of working natural gas storage capacity and 155 terminals.2.2 Bcf per year of renewable natural gas generation capacity. Our pipelines transport natural gas, refined petroleum products, renewable fuels, crude oil, condensate, CO2 and other products, and our terminals transload and store petroleum products, ethanol and chemicals, and handle products,various commodities including gasoline, diesel fuel, renewable fuel feedstocks, chemicals, ethanol, metals and petroleum coke and steel. We are also a leading producer of CO2, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin.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 United StatesU.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. UnderIn 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 20162021 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.
Impairments and Losses on Divestitures, net

During the three and nine months ended September 30, 2017, we recorded non-cash pre-tax losses on impairments and divestitures netting to $7 million and $13 million, respectively. The three and nine months ended September 30, 2017 included (i) a $30 million non-cash impairment loss for both periods associated with the Colden storage facility within our Natural Gas Pipelines business segment, of which $3 million is included in “Costs of Sales” on the accompanying consolidated statement of income; (ii) a $23 million gain for both periods primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture within our Terminals business segment; and (iii) losses of $3 million and $9 million, respectively, related to miscellaneous asset disposals. During the three and nine months ended September 30, 2016, we recorded non-cash pre-tax losses on impairments and divestitures netting to $426 million and $683 million, respectively. The three and nine months ended September 30, 2016 included (i) losses of $350 million and $356 million, respectively, related to equity investments within our Natural Gas Pipelines business segment, related primarily to our equity investment in MEP; (ii) an $84 million loss for both periods on the sale of a 50% interest in our SNG natural gas pipeline system; (iii) losses of $1 million and $9 million, respectively, related to the sale of a Transmix facility in our Products Pipelines business segment; and (iv) a $9 million net gain and a $3 million net loss, respectively, on other asset disposals. The nine months ended September 30, 2016 also included (i) $211 million of project write-offs across our Natural Gas Pipelines, CO2,and Products Pipelines business segments, of which $20 million was related to our share of impairments recorded by our equity investees; and (ii) $20 million of impairments related to certain coal facilities in our Terminals business segment.

In addition, during the nine months ended September 30, 2016 we recognized a $12 million gain on the sale of an equity investment, which is included in “Loss on impairments and divestitures of equity investments, net” on the accompanying consolidated statements of income.


These impairments were driven by market conditions that then existed and required management to estimate the fair value of these assets. The impairments resulting from decisions to classify assets as held-for-sale are based on the value expected to be realized in the transaction which is generally known at the time. The estimates of fair value are based on Level 3 valuation estimates using industry standard income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. In certain cases, management’s decisions to dispose of certain assets may trigger impairments. We typically use discounted cash flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible outcomes. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset.

We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain assets, including some equity investments and oil and gas producing properties, have been written down to fair value, any deterioration in fair value relative to our carrying value increases the likelihood of 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 be not fully recoverable.


Goodwill


WeIn addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For this purpose,our May 31, 2022 evaluation, we havegrouped our businesses into seven 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; (vi) Terminals;Terminals and (vii) Kinder Morgan Canada. The evaluation of goodwill for impairment involves a two-step test.Energy Transition Ventures.

Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment.

The results of our May 31, 2017 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value and step 2 was not required. For our Natural Gas Pipelines - Non-Regulated, the reporting unit fair value exceeded the carrying value (including approximately $4 billion of allocated goodwill) by 3%.


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

We expect that the fair value of our Natural Gas Pipelines - Non-Regulated reporting unit will continue to exceed carrying value so long as our estimate of future cash flows and the market valuation remain consistent with current levels. A continued period of volatile commodity prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. Changes to any one or a combination of these factors would result in changesa change to the reporting unit fair values, discussed above which could lead to future impairment charges. Such potential impairmentnon-cash impairments could have a materialsignificant effect on our results of operations.


The results of our May 31, 2022 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock 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 management employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

10




The following table sets forth the allocation of net income available to shareholders of Class P sharescommon stock and participating securities (in millions):securities:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except per share amounts)
Net Income Available to Stockholders$576 $495 $1,878 $1,147 
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)(4)(4)(9)(10)
Net Income Allocated to Class P Stockholders$572 $491 $1,869 $1,137 
Basic Weighted Average Shares Outstanding2,253 2,267 2,262 2,265 
Basic Earnings Per Share$0.25 $0.22 $0.83 $0.50 
 Three Months Ended September 30, Nine Months Ended September 30,

2017 2016 2017 2016
Class P shares$332
 $(228) $1,068
 $379
Participating securities:       
   Restricted stock awards(a)2
 1
 4
 3
Net Income (Loss) Available to Common Stockholders$334
 $(227) $1,072
 $382
(a)As of September 30, 2022, there were 13 million restricted stock awards outstanding.
________
(a)As of September 30, 2017, there were approximately 11 million restricted stock awards.


On May 25, 2017, approximately 293 million of unexercised warrants expired withoutThe following table presents the issuance of Class P common stock. In addition, the following maximum number of potential common stock equivalents which are antidilutive and accordingly are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share (in millions onare the same as our basic earnings per share for all periods presented.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions on a weighted average basis)
Unvested restricted stock awards13 13 13 13 
Convertible trust preferred securities3 3 3 3 

2. Acquisitions and Divestitures

Business Combinations

As of September 30, 2022, our preliminary allocation of the purchase price for significant acquisitions completed during the nine months ended September 30, 2022 are detailed below.
Assignment of Purchase Price
RefDateAcquisitionPurchase priceCurrent assetsProperty, plant & equipmentOther long-term assetsGoodwillCurrent liabilities
(In millions)
(1)8/22North American Natural Resources, Inc.$132 $2 $5 $64 $61 $— 
(2)7/22Mas CanAm, LLC358 9 31 319 — (1)

The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.

(1) North American Natural Resources Acquisition

On August 11, 2022, we completed the acquisition of seven landfill assets from North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR) consisting of gas-to-power facilities in Michigan and Kentucky for $132 million, including a weighted-average basis):preliminary purchase price adjustment for working capital. Other long-term assets within the purchase price allocation consists of intangibles related to gas rights and customer contracts with a weighted average amortization period of approximately 13 years. While our analysis of this transaction is ongoing, we currently believe the goodwill associated with this acquisition is tax deductible.

11


 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Unvested restricted stock awards10
 9
 9
 8
Convertible trust preferred securities3
 8
 3
 8
Mandatory convertible preferred stock(a)58
 58
 58
 58
(2) Mas CanAm Acquisition
_______
(a) Until our mandatory convertible preferred shares are convertedOn July 19, 2022, we completed an acquisition of three landfill assets from Mas CanAm, LLC, comprising a renewable natural gas facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for $358 million including a preliminary purchase price adjustment for working capital. Other long-term assets within the purchase price allocation reflects an intangible related to common shares, on or beforea customer contract with an amortization period of approximately 17 years.

Pro Forma Information

Pro forma consolidated income statement information that gives effect to the expected mandatory conversion dateabove acquisitions as if they had occurred as of October 26, 2018,January 1, 2022 is not presented because it would not be materially different from the holder of each preferred share participatesinformation presented in our earnings by receiving preferred stock dividends.

2.  Divestitures
Sale of Approximate 30% Interest in Canadian Business

On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million (USD $1,299 million). The net proceeds from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business with KMI retaining the remaining 70% interest. We used the proceeds from KML to pay down debt.
Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in ouraccompanying consolidated statements of stockholders’ equityincome.

Goodwill

After measuring all of the identifiable tangible and consolidated balance sheets. Earnings attributableintangible assets acquired and liabilities assumed at fair value on the acquisition date, the excess purchase price is assigned to goodwill. Goodwill is an intangible asset representing the public ownershipfuture economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of KML are presented in “Netthe synergies created between the acquired assets and our pre-existing assets, and/or our expected ability to grow the business we acquired by leveraging our pre-existing business experience. We apply a look through method of recording deferred income attributable to noncontrolling interests”taxes on the outside book-tax basis differences in our consolidated statementsinvestments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.

Changes in the amounts of income for the periods presented after May 30, 2017.
The net proceeds received of $1,245 million are presented as “Contributions from noncontrolling interests - net proceeds from KML IPO” on our consolidated statement of cash flowsgoodwill for the nine months ended September 30, 2017. Because2022 are summarized by reporting unit as follows:
Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-Regulated
CO2
Products PipelinesProducts Pipelines TerminalsTerminals
CO2 – Energy Transition Ventures
Total
(In millions)
Goodwill as of December 31, 2021$14,249 $2,343 $928 $1,378 $151 $802 $63 $19,914 
Acquisitions(a)— — — — — — 51 51 
Goodwill as of September 30, 2022$14,249 $2,343 $928 $1,378 $151 $802 $114 $19,965 
(a)Includes goodwill arising from our acquisition of NANR and a $10 million purchase price adjustment related to our 2021 acquisition of Kinetrex that was attributed to long-term deferred tax liabilities.

Divestitures

Sale of Interest in Elba Liquefaction Company L.L.C.

On September 26, 2022, we retained controlcompleted the sale of KML subsequenta 25.5% ownership interest in Elba Liquefaction Company L.L.C. (ELC). We received net proceeds of $557 million which were used to the IPO, the $314reduce short-term borrowings. As we continue to have a controlling financial interest in ELC, we recorded an increase of $190 million adjustment made to “Additional paid-inpaid in capital” for the impact of the change in our ownership interest in ELC, which is reflected on our accompanying consolidated statementstatements of stockholdersstockholders’ equity for the three and nine months ended September 30, 2017 represents the difference between our book value prior2022. We continue to the saleown a 25.5% interest in and our share of book value in KML’s net assets after the sale. The impact of the IPO resulted in a $166 million deferred income tax adjustment. At the date of the IPO, $765 million was attributedoperate ELC.

We continue to the KML public shareholders to reflect their proportionate ownership percentage in the net assets of KML acquired from us and is included in “Noncontrolling interests” on our consolidated statement of stockholders equity. The above amounts recorded to “Additional paid-in capital” and “Noncontrolling interests” are net of IPO fees.
The above amount recorded to “Noncontrolling interests” at the date of the IPO was reduced by $81 million primarily associated with the allocation of currency translation adjustments from “Accumulated other comprehensive loss” to “Noncontrolling interests.”
The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Product Pipelines business segments and include (i) the Trans

Mountain pipeline system; (ii) the Canadian Cochin pipeline system; (iii) the Puget Sound pipeline system; (iv) the Jet Fuel pipeline system; and (v) terminal facilities located in Western Canada.

In conjunction with the IPO, Kinder Morgan Canada Limited Partnership (KMC LP) and Kinder Morgan Canada GP Inc. (KMC GP) were formed to hold our Canadian business.consolidate ELC. We have determined that KMC LPELC is a variable interest entity because a simple majority or lower threshold of the limited partnership interests do not possess substantive “kick-out rights” (i.e.and Southern Liquefaction Company, LLC (SLC), the right to remove the general partner or to dissolve (liquidate) the entity without cause) or substantive participation rights. We have also determined KMC GPwhich is indirectly controlled by us, is the primary beneficiary because it has the powerability to direct the activities that most significantly impact KMC LP’sELC’s economic performance and the right to receive benefits and the obligation to absorb losses, that could be significantlosses. In addition to KMC LP. Asbeing the operator of ELC, the evaluation of ELC as a result, KMC GP consolidates KMC LP. KMC GP is a wholly-owned subsidiary of KML, which is indirectly controlled by us through our 100% interest in KML’s special voting shares that represent approximately 70% of KML’s total voting shares (comprised of restricted voting shares and special voting shares). Consequently, we consolidate KML and the variable interest entity KMC LP, in our consolidated financial statements.and SLC as the primary beneficiary included consideration of the following: (i) a liquefaction service agreement between ELC and its customer was designed for recovery by ELC of actual costs for operating and maintaining ELC’s facilities, which reduces the risk for all equity owners to absorb losses resulting from cost variability; and (ii) substantially all ELC’s activities involve KMI subsidiaries under common control that provide services for and benefit from the operations of ELC.

12



The following table shows the carrying amount and classification of KMC LP’sELC’s assets and liabilities in our consolidated balance sheet (in millions):sheet:
September 30, 2022
(In millions)
Assets
Current assets$43 
Property, plant and equipment, net1,207 
Deferred charges and other assets6 
Liabilities
Current liabilities$28 
Other long-term liabilities and deferred credits5 
  September 30, 2017
Assets  
Total current assets $340
Property, plant and equipment, net 2,837
Total goodwill, deferred charges and other assets 314
         Total assets $3,491
Liabilities  
Current portion of debt $132
Total other current liabilities 242
Long-term debt, excluding current maturities —
Total other long-term liabilities and deferred credits 397
         Total liabilities $771


We receive distributions from KMC LPELC, indirectly, through our indirectly owned limited partnership interestsinterest in KMC LP,SLC, but otherwise, the assets of KMC LPELC cannot be used to settle our obligations. Our subsidiaries that are the direct owners ofELC’s creditors have no recourse against our limited partnership interests in KMC LP have guaranteed the obligations of KMC LP’s wholly owned subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, under the Credit Facility (see Note 3), but recourse in respect of such guarantee is limited solely to the limited partnership interests of KMC LP held by such subsidiaries and any proceeds thereof.  Additionally, in connection with the Credit Facility, we entered into an Equity Nomination and Support Agreement whereby, among other things, we commit to contribute or cause to be contributed at the time of each drawdown on the constructiongeneral credit facility or the contingent credit facility either equity or subordinated debt to Kinder Morgan Cochin ULC in an amount sufficient to cause the outstanding indebtedness under the credit facilities and any other funded debt for the Trans Mountain expansion project not to exceed 60% of the total project costs for the project as projected over the six month period following the date of such drawdown.  Other than such guarantees and the Equity Nomination and Support Agreement, we do not guarantee the debt, commercial paper or other similar commitments of KMC LP or any of its subsidiaries, and the obligations of KMC LPELC may only be settled using the assets of KMC LP. KMC LPELC. ELC does not guarantee theour debt or other similar commitments of KMI.commitments.


Sale of an Interest in Elba Liquefaction Company L.L.C. (ELC)NGPL Holdings

Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG Global Energy Partners (EIG). We continue to own a 51% controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and which are wholly owned by us. In certain limited circumstances which are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account.

As a result of these contingencies, the sale proceeds of $386 million, and subsequent EIG contributions, have been recorded as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of September 30, 2017. EIG is not entitled to any specified return on its capital. Once these contingencies expire, EIG’s capital account will be reflected as noncontrolling interest on our consolidated balance sheet.
Sale of Equity Interest in SNG


On September 1, 2016,March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a 50%combined 25% interest in our SNG natural gas pipeline systemjoint venture, NGPL Holdings LLC (NGPL Holdings), to The Southern Company (Southern Company), receivinga fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $1.4 billion, and$412 million for our proportionate share of the formation of a joint venture, which includes our remaining 50% interest in SNG. We used the proceeds from the sale to reduce outstanding debt.interests sold. We recognized a pre-tax lossgain of $84$206 million on the sale offor our interest in SNGproportionate share, which is included within “Loss on impairments and divestitures,“Other, net” on theour accompanying consolidated statementsstatement of income for the three and nine months ended September 30, 2016. 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

3. Losses on Impairments and Other Write-downs

Long-lived Asset Impairment

During the second quarter of 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. We utilized an income approach to estimate fair value and compared it to the carrying value. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates, a Level 3 input. As a result of this transaction,our evaluation, we no longer holdrecognized a controlling interestnon-cash, long-lived asset impairment of $1,600 million during the nine months ended September 30, 2021.

Investment in SNG or Bear Creek Storage Company, LLC (Bear Creek) (50%Ruby

During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, which is owned by SNG) and, as such, we now account for our remainingincluded within “Earnings from equity interests in SNG and Bear Creek as equity investments.

3. Debt

We classify our debt basedinvestments” on the contractual maturity dates of the underlying debt instruments.  We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statementsstatement of income.income for the nine months ended September 30, 2021. The write-down was driven by the impairment recognized by Ruby of its assets.


Ruby Chapter 11 Bankruptcy Filing

The balance of Ruby Pipeline, L.L.C.’s 2022 unsecured notes matured on April 1, 2022 in the principal amount of $475 million. Although Ruby has sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its obligations under the 2022 unsecured notes on the maturity date of April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Ruby, as the debtor, will continue to operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. We had no amounts included in our “Investments” on our accompanying consolidated balance sheets associated with Ruby as of September 30, 2022 or December 31, 2021.
13



4. Debt

The following table provides detailinformation on the principal amount of our outstanding debt balances.balances:
September 30, 2022December 31, 2021
(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026$— $— 
$500 million credit facility due November 16, 2023— — 
Commercial paper notes— — 
Current portion of senior notes
8.625%, due January 2022(a)— 260 
4.15%, due March 2022(a)— 375 
1.50%, due March 2022(a)(b)— 853 
3.95% due September 2022(c)— 1,000 
3.15% due January 20231,000 — 
Floating rate, due January 2023(d)250 — 
3.45% due February 2023625 — 
3.50% due September 2023600 — 
Trust I preferred securities, 4.75%, due March 2028111 111 
Current portion of other debt48 47 
Total current portion of debt2,634 2,646 
Long-term debt (excluding current portion)
Senior notes28,343 29,097 
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035336 348 
Trust I preferred securities, 4.75%, due March 2028109 110 
Other212 217 
Total long-term debt29,000 29,772 
Total debt(e)$31,634 $32,418 
(a)We repaid the principal amount of these senior notes during the first quarter of 2022.
(b)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The table amounts exclude allDecember 31, 2021 balance is reported above at the exchange rate of 1.1370 U.S. dollars per Euro. As of December 31, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $38 million related to these notes, which was offset by a corresponding change in the value of cross-currency swaps reflected in “Current Assets—Fair value of derivative contracts” and “Current Liabilities—Fair value of derivative contracts” on our accompanying consolidated balance sheet. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 6 “Risk Management—Foreign Currency Risk Management”).
(c)We repaid the principal amount of these senior notes on June 1, 2022.
(d)These senior notes have an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge (see Note 6 “Risk Management—Interest Rate Risk Management”).
(e)Excludes our “Debt fair value adjustments, includingadjustments” which, as of September 30, 2022 and December 31, 2021, increased our total debt discounts, premiumsbalances by $107 million and issuance costs (in millions):$902 million, respectively.
 September 30, 2017 December 31, 2016
Unsecured term loan facility, variable rate, due January 26, 2019(a)$—
 $1,000
Senior notes, floating rate, due January 15, 2023(a)250
 —
Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)(b)13,612
 13,236
Credit facility due November 26, 2019—
 —
Commercial paper borrowings60
 —
KML Credit Facility(c)132
 —
KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(d)18,885
 19,485
TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(e)1,240
 1,540
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(f)760
 1,115
CIG senior notes, 4.15% and 6.85%, due 2026 and 2037475
 475
Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036786
 786
Hiland Partners Holdings LLC, senior note, 5.50%, due 2022(a)(g)—
 225
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035424
 433
Trust I preferred securities, 4.75%, due March 31, 2028(h)221
 221
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock100
 100
Other miscellaneous debt280
 285
Total debt – KMI and Subsidiaries37,225
 38,901
Less: Current portion of debt(i)3,156
 2,696
Total long-term debt – KMI and Subsidiaries(j)$34,069
 $36,205
_______

(a)On August 10, 2017, we entered into a $1 billion unsecured senior note with a fixed rate of 3.15% and a $250 million, unsecured senior note with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay the principal amount of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019. Interest on the 3.15% senior notes due 2023 is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2018, and the notes will mature on January 15, 2023. Interest on the floating rate senior notes due 2023 is payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on October 15, 2017, and such notes will mature on January 15, 2023. We may redeem all or a part of the fixed rate notes at any time at the redemption prices. The floating rate notes will not be redeemable at our option. See (b) and (g) below.

(b)
Amounts include senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the September 30, 2017 exchange rate of 1.1814 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. For the nine months ended September 30, 2017, our debt balance increased by $162 million as a result of the change in the exchange rate of U.S. dollars per Euro. The increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “Other long-term liabilities and deferred credits” on our consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 5 “Risk Management—Foreign Currency Risk Management”). In June 2017, we repaid $786 million of maturing 7.00% senior notes. The September 30, 2017 balance includes the $1 billion unsecured term note with a fixed rate of 3.15% due January 15, 2023 discussed in (a) above.
(c)
The KML credit facility is denominated in C$ and has been converted to U.S. dollars and reported above at the September 30, 2017 exchange rate of 0.8013 U.S. dollars per C$. See “—Credit Facilities” below.
(d)In February 2017, we repaid $600 million of maturing 6.00% senior notes.
(e)In April 2017, we repaid $300 million of maturing 7.50% senior notes.
(f)In April 2017, we repaid $355 million of maturing 5.95% senior notes.
(g)In August 2017, we repaid $225 million of the outstanding principal amount of 5.50% senior notes with a maturity date of May 15, 2022 using net proceeds from the sale of the January 2023 notes (see (a) above). We recognized a $3.8 million loss from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the three and nine months ended September 30, 2017 consisting of a $9.3 million premium on the debt repaid and a $5.5 million gain from the write-off of unamortized purchase accounting associated with the early extinguishment of debt.
(h)The Trust I Preferred Securities are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder. Prior to May 25, 2017, conversions of these securities were converted into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with conversion of 1.100 warrants to purchase a share of our Class P common mixed consideration.
(i)
Amounts include KMI and KML outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months (see “—Current Portion of Debt” below).
(j)Excludes our “Debt fair value adjustments” which, as of September 30, 2017 and December 31, 2016, increased our combined debt balances by $1,047 million and $1,149 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 a partyparties 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. Also, see Note 11.


On February 23, 2022, EPNG issued in a private offering $300 million aggregate principal amount of 3.50% senior notes due 2032 and received net proceeds of $298 million after discount and issuance costs. These notes are guaranteed through the cross guarantee agreement discussed above.

On August 3, 2022, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 4.80% senior notes due 2033 and $750 million aggregate principal amount of 5.45% senior notes due 2052 and received combined net proceeds of $1,484 million. We used a portion of the proceeds to repay short-term borrowings and for general corporate purposes.

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Credit Facilities and Restrictive Covenants


As of September 30, 2017,2022, we had no borrowings outstanding under our credit facilities, no borrowings outstanding under our commercial paper program and KML$81 million in letters of credit. Our availability under our credit facilities as of September 30, 2022 was $3.9 billion. As of September 30, 2022, we were in compliance with all required covenants. As

Fair Value of September 30, 2017, KML had $132 million outstanding on its construction facility and no amount outstanding on its working capital facility, both included in “Current portion of debt” on our consolidated balance sheet.Financial Instruments

KMI
As of September 30, 2017, we had $4,830 million available under our $5.0 billion revolving credit agreement, which is net of $110 million in letters of credit and $60 million of outstanding commercial paper borrowings. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.

KML

On June 16, 2017, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, our indirect subsidiaries of KML, entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the Trans Mountain expansion project, (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional Trans Mountain expansion project costs (and, subject to the need to fund such additional costs, meeting the Canadian National Energy Board-mandated liquidity requirements) and (iii) a C$500 million revolving working capital facility to be used for working capital and other general corporate purposes (collectively, the “Credit Facility”). The Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the Credit Facility will incur a standby fee of 0.30% to 0.625%, with the range dependent on the credit ratings of Kinder Morgan Cochin

ULC or KML. The Credit Facility is guaranteed by KML and all of the non-borrower subsidiaries of KML and are secured by a first lien security interest on all of the assets of KML and the equity and assets of the other guarantors.

Draw downs of funds on the KML Credit Facility bear interest dependent on the type of loans requested and are as follows:

bankers’ acceptances or London Interbank Offered Rate loans are at an annual rate of approximately CDOR or the London Interbank Offered Rate, as the case may be, plus a fixed spread ranging from 1.50% to 2.50%;
loans in Canadian dollars or U.S. dollars are at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from 0.50% to 1.50%, in each case, with the range dependent on the credit ratings of the Company;
letters of credit (under working capital facility only) will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from 1.50% to 2.50%, with the range dependent on the credit ratings of the Company.


The foregoing ratescarrying value and fees will increase by 0.25% uponestimated fair value of our outstanding debt balances are disclosed below: 
September 30, 2022December 31, 2021
Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Total debt$31,741 $29,188 $33,320 $37,775 
(a)Included in the fourth anniversaryestimated fair value are amounts for our Trust I Preferred Securities of the KML Credit Facility.

Our KML Credit Facility includes various financial$203 million and other covenants including:

a maximum ratio of consolidated total funded debt to consolidated capitalization of 70%;
restrictions on ability to incur debt;
restrictions on ability to make dispositions, restricted payments and investments;
restrictions on granting liens and on sale-leaseback transactions;
restrictions on ability to engage in transactions with affiliates; and
restrictions on ability to amend organizational documents and engage in corporate reorganization transactions.

Current Portion of Debt
Our current portion of debt$218 million as of September 30, 2017, primarily includes2022 and December 31, 2021, respectively.

We used Level 2 input values to measure the following significant seriesestimated fair value of long-term notes maturing within the next 12 months:
Senior notes - $500 million 2.00% notes due December 2017
Kinder Morgan Finance Company, LLC, senior notes - $750 million 6.00% notes due January 2018
Senior notes - $82 million 7.00% notes due February 2018
KMP senior notes - $975 million 5.95% notes due February 2018
Senior notes - $477 million 7.25% notes due June 2018

4.  Stockholders’ Equity
Common Equity
Asour outstanding debt balance as of both September 30, 2017, our common equity consisted of our 2022 and December 31, 2021.

5. Stockholders’ Equity

Class P common stock. For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2016 Form 10-K.

KMI Common Stock Dividends


Holders of our common stock participate in any dividend declared byOn July 19, 2017, our board of directors subject to the rights of the holders of any outstanding preferred stock. Our perapproved a $2 billion share dividends declared for and paidbuy-back program that began in December 2017. During the nine month periodsmonths ended September 30, 2017 and 2016 were $0.3752022, we repurchased approximately 19 million of our shares for $333 million at an average price of $16.97 per share. Subsequent to September 30, 2022 and through October 20, 2022, we repurchased 2 million of our shares for $34 million at an average price of $16.75 per share, and since December 2017, in total, we have repurchased 54 million of our shares under the program at an average price of $17.40 per share for $942 million.

Dividends

The following table provides information about our per share dividends:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Per share cash dividend declared for the period$0.2775 $0.27 $0.8325 $0.81 
Per share cash dividend paid in the period0.2775 0.27 0.8250 0.8025 

On October 18, 2017,19, 2022, our board of directors declared a cash dividend of $0.125$0.2775 per common share for the quarterly period ended September 30, 2017,2022, which is payable on November 15, 20172022 to common shareholders of record as of the close of business on October 31, 2017.2022.


WarrantsAdoption of Accounting Pronouncement


On May 25, 2017, 293 million of unexercised warrants to buy KMI common stock expired without the issuance of Class P common stock. Prior to expiration, eachJanuary 1, 2022, we adopted Accounting Standards Update (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 warrants entitled the holder to purchase one share of our common stockthree models in ASC 470-20 that require separate accounting for an exercise price of $40embedded conversion features, (ii) amends diluted earnings per share payablecalculations 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 cash oran entity’s own equity by cashless exercise.


Mandatory Convertible Preferred Stock

We have issued and outstanding 1,600,000 sharesremoving certain requirements. Using the modified retrospective method, the adoption of 9.750% Series A mandatory convertible preferred stock, withthis ASU resulted in a liquidating preferencepre-tax adjustment of $1,000 per share. For additional information regarding our mandatory convertible preferred stock, see Note 11$14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated financial statements includedbalance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our 2016 Form 10-K.

Preferred Stock Dividends

On July 19, 2017, our boardconsolidated statement of directors declared a cash dividend of $24.375 per share of our mandatory convertible preferred stock (equivalent of $1.21875 per depositary share)stockholders’ equity for the period from and including July 26, 2017 through and including October 25, 2017, which is payable on October 26, 2017 to mandatory convertible preferred shareholders of record as of the close of business on October 11, 2017.

Noncontrolling Interests

KML Restricted Voting Shares

As discussed in Note 2, on May 30, 2017 our indirect subsidiary, KML, issued 102,942,000 restricted voting shares in a public offering. The public ownership of the KML restricted voting shares represents an approximate 30% interest in our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the periods presented after May 30, 2017.

KML Distributions

On August 15, 2017, KML paid a dividend of C$0.0571 per restricted voting share to restricted voting shareholders of record as of the close of business on July 31, 2017 for the quarterly period ended June 30, 2017. This initial dividend was prorated from May 30, 2017, the day KML closed on its IPO, to June 30, 2017 and amounted to approximately C$6 million. KML paid approximately C$4 million of this dividend to restricted voting shareholders in cash, and, under KML’s Dividend Reinvestment Plan (DRIP), 94,003 restricted voting shares were issued in lieu of cash dividends. KML’s DRIP allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion). The market discount for the dividend paid on August 15, 2017 was 3%.

On October 17, 2017, KML’s board of directors declared a dividend for the quarterly periodnine months ended September 30, 20172022.
15



Accumulated Other Comprehensive Loss

Changes in the components of C$0.1625 per restricted voting share, payable on November 15, 2017, to restricted voting shareholders of recordour “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as of the close of business on October 31, 2017.follows:

Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2021$(172)$(239)$(411)
Other comprehensive (loss) gain before reclassifications(366)18 (348)
Loss reclassified from accumulated other comprehensive loss396 — 396 
Net current-period change in accumulated other comprehensive loss30 18 48 
Balance as of September 30, 2022$(142)$(221)$(363)
KML Preferred Share Offering
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2020$(13)$(394)$(407)
Other comprehensive (loss) gain before reclassifications(444)28 (416)
Loss reclassified from accumulated other comprehensive loss181 — 181 
Net current-period change in accumulated other comprehensive loss(263)28 (235)
Balance as of September 30, 2021$(276)$(366)$(642)


On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (USD $235 million). The net proceeds of C$293 million from the offering were used by KML to indirectly subscribe for preferred units in KMC LP, which in turn were used by KMC LP to repay the KML Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the Trans Mountain Expansion project and Base Line Terminal project, and for its general corporate purposes.

Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022.

On October 17, 2017, KML’s board of directors declared a cash dividend of C$0.3308 per share of its Series 1 Preferred Shares for the period from and including August 15, 2017 through and including November 14, 2017, which is payable on November 15, 2017 to Series 1 Preferred Shareholders of record as of the close of business on October 31, 2017.


5.6.  Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks. In addition, prior to May 2016, we had legacy power forward and swap contracts related to operations of acquired businesses.


Energy Commodity Price Risk Management

As of September 30, 2017,2022, 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(19.4))MMBbl
Crude oil basis(5.6(6.0))MMBbl
Natural gas fixed price(47.0(50.8))Bcf
Natural gas basis(7.1(28.0))Bcf
NGL fixed price(0.7)MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(0.9(1.2))MMBbl
Crude oil basis(0.2(9.0))MMBbl
Natural gas fixed price(2.9(7.5))Bcf
Natural gas basis(33.3(37.8))Bcf
NGL and other fixed price(6.7(0.8))MMBbl


16


As of September 30, 2017,2022, 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 2021.2026.


Interest Rate Risk Management


 AsWe utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2017 and December 31, 2016, we had a combined notional2022:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)$7,500 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 contracts5,100 Mark-to-MarketDecember 2022
(a)The principal amount of $9,575hedged senior notes consisted of $700 million included in “Current portion of debt” and $9,775$6,800 million respectively,included in “Long-term debt” on our accompanying consolidated balance sheet.
(b)During the three and nine months ended September 30, 2022, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of fixed-to-variable interest rate swap agreements, all of which were designated asthese contracts to preserve fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates basedhedge accounting treatment. See Note 11 “Recent Accounting Pronouncements” for further information on an interest rate of London Interbank Offered Rate plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of September 30, 2017, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.Topic 848.


Foreign Currency Risk Management


AsWe utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, 2017, we had a notional principal amount of $1,358 million of cross-currency swap agreements to manage2022:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$543 Cash flow hedgeMarch 2027
(a)These swaps eliminate the foreign currency risk related toassociated with our Euro denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7-year and 12-year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes. Euro-denominated debt.


Fair Value
17


Impact of Derivative Contracts on Our Consolidated Financial Statements

The following table summarizes the fair values of our derivative contracts included inon our accompanying consolidated balance sheets:
Fair Value of Derivative Contracts
Derivatives AssetDerivatives Liability
September 30,
2022		December 31,
2021		September 30,
2022		December 31,
2021
LocationFair valueFair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Fair value of derivative contracts)$104 $61 $(229)$(141)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)29 3 (67)(94)
Subtotal133 64 (296)(235)
Interest rate contractsFair value of derivative contracts/(Fair value of derivative contracts)3 101 (115)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)36 284 (307)(15)
Subtotal39 385 (422)(18)
Foreign currency contractsFair value of derivative contracts/(Fair value of derivative contracts)— 35 (6)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)— 6 (62)— 
Subtotal— 41 (68)(3)
Total172 490 (786)(256)
Derivatives not designated as hedging instruments
Energy commodity derivative contractsFair value of derivative contracts/(Fair value of derivative contracts)48 11 (151)(31)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)20 1 (22)(6)
Subtotal68 12 (173)(37)
Interest rate contractsFair value of derivative contracts/(Fair value of derivative contracts)39 12 — — 
Total107 24 (173)(37)
Total derivatives$279 $514 $(959)$(293)

18


The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets (in millions):on a gross basis that are eligible for netting under master netting agreements.
Balance sheet asset
fair value measurements by level		Contracts available for nettingCash collateral held(b)
Level 1Level 2Level 3Gross amountNet amount
(In millions)
As of September 30, 2022
Energy commodity derivative contracts(a)$63 $138 $— $201 $(169)$— $32 
Interest rate contracts— 78 — 78 — — 78 
As of December 31, 2021
Energy commodity derivative contracts(a)$56 $20 $— $76 $(53)$(20)$3 
Interest rate contracts— 397 — 397 (9)— 388 
Foreign currency contracts— 41 — 41 (3)— 38 
Fair Value of Derivative Contracts
    Asset derivatives Liability derivatives
    September 30,
2017		 December 31,
2016		 September 30,
2017		 December 31,
2016
  Location Fair value Fair value
Derivatives designated as hedging contracts          
Natural gas and crude derivative contracts Fair value of derivative contracts/(Other current liabilities) $98
 $101
 $(11) $(57)
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 50
 70
 (4) (24)
Subtotal   148
 171
 (15) (81)
Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) 71
 94
 —
 —
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 191
 206
 (31) (57)
Subtotal   262
 300
 (31) (57)
Cross-currency swap agreements Fair value of derivative contracts/(Other current liabilities) —
 —
 (13) (7)
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 135
 —
 —
 (24)
Subtotal   135
 —
 (13) (31)
Total   545
 471
 (59) (169)
           
Derivatives not designated as hedging contracts    
    
  
Natural gas, crude, NGL and other derivative contracts Fair value of derivative contracts/(Other current liabilities) 6
 3
 (17) (29)
  Deferred charges and other assets/(Other long-term liabilities and deferred credits) 1
 —
 (1) (1)
Subtotal   7
 3
 (18) (30)
Total   7
 3
 (18) (30)
Total derivatives   $552
 $474
 $(77) $(199)
Balance sheet liability
fair value measurements by level		Contracts available for nettingCash collateral posted(b)
Level 1Level 2Level 3Gross amountNet amount
(In millions)
As of September 30, 2022
Energy commodity derivative contracts(a)$(127)$(342)$— $(469)$169 $135 $(165)
Interest rate contracts— (422)— (422)— — (422)
Foreign currency contracts— (68)— (68)— — (68)
As of December 31, 2021
Energy commodity derivative contracts(a)$(15)$(257)$— $(272)$53 $— $(219)
Interest rate contracts— (18)— (18)9 — (9)
Foreign currency contracts— (3)— (3)3 — — 

(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.

Effect of Derivative Contracts on the Income Statement

The following tables summarize the pre-tax impact of our derivative contracts inon our accompanying consolidated statements of income (in millions): and comprehensive income:
Derivatives in fair value hedging relationshipsLocationGain/(loss) recognized in income
 on derivative and related hedged item
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Interest rate contractsInterest, net$(278)$(39)$(754)$(228)
Hedged fixed rate debt(a)Interest, net$279 $39 $761 $229 
(a)As of September 30, 2022, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $385 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

19


Derivatives in fair value hedging relationships Location 
Gain/(loss) recognized in income
 on derivatives and related hedged item
    Three Months Ended September 30, Nine Months Ended September 30,
    2017 2016 2017 2016
           
Interest rate swap agreements Interest, net $(19) $(84) $(12) $315
           
Hedged fixed rate debt Interest, net $17
 $81
 $6
 $(323)
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,
2022202120222021
(In millions)(In millions)
Energy commodity derivative contracts$195 $(140)Revenues—Commodity sales$(116)$(94)
Costs of sales17 8 
Interest rate contracts— 1 Interest, net— — 
Foreign currency contracts(32)(33)Other, net(34)(34)
Total$163 $(172)Total$(133)$(120)


Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)(In millions)
Energy commodity derivative contracts$(375)$(514)Revenues—Commodity sales$(433)$(167)
Costs of sales34 10 
Interest rate contracts7 3 Interest, net— — 
Foreign currency contracts(107)(68)Other, net(115)(79)
Total$(475)$(579)Total$(514)$(236)
Derivatives in cash flow hedging relationships Gain/(loss)
recognized in OCI on derivative (effective portion)(a)		 Location Gain/(loss) reclassified from Accumulated OCI
into income (effective portion)(b)		 Location Gain/(loss)
recognized in income
on derivative
(ineffective portion
and amount
excluded from
effectiveness testing)
  Three Months Ended September 30,   Three Months Ended September 30,   Three Months Ended September 30,
  2017 2016   2017 2016   2017 2016
Energy commodity derivative contracts $(32) $20
 Revenues—Natural
gas sales		 $4
 $(3) Revenues—Natural
gas sales		 $—
 $—
      Revenues—Product
sales and other		 13
 34
 Revenues—Product
sales and other		 4
 (2)
      Costs of sales 1
 (1) Costs of sales —
 —
Interest rate swap
agreements(c)		 —
 —
 Interest, net (1) (1) Interest, net —
 —
Cross-currency swap 39
 30
 Other, net 31
 10
 Other, net —
 —
Total $7
 $50
 Total $48
 $39
 Total $4
 $(2)
(a)We expect to reclassify approximately $124 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2022 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, 2022 and 2021, we recognized approximate gains of $34 million and $6 million, respectively, 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).

Derivatives in cash flow hedging relationships 
Gain/(loss)
recognized in OCI on derivative (effective portion)(a)
 Location 
Gain/(loss) reclassified from Accumulated OCI
into income (effective portion)(b)
 Location 
Gain/(loss)
recognized in income
on derivative
(ineffective portion
and amount
excluded from
effectiveness testing)
  Nine Months Ended September 30,   Nine Months Ended September 30,   Nine Months Ended September 30,
  2017 2016   2017 2016   2017 2016
Energy commodity derivative contracts $88
 $(64) 
Revenues—Natural
 gas sales
 $5
 $20
 
Revenues—Natural
 gas sales
 $—
 $—
      
Revenues—Product
 sales and other
 33
 124
 
Revenues—Product
 sales and other
 12
 (7)
      Costs of sales 5
 (13) Costs of sales —
 —
Interest rate swap
agreements(c)		 (1) (5) Interest, net (2) (2) Interest, net —
 —
Cross-currency swap 98
 50
 Other, net 103
 29
 Other, net —
 —
Total $185
 $(19) Total $144
 $158
 Total $12
 $(7)
Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Energy commodity derivative contractsRevenues—Commodity sales$44 $(40)$18 $(703)
Costs of sales(30)(7)(129)154 
Earnings from equity investments(7)(2)(11)(4)
Interest rate contractsInterest, net(20)— 28 — 
Total(a)$(13)$(49)$(94)$(553)
_____
(a)We expect to reclassify an approximate $32 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of September 30, 2017 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur), 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).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive loss.

Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives
    Three Months Ended September 30, Nine Months Ended September 30,
    2017 2016 2017 2016
Energy commodity derivative contracts Revenues—Natural gas sales $2
 $1
 $13
 $(4)
  Revenues—Product sales and other (18) 7
 1
 (7)
  Costs of sales —
 1
 —
 (1)
Interest rate swap agreements Interest, net —
 (14) —
 63
Total(a)   $(16) $(5) $14
 $51
_______
(a) ThreeThe three and nine months ended September 30, 2017 includes2022 amounts include approximate gainslosses of $18$19 million and $47$39 million, respectively, and the three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480 million, respectively, associated with natural gas, crude and NGL derivative contract settlements. Three and nine months ended September 30, 2016 includes approximate gains of $20 million and $59 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.


20


Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, 20172022 and December 31, 2016,2021, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2017 and December 31, 2016,2022, we had cash margins of $13$223 million and $37 million, respectively, posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets.sheet. As of December 31, 2021, we had cash margins of $14 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at September 30, 2017, consisted of2022 represents our initial margin requirements of $18$88 million offset byand variation margin requirements of $5 million.$135 million posted by us with our counterparties. We also use industry standard commercial agreements whichthat allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of September 30, 2017,2022, based on our current mark to marketmark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post $4 million of additional collateral and no additional collateral beyond this $4 million ifcollateral. If we were downgraded two notches.notches, we estimate that we would be required to post $100 million of additional collateral.



Reporting7. Revenue Recognition

Disaggregation of Amounts Reclassified OutRevenues

The following tables present our revenues disaggregated by revenue source and type of Accumulated Other Comprehensive Lossrevenue for each revenue source:
Cumulative
Three Months Ended September 30, 2022
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from customers(a)
Services
Firm services(b)$845 $57 $199 $— $— $1,101 
Fee-based services243 247 106 11 — 607 
Total services1,088 304 305 11 — 1,708 
Commodity sales
Natural gas sales1,902 — — 24 (7)1,919 
Product sales389 511 11 353 (1)1,263 
Total commodity sales2,291 511 11 377 (8)3,182 
Total revenues from customers3,379 815 316 388 (8)4,890 
Other revenues(c)
Leasing services(d)120 51 141 16 — 328 
Derivatives adjustments on commodity sales(12)— — (60)— (72)
Other18 6 — 7 — 31 
Total other revenues126 57 141 (37)— 287 
Total revenues$3,505 $872 $457 $351 $(8)$5,177 
21


Three Months Ended September 30, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from customers(a)
Services
Firm services(b)$836 $66 $181 $1 $(2)$1,082 
Fee-based services190 244 93 10 — 537 
Total services1,026 310 274 11 (2)1,619 
Commodity sales
Natural gas sales1,097 — — 7 (3)1,101 
Product sales372 247 8 279 (11)895 
Total commodity sales1,469 247 8 286 (14)1,996 
Total revenues from customers2,495 557 282 297 (16)3,615 
Other revenues(c)
Leasing services(d)119 42 140 15 — 316 
Derivatives adjustments on commodity sales(71)— — (63)— (134)
Other12 6 — 8 1 27 
Total other revenues60 48 140 (40)1 209 
Total revenues$2,555 $605 $422 $257 $(15)$3,824 
Nine Months Ended September 30, 2022
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from customers(a)
Services
Firm services(b)$2,633 $176 $585 $1 $(2)$3,393 
Fee-based services690 723 300 35 — 1,748 
Total services3,323 899 885 36 (2)5,141 
Commodity sales
Natural gas sales4,938 — — 68 (17)4,989 
Product sales1,141 1,577 22 1,105 (4)3,841 
Total commodity sales6,079 1,577 22 1,173 (21)8,830 
Total revenues from customers9,402 2,476 907 1,209 (23)13,971 
Other revenues(c)
Leasing services(d)355 144 430 44 — 973 
Derivatives adjustments on commodity sales(132)(3)— (280)— (415)
Other49 17 — 26 — 92 
Total other revenues272 158 430 (210)— 650 
Total revenues$9,674 $2,634 $1,337 $999 $(23)$14,621 
22


Nine Months Ended September 30, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from customers(a)
Services
Firm services(b)$2,501 $191 $570 $1 $(2)$3,261 
Fee-based services544 709 258 35 — 1,546 
Total services3,045 900 828 36 (2)4,807 
Commodity sales
Natural gas sales5,090 — — 9 (11)5,088 
Product sales840 529 20 766 (34)2,121 
Total commodity sales5,930 529 20 775 (45)7,209 
Total revenues from customers8,975 1,429 848 811 (47)12,016 
Other revenues(c)
Leasing services(d)356 128 427 42 — 953 
Derivatives adjustments on commodity sales(726)(1)— (143)— (870)
Other51 16 — 19 — 86 
Total other revenues(319)143 427 (82)— 169 
Total revenues$8,656 $1,572 $1,275 $729 $(47)$12,185 
(a)Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues expenses, gainsby type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (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 losses that under GAAPquantity amount are included within our comprehensive income but excludedfixed. Excludes service contracts with index-based pricing, which along with revenues from our earningsother customer service contracts are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity”“Fee-based services.”
(c)Amounts recognized as revenue under guidance prescribed in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):
 
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
 
Foreign
currency
translation
adjustments
 
Pension and
other
postretirement
liability adjustments
 
Total
accumulated other
comprehensive loss
Balance as of December 31, 2016$(1) $(288) $(372) $(661)
Other comprehensive gain before reclassifications185
 80
 20
 285
Gains reclassified from accumulated other comprehensive loss(144) —
 —
 (144)
KML IPO—
 44
 7
 51
Net current-period other comprehensive income41
 124
 27
 192
Balance as of September 30, 2017$40
 $(164) $(345) $(469)

 
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, 2015$219
 $(322) $(358) $(461)
Other comprehensive (loss) gain before reclassifications(19) 65
 16
 62
Gains reclassified from accumulated other comprehensive loss(158) —
 —
 (158)
Net current-period other comprehensive (loss) income(177) 65
 16
 (96)
Balance as of September 30, 2016$42
 $(257) $(342) $(557)

6.  Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessmentTopics of the availabilityASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 6 “Risk Management” for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of observable market dataspecific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.

The three broad levels of inputs defined by the fair value hierarchy are as follows:
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the abilityright to access atdirect the measurement date;use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).Contract Balances

Fair Value of Derivative Contracts
The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. 
 
Balance sheet asset
fair value measurements by level
   Net amount
 Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(b)
As of September 30, 2017             
Energy commodity derivative contracts(a)$9
 $146
 $—
 $155
 $(18) $(5) $132
Interest rate swap agreements—
 262
 —
 262
 (11) —
 251
Cross-currency swap agreements—
 135
 —
 135
 (13) —
 122
As of December 31, 2016             
Energy commodity derivative contracts(a)$6
 $168
 $—
 $174
 $(43) $—
 $131
Interest rate swap agreements—
 300
 —
 300
 (18) —
 282

 
Balance sheet liability
fair value measurements by level
   Net amount
 Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(b)
As of September 30, 2017             
Energy commodity derivative contracts(a)$(2) $(31) $—
 $(33) $18
 $—
 $(15)
Interest rate swap agreements—
 (31) —
 (31) 11
 —
 (20)
Cross-currency swap agreements—
 (13) —
 (13) 13
 —
 —
As of December 31, 2016             
Energy commodity derivative contracts(a)$(29) $(82) $—
 $(111) $43
 $37
 $(31)
Interest rate swap agreements—
 (57) —
 (57) 18
 —
 (39)
Cross-currency swap agreements—
 (31) —
 (31) —
 —
 (31)
_______
(a)Level 1 consists primarily of New York Mercantile Exchange natural gas futures.  Level 2 consists primarily of OTC West Texas Intermediate swaps and options and NGL 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 table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions): 
Significant unobservable inputs (Level 3)
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Derivatives-net asset (liability)       
Beginning of Period$—
 $—
 $—
 $(15)
Total gains or (losses) included in earnings—
 —
 —
 (9)
Settlements—
 —
 —
 24
End of Period$—

$—
 $—
 $—
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date$—
 $—
 $—
 $—


As of September 30, 2016,2022 and December 31, 2021, our Level 3 derivativecontract asset balances were $57 million and $39 million, respectively. Of the contract asset balance at December 31, 2021, $29 million was transferred to accounts receivable during the nine months ended September 30, 2022. As of September 30, 2022 and December 31, 2021, our contract liability activity consisted primarilybalances were $204 million and $212 million, respectively. Of the contract liability balance at December 31, 2021, $77 million was recognized as revenue during the nine months ended September 30, 2022.

23


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 powerSeptember 30, 2022 that we will invoice or transfer from contract liabilities and recognize in future periods:
YearEstimated Revenue
(In millions)
Three months ended December 31, 2022$1,157 
20234,055 
20243,244 
20252,685 
20262,357 
Thereafter14,007 
Total$27,505 

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 expedient that we elected to apply, remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

8.  Reportable Segments

Financial information by segment follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers$3,497 $2,541 $9,653 $8,611 
Intersegment revenues8 14 21 45 
Products Pipelines872 605 2,634 1,572 
Terminals
Revenues from external customers457 421 1,335 1,273 
Intersegment revenues— 1 2 2 
CO2
351 257 999 729 
Corporate and intersegment eliminations(8)(15)(23)(47)
Total consolidated revenues$5,177 $3,824 $14,621 $12,185 
24


Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Segment EBDA(a)
Natural Gas Pipelines$1,135 $1,069 $3,453 $2,602 
Products Pipelines257 279 855 792 
Terminals240 216 731 689 
CO2
215 163 619 599 
Total Segment EBDA1,847 1,727 5,658 4,682 
DD&A(551)(526)(1,632)(1,595)
Amortization of excess cost of equity investments(19)(21)(57)(56)
General and administrative and corporate charges(149)(167)(438)(465)
Interest, net(399)(368)(1,087)(1,122)
Income tax expense(134)(134)(512)(248)
Total consolidated net income$595 $511 $1,932 $1,196 
September 30, 2022December 31, 2021
(In millions)
Assets
Natural Gas Pipelines$47,872 $47,746 
Products Pipelines8,994 9,088 
Terminals8,362 8,513 
CO2
3,470 2,843 
Corporate assets(b)1,294 2,226 
Total consolidated assets$69,992 $70,416 
(a)Includes revenues, earnings from equity investments, operating expenses, (gain) loss on divestitures and impairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, (which expiredcorporate headquarters in April 2016), where a significant portionHouston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

9.  Income Taxes

Income tax expense included on our accompanying consolidated statements of fair valueincome is calculated from underlying market data thatas follows:

Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except percentages)
Income tax expense$134 $134 $512 $248 
Effective tax rate18.4 %20.8 %20.9 %17.2 %
is not readily observable.  The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures.  The use of these inputs results in management’s best estimate of fair value, and management would not expect materially different valuation results were we to use different input amounts within reasonable ranges.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions): 
 September 30, 2017 December 31, 2016
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
Total debt$38,272
 $40,267
 $40,050
 $41,015
We used Level 2 input values to measure the estimated fair value of our outstanding debt balances as of both September 30, 2017 and December 31, 2016.

7.  Reportable Segments
Segment resultseffective tax rate for the three and nine months ended September 30, 2016 have been retrospectively adjusted2022 is lower than the statutory federal rate of 21% primarily due to reflect the eliminationrecognition of additional 2021 enhanced oil recovery credits from our initial estimate, the adjustment to the deferred tax liability as a result of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within the Corporate non-segment activities in reconciling to the consolidated totalsreduction in the respective segment reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated withstate tax rate and dividend-received deductions from our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interestinvestments in Florida Gas Pipeline (Citrus), NGPL Holdings and Products (SE) Pipe Line Company (PPL), partially offset by state income and income tax expense previously allocated to our business segments are now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables.taxes.
Financial information by segment follows (in millions):
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Revenues       
Natural Gas Pipelines       
    Revenues from external customers$2,022
 $2,048
 $6,283
 $5,900
    Intersegment revenues2
 2
 7
 4
CO2
289
 310
 899
 916
Terminals       
    Revenues from external customers485
 484
 1,458
 1,436
    Intersegment revenues—
 —
 1
 1
Products Pipelines       
    Revenues from external customers411
 415
 1,222
 1,204
    Intersegment revenues1
 4
 10
 12
Kinder Morgan Canada66
 66
 185
 188
Corporate and intersegment eliminations(a)5
 1
 8
 8
Total consolidated revenues$3,281
 $3,330
 $10,073
 $9,669

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Segment EBDA(b)       
Natural Gas Pipelines$884
 $542
 $2,846
 $2,503
CO2
197
 217
 636
 608
Terminals314
 294
 925
 856
Products Pipelines302
 292
 913
 761
Kinder Morgan Canada50
 48
 136
 140
Total Segment EBDA1,747
 1,393
 5,456
 4,868
DD&A(562) (549) (1,697) (1,652)
Amortization of excess cost of equity investments(15) (15) (45) (45)
General and administrative and corporate charges(164) (163) (490) (537)
Interest, net(459) (472) (1,387) (1,384)
Income tax expense(160) (377) (622) (744)
Total consolidated net income (loss)$387
 $(183) $1,215
 $506
 September 30, 2017 December 31, 2016
Assets   
Natural Gas Pipelines$51,021
 $50,428
CO2
4,016
 4,065
Terminals9,918
 9,725
Products Pipelines8,505
 8,329
Kinder Morgan Canada1,950
 1,572
Corporate assets(c)4,941
 6,108
Assets held for sale—
 78
Total consolidated assets$80,351
 $80,305
_______
(a)Includes a management fee for services we perform as operator of an equity investee.
(b)Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, net, loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net.
(c)Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy operations) not allocated to the reportable segments.

8.  Income Taxes
Income tax expense included in our accompanying consolidated statements of income were as follows (in millions, except percentages): 
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Income tax expense$160
 $377
 $622
 $744
Effective tax rate29.3% 194.3% 33.9% 59.5%


The effective tax rate for the three months ended September 30, 20172021 is lower than the statutory federal rate of 35%21% primarily due to (i) dividend-received deductions from our investmentinvestments in Florida Gas Transmission Company (Citrus)Citrus, NGPL Holdings and Plantation Pipe Line; (ii) adjustments to our income tax reserve for uncertain tax positions; and (iii) the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision. These decreases arePPL, partially offset by (i) state and foreign income taxes; (ii) a change in our state effective tax rate; and (iii) tax deductions related to equity compensation.taxes.


The effective tax rate for the three months ended September 30, 2016 is higher than the statutory federal rate of 35% primarily due to (i) the impact of our Regulated Natural Gas Pipeline segment’s $817 million non-tax-deductible goodwill as a result of the sale of a 50% interest in SNG; and (ii) state and foreign income taxes, partially offset by (i) dividend-received
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deductions from our investment in Citrus and Plantation Pipe Line. The SNG partial sale transaction generated a taxable gain resulting from non-deductible goodwill attributable to the transaction which generated a deferred tax provision of $269 million.

The effective tax rate for the nine months ended September 30, 20172021 is lower than the statutory federal rate of 35%21% primarily due to (i)the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings and dividend-received deductions from our investmentinvestments in Citrus, NGPL Holdings and Plantation Pipe Line; and (ii) the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision;PPL, partially offset by state and foreign income taxes.

The effective tax rate for the nine months ended September 30, 2016 is higher than the statutory federal rate of 35% primarily due to (i) state
10.   Litigation and foreign income taxes; and (ii) the impact of our Regulated Natural Gas Pipeline segment’s $817 million non-tax-deductible goodwill as a result of the sale of a 50% interest in SNG; partially offset by (i) dividend-received deductions from our investment in Citrus and Plantation Pipe Line; and (ii) adjustments to our income tax reserve for uncertain tax positions.Environmental

Adoption of ASU 2016-09 “Compensation - Stock Compensation (Topic 718)”

The tax impact of ASU 2016-09, which was adopted and effective January 1, 2017, resulted in $8 million of deferred tax assets being recorded through a cumulative-effect adjustment to our retained deficit. The previously unrecorded deferred tax asset is related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Post-adoption the excess tax benefits or deficiencies are recognized for income tax purposes in the period in which they occur through the income statement.

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 on our business, financial position, results of operations or dividends to our shareholders.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 the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

Federal Energy Regulatory Commission Proceedings

SFPP

The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers the most recent of which was filed in late 2015 with the FERC (docketed at OR16-6) challenging SFPP’s filed East Line rates. 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. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing date of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. 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. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On July 21, 2017, an initial decision by the Administrative Law Judge (ALJ) in OR16-6 concluded that the Complainants are due reparations, with appropriate interest, equal to the difference between what SFPP collected from the Complainants for service on the East Line and the amounts SFPP would have collected had it charged just and reasonable rates for that line.  The ALJ ruled that an income tax allowance should be included in the cost of service both to determine reparations and to set going forward rates, and found that the new just and reasonable rates are not knowable until the FERC reviews the initial decision and orders a compliance filing.  The FERC will determine which portions of the initial decision to affirm, reject or amend.  With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking

approximately $40 million in annual rate reductions and approximately $220 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, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.


EPNG FERC Proceeding

The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it will apply its findings in Opinion 517-A to the same issues in the 2010 rate case. EPNG sought federal appellate review of Opinion 517-A and oral arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until the FERC rules on the rehearing requests pending in the 2010 Rate Case. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. EPNG and two intervenors sought rehearing of certain aspects of the decision, and the judicial review sought by certain intervenors has been delayed until the FERC issues an order on rehearing. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. With respect to the 2010 rate case, EPNG believes it has an appropriate reserve related to the findings in Opinions 517-A and 528-A.

NGPL and WIC


On January 19, 2017, NGPL and WIC were separatelyApril 21, 2022, EPNG was notified by the FERC of the commencement of a rate proceedingsproceeding against themit pursuant to sectionSection 5 of the Natural Gas Act. The matters were setThis proceeding sets the matter for hearingshearing to determine whether NGPL’s and WIC’sEPNG’s current rates remain just and reasonable. A proceeding under sectionSection 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. NGPLUnless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in the second quarter of 2023. We are engaged actively in settlement discussions and WIC each submittedanticipate joining with FERC Trial Staff and other active participants in the proceeding in filing an unopposed motion to suspend the FERC an Offerprocedural schedule to enable the parties to prepare documents necessary to document a settlement in principle that would fully resolve the proceeding. We do not believe that the ultimate resolution of Settlement in their respective proceedings. The presiding ALJ in both proceedings certificated the settlements as uncontested, and the companies expect FERC approval by the end of the year. As currently negotiated, the settlements would notthis proceeding will have a material adverse impact on KMI’s results of operations or cash flows from operations.

Trans Mountain Expansion Project Litigation

There are numerous legal challenges pending before the Federal Court of Appeal which have been filed by various governmental and non-governmental organizations, Aboriginal groups or other parties that seek judicial review of the recommendation of the National Energy Board (NEB) and subsequent decision by the Federal Governor in Council to conditionally approve the Trans Mountain Pipeline Expansion Project (the ‘‘Project’’). The petitions allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of the Project were not adequately considered. The remedies sought include requests that the NEB recommendation be quashed, that additional consultations be undertaken, and that the order of the Governor in Council approving the Project be quashed. After provincial elections in British Columbia on May 9, 2017, the New Democratic Party and Green Party formed a majority government. The new British Columbia government sought and was granted limited intervenor status in the Federal Court of Appeal proceedings to argue against the government’s approval of the Project. A hearing was conducted by the Federal Court of Appeal from October 2 through October 13, 2017. A decision is expected in the coming months, and is subject to potential further appeal to the Supreme Court of Canada. Although we believe that each of the foregoing appeals lacks merit, in the event an applicant is successful at the Supreme Court of Canada, among other potential impacts, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, the Project may be subject to additional significant regulatory reviews, there may be significant changes to the Project plans, further obligations or restrictions may be implemented, or the Project may be stopped altogether, which could materially impact the overall feasibility or economic benefits of the Project, which in turn would have a material adverse effect on the Project and, consequently, our investment in KML.

In addition to the judicial reviews of the NEB recommendation report and Governor in Council’s order, two judicial review proceedings have been commenced at the Supreme Court of British Columbia (Squamish Nation; and the City of Vancouver). The petitions allege a duty and failure to consult or accommodate First Nations, and generally, among other claims, that the Province ought not to have approved the Project. Each Applicant seeks to quash the Environmental Assessment Certificate (EAC) that was issued by the British Columbia Environmental Assessment Office. On September 29, 2017, the British Columbia government filed evidence in support of the EAC approval in the judicial review proceeding involving the Squamish

Nation. Hearings are scheduled for October and November 2017, respectively, for the City of Vancouver and the Squamish Nation judicial review proceedings. Although we believe that each of the foregoing appeals lacks merit, in the event that an applicant for judicial review is successful, among other potential impacts, the EAC may be quashed, provincial permits may be revoked, the Project may be subject to additional significant regulatory reviews, there may be significant changes to the Project plans, further obligations or restrictions may be imposed or the Project may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of British Columbia, they may further seek to appeal the decision to the British Columbia Court of Appeal. Any decision of the British Columbia Court of Appeal may be appealed to the Supreme Court of Canada. A successful appeal at either of these levels could result in the same types of consequences described above.

Other Commercial Matters

Union Pacific Railroad Company Easements & Related Litigation

SFPP and Union Pacific Railroad Company (UPRR) engaged in a proceeding to determine the extent, if any, to which rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., et al., Superior Court of the State of California, County of Los Angeles, Case No. BC319170). In September 2011, the trial judge determined that the annual rent payable as of January 1, 2004 was $14 million, subject to annual consumer price index increases. SFPP appealed the judgment.

In addition, as part of the second ten-year rent setting period, in 2013 UPRR demanded the payment of $22.3 million in rent for the first year of the next ten-year period beginning January 1, 2014, which SFPP rejected. On November 5, 2014, the Court of Appeals issued an opinion which reversed the judgment, including the award of prejudgment interest, and remanded the matter to the trial court for a determination of UPRR’s property interest in its right-of-way, including whether UPRR has sufficient interest to grant SFPP’s easements. UPRR filed a petition for review to the California Supreme Court which was denied. In July 2017, UPRR and SFPP reached a settlement of the rental disputes on terms that are confidential and within the right-of-way liability previously recorded for back rent.

After the above-referenced decision by the California Court of Appeals which held that UPRR does not own the subsurface rights to grant certain easements and may not be able to collect rent from those easements, a purported class action lawsuit was filed in 2015 in a U.S. District Court in California by private landowners in California who claim to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on lawsuits were filed and are pending in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which are brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, assert claims against UPRR, SFPP, KMGP, and Kinder Morgan Operating L.P. “D” for declaratory judgment, trespass, ejectment, quiet title, unjust enrichment, inverse condemnation and accounting arising from defendants’ alleged improper use or occupation of subsurface real property. Plaintiffs’ motions for class certification were denied by the federal courts in Arizona and California. The Ninth Circuit Court of Appeals denied Plaintiffs’ request for interlocutory review of the decisions on class certification. The New Mexico and Nevada lawsuits have been stayed. SFPP views these cases as primarily a dispute between UPRR and the plaintiffs. UPRR purported to grant SFPP a network of subsurface pipeline easements along UPRR’s railroad right-of-way. SFPP relied on the validity of those easements and paid rent to UPRR for the value of those easements.

SFPP and UPRR also engaged in multiple disputes since 2000 over the circumstances and conditions under which SFPP must pay to relocate its pipeline within the UPRR right-of-way. In July 2017, UPRR and SFPP reached a settlement of the relocation disputes on terms that are confidential but which generally require the parties to share and allocate the cost of future relocations. Although the cost sharing mechanism in the settlement is expected to reduce the cost of future relocations, SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations such that it is difficult to quantify the cost of future potential relocations. Such costs could have an adverse effect on our financial position, results of operations, cash flows, and dividends to our shareholders.business.


Gulf LNG Facility ArbitrationDisputes


On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and Disputed Statements and 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 iswas 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 itsThe Notice of Arbitration Eni USA seekssought declaratory and monetary relief based upon itsEni USA’s 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.  As set forth in the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. We expectOn June 29, 2018, the arbitration panel will issue its decision beforetribunal delivered an Award that called for the end of fourth quarter 2017. Eni USA has indicated that it will continue to pay the amounts claimed to be due pending resolutiontermination of the dispute. The successful assertion byagreement and Eni USAUSA’s payment of its claimcompensation to terminate or amend its payment obligations under the agreement prior to the expiration of its initial term could have an adverse effect on the business, financial position, results of operations, or cash flows of GLNG and distributions to KMI, a 50% shareholder of GLNG. We view the demand for arbitration to be without merit, and we will continue to contest it vigorously.

Brinckerhoff Merger Litigation

In April 2017, a purported class action suit was filed inOn February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

On September 28, 2018, GLNG filed a former EPB unitholderlawsuit 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. In response to the foregoing lawsuit, Eni S.p.A. filed counterclaims under the terminal use agreement and claims under a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing claims asserted by Eni S.p.A seek unspecified damages and involve the same allegations as the claims which were resolved conclusively in the arbitrations with Eni USA described above and with GLNG’s remaining customer as described below. On January 4, 2022, the trial court entered a decision granting Eni S.p.A’s motion for summary judgment on behalfthe claims asserted by GLNG to enforce the Guarantee Agreement. GLNG filed an interlocutory appeal of the decision. Pending resolution of GLNG’s appeal and further proceedings in the trial court, the foregoing counterclaims and other claims asserted by Eni S.p.A under the terminal use agreement and parent direct agreement remain pending in the trial court.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a classconsortium of former unaffiliated unitholdersinternational oil companies including Eni S.p.A., filed a Notice of EPB,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 challengeEni USA. On July 15, 2021, the $9.2 billion mergerarbitration tribunal delivered an Award on the merits of EPBall
26

claims submitted to the tribunal and denied all of ALSS’s claims with prejudice. On November 23, 2021, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award.

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 subsidiary of KMI as part of a series of transactionssettlement agreement in November 2014 whereby KMI acquiredJune 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 filed an amended petition in which it asserted that Hiland Partners’ failure to construct certain facilities by specific dates nullified the outstanding equity interestsrelease contained in KMP, KMR,the settlement agreement. CLR’s amended petition asserted additional claims under both the GPA and EPBa May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that KMIHiland Partners was not allowed to deduct third-party processing fees from the gas purchase price. CLR sought damages in excess of $276 million. On September 14, 2022, the parties entered into a confidential settlement agreement, including an unconditional release and its subsidiaries did not already own. Thedismissal of the litigation with prejudice.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed suit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that the merger consideration did not sufficiently compensate EPB unitholders for the value of three derivative suits concerning drop down transactions which the derivative plaintiff lost standing to pursue after the mergerit is owed approximately $104 million, plus attorney fees and which the present suit now alleges were collectively worth as much as $700 million. The suit claims that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constitutes a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserts claims against KMI and certain individual defendants for allegedly tortiously interfering with and/or aiding and abetting the alleged breach of the limited partnership agreement. Defendants have moved to dismiss the suit.interest. We continue to believe that both the merger and the drop down transactions were appropriate and in the best interestsour declaration of EPB,force majeure was valid and we intend to continue tovigorously defend this lawsuit vigorously.case.

Price Reporting Litigation

Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which are pending in a U.S. District Court in Nevada, were dismissed, but the dismissal was reversed by the NinthCircuit Court of Appeals. The U.S. Supreme Court affirmed the Ninth Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the District Court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the District Court granted a motion for summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages has been alleged. That ruling has been appealed to the Ninth Circuit Court of Appeals. Settlements have been reached in class actions originally filed in Kansas and Missouri, which settlements received final court approval and have been paid. In the remaining case, a Wisconsin class action in which approximately $300 million in damages has been alleged against all defendants, the District Court denied plaintiff’s motion for class certification. The Ninth Circuit Court of Appeals granted plaintiff’s request for an interlocutory appeal of this ruling. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are not currently determinable.


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.


Arizona Line 2000 Rupture

On August 15, 2021, the 30” EPNG Line 2000 natural gas transmission pipeline ruptured in a rural area in Coolidge, Arizona. The failure resulted in a fire which destroyed a home, resulting in two fatalities and one injury. The National Transportation Safety Board is investigating the incident. The impacted pipeline segment is currently out of service. While no litigation is pending at this time, we notified our insurers of the incident and do not expect that the resolution of claims will have a material adverse impact to our business.

General


As of September 30, 20172022 and December 31, 2016,2021, our total reserve for legal matters was $330$42 million and $407$231 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments.


Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal,local, state and localfederal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline,
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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 local, state and federal environmental and safety regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the Clean Air Act.regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material to our business, individually or in the aggregate, will be material.aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.remediation efforts.


In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state superfundSuperfund 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, crude oil, NGL, natural gas or CO2.

PHMSA Enforcement Matter for KMLT Midwest Terminals

On July 11, 2022, Kinder Morgan Liquid Terminals (KMLT) received a Notice of Probable Violation (NOPV) from PHMSA relating to inspections conducted during 2021 at KMLT’s Cincinnati, Indianapolis, Dayton, Argo, O’Hare, and CO2.Wood River Terminals. The NOPV alleges 16 violations of Department of Transportation regulations. The NOPV proposes a penalty of approximately $455,000 and seeks a compliance agreement relating to three of the alleged violations. The alleged violations are predominately procedural in nature. On September 1, 2022, we submitted a Request for Hearing, Statement of Issues and Response to the NOPV. At the same time we initiated settlement discussions with PHMSA which are ongoing. We do not anticipate the costs to resolve this matter, including any costs to implement a compliance agreement, will have a material adverse impact to our business.


Portland Harbor Superfund Site, Willamette River, Portland, Oregon


In December 2000,On January 6, 2017, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). AtRecord of Decision (ROD) that time, GATX owned two liquids terminals alongestablished a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River an industrialized area knowncommonly referred to as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site.Superfund Site (PHSS). The EPA issued the FS and the Proposed Plan on June 8, 2016 which included a proposed combination of dredging, capping, and enhanced natural recovery. On January 6, 2017, the EPA issued its Record of Decision (ROD)cost for the final cleanup plan. The final remedy is estimated to be more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost increased from approximately $750 million to approximately $1.1$2.8 billion and active cleanup is now expected to take as long as 13more than 10 years to complete. KMLT, KMBT, and some 90 other partiesPRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs.costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT and KMBT in(in connection with their current or formerits ownership or operation of four facilities located in Portland Harbor.two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for Portland Harbor Superfund Sitethe PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around October 2023. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the site. PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the site. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.PHSS.

Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona
The Roosevelt Irrigation District sued KMGP, KMEP and others under CERCLA for alleged contamination of the water purveyor’s wells. The First Amended Complaint sought $175 million in damages from approximately 70 defendants. On August 6, 2013 plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. We have filed an answer, general denial, and affirmative defenses in response to the Second Amended Complaint and fact discovery is proceeding.


Uranium Mines in Vicinity of Cameron, Arizona


In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty20 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 potentially responsible partyPRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of
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Work pursuant to which EPNG is conducting a radiological assessmentenvironmental assessments of the surface ofmines and the mines.immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona (Case No. 3:14-08165-DGC) seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, givenmines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the positionU.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that our share of the United States as ownercosts of the Navajo Reservation and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are knownremediation will have a material adverse impact to exist. In August 2017, the District Court found the United States liable under CERCLA as owner of the Navajo Reservation. The matter seeking cost recovery and contribution from federal government agencies is set for trial in February 2018. We intend to continue to prosecute and defend this case vigorously.our business.


Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, New Jersey


EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI,(collectively EPEC) are involvedidentified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged thatRiver in New Jersey. EPEC Polymers and EPEC Oil Trust may be potentially responsible parties (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 themobligates EPEC to investigate and characterize contamination at the Site. They are alsoEPEC is part of a joint defense group of approximately 7044 cooperating parties referred to as the Cooperating Parties Group (CPG), which has entered into AOCs and is directing and funding the AOC work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted to the EPA in 2015, and comments from the EPA remain pending. Under the second AOC, the CPG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with thethese two AOCs.

On April 11, 2014,March 4, 2016, the EPA announced the issuanceissued a Record of its Focused Feasibility Study (FFS)Decision (ROD) for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to addressSite. At that time the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to $3.2 billion. The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at an estimated cost of $1.7 billion. On March 4, 2016, the EPA issued its ROD for the lower 8.3 miles of the Passaic River Study area. The final cleanup plan in the ROD is substantially similarwas estimated to the EPA’s preferred alternative announced on April 11, 2014. On October 5, 2016, the EPA entered into an AOC with one member of the PRP group requiring such member to spend $165 million to perform engineering and design work necessary to begin the cleanup of the lower 8.3 miles of the Passaic River.cost $1.7 billion. The design work is expected to take four years to complete and the cleanup is expected to take at least six years to complete.

complete once it begins. In addition, the EPA has notified otherand numerous PRPs, including EPEC, Polymers and EPEC Oil Trust, that the EPA intends to pursue agreements with other “major PRPs” and initiate negotiations over cash buyouts with parties whom the EPA does not consider “major PRPs.” The EPA also notified the parties ofengaged in an allocation process that couldfor the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020 and certain PRPs, including EPEC, are engaged in discussions with the EPA as a result in cash-out settlements with a number of them. The notices createthereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS andlower eight mile ROD. On October 4, 2021, the EPA issued a ROD and provide no guidance asfor the upper nine miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the EPA’s definition of a “major PRP”,cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the allocation process including how it will impactEPA concerning the PRPs, or the potential amount or range of cash buyouts.upper nine miles. There is alsoremains significant uncertainty as to the impactimplementation and associated costs of the RI/FSremedy set forth in the upper nine mile ROD. Until the ongoing discussions with the EPA conclude, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that the CPG is currently preparing for portionsour share of the Site. The draft RI/FS was submitted bycosts to resolve this matter, including the CPG earlier in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore, the scopecosts of potential EPA claims for the lower eight milesany remediation of the Passaic River is not reasonably estimable at this time.Site, will have a material adverse impact to our business.



Southeast Louisiana Flood ProtectionGovernmental Coastal Zone Erosion Litigation


On July 24,Beginning in 2013, several parishes in Louisiana and the BoardCity of CommissionersNew 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 Southeast Louisiana Flood Protection Authority - East (SLFPA) filed a petition for damagesdefendants’ oil and injunctive reliefgas exploration, production and transportation operations were conducted in a state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP, SNGviolation of the State and approximately 100 other energy companies, allegingLocal Coastal Resources Management Act of 1978, as amended (SLCRMA) and that defendants’ drilling, dredging, pipeline and industrialthose operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damagessubstantial damage to the plaintiff.coastal waters of Louisiana and nearby lands. The SLFPA asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. AmongPlaintiffs seek, among other relief, the petition seeks unspecified monetarymoney damages, attorneyattorneys’ fees, interest, and injunctive reliefpayment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in the formLouisiana against oil and gas companies, one of abatementwhich is against TGP and restorationone of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On February 13, 2015, the Court granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing the SLFPA’s claims with prejudice. On March 3, 2017, the Fifth Circuit Court of Appeals affirmed the U.S. District Court’s decision. On March 17, 2017, the SLFPA filed a petition seeking en banc review and reconsideration of the decision by the Fifth Circuit Court of Appeals, and such petition was denied. On July 11, 2017, the SLFPA filed a petition for a writ of certiorari to the U.S. Supreme Court.which is against SNG, both described further below.


Plaquemines Parish Louisiana Coastal Zone Litigation

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the State District Courtstate district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that the defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, EmpirePlaquemines Parish violated SLCRMA and Fort Jackson oilLouisiana law, and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act,lands. Plaquemines Parish seeks, among other relief, unspecified monetary relief,money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxifyareas. In December 2013, the Coastal Zone. In connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. TGP responded to Kinetica by reasserting TGP’s demand for defense and indemnity and reserving its rights. On November 12, 2015, the Plaquemines Parish Council adopted a resolution directing its legal counsel in all its Coastal Zone cases to take all actions necessary to cause the dismissal of all such cases. On April 14, 2016, following interventions in the suit by the Louisiana Department of Natural Resources and Attorney General, the Parish Council passed a resolution rescinding its November 12, 2015 resolution that had directed its counsel to dismiss the suit. We intend to continue to vigorously defend the suit.

Vermilion Parish Louisiana Coastal Zone Litigation

On July 28, 2016, the District Attorney for the Fifteenth Judicial District of Louisiana, purporting to act on behalf of Vermilion Parish and the State of Louisiana, filed suit in the State District Court for Vermilion Parish, Louisiana against TGP and 52 other energy companies, alleging that the defendants’ oil and gas and transportation operations associated with the development of several fields in Vermilion Parish (Operational Areas) were conducted in violation of the Coastal Zone Management Act. The suit alleges such operations caused substantial damage to the coastal waters and nearby lands (Coastal Zone) of Vermilion Parish, resulting in the release of pollutants and contaminants into the environment, improper discharge of oil field wastes, the improper use of waste pits and failure to close such pits, and the dredging of canals, which resulted in degradation of the Operational Areas, including erosion of marshes and degradation of terrestrial and aquatic life therein. As a result of such alleged violations of the Coastal Zone Management Act, the suit seeks a judgment against the defendants awarding all appropriate damages, the payment of costs to clear, revegetate, detoxify and otherwise restore the Vermilion Parish Coastal Zone, actual restoration of the affected Coastal Zone to its original condition, and reasonable costs and attorney fees. On September 2, 2016, the case was removed to the U.S. District Court for the Western District of Louisiana. Plaintiffs filed a motion to remand the case to the state district court. On September 26, 2017, the U.S. District Court remanded the case to the State District Court for Vermillion Parish. We intend to vigorously defend the suit.

Vintage Assets, Inc. Coastal Erosion Litigation

On December 18, 2015, Vintage Assets, Inc. and several individual landowners filed a petition in the State District Court for Plaquemines Parish, Louisiana alleging that its 5,000 acre property is composed of coastal wetlands, and that SNG and TGP failed to maintain pipeline canals and banks, causing widening of the canals, land loss, and damage to the ecology and hydrology of the marsh, in breach of right of way agreements, prudent operating practices, and Louisiana law. The suit also claims that defendants’ alleged failure to maintain pipeline canals and banks constitutes negligence and has resulted in encroachment of the canals, constituting trespass. The suit seeks in excess of $80 million 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. The suit was removed to the U.S. District Court for the Eastern District of Louisiana. The SNG assets at issue were sold to Highpoint Gas Transmission, LLC in 2011, which was subsequently purchased by American Midstream Partners, LP. In response to SNG’s demand for defense and indemnity, American Midstream Partners agreed to pay 50% of joint defense costs and expenses, with a percentage of indemnity to be determined upon final resolution ofApril 2015, the suit. On October 20, 2016, plaintiffs filed an amended complaint naming Highpoint Gas Transmission, LLC as an additional defendant. A non-jury trial was held during September 2017. TheU.S. District Court ordered the partiescase to submit post-trial briefing.be remanded to the state district court for Plaquemines Parish. In May 2018, the case was removed for a second time to the U.S. District Court. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court. The case has been effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal court and ordered to be remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. The defendants to those consolidated cases pursued an appeal of the remand decisions to the United States Court of Appeals for the Fifth Circuit to determine whether there is federal officer jurisdiction. On October 17, 2022, the United States Court of Appeals ordered those consolidated cases to be remanded to the state district courts. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We anticipate a ruling in the fourth quarter 2017 or first quarter 2018. We will continueintend to vigorously defend this case.

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

Products Pipeline Incident, Walnut Creek, California

On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in California from Concord to San Jose. We shut down the pipeline and notified the appropriate regulatory agencies of a “threatened release” of gasoline. We investigated the issue over the next several days and on November 24, 2020, identified a crack in the pipeline and notified the regulatory agencies of a “confirmed release.” The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on November 26, 2020. We reported the estimated volume of gasoline released to be 8.1 Bbl. On December 2, 2020, complaints of gasoline odors were reported along the LS-16 pipeline corridor in Walnut Creek. A unified response was implemented by us along with the EPA, the California Office of Spill Prevention and Response, the California Fire Marshall, and the San Francisco Regional Water Quality Control Board. On December 8, 2020, we reported an updated estimated spill volume of up to 1,000 Bbl.

On October 28, 2021, we were informed by the California Attorney General it was contemplating criminal charges against us asserting the November 2020 discharge of gasoline affected waters of the State of California, and there was a failure to make timely notices of this discharge to appropriate state agencies. On December 16, 2021, we entered into a plea agreement with the State of California to resolve misdemeanor charges of the unintentional, non-negligent discharge of gasoline resulting from the trial.release and the claimed failure to provide timely notices of the discharge to appropriate state agencies. Under the plea agreement, SFPP plead no-contest to two misdemeanors and paid approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and was placed on informal, unsupervised probation for a term of 18 months.


Since the November 2020 release, we have cooperated fully with federal and state agencies and have worked diligently to remediate the affected areas. We anticipate civil enforcement actions by federal and state agencies arising from the November 2020 release as well as ongoing monitoring and, where necessary, remediation under the oversight of the San Francisco Regional Water Quality Control Board until site conditions demonstrate no further actions are required. We do not anticipate the costs to resolve those enforcement matters, including the costs to monitor and further remediate the site, will have a material adverse impact to our business.

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 September 30, 20172022 and December 31, 2016,2021, we have accrued a total reserve for environmental liabilities in the amount of $290$227 million and $302$243 million, respectively. In addition, as of both September 30, 20172022 and December 31, 2016,2021, we havehad receivables of $11 million and $12 million, respectively, recorded a receivable of $13 million, for expected cost recoveries that have been deemed probable.


10.11. Recent Accounting Pronouncements

Topic 606Accounting Standards Updates


Reference Rate Reform (Topic 848)

On May 28, 2014,March 12, 2020, the FASB issued ASU No. 2014-09,2020-04, “Revenue from Contracts with CustomersReference Rate Reform – Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” followed by a series of related accounting standard updates (collectively referredThis ASU provides temporary optional expedients and exceptions to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensiveGAAP guidance for transactions such as service revenue,on contract modifications and multiple-element arrangements.

We are inhedge accounting to ease the process of comparing our current revenue recognition policies to the requirements of Topic 606 for each of our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete, and we have not concluded on the overall impacts of adopting Topic 606. Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amountfinancial reporting burdens of the transaction price allocatedexpected market transition from LIBOR and other interbank offered rates to performance obligations that are unsatisfied (or partially unsatisfied)alternative reference rates, such as of the end of the reporting period, as applicable. We anticipate utilizing the modified retrospective method to adopt the provisions of this standard effective January 1, 2018, which requires usSecured Overnight Financing Rate (SOFR).
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Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the new revenue standardcontracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to (i) all new revenue contracts entered into aftercontinue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.

On January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be revised.

ASU No. 2015-11

On July 22, 2015,7, 2021, the FASB issued ASU No. 2015-11,2021-01, “InventoryReference Rate Reform (Topic 330)848): Simplifying the Measurement of Inventory.” This ASU requires entities to subsequently measure inventory at the lower of cost and net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. ASU No. 2015-11 was effective January 1, 2017. We adopted ASU No. 2015-11 with no material impact to our financial statements.

ASU No. 2016-02

On February 25, 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU requires that lessees will be required to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02.

ASU No. 2016-09

On March 30, 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718).” This ASU was issued as part of the FASB’s simplification initiative and affects all entities that issue share-based payment awards to their employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We adopted ASU No. 2016-09 with no material impact to our financial statements. See Note 8.

ASU No. 2016-13

On June 16, 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No. 2016-13 will be effective for us as of January 1, 2020. We are currently reviewing the effect of ASU No. 2016-13.

ASU No. 2016-18

On November 17, 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows.  ASU No. 2016-18 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-04

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

ASU No. 2017-05

On February 22, 2017, the FASB issued ASU No. 2017-05, “Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting of a financial asset that meetswithout de-designating the definition of an “in-substance nonfinancial asset” and defines the term “in-substance nonfinancial asset.”  This ASU also adds guidance for partial sales of nonfinancial assets.  ASU No. 2017-05 will be effective at the same time Topic 606, Revenue from Contracts with Customers, is effective.  We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-07

On March 10, 2017, the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715).” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allow only the service cost component of net benefit cost to be eligible for capitalization, and how to present the service cost component and the other components of net benefit cost in the income statement. ASU No. 2017-07 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.


ASU No. 2017-12

On August 28, 2017, the FASB issued ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance in order to allow companies to more accurately present the economic effects of risk management activities in the financial statements. ASU No. 2017-12 will be effective for us as of January 1, 2019, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

11. Guarantee of Securities of Subsidiaries

KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each partyhedging relationship to the agreement unconditionally guarantees, jointlyextent such derivatives are impacted by the Discounting Transition.

The guidance was effective upon issuance and severally,generally can be applied through December 31, 2022.

During the paymentnine months ended September 30, 2022 we amended certain of specified indebtednessour existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of each other partysuch agreements from LIBOR to the agreement. Accordingly,SOFR. These agreements contain a combined notional principal amount of $1,725 million and convert a portion of our fixed rate debt to variable rates through March 2035. Concurrent with the exception ofthese amendments, we elected certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuer and other subsidiaries are all guarantors of each series of public debt. As a result of the cross guarantee agreement, a holderoptional expedients provided in Topic 848 which allow us to maintain our prior designation of fair value hedge accounting to these agreements. As we continue to amend our interest rate swap agreements to transition from LIBOR to SOFR, we will assess whether such amendments qualify for any of the guaranteed public debt securities issued by KMI or KMP isoptional expedients in the same position with respectTopic 848 and, should they qualify, whether we wish to the net assets, income and cash flows of KMI and the Subsidiary Issuer and Guarantors. The only amounts that are not available to the holders of each of the guaranteed public debt securities to satisfy the repayment ofelect any such securities are the net assets, income and cash flows of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statementsoptional expedients. See Note 6“Risk Management—Interest Rate Risk Management” for subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements basedmore information on Rule 3-10 of the SEC’s Regulation S-X.  We have presented each of the parent and subsidiary issuer in separate columns in this single set of condensed consolidating financial statements.

On September 1, 2016, we sold a 50% equity interest in SNG. Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors column of these condensed consolidating financial statements.

Excluding fair value adjustments, as of September 30, 2017, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $13,921 million, $18,885 million, and $3,310 million, respectively, of Guaranteed Notes outstanding.  Included in the Subsidiary Guarantors debt balance as presented in the accompanying September 30, 2017 condensed consolidating balance sheet is approximately $164 million of capital lease obligations that are not subject to the cross guarantee agreement.

The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Guarantors and Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only.  These intercompany investments and related activities eliminate in consolidation and are presented separately in the accompanying condensed consolidating balance sheets and statements of income and cash flows.

A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries.  As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries.  We utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cashrate risk management activities.


31
Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended September 30, 2017
(In Millions)
(Unaudited)

  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Total Revenues $8
 $—
 $2,899
 $413
 $(39) $3,281
             
Operating Costs, Expenses and Other            
Costs of sales —
 —
 975
 81
 (27) 1,029
Depreciation, depletion and amortization 4
 —
 487
 71
 —
 562
Other operating expenses 12
 1
 711
 148
 (12) 860
Total Operating Costs, Expenses and Other 16
 1
 2,173
 300
 (39) 2,451
             
Operating (loss) income (8) (1) 726
 113
 —
 830
             
Other Income (Expense)            
Earnings from consolidated subsidiaries 690
 688
 111
 15
 (1,504) —
Earnings from equity investments —
 —
 167
 —
 —
 167
Interest, net (174) (1) (277) (7) —
 (459)
Amortization of excess cost of equity investments and other, net —
 —
 3
 6
 —
 9
             
Income Before Income Taxes 508
 686
 730
 127
 (1,504) 547
             
Income Tax Expense (135) (1) (18) (6) —
 (160)
             
Net Income 373
 685
 712
 121
 (1,504) 387
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
 (14) (14)
             
Net Income Attributable to Controlling Interests 373
 685
 712
 121
 (1,518) 373
             
Preferred Stock Dividends (39) —
 —
 —
 —
 (39)
Net Income Available to Common Stockholders $334
 $685
 $712
 $121
 $(1,518) $334
             
Net Income $373
 $685
 $712
 $121
 $(1,504) $387
Total other comprehensive income (loss) 14
 (1) (3) 105
 (71) 44
Comprehensive income 387
 684
 709
 226
 (1,575) 431
Comprehensive income attributable to noncontrolling interests —
 —
 —
 —
 (44) (44)
Comprehensive income attributable to controlling interests $387
 $684
—
$709
 $226
 $(1,619) $387


Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended September 30, 2016
(In Millions)
(Unaudited)

  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Total Revenues $9
 $—
 $2,953
 $386
 $(18) $3,330
             
Operating Costs, Expenses and Other            
Costs of sales —
 —
 916
 61
 (6) 971
Depreciation, depletion and amortization 4
 —
 466
 79
 —
 549
Other operating expenses 663
 —
 145
 132
 (12) 928
Total Operating Costs, Expenses and Other 667
 —
 1,527
 272
 (18) 2,448
             
Operating (loss) income (658) —
 1,426
 114
 —
 882
             
Other Income (Expense)            
Earnings from consolidated subsidiaries 963
 1,004
—
99
 14
 (2,080) —
Losses from equity investments —
 —
—
(213) —
 —
 (213)
Interest, net (173) (6)—
(281) (12) —
 (472)
Amortization of excess cost of equity investments and other, net (1) —
—
(6) 4
 —
 (3)
             
Income Before Income Taxes 131
 998
 1,025
 120
 (2,080) 194
             
Income Tax Expense (319) (2)—
(22) (34) —
 (377)
             
Net (Loss) Income (188) 996
 1,003
 86
 (2,080) (183)
Net Income Attributable to Noncontrolling Interests —
 —
—
—
 —
 (5) (5)
             
Net (Loss) Income Attributable to Controlling Interests (188) 996
 1,003
 86
 (2,085) (188)
             
Preferred Stock Dividends (39) —
—
—
 —
 —
 (39)
Net (Loss) Income Available to Common Stockholders (227) 996
 1,003
 86
 (2,085) (227)
             
Net (Loss) Income $(188) $996
 $1,003
 $86
 $(2,080) $(183)
Total other comprehensive loss (3) (47)—
(32) (31) 110
 (3)
Comprehensive (loss) income (191) 949
 971
 55
 (1,970) (186)
Comprehensive income attributable to noncontrolling interests —
 —
—
—
 —
 (5) (5)
Comprehensive (loss) income attributable to controlling interests $(191) $949
 $971
 $55
 $(1,975) $(191)

Condensed Consolidating Statements of Income and Comprehensive Income
for the Nine Months Ended September 30, 2017
(In Millions)
(Unaudited)

  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Total Revenues $26
 $—
 $8,959
 $1,190
 $(102) $10,073
             
Operating Costs, Expenses and Other            
Costs of sales —
 —
 3,033
 235
 (68) 3,200
Depreciation, depletion and amortization 12
 —
 1,451
 234
 —
 1,697
Other operating expenses 37
 1
 2,065
 375
 (34) 2,444
Total Operating Costs, Expenses and Other 49
 1
 6,549
 844
 (102) 7,341
             
Operating (loss) income (23) (1) 2,410
 346
 —
 2,732
             
Other Income (Expense)            
Earnings from consolidated subsidiaries 2,283
 2,258
 323
 50
 (4,914) —
Earnings from equity investments —
 —
 477
 —
 —
 477
Interest, net (528) 9
 (832) (36) —
 (1,387)
Amortization of excess cost of equity investments and other, net —
 —
 1
 14
 —
 15
             
Income Before Income Taxes 1,732
 2,266
 2,379
 374
 (4,914) 1,837
             
Income Tax Expense (543) (4) (53) (22) —
 (622)
             
Net Income 1,189
 2,262
 2,326
 352
 (4,914) 1,215
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
 (26) (26)
             
Net Income Attributable to Controlling Interests 1,189
 2,262
 2,326
 352
 (4,940) 1,189
             
Preferred Stock Dividends (117) —
 —
 —
 —
 (117)
Net Income Available to Common Stockholders $1,072
 $2,262
 $2,326
 $352
 $(4,940) $1,072
             
Net Income $1,189
 $2,262
 $2,326
 $352
 $(4,914) $1,215
Total other comprehensive income 141
 273
 290
 178
 (692) 190
Comprehensive income 1,330
 2,535
 2,616
 530
 (5,606) 1,405
Comprehensive income attributable to noncontrolling interests —
 —
 —
 —
 (75) (75)
Comprehensive income attributable to controlling interests $1,330
 $2,535
 $2,616
 $530
 $(5,681) $1,330


Condensed Consolidating Statements of Income and Comprehensive Income
for the Nine Months Ended September 30, 2016
(In Millions)
(Unaudited)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Total Revenues $26
 $—
 $8,555
 $1,127
 $(39) $9,669
             
Operating Costs, Expenses and Other            
Costs of sales —
 —
 2,261
 197
 (4) 2,454
Depreciation, depletion and amortization 13
 —
 1,400
 239
 —
 1,652
Other operating expenses 712
 4
 1,644
 600
 (35) 2,925
Total Operating Costs, Expenses and Other 725
 4
 5,305
 1,036
 (39) 7,031
             
Operating (loss) income (699) (4) 3,250
 91
 —
 2,638
             
Other Income (Expense)            
Earnings from consolidated subsidiaries 2,373
 2,335
 174
 45
 (4,927) —
Losses from equity investments —
 —
 (1) —
 —
 (1)
Interest, net (519) 91
 (918) (38) —
 (1,384)
Amortization of excess cost of equity investments and other, net —
 —
 (17) 14
 —
 (3)
             
Income Before Income Taxes 1,155
 2,422
 2,488
 112
 (4,927) 1,250
             
Income Tax Expense (656) (5) (32) (51) —
 (744)
             
Net Income 499
 2,417
 2,456
 61
 (4,927) 506
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
 (7) (7)
             
Net Income Attributable to Controlling Interests 499
 2,417
 2,456
 61
 (4,934) 499
             
Preferred Stock Dividends (117) —
 —
 —
 —
 (117)
Net Income Available to Common Stockholders 382
 2,417
 2,456
 61
 (4,934) 382
             
Net Income $499
 $2,417
 $2,456
 $61
 $(4,927) $506
Total other comprehensive (loss) income (96) (208) (261) 101
 368
 (96)
Comprehensive income 403
 2,209
 2,195
 162
 (4,559) 410
Comprehensive income attributable to noncontrolling interests —
 —
 —
 —
 (7) (7)
Comprehensive income attributable to controlling interests $403
 $2,209
 $2,195
 $162
 $(4,566) $403



Condensed Consolidating Balance Sheets as of September 30, 2017
(In Millions)
(Unaudited)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 
Consolidating
Adjustments
 Consolidated KMI
ASSETS            
Cash and cash equivalents $11
 $—
 $—
 $534
 $(6) $539
Other current assets - affiliates 11,645
 6,008
 16,883
 800
 (35,336) —
All other current assets 107
 78
 1,680
 213
 (4) 2,074
Property, plant and equipment, net 243
 —
 30,976
 8,648
 —
 39,867
Investments 665
 —
 6,688
 131
 —
 7,484
Investments in subsidiaries 26,686
 28,372
 5,304
 4,012
 (64,374) —
Goodwill 13,789
 22
 5,167
 3,186
 —
 22,164
Notes receivable from affiliates 1,043
 20,776
 1,362
 493
 (23,674) —
Deferred income taxes 5,802
 —
 —
 —
 (2,370) 3,432
Other non-current assets 217
 184
 4,208
 182
 —
 4,791
Total assets $60,208
 $55,440

$72,268

$18,199

$(125,764)
$80,351
             
LIABILITIES AND STOCKHOLDERS’ EQUITY            
Liabilities            
Current portion of debt $1,119
 $975
 $806
 $256
 $—
 $3,156
Other current liabilities - affiliates 7,808
 16,531
 10,313
 684
 (35,336) —
All other current liabilities 400
 158
 1,966
 504
 (10) 3,018
Long-term debt 13,121
 18,270
 3,059
 666
 —
 35,116
Notes payable to affiliates 1,856
 448
 21,015
 355
 (23,674) —
Deferred income taxes —
 —
 727
 1,643
 (2,370) —
All other long-term liabilities and deferred credits 679
 102
 1,291
 465
 —
 2,537
     Total liabilities 24,983
 36,484

39,177

4,573

(61,390)
43,827
             
Stockholders’ equity            
Total KMI equity 35,225
 18,956
 33,091
 13,626
 (65,673) 35,225
Noncontrolling interests —
 —
 —
 —
 1,299
 1,299
Total stockholders’ Equity 35,225
 18,956

33,091

13,626

(64,374)
36,524
Total Liabilities and Stockholders’ Equity $60,208
 $55,440

$72,268

$18,199

$(125,764)
$80,351


Condensed Consolidating Balance Sheets as of December 31, 2016
(In Millions)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 
Consolidating
Adjustments
 Consolidated KMI
ASSETS            
Cash and cash equivalents $471
 $—
 $9
 $205
 $(1) $684
Other current assets - affiliates 5,739
 1,999
 13,207
 655
 (21,600) —
All other current assets 269
 139
 1,935
 205
 (3) 2,545
Property, plant and equipment, net 242
 —
 30,795
 7,668
 —
 38,705
Investments 665
 2
 6,236
 124
 —
 7,027
Investments in subsidiaries 26,907
 29,421
 4,307
 4,028
 (64,663) —
Goodwill 13,789
 22
 5,167
 3,174
 —
 22,152
Notes receivable from affiliates 516
 21,608
 1,132
 412
 (23,668) —
Deferred income taxes 6,647
 —
 —
 —
 (2,295) 4,352
Other non-current assets 72
 206
 4,455
 107
 —
 4,840
Total assets $55,317
 $53,397

$67,243

$16,578

$(112,230)
$80,305
             
LIABILITIES AND STOCKHOLDERS’ EQUITY            
Liabilities            
Current portion of debt $1,286
 $600
 $687
 $123
 $—
 $2,696
Other current liabilities - affiliates 3,551
 13,299
 4,197
 553
 (21,600) —
All other current liabilities 432
 362
 2,016
 422
 (4) 3,228
Long-term debt 13,308
 19,277
 4,095
 674
 —
 37,354
Notes payable to affiliates 1,533
 448
 20,520
 1,167
 (23,668) —
Deferred income taxes —
 —
 681
 1,614
 (2,295) —
Other long-term liabilities and deferred credits 776
 111
 821
 517
 —
 2,225
     Total liabilities 20,886
 34,097

33,017

5,070

(47,567)
45,503
             
Stockholders’ equity            
Total KMI equity 34,431
 19,300
 34,226
 11,508
 (65,034) 34,431
Noncontrolling interests —
 —
 —
 —
 371
 371
Total stockholders’ Equity 34,431

19,300

34,226

11,508

(64,663)
34,802
Total Liabilities and Stockholders’ Equity $55,317
 $53,397

$67,243

$16,578

$(112,230)
$80,305

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2017
(In Millions)
(Unaudited)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Net cash (used in) provided by operating activities $(2,191) $2,925
 $8,718
 $657
 $(6,802) $3,307
             
Cash flows from investing activities            
Acquisitions of assets and investments, net of cash acquired —
 —
 (4) —
 —
 (4)
Capital expenditures (18) —
 (1,699) (514) —
 (2,231)
Sales of property, plant and equipment, and other net assets, net of removal costs 7
 —
 98
 13
 —
 118
Contributions to investments (215) —
 (408) (8) —
 (631)
Distributions from equity investments in excess of cumulative earnings 1,525
 —
 223
 —
 (1,496) 252
Funding (to) from affiliates (3,658) 639
 (5,533) (567) 9,119
 —
Other, net (16) 24
 4
 (2) —
 10
Net cash (used in) provided by investing activities (2,375) 663

(7,319)
(1,078)
7,623

(2,486)
             
Cash flows from financing activities            
Issuances of debt 7,570
 —
 —
 220
 —
 7,790
Payments of debt (8,053) (600) (895) (106) —
 (9,654)
Debt issue costs (12) —
 —
 (57) —
 (69)
Cash dividends - common shares (840) —
 —
 —
 —
 (840)
Cash dividends - preferred shares (117) —
 —
 —
 —
 (117)
Funding from (to) affiliates 5,563
 749
 3,197
 (390) (9,119) —
Contributions from investment partner —
 —
 444
 —
 —
 444
Contributions from parents, including net proceeds from KML IPO and preferred share issuance —
 —
 —
 1,483
 (1,483) —
Contributions from noncontrolling interests - net proceeds from KML IPO 4
 —
—
—
 —
 1,241
 1,245
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance —
 —
 —
 —
 230
 230
Contributions from noncontrolling interests - other —
 —
 —
 —
 12
 12
Distributions to parents —
 (3,737) (4,154) (428) 8,319
 —
Distributions to noncontrolling interests —
 —
 —
 —
 (26) (26)
Other, net (9) —
 —
 —
 —
 (9)
Net cash provided by (used in) financing activities 4,106
 (3,588)
(1,408)
722

(826)
(994)
             
Effect of exchange rate changes on cash and cash equivalents —
 —
 —
 28
 —
 28
             
Net (decrease) increase in cash and cash equivalents (460) —

(9)
329

(5)
(145)
Cash and cash equivalents, beginning of period 471
 —
 9
 205
 (1) 684
Cash and cash equivalents, end of period $11
 $—

$—

$534

$(6)
$539

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2016
(In Millions)
(Unaudited)
  Parent
Issuer and
Guarantor		 Subsidiary
Issuer and
Guarantor -
KMP		 Subsidiary
Guarantors		 Subsidiary
Non-Guarantors		 Consolidating Adjustments Consolidated KMI
Net cash (used in) provided by operating activities $(3,015) $3,903
 $8,778
 $681
 $(6,844) $3,503
             
Cash flows from investing activities            
Acquisitions of assets and investments, net of cash acquired (2) —
 (331) —
 —
 (333)
Capital expenditures (39) —
 (1,550) (520) —
 (2,109)
Proceeds from sale of equity interests in subsidiaries, net —
 —
 1,402
 —
 —
 1,402
Sales of property, plant and equipment, and other net assets, net of removal costs —
 —
 250
 —
 —
 250
Contributions to investments (343) —
 (36) (10) —
 (389)
Distributions from equity investments in excess of cumulative earnings 1,773
 298
 127
 —
 (2,040) 158
Funding to affiliates (2,354) (495) (3,650) (529) 7,028
 —
Other, net —
 (52) 37
 (11) —
 (26)
Net cash used in investing activities (965) (249)
(3,751)
(1,070)
4,988
 (1,047)
             
Cash flows from financing activities            
Issuances of debt 8,111
 —
 374
 —
 —
 8,485
Payments of debt (7,178) (500) (1,449) (8) —
 (9,135)
Restricted cash held in escrow for debt repayment —
 —
—
(776) —
 —
 (776)
Debt issue costs (13) —
 (1) (1) —
 (15)
Cash dividends - common shares (839) —
 —
 —
 —
 (839)
Cash dividends - preferred shares (115) —
 —
 —
 —
 (115)
Funding from affiliates 4,070
 973
 1,539
 446
 (7,028) —
Contributions from parents —
 —
 88
 —
 (88) —
Contributions from noncontrolling interests —
 —
 —
 —
 88
 88
Distributions to parents —
 (4,127) (4,801) (14) 8,942
 —
Distributions to noncontrolling interests —
 —
 —
 —
 (17) (17)
Other, net (8) —
 —
 —
 —
 (8)
Net cash provided by (used in) financing activities 4,028
 (3,654) (5,026)
423

1,897
 (2,332)
             
Effect of exchange rate changes on cash and cash equivalents —
 —
 —
 4
 —
 4
             
Net increase in cash and cash equivalents 48

—

1

38

41
 128
Cash and cash equivalents, beginning of period 123
 —
 12
 142
 (48) 229
Cash and cash equivalents, end of period $171

$—

$13

$180

$(7) $357

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

General and Basis of Presentation

The following discussion and analysis should be read in conjunction with our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes andin our 2021 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 20162021 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2021 Form 10-K; and (iv) “Risk Factors” in Part I, Item 1A of our 2021 Form 10-K.


Sale of Approximate 30% Interest in our Canadian BusinessElba Liquefaction Company L.L.C.


On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million. The net proceeds of C$1,677 million (USD $1,245 million) from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business with us retaining the remaining 70% interest. We used the proceeds from KML to pay down debt.
Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017.
The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Products Pipelines business segments and included the Trans Mountain Pipeline system (including related terminals assets), Trans Mountain Expansion Project, the Puget Sound and Jet Fuel Pipeline systems, the Canadian portion of the Cochin Pipeline system, the Vancouver Wharves Terminal and the North 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal.

In addition, upon completion of the IPO, we announced our final investment decision for the Trans Mountain Expansion Project. Construction on the Trans Mountain Expansion Project, a C$7.4 billion project, began in September 2017 with completion expected in December 2019.

Sale of Equity Interest in SNG

On September 1, 2016,27, 2022, we completed the sale of a 50%25.5% ownership interest in our SNG natural gas pipeline system to The SouthernElba Liquefaction Company (Southern Company), receivingL.L.C. (ELC). We received net proceeds of $1.4 billion, and the formation of$557 million which were used to reduce short-term borrowings. As we continue to have a joint venture, which includes our remaining 50%controlling financial interest in SNG. We usedand consolidate ELC, we recorded an increase of $190 million to “Additional paid in capital” for the proceeds fromimpact of the sale to reduce outstanding debt. We recognized a pre-tax loss of $84 million on the sale ofchange in our ownership interest in SNGELC, which is included within “Lossreflected on impairments and divestitures, net” on theour accompanying consolidated statements of incomestockholders’ equity for the three and nine months ended September 30, 2016. As2022. We continue to own a result of this transaction, we no longer hold a controlling25.5% interest in SNGand operate ELC. See Note 2 “Acquisitions and Divestitures” for additional information regarding ELC.

North American Natural Resources Acquisition

On August 11, 2022, we completed the acquisition of seven landfill assets from North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR) consisting of gas-to-power facilities in Michigan and Kentucky for $132 million, including a preliminary purchase price adjustment for working capital. We plan to convert three of the seven gas-to-power facilities to renewable natural gas facilities with a capital spend of approximately $145 million. We expect these facilities to be in service by mid-2024 and, once complete, are expected to generate approximately 1.7 Bcf per year of renewable natural gas. The remaining four NANR assets, projected to produce 8.0 megawatt-hours in 2023, further diversify KMI’s renewable portfolio by adding electricity generation to its landfill gas-to-power operations.

Mas CanAm Acquisition

On July 19, 2022, we completed an acquisition of three landfill assets from Mas CanAm, LLC, comprising a renewable natural gas facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for $358 million including a preliminary purchase price adjustment for working capital. The Arlington facility is expected to produce 1.4 Bcf of renewable natural gas in 2023 and has the potential to grow significantly over the next decade.

2022 Dividends and Discretionary Capital

We expect to declare dividends of $1.11 per share for 2022, a 3% increase from the 2021 declared dividends of $1.08 per share. We now expect to invest $1.8 billion in expansion projects, acquisitions, and contributions to joint ventures or Bear Creek Storage Company, LLC (Bear Creek) (50%discretionary capital expenditures during 2022.

The expectations for 2022 discussed above involve risks, uncertainties and assumptions, and are not guarantees of whichperformance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is owned by SNG) and, as such, we now account for our remaining equity interests in SNG and Bear Creek as equity investments.advisable not to put undue reliance on any forward-looking statement.


Results of Operations

Overview


OurAs described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 8 “Reportable Segments”) and as discussed below under “—Non-GAAP Measures,” distributable cash flow, orNet 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, before certain items.Adjusted EBITDA and Net Debt.

32

GAAP Financial Measures

The Consolidated Earnings Results for the three and nine months ended September 30, 2022 and 2021 present Segment EBDA and Net 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.

Segment results for the three and nine months ended September 30, 2016 have been retrospectively adjusted to reflect the elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within Corporate non-segment activities in reconciling to the consolidated totals in the respective segment reporting

tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest income and income tax expense previously allocated to our business segments are now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables.
Consolidated Earnings Results

 Three Months Ended September 30,  
 2017 2016 Earnings
increase/(decrease)
 (In millions, except percentages)
Segment EBDA(a)       
Natural Gas Pipelines$884
 $542
 $342
 63 %
CO2
197
 217
 (20) (9)%
Terminals314
 294
 20
 7 %
Products Pipelines302
 292
 10
 3 %
Kinder Morgan Canada50
 48
 2
 4 %
Total Segment EBDA(b)1,747
 1,393
 354
 25 %
DD&A(562) (549) (13) (2)%
Amortization of excess cost of equity investments(15) (15) —
 — %
General and administrative and corporate charges(c)(164) (163) (1) (1)%
Interest, net(d)(459) (472) 13
 3 %
Income before income taxes547
 194
 353
 182 %
Income tax expense(160) (377) 217
 58 %
Net income (loss)387
 (183) 570
 311 %
Net income attributable to noncontrolling interests(14) (5) (9) (180)%
Net income (loss) attributable to Kinder Morgan, Inc.373
 (188) 561
 298 %
  Preferred Stock Dividends(39) (39) —
 — %
Net income (loss) available to common stockholders$334
 $(227) $561
 247 %


 Nine Months Ended September 30,  
 2017 2016 Earnings
increase/(decrease)
 (In millions, except percentages)
Segment EBDA(a)       
Natural Gas Pipelines$2,846
 $2,503
 $343
 14 %
CO2
636
 608
 28
 5 %
Terminals925
 856
 69
 8 %
Products Pipelines913
 761
 152
 20 %
Kinder Morgan Canada136
 140
 (4) (3)%
Total Segment EBDA(b)5,456
 4,868
 588
 12 %
DD&A(1,697) (1,652) (45) (3)%
Amortization of excess cost of equity investments(45) (45) —
 — %
General and administrative and corporate charges(c)(490) (537) 47
 9 %
Interest, net(d)(1,387) (1,384) (3) — %
Income before income taxes1,837
 1,250
 587
 47 %
Income tax expense(622) (744) 122
 16 %
Net income1,215
 506
 709
 140 %
Net income attributable to noncontrolling interests(26) (7) (19) (271)%
Net income attributable to Kinder Morgan, Inc.1,189
 499
��690
 138 %
  Preferred Stock Dividends(117) (117) —
 — %
Net income available to common stockholders$1,072
 $382
 $690
 181 %

_______
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, other expense (income), net, losses on impairments and divestitures, net and losses on impairments and divestitures of equity investments, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
Certain items affecting Total Segment EBDA (see “—Non-GAAP Measures” below)
(b)Three and nine month 2017 amounts include a net decrease in earnings of $46 million and increase in earnings of $33 million, respectively, and three and nine month 2016 amounts include net decreases in earnings of $429 million and $740 million, respectively, related to the combined effect of the certain items impacting Total Segment EBDA. The extent to which these items affect each of our business segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”
(c)Three and nine month 2017 amounts include increases in expense of $5 million and $8 million, respectively, and nine month 2016 amount includes net increases in expense of $24 million related to the combined effect of the certain items related to general and administrative expense and corporate charges disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
(d)Three and nine month 2017 amounts include net decreases in expense of $4 million and $21 million, respectively, and three and nine month 2016 amounts include net decreases in expense of $31 million and $140 million, respectively, related to the combined effect of the certain items related to interest expense, net of interest income disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

The certain item totals reflected in footnotes (b), (c), and (d) to the table above accounted for $351 million of the increase in income before income taxes for the third quarter of 2017, as compared to the same prior year period (representing the difference between the decreases of $47 million and $398 million, respectively, in income before income taxes for the third quarters of 2017 and 2016, respectively) and an increase of $670 million in income before income taxes for the nine months ended September 30, 2017, when compared to the same prior year period (representing the difference between an increase of $46 million and a decrease of $624 million in income before income taxes for the nine months ended September 30, 2017 and 2016, respectively). After giving effect to these certain items, the remaining increase in income before income taxes from the prior year quarter was $2 million (0%) and the remaining decrease in income before income taxes year-to-date was $83 million (4%). The quarter-to-date increase from 2016 is primarily attributable to decreased interest expense partially offset by decreased performance from our Natural Gas Pipelines business segment, largely associated with our sale of a 50% interest in SNG to The Southern Company on September 1, 2016, and increased DD&A expense. The year-to-date decrease from 2016 is primarily attributable to decreased performance from our Natural Gas Pipelines business segment, largely associated with our sale of a 50% interest in SNG to The Southern Company on September 1, 2016, and increased DD&A expense partially offset by decreased general and administrative expense and by decreased interest expense.


Non-GAAP Financial Measures


Our non-GAAP performancefinancial measures are DCF, bothdescribed below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the aggregatelimitations of these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and per share,taking this information into account in its analysis and Segment EBDA before certain items. its decision making processes.

Certain itemsItems

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in netNet income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and 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, hurricane impactsenactment of new tax legislation and casualty losses). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,”“—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below). In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.


Our non-GAAP performance measures described below should not be considered alternativesAdjusted Earnings

Adjusted Earnings is calculated by adjusting Net income attributable to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measuresKinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by others. You should not consider these non-GAAP performance measures in isolation or as substitutes for an analysisus and certain external users of our resultsfinancial statements to assess the earnings of our business excluding Certain Items as reported under GAAP.another reflection of our ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net 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 share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting Net 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 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. Management compensates for the limitations of these non-GAAP performance measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

Distributable Cash Flow

DCF is a significant performance measure used by us and by external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate cash earnings after servicing our debt and preferred stock dividends, 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. Management uses this performance measure and believes it provides users of our financial statements a useful performance measure reflective of our business’s ability to generate cash earnings to supplement the comparable GAAP measure. We believe the GAAP measure most directly comparable to DCF is netNet income availableattributable to common stockholders. A reconciliation of DCF to net income available to common stockholders is provided in the table below.Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends.

See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” and “—Non-GAAP Financial Measures—Adjusted Segment EBDA Beforeto Adjusted EBITDA to DCF” below.

33

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items

attributable to the segment. Adjusted Segment EBDA before certain items is used by management in its analysis of segment performance and management of our business. General and administrative expenses are generally not under the control of our segment operating managers, and therefore, are not included when we measure business segment operating performance. We believe Adjusted Segment EBDA before certain items is a significantuseful performance metric because it provides usmanagement 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 performance 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 before certain items is segment earnings before DD&A and amortization of excess cost of equity investments (Segment EBDA).

In the tables for each of our business segments under “— Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” below, for a reconciliation of Segment EBDA before certain itemsto Adjusted Segment EBDA by business segment.

Adjusted EBITDA

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

Amounts from Joint Ventures

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

Net Debt

Net Debt is calculated, based on amounts as of September 30, 2022, by subtracting the following amounts from our debt balance of $31,741 million: (i) cash and cash equivalents of $483 million; and (ii) debt fair value adjustments of $107 million; and excluding the foreign exchange impact on Euro-denominated bonds of $(53) million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt is a non-GAAP financial measure that management believes 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.

34

Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.
Three Months Ended
September 30,
20222021Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$1,135$1,069$666%
Products Pipelines257279(22)(8)%
Terminals2402162411%
CO2
2151635232%
Total Segment EBDA1,8471,7271207%
DD&A(551)(526)(25)(5)%
Amortization of excess cost of equity investments(19)(21)210%
General and administrative and corporate charges(149)(167)1811%
Interest, net(399)(368)(31)(8)%
Income before income taxes7296458413%
Income tax expense(134)(134)——%
Net income5955118416%
Net income attributable to noncontrolling interests(19)(16)(3)(19)%
Net income attributable to Kinder Morgan, Inc.$576$495$8116%

Nine Months Ended
September 30,
20222021Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$3,453 $2,602 $851 33 %
Products Pipelines855 792 63 8 %
Terminals731 689 42 6 %
CO2
619 599 20 3 %
Total Segment EBDA5,658 4,682 976 21 %
DD&A(1,632)(1,595)(37)(2)%
Amortization of excess cost of equity investments(57)(56)(1)(2)%
General and administrative and corporate charges(438)(465)27 6 %
Interest, net(1,087)(1,122)35 3 %
Income before income taxes2,444 1,444 1,000 69 %
Income tax expense(512)(248)(264)(106)%
Net income1,932 1,196 736 62 %
Net income attributable to noncontrolling interests(54)(49)(5)(10)%
Net income attributable to Kinder Morgan, Inc.$1,878 $1,147 $731 64 %
(a)Includes revenues, earnings from equity investments, operating expenses, (gain) loss on divestitures and describedimpairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

Net income attributable to Kinder Morgan, Inc. increased $81 million and $731 million for the three and nine months ended September 30, 2022, respectively, as compared to the respective prior year periods. The third quarter increase was
35

primarily due to higher earnings from our Natural Gas Pipelines and CO2 business segments. The year-to-date increase was primarily due to the $1,600 million pre-tax non-cash impairment loss in 2021 related to South Texas gathering and processing assets within our Natural Gas Pipeline segment and higher earnings from our Products Pipelines business segment with our West Coast Refined Products and Southeast Refined Products assets partially offset by the benefit in the 2021 period of $1,097 million for largely nonrecurring earnings related to the February 2021 winter storm, mostly impacting the earnings from our Natural Gas Pipelines and CO2 business segments.

Certain Items Affecting Consolidated Earnings Results


Three Months Ended September 30,
20222021
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$1,135 $24 $1,159 $1,069 $21 $1,090 $69 
Products Pipelines257— 257 279 1 280 (23)
Terminals240 — 240 216 17 233 7 
CO2
215 (20)195 163 (9)154 41 
Total Segment EBDA(a)1,847 4 1,851 1,727 30 1,757 94 
DD&A and amortization of excess cost of equity investments(570)— (570)(547)— (547)(23)
General and administrative and corporate charges(a)(149)— (149)(167)— (167)18 
Interest, net(a)(399)15 (384)(368)(8)(376)(8)
Income before income taxes729 19 748 645 22 667 81 
Income tax expense(b)(134)(20)(154)(134)(12)(146)(8)
Net income595 (1)594 511 10 521 73 
Net income attributable to noncontrolling interests(19)— (19)(16)— (16)(3)
Net income attributable to Kinder Morgan, Inc.$576 $(1)$575 $495 $10 $505 $70 


36

Nine Months Ended September 30,
20222021
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$3,453 $136 $3,589 $2,602 $1,646 $4,248 $(659)
Products Pipelines855 — 855 792 44 836 19 
Terminals731 — 731 689 17 706 25 
CO2
619 (5)614 599 (3)596 18 
Total Segment EBDA(a)5,658 131 5,789 4,682 1,704 6,386 (597)
DD&A and amortization of excess cost of equity investments(1,689)— (1,689)(1,651)— (1,651)(38)
General and administrative and corporate charges(a)(438)— (438)(465)— (465)27 
Interest, net(a)(1,087)(46)(1,133)(1,122)(17)(1,139)6 
Income before income taxes2,444 85 2,529 1,444 1,687 3,131 (602)
Income tax expense(b)(512)(35)(547)(248)(439)(687)140 
Net income1,932 50 1,982 1,196 1,248 2,444 (462)
Net income attributable to noncontrolling interests(a)(54)— (54)(49)— (49)(5)
Net income attributable to Kinder Morgan, Inc.$1,878 $50 $1,928 $1,147 $1,248 $2,395 $(467)
(a)For a more detailed discussion of Certain Items, see the footnotes to those tables.the tables within “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.

(b)The combined net effect of the income tax Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

Net income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) increased by $70 million for the three months ended September 30, 2022 and decreased by $467 million for the nine months ended September 30, 2022 as compared to the respective prior year periods. The third quarter increase was primarily due to higher earnings from our Natural Gas Pipeline and CO2 business segments. The year-to-date decrease was impacted by lower earnings of $744 million from our Natural Gas Pipelines business segment’s Midstream region (primarily related to the February 2021 winter storm, and therefore largely nonrecurring) partially offset by lower income tax expense.

37

Non-GAAP Financial Measures

Reconciliation of Net Income AvailableAttributable to Common StockholdersKinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Net income attributable to Kinder Morgan, Inc. (GAAP)$576 $495 $1,878 $1,147 
Total Certain Items(1)10 50 1,248 
Adjusted Earnings(a)575 505 1,928 2,395 
DD&A and amortization of excess cost of equity investments for DCF(b)647 612 1,897 1,854 
Income tax expense for DCF(a)(b)167 165 601 754 
Cash taxes(b)(15)(12)(63)(56)
Sustaining capital expenditures(b)(243)(241)(581)(558)
Other items(c)(9)(16)(29)(22)
DCF$1,122 $1,013 $3,753 $4,367 

Adjusted Segment EBDA to Adjusted EBITDA to DCF
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except per share amounts)
Natural Gas Pipelines$1,159 $1,090 $3,589 $4,248 
Products Pipelines257 280 855 836 
Terminals240 233 731 706 
CO2
195 154 614 596 
Adjusted Segment EBDA(a)1,851 1,757 5,789 6,386 
General and administrative and corporate charges(a)(149)(167)(438)(465)
Joint venture DD&A and income tax expense(a)(b)90 84 262 270 
Net income attributable to noncontrolling interests(a)(19)(16)(54)(49)
Adjusted EBITDA1,773 1,658 5,559 6,142 
Interest, net(a)(384)(376)(1,133)(1,139)
Cash taxes(b)(15)(12)(63)(56)
Sustaining capital expenditures(b)(243)(241)(581)(558)
Other items(c)(9)(16)(29)(22)
DCF$1,122 $1,013 $3,753 $4,367 
Adjusted Earnings per share$0.25 $0.22 $0.85 $1.05 
Weighted average shares outstanding for dividends(d)2,267 2,279 2,275 2,278 
DCF per share$0.49 $0.44 $1.65 $1.92 
Declared dividends per share$0.2775 $0.27 $0.8325 $0.81 
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.
(b)Includes or represents DD&A, income tax expense, cash taxes and/or sustaining capital expenditures (as applicable for each item) from joint ventures. See tables included in “—Supplemental Information” below.
(c)Includes pension contributions, non-cash pension expense and non-cash compensation associated with our restricted stock program.
(d)Includes restricted stock awards that participate in dividends.
38

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In millions, except per share amounts)
Net Income (Loss) Available to Common Stockholders$334
 $(227) $1,072
 $382
Add/(Subtract):       
Certain items before book tax(a)47
 398
 (46) 624
Book tax certain items(b)(53) 172
 (24) 70
Certain items after book tax(6) 570
 (70) 694
        
Noncontrolling interest certain items(c)—
 —
 1
 (9)
Net income available to common stockholders before certain items328
 343
 1,003
 1,067
Add/(Subtract):       
DD&A expense(d)661
 653
 2,018
 1,961
Total book taxes(e)244
 230
 730
 745
Cash taxes(f)(9) (22) (54) (61)
Other items(g)(13) 11
 11
 31
Sustaining capital expenditures(h)(156) (134) (416) (379)
DCF$1,055
 $1,081
 $3,292
 $3,364
        
Weighted average common shares outstanding for dividends(i)2,241
 2,239
 2,240
 2,237
DCF per common share$0.47
 $0.48
 $1.47
 $1.50
Declared dividend per common share$0.125
 $0.125
 $0.375
 $0.375
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA
_______
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Net income attributable to Kinder Morgan, Inc. (GAAP)$576 $495 $1,878 $1,147 
Certain Items:
Fair value amortization(4)(7)(11)(15)
Legal, environmental and taxes other than income tax reserves23 — 23 112 
Change in fair value of derivative contracts(a)(6)22 49 64 
Loss on impairments, divestitures and other write-downs, net(b)— 4 — 1,515 
Income tax Certain Items(20)(12)(35)(439)
Other6 3 24 11 
Total Certain Items(c)(1)10 50 1,248 
DD&A and amortization of excess cost of equity investments570 547 1,689 1,651 
Income tax expense(d)154 146 547 687 
Joint venture DD&A and income tax expense(d)(e)90 84 262 270 
Interest, net(d)384 376 1,133 1,139 
Adjusted EBITDA$1,773 $1,658 $5,559 $6,142 
(a)
Consists of certain items summarized in footnotes (b) through (d) to the “—Results of Operations—Consolidated Earnings Results” tables included above, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
(a)Gains or losses are reflected in our DCF when realized.
(b)Nine months ended September 30, 2021 amount includes a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment reported within “(Gain) loss on divestitures and impairments, net” and a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings LLC, offset partially by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, reported within “Other, net” and “Earnings from equity investments,” respectively, on the accompanying consolidated statement of income.
(c)Three months ended September 30, 2022 and 2021 amounts include less than $1 million and $2 million, respectively, and nine months ended September 30, 2022 and 2021 amounts include $4 million and $129 million, respectively, reported within “Earnings from equity investments” on our consolidated statements of income.
(d)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
(e)Represents joint venture DD&A and income tax expense. See tables included in “—Supplemental Information” below.

39

Supplemental Information
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
DD&A (GAAP)$551 $526 $1,632 $1,595 
Amortization of excess cost of equity investments (GAAP)19 21 57 56 
DD&A and amortization of excess cost of equity investments570 547 1,689 1,651 
Joint venture DD&A77 65 208 203 
DD&A and amortization of excess cost of equity investments for DCF$647 $612 $1,897 $1,854 
Income tax expense (GAAP)$134 $134 $512 $248 
Certain Items20 12 35 439 
Income tax expense(a)154 146 547 687 
Unconsolidated joint venture income tax expense(a)(b)13 19 54 67 
Income tax expense for DCF(a)$167 $165 $601 $754 
Additional joint venture information
Unconsolidated joint venture DD&A$89 $76 $242 $236 
Less: Consolidated joint venture partners’ DD&A12 11 34 33 
Joint venture DD&A77 65 208 203 
Unconsolidated joint venture income tax expense(a)(b)13 19 54 67 
Joint venture DD&A and income tax expense(a)$90 $84 $262 $270 
Unconsolidated joint venture cash taxes(b)$(12)$(13)$(51)$(47)
Unconsolidated joint venture sustaining capital expenditures$(38)$(29)$(89)$(81)
Less: Consolidated joint venture partners’ sustaining capital expenditures(2)(2)(6)(5)
Joint venture sustaining capital expenditures$(36)$(27)$(83)$(76)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments.

40

(b)Represents income tax provision on certain items, plus discrete income tax certain items. For the three and nine months ended September 30, 2017, discrete income tax items included a $36 million federal return-to-provision tax benefit as a result of the recognition of an enhanced oil recovery credit instead of deduction. For the three and nine months ended September 30, 2016, discrete income tax items included a $276 million increase in tax expense primarily due to the impact of the sale of a 50% interest in SNG discussed in Note 8 “Income Taxes” to our consolidated financial statements.
(c)Represents noncontrolling interests share of certain items.
(d)Includes DD&A and amortization of excess cost of equity investments. Three and nine month 2017 amounts also include $84 million and $276 million, respectively, and three and nine month 2016 amounts also include $89 million and $264 million, respectively, of our share of certain equity investees' DD&A, net of the DD&A associated with noncontrolling interests in KML and consolidating joint venture partners’ share of DD&A.
(e)Excludes book tax certain items. Three and nine month 2017 amounts also include $31 million and $84 million, respectively, and three and nine month 2016 amounts also include $25 million and $71 million, respectively, of our share of taxable equity investees’ book tax expense.
(f)Three and nine month 2017 amounts also include $(9) million and $(54) million, respectively, and three and nine month 2016 amounts include $(25) million and $(59) million, respectively, of our share of taxable equity investees’ cash taxes.

(g)Amounts include non-cash compensation associated with our restricted stock program. Three and nine months ended September 30, 2017 also include a pension contribution and the noncontrolling interest portion of KML’s book taxes.
(h)Three and nine month 2017 amounts include $(29) million and $(74) million, respectively, and three and nine month 2016 amounts include $(24) million and $(66) million, respectively, of our share of equity investees’ sustaining capital expenditures.
(i)Includes restricted stock awards that participate in common share dividends.

Segment Earnings Results


Natural Gas Pipelines
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In millions, except operating statistics)
Revenues(a)$2,024
 $2,050
 $6,290
 $5,904
Operating expenses(1,262) (1,199) (3,846) (3,142)
Loss on impairments and divestitures, net(b)(27) (78) (27) (199)
Earnings from equity investments(b)134
 111
 389
 273
Loss on impairments of equity investments(b)—
 (350) —
 (356)
Other, net15
 8
 40
 23
Segment EBDA(b)884
 542
 2,846
 2,503
Certain items(b)44
 417
 6
 547
Segment EBDA before certain items$928
 $959
 $2,852
 $3,050
        
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(16) (1)% $381
 6 %
Segment EBDA before certain items$(31) (3)% $(198) (6)%
        
Natural gas transport volumes (BBtu/d)(c)28,879
 28,144
 28,796
 28,162
Natural gas sales volumes (BBtu/d)(c)2,181
 2,438
 2,329
 2,350
Natural gas gathering volumes (BBtu/d)(c)2,523
 2,935
 2,635
 3,044
Crude/condensate gathering volumes (MBbl/d)(c)271
 270
 268
 300
_______
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except operating statistics)
Revenues$3,505 $2,555 $9,674 $8,656 
Operating expenses(2,548)(1,634)(6,706)(4,981)
Gain (loss) on divestitures and impairments, net8 — 8 (1,599)
Other income— — 2 2 
Earnings from equity investments168 144 471 311 
Other, net2 4 4 213 
Segment EBDA1,135 1,069 3,453 2,602 
Certain Items(a)24 21 136 1,646 
Adjusted Segment EBDA$1,159 $1,090 $3,589 $4,248 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$69 $(659)
Volumetric data(b)
Transport volumes (BBtu/d)38,637 38,527 38,726 38,593 
Sales volumes (BBtu/d)2,469 2,616 2,521 2,480 
Gathering volumes (BBtu/d)3,179 2,808 2,999 2,662 
NGLs (MBbl/d)24 29 29 30 
Certain itemsItems affecting Segment EBDA
(a)Three and nine month 2017 amounts include decreases in revenue of $12 million and increases in revenue of $10 million, respectively, and three and nine month 2016 amounts include decreases in revenue of $2 million and $34 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. Nine month 2016 amount also includes an increase in revenue of $39 million associated with revenue collected on a customer’s early buyout of a long-term natural gas storage contract.
(b)In addition to the revenue certain items described in footnote (a) above: three and nine month 2017 amounts also include (i) decreases in earnings of $30 million for both periods related to a non-cash impairment loss associated with the Colden storage field; (ii) increases in earnings from our equity investment in EagleHawk of $12 million for both periods related to a customer contract settlement; (iii) decreases in earnings of $7 million and $12 million, respectively, related to early termination of debt at an equity investee; and (iv) decreases in earnings of $7 million and $8 million, respectively, from other certain items. Also, nine month 2017 amount includes an increase in earnings from equity investments of $22 million on the sale of a claim related to the early termination of a long-term natural gas transportation contract of an equity investee as a result of a customer bankruptcy proceeding, and three and nine month 2016 amounts also include (i) a $350 million impairment of our equity investment in MEP; (ii) an $84 million pre-tax loss on the sale of a 50% interest in our SNG natural gas pipeline system; (iii) an increase in earnings of $18 million related to the early termination of a customer contract at an equity investee; and (iv) an increase in earnings of $1 million and a decrease in earnings $17 million, respectively, from other certain items. Nine month 2016 amount also includes decreases in earnings of (i) $106 million of project write-offs; and (ii) $13 million related to an equity investment impairment.
(a)Three months ended September 30, 2022 amount includes an increase in revenues of $51 million and an increase in costs of sales of $47 million, and nine months ended September 30, 2022 amount includes an increase in revenues of $48 million and an increase in costs of sales of $133 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales and purchases. Three and nine months ended September 30, 2022 amounts also include an increase in other operating expenses of $23 million related to a certain litigation matter and $6 million and $24 million, respectively, related to costs associated with a pipeline rupture. Three and nine months ended September 30, 2021 amounts include decreases in revenues of $14 million and $36 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash asset impairment loss of $1,600 million related to our South Texas gathering and processing assets, a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a litigation reserve partially offset by a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings.
Other
(c)Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the entire period, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

(b)Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included and volumes for assets sold are excluded for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.


41

Below are the changes in bothAdjusted Segment EBDA before certain items and revenues before certain items, in the comparable three and nine monthnine-month periods ended September 30, 20172022 and 2016:2021:


Three months endedMonths Ended September 30, 20172022 versus Three months endedMonths Ended September 30, 20162021

 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
SNG$(49) (62)% $(85) (91)%
South Texas Midstream(18) (26)% (21) (8)%
CIG(12) (20)% (11) (14)%
Hiland Midstream(5) (10)% 29
 21 %
TGP23
 9 % 29
 8 %
Elba Express11
 50 % 13
 59 %
EPNG11
 10 % 6
 4 %
Texas Intrastate Natural Gas Pipeline Operations—
 — % 12
 2 %
All others (including eliminations)8
 4 % 12
 6 %
Total Natural Gas Pipelines$(31) (3)% $(16) (1)%
Adjusted Segment EBDA
20222021increase/
(decrease)
Midstream$351 $289 $62 
East595 577 18 
West213 224 (11)
Total Natural Gas Pipelines$1,159 $1,090 $69 


Nine months endedMonths Ended September 30, 20172022 versus Nine months endedMonths Ended September 30, 20162021

 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
SNG$(206) (70)% $(350) (94)%
South Texas Midstream(42) (20)% (29) (4)%
CIG(41) (20)% (38) (14)%
Hiland Midstream(17) (11)% 119
 31 %
TGP59
 7 % 67
 6 %
Elba Express31
 46 % 35
 52 %
EPNG16
 5 % 15
 3 %
Texas Intrastate Natural Gas Pipeline Operations9
 3 % 554
 29 %
All others (including eliminations)(7) (1)% 8
 1 %
Total Natural Gas Pipelines$(198) (6)% $381
 6 %
Adjusted Segment EBDA
20222021increase/
(decrease)
Midstream$1,063 $1,807 $(744)
East1,846 1,706 140 
West680 735 (55)
Total Natural Gas Pipelines$3,589 $4,248 $(659)



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 before certain items in the comparable three and nine monthnine-month periods ended September 30, 20172022 and 2016:2021:
decreases of $49•$62 million (62%(21%) increase and $206$744 million (70%(41%), decrease, respectively, from SNG due to our sale of a 50% interest in SNG toMidstream. The Southern Company on September 1, 2016;
decreases of $18 million (26%) and $42 million (20%), respectively, from South Texas Midstreamthird quarter increase was primarily due to lowerhigher volumes on commodity based service revenues and residue gasour KinderHawk assets, higher sales partially offset by higher revenues due to NGL prices, and for the nine month period, higher costs due to index prices;
decreases of $12 million (20%) and $41 million (20%), respectively, from CIG primarily due to a decrease in tariff rates effective January 1, 2017 as a result of a rate case settlement entered into in 2016;
decreases of $5 million (10%) and $17 million (11%), respectively, from Hiland Midstream primarily due to lower crude oil margins driven by lower crude oil gathering and delivery volumes and higher operating expenses partially offset by higher natural gas margins primarily due to higher NGL prices and renegotiated contracts. The increases in revenues of $29 million and $119 million, respectively, resulted primarily from an increase in natural gas revenue due to higher commodity prices which was largely offset by a corresponding increase in costs of sales;

increases of $23 million (9%) and $59 million (7%), respectively, from TGP primarily due to higher firm transportation revenues driven by incremental capacity sales and an expansion project placed in service fourth quarter 2016;
increases of $11 million (50%) and $31 million (46%), respectively, from Elba Express primarily due to an expansion project placed in service in December 2016;
increases of $11 million (10%) and $16 million (5%), respectively, from EPNG primarily due to higher transportation revenues driven by incremental Permian capacity sales and an increase in volumes due to the ramp up of existing customer volumes associated with an expansion project; and
flat and increase of $9 million (3%), respectively, fromon our Texas intrastate natural gas pipeline operations (includingand Altamont asset. The year-to-date decrease was primarily due to lower sales margins of $840 million on our Texas intrastate natural gas pipeline operations and $65 million on our South Texas assets largely driven by higher 2021 commodity prices related to the operationsFebruary 2021 winter storm. These decreases were partially offset by higher volumes on our KinderHawk assets, higher NGL sales margins driven by higher prices on our Altamont asset and higher earnings on our Oklahoma assets from higher 2021 commodity prices on certain purchase contracts as a result of itsthe February 2021 winter storm. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales;
•$18 million (3%) and $140 million (8%) increases, respectively, in the East Region were primarily due to higher capacity sales associated with our Stagecoach assets, higher equity earnings from SNG as a result of increased revenues due to an increase in demand for services and increased earnings from Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems). The quarter-to-date results were primarily affectedLouisiana Pipeline, LLC reflecting a new LNG customer contract partially offset by decreased earnings on TGP driven by higher parkoperating expenses due in part to higher property taxes and loan revenues and transportation margins offset by lower storage and sales margins.pipeline integrity costs. The year-to-date increase was further impacted by our July 2021 acquisition of the Stagecoach assets; and
•$11 million (5%) and $55 million (7%) decreases, respectively, in the West Region were primarily due to higher transportation margins aslower earnings from Colorado Interstate Gas Company, L.L.C. driven by lower revenues resulting from a result of higher volumesrate case settlement and highera decrease in revenues from EPNG driven by lower commodity and park and loan revenues partially offset by lower storage and sales margins. The increases in revenues of $12 million and $554 million, respectively,volumes that resulted primarily from an increase in sales revenue due to higher commodity prices which was largely offset by a corresponding increase in costs of sales.

CO2partial pipeline outage.
42
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In millions, except operating statistics)
Revenues(a)$289
 $310
 $899
 $916
Operating expenses(102) (102) (294) (302)
Gain (loss) on impairments and divestitures, net(b)—
 —
 1
 (20)
Earnings from equity investments(b)10
 9
 30
 14
Segment EBDA(b)197
 217
 636
 608
Certain items(b)20
 12
 23
 73
Segment EBDA before certain items$217
 $229
 $659
 $681
        
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(13) (4)% $(33) (3)%
Segment EBDA before certain items$(12) (5)% $(22) (3)%
        
Southwest Colorado CO2 production (gross)(Bcf/d)(c)
1.2
 1.2
 1.3
 1.2
Southwest Colorado CO2 production (net)(Bcf/d)(c)
0.6
 0.6
 0.6
 0.6
SACROC oil production (gross)(MBbl/d)(d)27.5
 28.9
 27.7
 29.7
SACROC oil production (net)(MBbl/d)(e)22.9
 24.1
 23.1
 24.8
Yates oil production (gross)(MBbl/d)(d)17.1
 17.9
 17.5
 18.5
Yates oil production (net)(MBbl/d)(e)7.6
 7.9
 7.8
 8.2
Katz, Goldsmith and Tall Cotton oil production (gross)(MBbl/d)(d)8.4
 6.9
 7.9
 6.9
Katz, Goldsmith and Tall Cotton oil production (net)(MBbl/d)(e)7.1
 5.8
 6.7
 5.8
NGL sales volumes (net)(MBbl/d)(e)9.6
 10.6
 9.9
 10.3
Realized weighted-average oil price per Bbl(f)$58.29
 $62.12
 $58.08
 $61.27
Realized weighted-average NGL price per Bbl(g)$24.79
 $18.03
 $23.92
 $16.42

_______Products Pipelines
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except operating statistics)
Revenues$872 $605 $2,634 $1,572 
Operating expenses(632)(341)(1,846)(828)
Gain on divestitures and impairments, net— — 12 — 
Earnings from equity investments17 15 55 48 
Segment EBDA257 279 855 792 
Certain Items(a)— 1 — 44 
Adjusted Segment EBDA$257 $280 $855 $836 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$(23)$19 
Volumetric data(b)
Gasoline(c)989 1,023 982 987 
Diesel fuel368 389 370 395 
Jet fuel278 250 262 217 
Total refined product volumes1,635 1,662 1,614 1,599 
Crude and condensate467 491 477 503 
Total delivery volumes (MBbl/d)2,102 2,153 2,091 2,102 
Certain itemsItems affecting Segment EBDA
(a)
Three and nine month 2017 amounts include unrealized losses of $20
(a)Nine months ended September 30, 2021 amount includes increases in expenses of $28 million and $15 million and $33 million, respectively, and three and nine month 2016 amounts include unrealized losses of $12 million and $40 million, respectively, related to non-cash mark to market derivative contracts used to hedge forecasted commodity sales. Nine month 2017 amount also includes an increase in revenues of $9 million related to the settlement of a CO2 customer sales contract.
(b)In addition to the revenue certain items described in footnote (a) above: nine month 2017 amount also includes a $1 million decrease in expense related to source and transportation project write-offs, and nine month 2016 amount also includes a decrease of $12 million in

equity earnings for our share of a project write-off recorded by an equity investee and a $21 million increase in expense related to sourcea litigation reserve and transportation project write-offs.an environmental reserve adjustment, respectively.
Other
(c)Includes McElmo Dome and Doe Canyon sales volumes.
(d)Represents 100% of the production from the field.  We own approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz unit and a 99% working interest in the Goldsmith Landreth unit and a 100% working interest in the Tall Cotton field. 
(e)Net after royalties and outside working interests. 
(f)Includes all crude oil production properties.
(g)Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

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

43

Below are the changes in bothAdjusted Segment EBDA before certain items and revenues before certain items, in the comparable three and nine monthnine-month periods ended September 30, 20172022 and 2016.2021:


Three months endedMonths Ended September 30, 20172022 versus Three months endedMonths Ended September 30, 20162021


Adjusted Segment EBDA
20222021increase/
(decrease)
Crude and Condensate$72 $85 $(13)
Southeast Refined Products57 64 (7)
West Coast Refined Products128 131 (3)
Total Products Pipelines$257 $280 $(23)
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Source and Transportation Activities$—
 — % $(4) (5)%
Oil and Gas Producing Activities(12) (8)% (11) (4)%
Intrasegment eliminations—
 — % 2
 20 %
Total CO2 
$(12) (5)% $(13) (4)%


Nine months endedMonths Ended September 30, 20172022 versus Nine months endedMonths Ended September 30, 20162021


Adjusted Segment EBDA
20222021increase/
(decrease)
Crude and Condensate$250 $269 $(19)
Southeast Refined Products209 198 11 
West Coast Refined Products396 369 27 
Total Products Pipelines$855 $836 $19 
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Source and Transportation Activities$11
 5 % $4
 2 %
Oil and Gas Producing Activities(33) (7)% (35) (5)%
Intrasegment eliminations—
 — % (2) (7)%
Total CO2 
$(22) (3)% $(33) (3)%

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and nine month periods ended September 30, 2017 and 2016:
flat and increase of $11 million (5%), respectively, from our Source and Transportation activities. Quarter-to-date results were impacted by lower revenues of $4 million driven by lower volumes of $6 million partially offset by higher contract sales prices of $2 million which were offset by lower operating expenses of $3 million and increased earnings from an equity investee of $1 million. The year-to-date increase was primarily due to higher revenues of $4 million driven by increased volumes of $9 million partially offset by lower contract sales prices of $5 million, $4 million related to increased earnings from an equity investee and lower operating expenses of $3 million; and
decreases of $12 million (8%) and $33 million (7%), respectively, from our Oil and Gas Producing activities primarily due to decreased revenues of $11 million and $35 million, respectively, driven by lower volumes of $5 million and $26 million, respectively, and lower commodity prices of $6 million and $9 million, respectively. These decreases were also impacted by an increase of $1 million and a decrease of $2 million, respectively, in operating expenses.


Terminals
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In millions, except operating statistics)
Revenues(a)$485
 $484
 $1,459
 $1,437
Operating expenses(202) (194) (575) (580)
Gain (loss) on impairments and divestitures, net(b)22
 (4) 16
 (21)
Earnings from equity investments6
 6
 18
 17
Other, net3
 2
 7
 3
Segment EBDA(b)314
 294
 925
 856
Certain items(b)(18) (1) (28) 8
Segment EBDA before certain items$296
 $293
 $897
 $864
        
Change from prior periodIncrease/(Decrease)
Revenues before certain items$5
 1% $37
 3%
Segment EBDA before certain items$3
 1% $33
 4%
        
Bulk transload tonnage (MMtons)15.5
 15.0
 44.4
 41.1
Ethanol (MMBbl)17.8
 17.3
 51.3
 48.9
Liquids leasable capacity (MMBbl)85.8
 84.7
 85.8
 84.7
Liquids utilization %(c)93.9% 96.1% 93.9% 96.1%
_______
Certain items affecting Segment EBDA
(a)Three and nine month 2017 amounts include increases in revenue of $2 million and $7 million, respectively, and three and nine month 2016 amounts include increases in revenue of $6 million and $22 million, respectively, from the amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act tankers.
(b)In addition to the revenue certain items described in footnote (a) above: three and nine month 2017 amounts also include an increase in earnings of $23 million for both periods primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017; partially offset by decreases in earnings of $7 million for both periods related to hurricane repairs, and nine month 2017 amount also includes (i) decreases in expense of $10 million related to a true-up of accrued dredging costs; (ii) losses of $8 million related to impairments and divestitures, net; and (iii) an increase in earnings of $3 million related to other certain items; and three and nine month 2016 amounts also include increases in expense of $5 million and $10 million, respectively, related to other certain items, and nine month 2016 amount also includes $20 million related to losses on impairments and divestitures, net.
Other
(c)The ratio of our actual leased capacity to our estimated potential capacity.

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and nine month periods ended September 30, 2017 and 2016.

Three months ended September 30, 2017 versus Three months ended September 30, 2016
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Marine Operations$13
 33 % $21
 36 %
Gulf Liquids2
 3 % 7
 8 %
Gulf Central(5) (20)% (5) (14)%
Held for sale operations(5) (100)% (16) (100)%
All others (including intrasegment eliminations)(2) (1)% (2) (1)%
Total Terminals$3
 1 % $5
 1 %

Nine months ended September 30, 2017 versus Nine months ended September 30, 2016
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Marine Operations$34
 32 % $55
 34 %
Gulf Liquids15
 8 % 28
 11 %
Gulf Central(9) (11)% (5) (5)%
Held for sale operations(13) (100)% (41) (87)%
All others (including intrasegment eliminations)6
 1 % —
 — %
Total Terminals$33
 4 % $37
 3 %


The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and nine month periods ended September 30, 2017 and 2016:
increases of $13 million (33%) and $34 million (32%), respectively, from our Marine Operations related to the incremental earnings from the May 2016, July 2016, September 2016, December 2016, March 2017, June 2017 and July 2017 deliveries of the Jones Act tankers, the Magnolia State, Garden State, Bay State, American Endurance,American Freedom, Palmetto State and American Liberty, respectively, partially offset by decreased charter rates on the Golden State, Pelican State, Sunshine State and Empire State Jones Act tankers;
increases of $2 million (3%) and $15 million (8%), respectively, from our Gulf Liquids terminals, primarily related to higher volumes as a result of various expansion projects, including the recently commissioned Kinder Morgan Export Terminal and North Docks terminal, partially offset by lost revenue associated with Hurricane Harvey-related operational disruptions;
decreases of $5 million (20%) and $9 million (11%), respectively, from our Gulf Central terminals, primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and the subsequent change in accounting treatment of our retained 11% membership interest as well as lost revenue associated with Hurricane Harvey-related operational disruptions; and
decreases of $5 million (100%) and $13 million (100%), respectively, from our sale of certain bulk terminal facilities to an affiliate of Watco Companies, LLC in December 2016 and early 2017.


Products Pipelines
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In millions, except operating statistics)
Revenues$412
 $419
 $1,232
 $1,216
Operating expenses(a)(124) (138) (353) (432)
Loss on impairments and divestitures, net(b)—
 (1) (1) (74)
Earnings from equity investments17
 12
 40
 40
Gain on divestiture of equity investment(c)—
 —
 —
 12
Other, net(3) —
 (5) (1)
Segment EBDA(a)(b)(c)302
 292
 913
 761
Certain items(a)(b)(c)—
 1
 (34) 112
Segment EBDA before certain items$302
 $293
 $879
 $873
        
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(7) (2)% $16
 1%
Segment EBDA before certain items$9
 3 % $6
 1%
        
Gasoline (MMBbl)(d)98.6
 97.4
 284.3
 280.9
Diesel fuel (MMBbl)33.4
 32.9
 94.8
 94.7
Jet fuel (MMBbl)27.5
 27.9
 81.2
 79.0
Total refined product volumes (MMBbl)(e)159.5
 158.2
 460.3
 454.6
NGL (MMBbl)(e)10.0
 9.9
 30.5
 28.9
Crude and condensate (MMBbl)(e)26.6
 28.8
 88.1
 87.6
Total delivery volumes (MMBbl)196.1
 196.9
 578.9
 571.1
Ethanol (MMBbl)(f)11.1
 10.9
 31.7
 31.7
_______
Certain items affecting Segment EBDA
(a)Nine month 2017 amounts include a decrease in expense of $34 million related to a right-of-way settlement, and nine month 2016 amount includes increases in expense of $31 million of rate case liability estimate adjustments associated with prior periods and $20 million related to a legal settlement.
(b)Three and nine month 2016 amounts include increases in expense of $1 million and $9 million, respectively, of non-cash impairment charges related to the sale of a Transmix facility; and nine month 2016 amount also includes an increase in expense of $64 million related to the Palmetto project write-off.
(c)Nine month 2016 amount includes $12 million of gains related to the sale of an equity investment.
Other
(d)Volumes include ethanol pipeline volumes.
(e)Joint venture throughput is reported at our ownership share.
(f)Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.


Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and nine month periods ended September 30, 2017 and 2016.

Three months ended September 30, 2017 versus Three months ended September 30, 2016
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Plantation Pipe Line$5
 36 % $—
 — %
Pacific operations4
 5 % 4
 3 %
South East Terminals4
 22 % 2
 7 %
Crude & Condensate Pipeline(2) (4)% (3) (5)%
Double H pipeline—
 — % (2) (11)%
Parkway pipeline—
 — % (1) (100)%
All others (including eliminations)(2) (2)% (7) (4)%
Total Products Pipelines $9
 3 % $(7) (2)%

Nine months ended September 30, 2017 versus Nine months ended September 30, 2016
 
Segment EBDA before certain items
increase/(decrease)
 
Revenues before
certain items
increase/(decrease)
 (In millions, except percentages)
Plantation Pipe Line$2
 4 % $—
 — %
Pacific operations3
 1 % 6
 2 %
South East Terminals2
 4 % 3
 3 %
Crude & Condensate Pipeline1
 1 % 5
 3 %
Double H pipeline4
 10 % 2
 4 %
Parkway pipeline(3) (100)% (1) (100)%
All others (including eliminations)(3) (1)% 1
 — %
Total Products Pipelines $6
 1 % $16
 1 %


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 before certain items in the comparable three and nine monthnine-month periods ended September 30, 20172022 and 2016:2021:
increases of $5•$13 million (36%(15%) and $2$19 million (4%(7%), decreases, respectively, from our equity investment in Plantation Pipe LineCrude and Condensate were primarily due to a favorablelower earnings from our Bakken Crude assets due to lower volumes from our Double H pipeline and an unfavorable inventory valuation adjustment made in the third quarter of 2017 to depreciation expense relateddue to a changedecline in depreciation rate partially offset by higher operating costs attributable to a project write-offcommodity prices and higher pipeline environmental costs;
increases of $4 million (5%) and $3 million (1%), respectively, from Pacific operations primarily due to higher service revenues driven by an increase in volumes;
increases of $4 million (22%) and $2 million (4%), respectively, from South East Terminals primarily due to higher revenues driven by higher volumes and favorable property taxes;
decrease of $2 million (4%) and increase of $1 million (1%), respectively, fromour Kinder Morgan Crude & Condensate Pipeline. pipeline driven primarily by lower deficiency revenues, partially offset by higher earnings from our KM Condensate Processing facility reflecting increased revenues due to higher volumes and rate escalations. Our Crude and Condensate pipeline also had higher revenues of $209 million and $832 million, respectively, with corresponding increases in cost of sales, resulting from increased marketing activities;
•$7 million (11%) decrease and $11 million (6%) increase, respectively, in Southeast Refined Products. The quarter-to-datethird quarter decrease was primarily due to lower services revenues driven by a decrease in pipeline throughput volumesearnings at our Transmix processing operations as a result of lower volumes during Hurricane Harvey. The year-to-date increase was primarilyan unfavorable inventory valuation adjustment due to favorable product sales impacting margins:
flat and increase of $4 million (10%), respectively, from Double H pipeline. The quarter-to-date results were affected by lower service revenues driven by lower volumes offset by a favorable changedecline in physical product gain/loss affecting operating costs.commodity prices. The year-to-date increase was primarily due to higher service revenues driven by higher volumes and a favorable change in physical product gain/loss affecting operating costs; and
flat and decrease of $3 million (100%), respectively, from Parkway pipelineearnings at our Transmix processing operations primarily due to our sale of our 50% interesthigher prices and volumes; and
•$3 million (2%) decrease and $27 million (7%) increase, respectively, in Parkway pipeline to Valero Energy Corp. on July 1, 2016.


Kinder Morgan Canada
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (In millions, except operating statistics)
Revenues$66
 $66
 $185
 $188
Operating expenses(24) (21) (67) (60)
Other, net8
 3
 18
 12
Segment EBDA$50
 $48
 $136
 $140
        
Change from prior periodIncrease/(Decrease)
Revenues$—
 —% $(3) (2)%
Segment EBDA$2
 4% $(4) (3)%
        
Transport volumes (MMBbl)(a)29.3
 30.7
 84.4
 88.1
_______
(a)Represents Trans Mountain pipeline system volumes.

For the comparable three and nine month periods of 2017 and 2016, the Kinder Morgan Canada business segment had an increase in Segment EBDA of $2 million (4%) and a decrease in Segment EBDA of $4 million (3%), respectively.West Coast Refined Products. The quarter-to-date increase was largely due to currency translation gains due to the strengthening of the Canadian dollar and higher capitalized equity financing costs due to spending on the Trans Mountain expansion project partially offset by timing of operating costs. The year-to-datethird quarter decrease was primarily due to operating expense timing changeslower earnings on our Pacific operations (SFPP) as a result of higher integrity management spending and lower Washington state revenues due to an overall decrease in volumes partially offset by currency translation gainsan increase in regulated rates. The year-to-date increase was primarily due to a gain on sale of land at Calnev Pipe Line LLC, increased earnings driven by higher revenues on our West Coast terminals from higher volumes and SFPP resulting from higher revenues driven by increased regulatory rates.

44

Terminals
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except operating statistics)
Revenues$457 $422 $1,337 $1,275 
Operating expenses(222)(200)(637)(588)
(Loss) gain on divestitures and impairments, net
— (14)9 (14)
Other income1 4 5 4 
Earnings from equity investments3 3 11 10 
Other, net1 1 6 2 
Segment EBDA240 216 731 689 
Certain Items(a)— 17 — 17 
Adjusted Segment EBDA$240 $233 $731 $706 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$7 $25 
Volumetric data(b)
Liquids leasable capacity (MMBbl)78.9 79.0 78.9 79.0 
Liquids utilization %(c)91.1 %94.7 %91.1 %94.7 %
Bulk transload tonnage (MMtons)13.4 13.4 40.0 37.9 
Certain Items affecting Segment EBDA
(a)Three and nine months ended September 30, 2021 amounts each include a pre-tax non-cash impairment loss of $14 million related to the strengtheningreclassification of an asset to held for sale.
Other
(b)Volumes for facilities divested, idled and/or held for sale are excluded for all periods presented.
(c)The ratio of our tankage capacity in service to tankage capacity available for service.

45

For purposes of the Canadian dollarfollowing tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical region and included within the All others group. Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:

Three Months Ended September 30, 2022 versus Three Months Ended September 30, 2021

Adjusted Segment EBDA
20222021increase/
(decrease)
Mid Atlantic$30 $15 $15 
Gulf Central35 31 4 
Gulf Liquids65 76 (11)
Northeast22 25 (3)
Marine operations34 37 (3)
All others (including intrasegment eliminations)54 49 5 
Total Terminals$240 $233 $7 

Nine Months Ended September 30, 2022 versus Nine Months Ended September 30, 2021

Adjusted Segment EBDA
20222021increase/
(decrease)
Mid Atlantic$77 $47 $30 
Gulf Central102 83 19 
Gulf Liquids217 220 (3)
Northeast67 80 (13)
Marine operations105 117 (12)
All others (including intrasegment eliminations)163 159 4 
Total Terminals$731 $706 $25 

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:
•$15 million (100%) and $30 million (64%) increases, respectively, in the Mid Atlantic terminals were primarily due to higher handling rates and coal volumes at our Pier IX facility;
•$4 million (13%) and $19 million (23%) increases, respectively, in the Gulf Central terminals were primarily due to lower property tax expense at our Battleground Oil Specialty Terminal Company LLC. The year-to-date increase was also impacted by higher volumes for petroleum coke handling activities, owing largely to refinery outages in the 2021 period associated with the February 2021 winter storm;
•$11 million (14%) and $3 million (1%) decreases, respectively, in the Gulf Liquids region were primarily due to higher property tax expense at Pasadena and Galena Park terminals. The year-to-date decrease was partially offset by increased revenues from contractual rate escalations and higher capitalized equity financing costsvolumes and associated ancillary fees;
•$3 million (12%) and $13 million (16%) decreases, respectively, in the Northeast terminals were primarily driven by decreased revenues associated with lower utilization and rates on re-contracted tank positions at our Carteret and Perth Amboy facilities; and
•$3 million (8%) and $12 million (10%) decreases, respectively, in Marine operations were primarily due to lower average charter rates partially offset by higher fleet utilization.


46

CO2
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except operating statistics)
Revenues$351 $257 $999 $729 
Operating expenses(143)(112)(408)(161)
Gain on divestitures and impairments, net— 11 1 8 
Earnings from equity investments7 7 27 23 
Segment EBDA215 163 619 599 
Certain Items(a)(20)(9)(5)(3)
Adjusted Segment EBDA$195 $154 $614 $596 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$41 $18 
Volumetric data
SACROC oil production19.9 20.1 19.6 19.9 
Yates oil production6.4 6.5 6.5 6.5 
Katz and Goldsmith oil production1.8 2.1 1.9 2.3 
Tall Cotton oil production1.0 1.1 1.0 1.0 
Total oil production, net (MBbl/d)(b)29.1 29.8 29.0 29.7 
NGL sales volumes, net (MBbl/d)(b)9.7 9.7 9.5 9.3 
CO2 sales volumes, net (Bcf/d)
0.3 0.4 0.4 0.4 
Realized weighted average oil price ($ per Bbl)$66.34 $53.03 $67.91 $52.21 
Realized weighted average NGL price ($ per Bbl)$37.68 $28.01 $41.01 $23.73 
Certain Items affecting Segment EBDA
(a)Three and nine months ended September 30, 2022 amounts include $(20) million and $(5) million, respectively, and three and nine months ended September 30, 2021 amounts include $1 million and $7 million, respectively, of changes in revenue related to non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales.
Other
(b)Net of royalties and outside working interests.

47

Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:

Three Months Ended September 30, 2022 versus Three Months Ended September 30, 2021

Adjusted Segment EBDA
20222021increase/
(decrease)
Oil and Gas Producing activities$132 $63 $69 
Source and Transportation activities59 89 (30)
Subtotal191 152 39 
Energy Transition Ventures4 2 2 
Total CO2
$195 $154 $41 

Nine Months Ended September 30, 2022 versus Nine Months Ended September 30, 2021

Adjusted Segment EBDA
20222021increase/
(decrease)
Oil and Gas Producing activities$410 $397 $13 
Source and Transportation activities190 197 (7)
Subtotal600 594 6 
Energy Transition Ventures14 2 12 
Total CO2
$614 $596 $18 


The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:
•$69 million (110%) and $13 million (3%) increases, respectively, in Oil and Gas Producing activities primarily due to spending onhigher realized crude oil and NGL prices which increased revenues by $44 million and $173 million, respectively and a third quarter 2021 settlement of $38 million for a terminated affiliate purchase contract with Source and Transportation activities. The year-to-date increase was also impacted by higher operating expenses of $179 million mainly driven by the Trans Mountain expansion project.benefit realized in the 2021 period from returning power to the grid by curtailing oil production during the February 2021 winter storm; and

•$30 million (34%) and $7 million (4%) decreases, respectively, in Source and Transportation activities primarily due to a third quarter 2021 settlement of $38 million for a terminated affiliate sales contract with Oil and Gas Producing activities offset by increased revenues of $12 million and $46 million, respectively, related to higher CO2 sales prices. The year-to-date decrease was also impacted by decreased revenues related to lower CO2 sales volumes.


48

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, 2022:

Remaining 20222023202420252026
Crude Oil(a)
Price ($ per Bbl)$62.42 $63.28 $61.04 $61.08 $65.67 
Volume (MBbl/d)26.40 21.10 13.40 8.95 3.00 
NGLs
Price ($ per Bbl)$56.02 $61.39 
Volume (MBbl/d)4.57 2.04 
Midland-to-Cushing Basis Spread
Price ($ per Bbl)$0.53 $0.87 
Volume (MBbl/d)23.65 14.50 
(a)Includes West Texas Intermediate hedges.

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


Three Months Ended
September 30,		Earnings
increase/(decrease)
20222021
(In millions, except percentages)
DD&A (GAAP)$(551)$(526)$(25)(5)%
General and administrative (GAAP)$(162)$(174)$12 7 %
Corporate benefit13 7 6 86 %
Certain Items(a)— — — — %
General and administrative and corporate charges(b)$(149)$(167)$18 11 %
Interest, net (GAAP)$(399)$(368)$(31)(8)%
Certain Items(c)15 (8)23 288 %
Interest, net(b)$(384)$(376)$(8)(2)%
Net income attributable to noncontrolling interests (GAAP)$(19)$(16)$(3)(19)%
Certain Items— — — — %
Net income attributable to noncontrolling interests(b)$(19)$(16)$(3)(19)%

49

 Three Months Ended September 30,  
 2017 2016 Increase/(decrease)
 (In millions, except percentages)
General and administrative and corporate charges(a)$164
 $163
 $1
 1 %
Certain items(a)(5) —
 (5) n/a
General and administrative and corporate charges before certain items(a)$159
 $163
 $(4) (2)%
        
Interest, net(b)$459
 $472
 $(13) (3)%
Certain items(b)4
 31
 (27) (87)%
Interest, net, before certain items$463
 $503
 $(40) (8)%
        
Net income attributable to noncontrolling interests$14
 $5
 $9
 180 %
Noncontrolling interests associated with certain items(c)—
 —
 —
 n/a
Net income attributable to noncontrolling interests before certain items$14
 $5
 $9
 180 %

 Nine Months Ended September 30,  
 2017 2016 Increase/(decrease)
 (In millions, except percentages)
General and administrative and corporate charges(a)$490
 $537
 $(47) (9)%
Certain items(a)(8) (24) 16
 67 %
General and administrative and corporate charges before certain items(a)$482
 $513
 $(31) (6)%
        
Interest, net(b)$1,387
 $1,384
 $3
 — %
Certain items(b)21
 140
 (119) (85)%
Interest, net, before certain items$1,408
 $1,524
 $(116) (8)%
        
Net income attributable to noncontrolling interests$26
 $7
 $19
 271 %
Noncontrolling interests associated with certain items(c)(1) 9
 (10) (111)%
Net income attributable to noncontrolling interests before certain items$25
 $16
 $9
 56 %
_______
n/a - not applicable

Nine Months Ended
September 30,		Earnings
increase/(decrease)
20222021
(In millions, except percentages)
DD&A (GAAP)$(1,632)$(1,595)$(37)(2)%
General and administrative (GAAP)$(470)$(490)$20 4 %
Corporate benefit32 25 7 28 %
Certain Items(a)— — — — %
General and administrative and corporate charges(b)$(438)$(465)$27 6 %
Interest, net (GAAP)$(1,087)$(1,122)$35 3 %
Certain Items(c)(46)(17)(29)(171)%
Interest, net(b)$(1,133)$(1,139)$6 1 %
Net income attributable to noncontrolling interests (GAAP)$(54)$(49)$(5)(10)%
Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)$(54)$(49)$(5)(10)%
Certain items
(a)
(a)Three and nine months ended September 30, 2022 amounts include less than $1 million of general and administrative and corporate charges associated with Certain Items.
(b)Amounts are adjusted for Certain Items.
(c)Three and nine months ended September 30, 2022 amounts include an increase of $19 million and a decrease of $35 million in interest expense, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt, primarily related to our floating-to-fixed LIBOR interest rate swaps which are not designated as accounting hedges and nine month 2017 amounts include (i) increases in expense of $1 million and $3 million, respectively, related to certain corporate litigation matters; and (ii) an increase in expense of $4 million and a decrease in expense of $2 million, respectively, related to other certain items. Nine month 2017 amount also includes an increase in expense of $7 million for acquisition and divestiture related costs. Three and nine month 2016 amounts include (i) a decrease in expense of $1 million and an increase in expense of $7 million, respectively, related to certain corporate legal matters; (ii) increases in expense of $1 million and $13 million, respectively, related to severance costs; (iii) increases in expense of $4 million and $12 million, respectively, related to acquisition and divestiture related costs; and (iv) decreases in expense of $4 million and $8 million, respectively, related to other certain items.
(b)Three and nine month 2017 amounts include (i) decreases in interest expense of $6 million and $35 million, respectively, related to debt fair value adjustments associated with acquisitions; and (ii) increases in interest expense of $2 million and $6 million, respectively, related to non-cash true-ups of our estimates of swap ineffectiveness. Also, nine month 2017 amounts include increases in interest expense of $8 million related to other certain items. Three and nine month 2016 amounts include (i) decreases in interest expense of $47 million and $84 million, respectively, related to debt fair value adjustments associated with acquisitions; and (ii) an increase in interest expense of $16 million and a decrease in interest expense of $56 million, respectively, related to non-cash true-ups of our estimates of swap ineffectiveness.
(c)Nine month 2017 amount includes a gain of $1 million associated with Terminals segment certain items and disclosed above in “—Terminals.” Nine month 2016 amount includes a loss of $9 million associated with Natural Gas Pipelines segment certain items and disclosed above in “—Natural Gas Pipelines.”

The decreases in generalexpense of $4 million and $11 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and nine months September 30, 2021 amounts include decreases of $7 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions.
(d)Nine months ended September 30, 2021 amount includes less than $1 million of noncontrolling interests associated with Certain Items.

General and administrative expenses and corporate charges before certain items of $4 million and $31 million, respectively,adjusted for Certain Items for the three and nine months ended September 30, 20172022 when compared with the respective prior year periods

was decreased $18 million and $27 million, respectively, primarily driven by the sale of a 50% interest in our SNG natural gas pipeline system (effective September 1, 2016) and due to higher capitalized costs of $10 million and $31 million, respectively, reflecting higher capital spending and lower benefit-related and pension costs of $5 million and $9 million, respectively, partially offset by $1 million and $12 million, respectively, of higher pensionlabor, travel and legal costs. The year-to-date decrease was also impacted by lower state franchise taxes, legal and insurance costs.


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 before certain itemsadjusted for Certain Items for the three and nine months ended September 30, 20172022 when compared with the respective prior year periods decreased $40increased $8 million and $116decreased $6 million, respectively. The decreases in interest expense wererespectively, primarily due to lower weightedlong-term average interest rates and long-term debt balances, as proceeds from our May 2017 KML IPO and September 2016 sale of a 50% interest in SNG were used to pay down debt, partially offset by a slightly higher overall weighted average interest rate on our outstandingshort-term debt. rates.


We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of September 30, 20172022 and December 31, 2016,2021, approximately 27% and 28% 8% and 21%, respectively, of the principal amount of our debt balances (excluding debt fair value adjustments) were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The September 30, 2022 rate was lower because we entered into variable-to-fixed interest rate hedges that expire at the end of 2022. Without those hedges, as of September 30, 2022, our debt subject to variable interest rates would have been approximately 24%. For more information on our interest rate swaps, see Note 56 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.


Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. Net income attributable to noncontrolling interests before certain items for the three and nine months ended September 30, 2017 when compared with the respective prior periods increase by $9 million due to the inclusion of earnings attributable to the public ownership of KML.


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Income Taxes


Our tax expense for the three months ended September 30, 20172022 was approximately $160$134 million as compared with $377$134 million for the same period of 2016.2021. The $217 million decrease in tax expense was the same due primarily due to (i) the 2016 impact of our Regulated Natural Gas Pipeline segment’s $817 million non-tax-deductible goodwillfederal taxes on higher pre-tax book income, partially offset by state income taxes as a result of the salereduction of a 50% interestthe state tax rate in SNG as discussed in Note 8 “Income Taxes” to our consolidated financial statements; (ii) the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision; and (iii) adjustments to our income tax reserve for uncertain tax positions. These decreases were partially offset by (i) an increase in quarter-over-quarter earnings as a result of no asset impairments or project write-offs in 2017; and (ii) tax deductions related to equity compensation.current period.


Our tax expense for the nine months ended September 30, 20172022 was approximately $622$512 million as compared with $744$248 million for the same period of 2016.2021. The $122$264 million decreaseincrease in tax expense iswas due primarily due to (i)federal and state taxes on higher pre-tax book income in the 2016 impact of our Regulated Natural Gas Pipeline segment’s $817 million non-tax-deductible goodwill as a resultcurrent year and the release of the salevaluation allowance on our investment in NGPL Holdings in the prior year.

On August 16, 2022, the U.S. government enacted the Inflation Reduction Act of 2022 (IRA) into law. The IRA includes a 50% interest in SNG;new corporate alternative minimum tax (Corporate AMT) of 15% on the adjusted financial statement income (AFSI) of corporations with average AFSI exceeding $1.0 billion over a three-year period. The Corporate AMT is effective for tax years beginning after December 31, 2022. We are evaluating the Corporate AMT and (ii)its potential impact on our current income tax expense and cash taxes. However, we currently do not believe this will have an impact on our cash taxes for the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision; partially offset by an increase in year-over-year earnings as a result of no asset impairments or project write-offs in 2017.2023 tax year.


Liquidity and Capital Resources


General


As of September 30, 2017,2022, we had $539$483 million of “Cash and cash equivalents,” a decrease of $145$657 million (21%) from December 31, 20162021. Additionally, as of September 30, 2022, we had borrowing capacity of approximately $3.9 billion under our credit facilities (discussed below in “—Short-term Liquidity”). WeAs discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility (discussed below in “—Short-term Liquidity”), and cash flows from operating activitiesfacilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.obligations.


We have consistently generated substantial cash flowflows from operations, providing a source of funds of $3,307$3,563 million and $3,503$4,440 million in the first nine months of 20172022 and 2016,2021, respectively. The period-to-period decrease is discussed below in “Cash“—Cash Flows—Operating Activities.Activities.” We have primarily reliedrely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and dividend payments.

On June 16, 2017, KML entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility forour growth capital expenditures; however, we may access the purposes of funding the development, construction and completion of the Trans Mountain expansion project; (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional Trans Mountain expansion project costs (and, subjectdebt capital markets from time to the need to fund such additional costs and regulatory approval, meeting the Canadian National Energy Board-mandated liquidity requirements); and (iii) a C$500 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “Credit Facility”). The KML Credit Facility

has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. As of September 30, 2017, KML had a combined C$165 million (USD$132 million) outstanding under its Credit Facility which is included in “Current portion of debt” on our consolidated balance sheet and C$47 million (USD$38 million) in letters of credit. In addition, KML received C$293 million (USD$230 million) of net proceeds from the issuance of preferred shares, Series 1 in August 2017.

We expect to fund KML’s Trans Mountain expansion project capital expenditures through (i) additional borrowings on KML’s Credit Facility; (ii) the additional issuance of KML preferred shares; (iii) the issuance of additional KML restricted voting stock; (iv) the issuance of KML long-term notes payable; and (v) KML’s retained cash flow from operations or a combination of the above. KML established a dividend policy on its restricted voting shares pursuant to which it will pay its quarterly dividend in an amount based on a portion of its distributable cash flow discussed below in “—Noncontrolling interests—KML Restricted Voting Share Dividendsbelow.

Generally, we expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debttime to refinance certain of our maturing long-term debt obligations. We also expect that KMI’s current common stockand finance incremental investments, if any.

Our board of directors declared a quarterly dividend level will allow it to use retained cash to fund our other growth projects in 2017. Moreover, as a result of KMI’s current common stock dividend policy and by continuing to focus on high-grading our other growth project backlog to allocate capital to the highest return opportunities, we do not expect the need to access the equity capital markets to fund our other growth projects$0.2775 per share for the foreseeable future.third quarter of 2022, consistent with the dividend declared for the previous quarter.


On February 23, 2022, EPNG issued in a private offering $300 million aggregate principal amount of 3.50% senior notes due 2032 and received net proceeds of $298 million after discount and issuance costs.

On August 3, 2022, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 4.80% senior notes due 2033 and $750 million aggregate principal amount of 5.45% senior notes due 2052 and received combined net proceeds of $1,484 million. We used a portion of the proceeds to repay short-term borrowings and for general corporate purposes.

During the first quarter, upon maturity, we repaid EPNG’s 8.625% senior notes, our 4.15% corporate senior notes, and the 1.50% series of our Euro denominated debt. During the second quarter 2022, we repaid $1 billion of our 3.95% senior notes using short-term borrowings. The short-term borrowings were repaid in the third quarter 2022 with proceeds from the August 2022 senior note issuances.

Short-term Liquidity


As of September 30, 2017,2022, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $5.0combined $4.0 billion revolvingof credit facilityfacilities and associated $4.0 billion commercial paper program; (ii) the KML Credit Facility (for the purposes described above) and (iii) cash from operations.program. The loan commitments under our revolving credit facilityfacilities can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. BorrowingsCommercial paper borrowings reduce borrowings allowed under our commercial paper programcredit facilities and letters of credit reduce borrowings allowed under ours and the KML respectiveour $3.5 billion credit facilities.facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facilityfacilities and, as previously discussed, have consistently generated strong cash flows from operations.


51

As of September 30, 2017,2022, our $3,156$2,634 million of short-term debt consisted primarily of (i) $132 million outstanding borrowings under the KML C$4.0 billion revolving construction facility; (ii) $60 million outstanding under our $4.0 billion commercial paper program; and (iii) $2,784 million of senior notes that mature in the next year.twelve months. We intend to refinancefund our short-term debt, as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or by issuing new long-term debt or paying down short-term debt using cash retained from operations.debt. Our short-term debt balance as of December 31, 20162021 was $2,696$2,646 million.


We had working capital (defined as current assets less current liabilities) deficits of $3,561$2,329 million and $2,695$1,992 million as of September 30, 20172022 and December 31, 2016,2021, respectively. OurFrom time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or partially pay down using retained cash from operations. The overall $866$337 million (32%) unfavorable change from year-end 20162021 was primarily due to (i) a net increase$657 million decrease in cash and cash equivalents which includes $1,190 million related to repayments of senior notes that matured in the first quarter of 2022 using cash on hand (while the change in our current portionmaturities of long-term debtsenior notes remains flat); (ii) unfavorable short-term fair value adjustments on derivative contracts of $349 million; and decreases(iii) a $58 million net unfavorable change in cashour accounts receivables and accounts receivable, net.payables; partially offset by (i) a $233 million increase in restricted deposits related to our derivative activity; (ii) a $192 million decrease in accrued contingencies; (iii) a $177 million decrease in accrued interest; and (iv) a $153 million increase in inventories, primarily gas in underground storage. 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.


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 which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results“—Results of Operations—Distributable Cash Flow”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 which 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 maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.


Our capital expenditures for the nine months ended September 30, 2017,2022, and the amount we expect to spend for the remainder of 20172022 to sustain our assets and grow our businessesbusiness are as follows:
Nine Months Ended September 30, 20222022 RemainingTotal 2022
(In millions)
Sustaining capital expenditures(a)(b)$581 $317 $898 
Discretionary capital investments(b)(c)(d)1,214 632 1,846 
(a)Nine months ended September 30, 2022, 2022 Remaining, and Total 2022 amounts include $83 million, $53 million, and $136 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “—Results of Operations—Non-GAAP Financial Measures—Supplemental Information.”
52

 Nine Months Ended September 30, 2017 2017 Remaining Total
 (In millions)
Sustaining capital expenditures(a)(c)$416
 $177
 $593
KMI Discretionary capital investments(b)(c)(d)(e)$2,289
 $770
 $3,059
KML Discretionary capital investments post IPO(c)$240
 $205
 $445
(b)Nine months ended September 30, 2022 amount includes $15 million due to increases in accrued capital expenditures and contractor retainage and net changes in other.
_______(c)Nine months ended September 30, 2022 amount includes $63 million of our contributions to certain unconsolidated joint ventures for capital investments. Both Nine Months Ended September 30, 2022 and Total 2022 amounts also include $490 million for our acquisitions of Mas CanAm, LLC and NANR.
(a)
Nine months ended September 30, 2017, 2017 Remaining, and Total 2017 amounts include $74 million, $34 million, and $108 million, respectively, for our proportionate share of sustaining capital expenditures of unconsolidated joint ventures.
(b)Nine months ended September 30, 2017 is net of $216 million of contributions from certain partners for capital investments at non-wholly owned consolidated subsidiaries offset by $570 million of our contributions to certain unconsolidated joint ventures for capital investments.
(c)Nine months ended September 30, 2017 includes $286 million of net changes from accrued capital expenditures, contractor retainage, and other.
(d)Nine months ended September 30, 2017 includes $107 million of capital spent on Canadian projects prior to KML’s May 25, 2017 IPO and excludes KML capital expenditures thereafter as it has the capacity to draw on its construction credit facility to fund its capital expenditures.
(e)2017 Remaining amount includes our estimated contributions to certain unconsolidated joint ventures, net of contributions estimated from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

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

Off Balance Sheet Arrangements


Other than commitments for the purchase of property, plant and equipment discussed below, thereThere 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, 20162021 in our 20162021 Form 10-K.


Commitments for the purchase of property, plant and equipment as of September 30, 20172022 and December 31, 20162021 were $857$556 million and $1,112$209 million, respectively. The $255increase of $347 million decrease iswas primarily related to a reduction in various capital commitments associated with our tankers and our natural gas business segment, partially offsetdriven by an overall increase inof capital commitments associated with our Trans Mountain pipeline project.commitments.


Cash Flows


Operating Activities


The net decrease of $196 million in cashCash provided by operating activities fordecreased $877 million in the first nine months of 2017ended September 30, 2022 compared to the respective 20162021 period was primarily attributabledue to:

���a $148 million decrease in operating cash flow resulting from the combined effects of adjusting the $709 million increase in net income for the period-to-period net decrease in non-cash items including the following: (i) net losses on


impairments and divestitures•a $576 million decrease in cash after adjusting the $736 million increase in net income by $1,312 million for the combined effects of assets and equity investmentsthe period-to-period net changes in non-cash items. This overall cash decrease primarily resulted from the benefit recognized in the 2021 period for largely nonrecurring earnings related to the February 2021 winter storm (see discussion above in “—Results of Operations”); (ii) changeand
•a $301 million decrease in fair market value of derivative contracts; (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments; and
a $48 million decreasecash associated with net changes in working capital items and other non-current assets and liabilities,liabilities. The decrease was primarily driven among other things, by unfavorable changes due to (i) increases in our customer accounts receivables largely in our Natural Gas business segment which was impacted by higher natural gas price increases in the 2022 period relative to the 2021 period; (ii) higher inventories reflecting higher storage rates and increased volumes; and (iii) a decrease in cash related to gasreserves associated with litigation matters in underground storage inventory resulting from an increase in storage injections and price increases, and payments related to certain litigation matters. These decreases were partially offset by an increase in cash due to a $144 million income tax refund received in 2017.the 2022 period compared with the 2021 period.


Investing Activities
The $1,439 million net increase in cash
Cash used in investing activities decreased $366 million for the first nine months of 2017ended September 30, 2022 compared to the respective 20162021 period was primarily attributable to:

•a $1,402$1,030 million increasedecrease in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by a combined $488 million of net cash used for our acquisitions of Mas CanAm, LLC and NANR in the 2022 period, compared with a combined $1,508 million of net cash used for the acquisitions of Stagecoach Gas Services LLC and Kinetrex Energy in the 2021 period; partially offset by,
•a $413 million decrease in proceeds from sales of investments primarily due to proceeds$412 million received in the 2016 period from the sale of a 50% equitypartial interest in SNG;our equity investment in NGPL Holdings in the 2021 period; and
•a $242 million increase in cash used for contributions to equity investments primarily due to the contributions we made in 2017 to Utopia Holding LLC, Fayetteville Express Pipeline LLC and SNG;
$132 million lower cash proceeds from sales of property, plant and equipment and other net assets, primarily driven by the higher proceeds we received in 2016 from sales of other long-lived assets; and
a $122$250 million increase in capital expenditures primarily due to higher expenditures related to natural gas and Trans Mountainreflecting an overall increase of expansion capital projects offset in part by lower expenditures in the Terminals segment; partially offset by2022 period over the comparative 2021 period.
a $329 million decrease in expenditures for acquisitions of assets and investments, primarily driven by the $324 million portion of the purchase price we paid in the 2016 period for the BP terminals acquisition; and
a $94 million increase in cash for distributions received from equity investments in excess of cumulative earnings, primarily driven by the higher distributions from Midcontinent Express Pipeline LLC and Ruby Pipeline Holding Company, L.L.C.


Financing Activities
The net decrease of $1,338 million in cash
Cash used in financing activities decreased $1,017 million for the first nine months of 2017ended September 30, 2022 compared to the respective 20162021 period was primarily attributable to:
a $1,399 million increase in cash due to contributions from noncontrolling interests, primarily reflecting $1,245 million in net proceeds received from the May 2017 KML IPO and $230
•an $837 million net proceeds received from the KML preferred share issuance in the third quarter of 2017, compared with $84 million of contributions received from BP for its 25% share of a newly formed joint venture in the 2016 period;
a $776 million increase in cash resulting from cash held in “Restricted deposits” at September 30, 2016 for an October, 2016 debt repayment; and
a $444 million increase in cash resulting from contributions received in the 2017 period from EIG, consisting of $386 million for the sale of a 49% partnership interest in ELC and $58 million as additional contributions for 2017 capital expenditures; partially offset by
a $1,268 million net increasedecrease in cash used related to debt activity as a result of higherlower net debt payments in the 20172022 period compared to the 2016 period. See Note 3 “Debt”2021 period; and
•$557 million of net proceeds received from the sale of a 25.5% ownership interest in ELC in the 2022 period; partially offset by,
•$333 million of cash used in the 2022 period for further information regardingshare repurchases under our debt activity.share buy-back program.

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Dividends and Stock Buyback Program

Dividends
KMI Common Stock Dividends


We expect to declare common stock dividends of $0.50$1.11 per share on our common stock for 2017 ($0.125/quarter).2022. The table below reflects our 2022 dividends declared:
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2022$0.2775 April 20, 2022May 2, 2022May 16, 2022
June 30, 20220.2775 July 20, 2022August 1, 2022August 15, 2022
September 30, 20220.2775 October 19, 2022October 31, 2022November 15, 2022
Three months ended Total quarterly dividend per share for the period Date of declaration Date of record Date of dividend
December 31, 2016 $0.125
 January 18, 2017 February 1, 2017 February 15, 2017
March 31, 2017 $0.125
 April 19, 2017 May 1, 2017 May 15, 2017
June 30, 2017 $0.125
 July 19, 2017 July 31, 2017 August 15, 2017
September 30, 2017 $0.125
 October 18, 2017 October 31, 2017 November 15, 2017



As a result of substantial balance sheet improvement achieved since the end of 2015, we announced multiple steps to return significant value to shareholders. First, we announced our expectation to declare an annual dividend of $0.80 per share for 2018, a 60% increase from the expected 2017 dividend. The first 2018 increase is expected to be the dividend declared for the first quarter of 2018. Additionally, we plan to increase our dividend to $1.00 per share in 2019 and $1.25 per share in 2020, a growth rate of 25% annually.

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 Part I, Item 1A. “Risk“Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 20162021 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 towill 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 Preferred Stock Dividends
Dividends onand 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 (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our mandatory convertible preferred stock are payable onguaranteed debt (Guaranteed Notes). As a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.750%result of the liquidation preferencecross guarantee agreement, a holder of $1,000 per share on January 26, April 26, July 26any of the Guaranteed Notes issued by KMI or Subsidiary Issuers are in the same position with respect to the net assets, and October 26income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each year, commencing on January 26, 2016 to, and including, October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividendsGuaranteed 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 the Obligated Group, 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.  Also, see Exhibit 10.1 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of September 30, 2022.”

All significant intercompany items among the Obligated Group have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock.
Period Total dividend per share for the period Date of declaration Date of record Date of dividend
October 26, 2016 through January 25, 2017 $24.375
 October 19, 2016 January 11, 2017 January 26, 2017
January 26, 2017 through April 25, 2017 $24.375
 January 18, 2017 April 11, 2017 April 26, 2017
April 26, 2017 through July 25, 2017 $24.375
 April 19, 2017 July 11, 2017 July 26, 2017
July 26, 2017 through October 25, 2017 $24.375
 July 19, 2017 October 11, 2017 October 26, 2017

eliminated in the supplemental summarized combined financial information. The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per depository share.

Stock Buyback Program

On July 19, 2017, our board of directors approved a $2 billion share buyback program expected to beginObligated Group’s investment balances in 2018.

Noncontrolling Interests
KML Restricted Voting Share Dividends
KML established a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its distributable cash flow. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. The actual amount of cash dividends paid to KML’s shareholders, if any, will depend on numerous factors including: (i) KML’s results of operations; (ii) KML’s financial requirements, including the funding of its current and future growth projects; (iii) the amount of distributions paid indirectly by KMC LP to KML through KMC GP, including any contributionsSubsidiary Non-Guarantors have been excluded from the completion of its growth projects; (iv)supplemental summarized combined financial information. Significant intercompany balances and activity for the satisfaction by KML and KMC GP of certain liquidity and solvency tests; (v) any agreements relatingObligated Group with other related parties, including Subsidiary Non-Guarantors, (referred to KML’s indebtedness oras “affiliates”) are presented separately in the limited partnership; and (vi) the cost and timely completion of current and future growth projects. KML intends to pay quarterly dividends, if any, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of recordaccompanying supplemental summarized combined financial information.

Excluding fair value adjustments, as of September 30, 2022 and December 31, 2021, the closeObligated Group had $30,842 million and $31,608 million, respectively, of business on or about the last business day of the month following the end of each calendar quarter.Guaranteed Notes outstanding.


On August 15, 2017, KML paid a dividend of C$0.0571 per restricted voting share to restricted voting shareholders of record as of the close of business on July 31, 2017Summarized combined balance sheet and income statement information for the quarterly period ended June 30, 2017. This initial dividend was prorated from May 30, 2017, the day KML closed on its IPO, to June 30, 2017 and amounted to approximately C$6 million. Based on a full quarter, the dividend amounted to C$0.1625 per restricted voting share (C$0.65 annualized). KML paid approximately C$4 million of this dividend to restricted voting shareholders in cash, and, under KML’s Dividend Reinvestment Plan (DRIP), 94,003 restricted voting shares were issued in lieu of cash dividends. KML’s DRIP allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion). The market discount for the dividend paid on August 15, 2017 was 3%.Obligated Group follows:

Summarized Combined Balance Sheet InformationSeptember 30, 2022December 31, 2021
(In millions)
Current assets$3,523 $3,556 
Current assets - affiliates6441,233 
Noncurrent assets61,39561,754 
Noncurrent assets - affiliates512508 
Total Assets$66,074 $67,051 
Current liabilities$5,826 $5,413 
Current liabilities - affiliates7091,332 
Noncurrent liabilities31,33732,310 
Noncurrent liabilities - affiliates1,0751,047 
Total Liabilities38,947 40,102 
Kinder Morgan, Inc.’s stockholders’ equity27,12726,949 
Total Liabilities and Stockholders’ Equity$66,074 $67,051 
For 2017, KML expects to pay a prorated dividend of C$0.3821 per restricted voting share (or C$0.65 per restricted voting share on an annualized basis).
Summarized Combined Income Statement InformationThree Months Ended
September 30, 2022		Nine Months Ended
September 30, 2022
(In millions)
Revenues$4,757 $13,490 
Operating income8112,606
Net income4821,587


On October 17, 2017, KML’s board of directors declared a dividend for the quarterly period ended September 30, 2017 of C$0.1625 per restricted voting share, payable on November 15, 2017, to restricted voting shareholders of record as of the close of business on October 31, 2017.
55

KML Preferred Share Offering


On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (USD $235 million). The net proceeds of C$293 million from the offering were used by KML to indirectly subscribe for preferred units in KMCLP, which in turn were used by KMC LP to repay Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the Trans Mountain Expansion project and Base Line Terminal project, and for general corporate purposes.

Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022.

On October 17, 2017, KML’s board of directors declared a cash dividend of C$0.3308 per share of its Series 1 Preferred Shares for the period from and including August 15, 2017 through and including November 14, 2017, which is payable on November 15, 2017 to Series 1 Preferred Shareholders of record as of the close of business on October 31, 2017.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2016,2021, in Part II, Item 7A in our 20162021 Form 10-K. For more information on our risk management activities, seerefer to Item 1, Note 56 “Risk Management” to our consolidated financial statements.


Item 4.  Controls and Procedures.

As of September 30, 2017,2022, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 20172022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


PART II.  OTHER INFORMATION


Item 1.  Legal Proceedings.


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


Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 20162021 Form 10-K. For more information on our risk management activities, refer to Part I, Item 1, Note 6 “Risk Management” to our consolidated financial statements.


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


Our Purchases of Our Class P Stock
Settlement PeriodTotal 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
July 1 to July 31, 20226,139,969 $16.63 6,139,969 $1,149,696,799 
August 1 to August 31, 2022— — — 1,149,696,799 
September 1 to September 30, 20223,531,359 16.42 3,531,359 1,091,722,406 
Total9,671,328 $16.55 9,671,328 $1,091,722,406 
(a)On July 19, 2017, our board of directors approved a $2 billion common share buybackbuy-back program expected to beginthat began in 2018.December 2017. After repurchase, the shares are canceled and no longer outstanding.

The warrant repurchase program, dated June 12, 2015, which authorized us(b)Amount includes any commission or other costs to repurchase upshares.

Subsequent to $100September 30, 2022 and through October 20, 2022, we repurchased approximately 2 million of warrants, expired along with the warrants on May 25, 2017.our shares for $34 million at an average price of $16.75 per share.


Item 3.  Defaults Upon Senior Securities.

None. 

56


Item 4.  Mine Safety Disclosures.

The Company no longer ownsExcept for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operatesoperate 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. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended September 30, 2017.2022.


Item 5.  Other Information.

None.

57


Item 6.  Exhibits.
3.1Exhibit Number
*
Amended and Restated Certificate of Incorporation of KMI (filed as Exhibit 3.1 to KMI’s Quarterly Report on Form 10‑Q for the three months ended June 30, 2015 (file No. 001-35081)).
Description
4.1 
3.2
*
4.1
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of KMIKinder Morgan, Inc. establishing the terms of the 3.150% Senior4.800% Notes due January 15, 2023.2033 and the 5.450% Notes due 2052.
4.210.1 
10.1
Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of September 30, 2017.2022.
10.222.1 
*
31.1
31.2
32.1
32.2
101
Interactive data files pursuant to Rule 405 of Regulation S-T:S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the three and nine months ended September 30, 20172022 and 2016;2021; (ii) our Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 20172022 and 2016;2021; (iii) our Consolidated Balance Sheets as of September 30, 20172022 and December 31, 2016;2021; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 20172022 and 2016;2021; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 20172022 and 2016;2021; and (vi) the notes to our Consolidated Financial Statements.
104 Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.
* Asterisk indicates exhibit incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.

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SIGNATURE


Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

KINDER MORGAN, INC.
Registrant

Date:October 20, 2017By:/s/ Kimberly A. DangKINDER MORGAN, INC.
Registrant
Kimberly A. Dang
Date:October 21, 2022By:/s/ David P. Michels
David P. Michels
Vice President and Chief Financial Officer

(principal financial and accounting officer)

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