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KINDER MORGAN, INC. - Quarter Report: 2021 September (Form 10-Q)


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
F O R M  10-Q  
 
☑  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2021
 
or
 
☐  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____to_____
 
Commission file number: 001-35081
kmi-20210930_g1.gif

KINDER MORGAN, INC.
(Exact name of registrant as specified in its charter)
 
Delaware80-0682103
(State or other jurisdiction of
incorporation or organization)		(I.R.S. Employer
Identification No.)
1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713-369-9000
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class P Common StockKMINew York Stock Exchange
1.500% Senior Notes due 2022KMI 22New York Stock Exchange
2.250% Senior Notes due 2027KMI 27 ANew York Stock Exchange
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No ☐
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes þ No ☐
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

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

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



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


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
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d=per dayEPA=U.S. Environmental Protection Agency
Bbl=barrelFASB=Financial Accounting Standards Board
BBtu=billion British Thermal Units FERC=Federal Energy Regulatory Commission
Bcf=billion cubic feetGAAP=U.S. Generally Accepted Accounting Principles
CERCLA=Comprehensive Environmental Response, Compensation and Liability ActLLC=limited liability company
LIBOR=London Interbank Offered Rate
CO2
=
carbon dioxide or our CO2 business segment
MBbl=thousand barrels
COVID-19=Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturnMMBbl=million barrels
MMtons=million tons
DCF=distributable cash flowNGL=natural gas liquids
DD&A=depreciation, depletion and amortization NYMEX=New York Mercantile Exchange
EBDA=earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investmentsOTC=over-the-counter
ROU=Right-of-Use
EBITDA=earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investmentsU.S.=United States of America
WTI=West Texas Intermediate


2

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “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 pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, our anticipated dividends, our proposed acquisition of Kinetrex Energy and our capital projects, including expected completion timing and benefits of the acquisition and those projects.

Important factors that could cause actual results to differ materially from those expressed in or implied by the forward-looking statements in this report include: the impacts of the COVID-19 pandemic and the pace and extent of economic recovery; the timing and extent of changes in the supply 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 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” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2020 (except to the 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 disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.

3

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.


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

 Three Months Ended
September 30,		Nine Months Ended
September 30,
 2021202020212020
Revenues 
Services$1,928 $1,881 $5,734 $5,664 
Commodity sales1,868 982 6,343 2,772 
Other28 56 108 149 
Total Revenues
3,824 2,919 12,185 8,585 
Operating Costs, Expenses and Other 
Costs of sales1,559 655 4,504 1,759 
Operations and maintenance614 643 1,710 1,869 
Depreciation, depletion and amortization526 539 1,595 1,636 
General and administrative174 153 490 461 
Taxes, other than income taxes106 100 324 295 
Loss on impairments and divestitures, net (Note 3)4 11 1,602 1,987 
Other income, net(3)(1)(6)(2)
Total Operating Costs, Expenses and Other
2,980 2,100 10,219 8,005 
Operating Income844 819 1,966 580 
Other Income (Expense) 
Earnings from equity investments169 194 392 562 
Amortization of excess cost of equity investments(21)(32)(56)(99)
Interest, net(368)(383)(1,122)(1,214)
Other, net (Note 3)21 14 264 32 
Total Other Expense
(199)(207)(522)(719)
Income (Loss) Before Income Taxes645 612 1,444 (139)
Income Tax Expense (134)(140)(248)(304)
Net Income (Loss) 511 472 1,196 (443)
Net Income Attributable to Noncontrolling Interests(16)(17)(49)(45)
Net Income (Loss) Attributable to Kinder Morgan, Inc.$495 $455 $1,147 $(488)
Class P Shares
Basic and Diluted Earnings (Loss) Per Share$0.22 $0.20 $0.50 $(0.22)
Basic and Diluted Weighted Average Shares Outstanding2,267 2,263 2,265 2,263 
The accompanying notes are an integral part of these consolidated financial statements.
4

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


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

 September 30, 2021December 31, 2020
ASSETS 
Current Assets 
Cash and cash equivalents$102 $1,184 
Restricted deposits177 25 
Accounts receivable1,433 1,293 
Fair value of derivative contracts199 185 
Inventories457 348 
Other current assets318 168 
Total current assets2,686 3,203 
Property, plant and equipment, net 35,576 35,836 
Investments7,620 7,917 
Goodwill20,033 19,851 
Other intangibles, net1,744 2,453 
Deferred income taxes303 536 
Deferred charges and other assets1,678 2,177 
Total Assets$69,640 $71,973 
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY  
Current Liabilities  
Current portion of debt $2,822 $2,558 
Accounts payable1,189 837 
Accrued interest332 525 
Accrued taxes284 267 
Accrued contingencies246 307 
Other current liabilities952 580 
Total current liabilities5,825 5,074 
Long-term liabilities and deferred credits  
Long-term debt  
Outstanding
28,988 30,838 
Debt fair value adjustments
1,014 1,293 
Total long-term debt30,002 32,131 
Other long-term liabilities and deferred credits2,160 2,202 
Total long-term liabilities and deferred credits32,162 34,333 
Total Liabilities37,987 39,407 
Commitments and contingencies (Notes 4 and 10)
Redeemable Noncontrolling Interest661 728 
Stockholders’ Equity  
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding
23 23 
Additional paid-in capital41,788 41,756 
Accumulated deficit(10,617)(9,936)
Accumulated other comprehensive loss(642)(407)
Total Kinder Morgan, Inc.’s stockholders’ equity30,552 31,436 
Noncontrolling interests440 402 
Total Stockholders’ Equity30,992 31,838 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity$69,640 $71,973 
The accompanying notes are an integral part of these consolidated financial statements.
6

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
 Nine Months Ended September 30,
 20212020
Cash Flows From Operating Activities 
Net income (loss)$1,196 $(443)
Adjustments to reconcile net income (loss) to net cash provided by operating activities 
Depreciation, depletion and amortization1,595 1,636 
Deferred income taxes236 164 
Amortization of excess cost of equity investments56 99 
Loss on impairments and divestitures, net (Note 3)1,602 1,987 
Gain on sale of interest in equity investment (Note 3)(206)— 
Earnings from equity investments(392)(562)
Distributions from equity investment earnings535 487 
Changes in components of working capital
Accounts receivable(119)238 
Inventories(89)41 
Other current assets(90)14 
Accounts payable362 (107)
Accrued interest, net of interest rate swaps(177)(208)
Accrued taxes15 (25)
Other current liabilities71 (93)
Rate reparations, refunds and other litigation reserve adjustments(97)48 
Other, net(58)6 
Net Cash Provided by Operating Activities4,440 3,282 
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired(1,518)(16)
Capital expenditures(894)(1,351)
Proceeds from sales of investments417 907 
Contributions to investments(36)(365)
Distributions from equity investments in excess of cumulative earnings121 105 
Other, net(1)(56)
Net Cash Used in Investing Activities(1,911)(776)
Cash Flows From Financing Activities
Issuances of debt 4,950 3,888 
Payments of debt (6,459)(3,991)
Debt issue costs(20)(23)
Dividends(1,828)(1,764)
Repurchases of shares— (50)
Contributions from investment partner and noncontrolling interests4 11 
Distributions to investment partner(67)(60)
Distributions to noncontrolling interests(14)(11)
Other, net(25)(13)
Net Cash Used in Financing Activities(3,459)(2,013)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits— (3)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits(930)490 
Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,209 209 
Cash, Cash Equivalents, and Restricted Deposits, end of period$279 $699 
7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
 Nine Months Ended September 30,
 20212020
Cash and Cash Equivalents, beginning of period$1,184 $185 
Restricted Deposits, beginning of period25 24 
Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,209 209 
Cash and Cash Equivalents, end of period102 632 
Restricted Deposits, end of period177 67 
Cash, Cash Equivalents, and Restricted Deposits, end of period279 699 
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits$(930)$490 
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized$35 $15 
Increase in property, plant and equipment from both accruals and contractor retainage4 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,313 1,440 
Cash paid during the period for income taxes, net8 202 
The accompanying notes are an integral part of these consolidated financial statements.
8

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

Common stock
 Issued sharesPar valueAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at June 30, 20212,265 $23 $41,793 $(10,496)$(609)$30,711 $429 $31,140 
Restricted shares
2 (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
 Issued sharesPar valueAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at June 30, 20202,261$23 $41,731 $(9,802)$(199)$31,753 $371 $32,124 
Restricted shares
35 5 5 
Net income455 455 17 472 
Distributions
— (4)(4)
Contributions
— 2 2 
Dividends(598)(598)(598)
Other comprehensive loss(56)(56)(56)
Balance at September 30, 20202,264$23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
The accompanying notes are an integral part of these consolidated financial statements.
9

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

Common stock
 Issued sharesPar valueAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at December 31, 20202,264 $23 $41,756 $(9,936)$(407)$31,436 $402 $31,838 
Restricted shares
3 32 32 32 
Net income1,147 1,147 49 1,196 
Distributions
— (14)(14)
Contributions
— 4 4 
Dividends(1,828)(1,828)(1,828)
Other
— (1)(1)
Other comprehensive loss(235)(235)(235)
Balance at September 30, 20212,267 $23 $41,788 $(10,617)$(642)$30,552 $440 $30,992 
Common stock
 Issued sharesPar valueAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Balance at December 31, 20192,265$23 $41,745 $(7,693)$(333)$33,742 $344 $34,086 
Repurchases of shares(4)(50)(50)(50)
Restricted shares
341 41 41 
Net (loss) income(488)(488)45 (443)
Distributions
— (11)(11)
Contributions
— 8 8 
Dividends(1,764)(1,764)(1,764)
Other comprehensive income78 78 78 
Balance at September 30, 20202,264$23 $41,736 $(9,945)$(255)$31,559 $386 $31,945 
The accompanying notes are an integral part of these consolidated financial statements.

10


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

1. General

Organization

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

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2020 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.

Goodwill

In 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 our May 31, 2021 evaluation, we grouped our businesses into six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; and (vi) Terminals. See Note 3 for results of our May 31, 2021 goodwill impairment test.

Earnings per Share

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

11


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

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions on a weighted average basis)
Unvested restricted stock awards13 13 13 13 
Convertible trust preferred securities3 3 3 3 

2. Acquisitions

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

Pro Forma Information

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

(1) Kinetrex Energy Acquisition

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



(2) Stagecoach Acquisition

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

Goodwill

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

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

13


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

We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and nine months ended September 30, 2021 and 2020:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)$— $— $1,600 $— 
Impairment of goodwill(a)— — — 1,000 
Gain on sale of interest in NGPL Holdings LLC(a)— — (206)— 
Loss on write-down of related party note receivable(a)— — 117 — 
Loss (gain) on divestitures of long-lived assets and other write-downs— 11 (1)11 
Products Pipelines
Impairment of long-lived and intangible assets— — — 21 
Terminals
Impairment of long-lived and intangible assets14 — 14 5 
CO2
Impairment of goodwill(a)— — — 600 
Impairment of long-lived assets(a)— — — 350 
Gain on divestitures of long-lived assets, net(11)— (8)— 
Other loss (gain) on divestitures of long-lived assets, net1 — (3)— 
Pre-tax loss on impairments, divestitures and other write-downs, net$4 $11 $1,513 $1,987 
(a)See below for a further discussion of these items.

Impairments

Long-lived Assets

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

During the first half of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment which resulted in a non-cash impairment of long-lived assets within our CO2 business segment shown in the above table during the nine months ended September 30, 2020.

Goodwill

The results of our May 31, 2021 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. The fair value estimates used in the goodwill impairment test are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect
14


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

During the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 and Natural Gas Pipelines business segments during the nine months ended September 30, 2020 as shown in the table above.

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

Sale of an Interest in NGPL Holdings

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

Other Write-downs

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

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4. Debt

The following table provides information on the principal amount of our outstanding debt balances:
September 30, 2021December 31, 2020
(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026(a)
$— $— 
$500 million credit facility due November 16, 2023(a)
— — 
Commercial paper notes160 — 
Current portion of senior notes
5.00%, due February 2021(b)
— 750 
3.50%, due March 2021(b)
— 750 
5.80%, due March 2021(b)
— 400 
5.00%, due October 2021(c)
— 500 
8.625%, due January 2022
260 — 
4.15%, due March 2022
375 — 
1.50%, due March 2022(d)
869 — 
3.95% due September 2022
1,000 — 
Trust I preferred securities, 4.75%, due March 2028
111 111 
Current portion of other debt47 47 
Total current portion of debt2,822 2,558 
Long-term debt (excluding current portion)
Senior notes28,306 30,141 
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035
353 364 
Trust I preferred securities, 4.75%, due March 2028
110 110 
Other219 223 
Total long-term debt28,988 30,838 
Total debt(e)$31,810 $33,396 
(a)On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.
(b)We repaid the principal amounts on these senior notes during the first quarter of 2021.
(c)These notes were repaid on July 1, 2021.
(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The September 30, 2021 balance is reported above at the exchange rate of 1.1580 U.S. dollars per Euro. As of September 30, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $54 million related to these notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance sheets. 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”).
(e)Excludes our “Debt fair value adjustments” which, as of September 30, 2021 and December 31, 2020, increased our total debt balances by $1,014 million and $1,293 million, respectively.

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

On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million. These notes are guaranteed through the cross guarantee agreement discussed above.

Credit Facilities and Restrictive Covenants

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


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

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

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

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

Fair Value of Financial Instruments

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

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

5. Stockholders’ Equity

Class P Stock

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

Dividends

The following table provides information about our per share dividends:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
Per share cash dividend declared for the period$0.27 $0.2625 $0.81 $0.7875 
Per share cash dividend paid in the period0.27 0.2625 0.8025 0.775 

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

Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2020$(13)$— $(394)$(407)
Other comprehensive (loss) gain before reclassifications(444)— 28 (416)
Loss reclassified from accumulated other comprehensive loss181 — — 181 
Net current-period change in accumulated other comprehensive loss(263)— 28 (235)
Balance as of September 30, 2021$(276)$— $(366)$(642)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Foreign
currency
translation
adjustments		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019$(7)$— $(326)$(333)
Other comprehensive (loss) gain before reclassifications(16)1 21 6 
Loss reclassified from accumulated other comprehensive loss72 — — 72 
Net current-period change in accumulated other comprehensive (loss) income56 1 21 78 
Balance as of September 30, 2020$49 $1 $(305)$(255)

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.

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Energy Commodity Price Risk Management

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

As of September 30, 2021, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2025.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2021:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)$7,100 Fair value hedgeMarch 2035
Variable-to-fixed interest rate contracts250 Cash flow hedgeJanuary 2023
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts6,250 Mark-to-MarketDecember 2022
(a)The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

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

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, 2021:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$1,358 Cash flow hedgeMarch 2027
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.
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The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
Fair Value of Derivative Contracts
Derivatives AssetDerivatives Liability
September 30,
2021		December 31,
2020		September 30,
2021		December 31,
2020
LocationFair valueFair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Other current liabilities)
$13 $42 $(256)$(33)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
1 33 (96)(8)
Subtotal14 75 (352)(41)
Interest rate contracts
Fair value of derivative contracts/(Other current liabilities)
127 119 (4)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
350 575 (14)(7)
Subtotal477 694 (18)(10)
Foreign currency contracts
Fair value of derivative contracts/(Other current liabilities)
49 — (6)(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
20 138 — — 
Subtotal69 138 (6)(6)
Total560 907 (376)(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Other current liabilities)
10 24 (63)(21)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
4 — (3)— 
Subtotal14 24 (66)(21)
Interest rate contracts
Fair value of derivative contracts/(Other current liabilities)
— — (1)— 
 
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
1 — — — 
Subtotal1 — (1)— 
Total15 24 (67)(21)
Total derivatives$575 $931 $(443)$(78)
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The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
Balance sheet asset fair value measurements by level

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

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


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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,
2021202020212020
(In millions)(In millions)
Energy commodity derivative contracts
$(140)$(143)
Revenues—Commodity sales
$(94)$(47)
Costs of sales
8 (7)
Interest rate contracts
1 — Earnings from equity investments(c)— (1)
Foreign currency contracts
(33)70 
Other, net
(34)61 
Total$(172)$(73)Total$(120)$6 
Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions)(In millions)
Energy commodity derivative contracts
$(514)$(29)
Revenues—Commodity sales
$(167)$(145)
Costs of sales
10 (12)
Interest rate contracts
3 (9)Earnings from equity investments(c)— (1)
Foreign currency contracts(68)17 Other, net(79)64 
Total$(579)$(21)Total$(236)$(94)
(a)We expect to reclassify approximately $181 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2021 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the nine months ended September 30, 2021, we recognized gains of $6 million associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).

Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$(40)$87 $(703)$353 
Costs of sales
(7)12 154 18 
Earnings from equity investments(2)— (4)— 
Total(a)$(49)$99 $(553)$371 
(a)The three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480 million, respectively, and the three and nine months ended September 30, 2020 amounts include approximate gains of $96 million and $349 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

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

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

7. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
Three Months Ended September 30, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with 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 contracts with 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 
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Three Months Ended September 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$818 $69 $185 $1 $(2)$1,071 
Fee-based services173 228 91 8 3 503 
Total services991 297 276 9 1 1,574 
Commodity sales
Natural gas sales507 — — 1 (2)506 
Product sales158 97 5 180 (5)435 
Total commodity sales665 97 5 181 (7)941 
Total revenues from contracts with customers1,656 394 281 190 (6)2,515 
Other revenues(c)
Leasing services(d)119 42 143 13 — 317 
Derivatives adjustments on commodity sales
(6)— — 46 — 40 
Other40 6 — 2 (1)47 
Total other revenues153 48 143 61 (1)404 
Total revenues$1,809 $442 $424 $251 $(7)$2,919 
Nine Months Ended September 30, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$2,501 $191 $570 $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 contracts with customers8,975 1,429 848 811 (47)12,016 
Other revenues(c)
Leasing services(d)356 128 427 42 — 953 
Derivatives adjustments on commodity sales(726)(1)— (143)— (870)
Other51 16 — 19 — 86 
Total other revenues(319)143 427 (82)— 169 
Total revenues$8,656 $1,572 $1,275 $729 $(47)$12,185 

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Nine Months Ended September 30, 2020
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$2,479 $215 $563 $1 $(2)$3,256 
Fee-based services523 670 307 31 1 1,532 
Total services3,002 885 870 32 (1)4,788 
Commodity sales
Natural gas sales1,385 — — 1 (5)1,381 
Product sales396 255 11 546 (22)1,186 
Total commodity sales1,781 255 11 547 (27)2,567 
Total revenues from contracts with customers4,783 1,140 881 579 (28)7,355 
Other revenues(c)
Leasing services(d)346 126 404 34 — 910 
Derivatives adjustments on commodity sales35 — — 173 — 208 
Other91 16 — 6 (1)112 
Total other revenues472 142 404 213 (1)1,230 
Total revenues$5,255 $1,282 $1,285 $792 $(29)$8,585 

(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 6 for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

As of September 30, 2021 and December 31, 2020, our contract asset balances were $62 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $14 million was transferred to accounts receivable during the nine months ended September 30, 2021. As of September 30, 2021 and December 31, 2020, our contract liability balances were $217 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $63 million was recognized as revenue during the nine months ended September 30, 2021.

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Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:
YearEstimated Revenue
(In millions)
Three months ended December 31, 2021$1,178 
20224,022 
20233,186 
20242,711 
20252,277 
Thereafter14,018 
Total$27,392 

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical 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,
2021202020212020
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers$2,541 $1,803 $8,611 $5,229 
Intersegment revenues14 6 45 26 
Products Pipelines605 442 1,572 1,282 
Terminals
Revenues from external customers421 423 1,273 1,282 
Intersegment revenues1 1 2 3 
CO2
257 251 729 792 
Corporate and intersegment eliminations(15)(7)(47)(29)
Total consolidated revenues$3,824 $2,919 $12,185 $8,585 
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Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions)
Segment EBDA(a)
Natural Gas Pipelines$1,069 $1,091 $2,602 $2,284 
Products Pipelines279 223 792 719 
Terminals216 246 689 732 
CO2
163 156 599 (453)
Total Segment EBDA1,727 1,716 4,682 3,282 
DD&A(526)(539)(1,595)(1,636)
Amortization of excess cost of equity investments(21)(32)(56)(99)
General and administrative and corporate charges(167)(150)(465)(472)
Interest, net (368)(383)(1,122)(1,214)
Income tax expense(134)(140)(248)(304)
Total consolidated net income (loss)$511 $472 $1,196 $(443)
September 30, 2021December 31, 2020
(In millions)
Assets
Natural Gas Pipelines$47,576 $48,597 
Products Pipelines9,118 9,182 
Terminals8,507 8,639 
CO2
2,808 2,478 
Corporate assets(b)1,631 3,077 
Total consolidated assets$69,640 $71,973 
(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

9.  Income Taxes

Income tax expense included in our accompanying consolidated statements of operations is as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions, except percentages)
Income tax expense$134 $140 $248 $304 
Effective tax rate20.8 %22.9 %17.2 %(218.7)%
The effective tax rate for the three months ended September 30, 2021 is slightly lower than the statutory federal rate of 21% primarily due to dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

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

The effective tax rate for the nine months ended September 30, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus, NGPL Holdings and PPL, partially offset by state income taxes.
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The effective tax rate for the nine months ended September 30, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to the $1,600 million impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit. This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus and PPL.

While we would normally expect a federal income tax benefit from our loss before income taxes for the nine months ended September 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for these periods.

10.   Litigation and Environmental

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

SFPP FERC Proceedings

The FERC approved the SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the EL Settlement were fully accrued on or before December 31, 2020.

The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two-year period preceding the filing date of their complaints and/or prospective refunds in protest cases from the date of protest, and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings at the FERC that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million in rate refunds and unspecified rate reductions as of the date of their complaints in 2014 and 2018. The claims pleaded by the shippers are expected to change due to the passage of time and interest. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. We do not believe the ultimate resolution of the shipper complaints and protests seeking rate reductions or refunds in the ongoing proceedings will have a material adverse impact on our business.

Gulf LNG Facility Disputes

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

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

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. Eni USA’s second arbitration sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the second arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from pursuing the second arbitration, including the breach of contract and negligent misrepresentation claims therein. On October 4, 2021, the U.S. Supreme Court denied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration and the claims asserted therein.

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

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

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

Freeport LNG Winter Storm Litigation

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

Pipeline Integrity and Releases

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

General

As of September 30, 2021 and December 31, 2020, our total reserve for legal matters was $192 million and $273 million, respectively.

Environmental Matters

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

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

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

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

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

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

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Uranium Mines in Vicinity of Cameron, Arizona

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

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

EPEC Polymers, Inc. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River in New Jersey. EPEC entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. EPEC is part of a joint defense group of approximately 44 cooperating parties which is directing and funding the AOC work required by the EPA. We have established a reserve for the anticipated cost of compliance with these two AOCs. On March 4, 2016, the EPA issued a Record of Decision (ROD) for the lower eight miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, engaged in an allocation process for 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 thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the remedy 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 our share of the costs to resolve this matter, including the costs of any remediation of the Site, will have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

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

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

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

Louisiana Landowner Coastal Erosion Litigation

Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including four cases against TGP, three cases against SNG, and one case against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. We will continue to vigorously defend the remaining cases.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of September 30, 2021 and December 31, 2020, we have accrued a total reserve for environmental liabilities in the amount of $242 million and $250 million, respectively. In addition, as of both September 30, 2021 and December 31, 2020, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.

11. Recent Accounting Pronouncements

Reference Rate Reform (Topic 848)

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

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

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

ASU No. 2020-06

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

ASU No. 2021-05

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

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

General and Basis of Presentation

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

Long-lived Asset Impairment

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

Stagecoach Acquisition

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

Kinetrex Energy Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets are included as part of our new Energy Transition Ventures group within our CO2 business segment.

Sale of an Interest in NGPL Holdings LLC

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

February 2021 Winter Storm

Our year-to-date earnings reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below. Some of the transactions executed during the winter storm remain subject to risks, including counterparty financial risk, potential disputed purchases and sales and potential legislative or regulatory action in response to, or litigation arising out of, the unprecedented circumstances of the winter storm, which could adversely affect our future earnings, cash flows and financial condition.

2021 Dividends and Discretionary Capital

We expect to declare dividends of $1.08 per share for 2021, a 3% increase from the 2020 declared dividends of $1.05 per share. Excluding the recent acquisitions, we expect to invest $0.8 billion in expansion projects and contributions to joint ventures during 2021.

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The expectations for 2021 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.

Results of Operations

Overview

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

GAAP Financial Measures

The Consolidated Earnings Results for the three and nine months ended September 30, 2021 and 2020 present Segment EBDA and Net income (loss) attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures

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

Certain Items

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

Adjusted Earnings

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

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DCF

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

Adjusted Segment EBDA

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

Adjusted EBITDA

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

Amounts from Joint Ventures

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

Net Debt

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

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Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.
Three Months Ended
September 30,
20212020Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$1,069 $1,091 $(22)(2)%
Products Pipelines279 223 56 25 %
Terminals216 246 (30)(12)%
CO2
163 156 7 4 %
Total Segment EBDA1,727 1,716 11 1 %
DD&A(526)(539)13 2 %
Amortization of excess cost of equity investments(21)(32)11 34 %
General and administrative and corporate charges(167)(150)(17)(11)%
Interest, net(368)(383)15 4 %
Income before income taxes645 612 33 5 %
Income tax expense(134)(140)6 4 %
Net income511 472 39 8 %
Net income attributable to noncontrolling interests(16)(17)1 6 %
Net income attributable to Kinder Morgan, Inc.$495 $455 $40 9 %

Nine Months Ended September 30,
20212020Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$2,602 $2,284 $318 14 %
Products Pipelines792 719 73 10 %
Terminals689 732 (43)(6)%
CO2
599 (453)1,052 232 %
Total Segment EBDA4,682 3,282 1,400 43 %
DD&A(1,595)(1,636)41 3 %
Amortization of excess cost of equity investments(56)(99)43 43 %
General and administrative and corporate charges(465)(472)7 1 %
Interest, net(1,122)(1,214)92 8 %
Income (loss) before income taxes1,444 (139)1,583 1,139 %
Income tax expense(248)(304)56 18 %
Net income (loss)1,196 (443)1,639 370 %
Net income attributable to noncontrolling interests(49)(45)(4)(9)%
Net income (loss) attributable to Kinder Morgan, Inc.$1,147 $(488)$1,635 335 %
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

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Net income attributable to Kinder Morgan, Inc. increased $40 million and $1,635 million for the three and nine months ended September 30, 2021, respectively, as compared to the respective prior year periods. The third quarter increase in results were impacted by higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals and Natural Gas Pipelines business segments and higher general and administrative and corporate charges expense. The year-to-date increase was primarily impacted by higher earnings from our Natural Gas Pipelines and CO2 business segments primarily related to the February 2021 winter storm and therefore largely nonrecurring, and a decrease of $362 million of impairments in 2021 as compared to 2020 primarily reflecting the $1,600 million pre-tax non-cash asset impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in 2021 compared to the combined $1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO2 business segment. The impacts of the long-lived asset impairments for both periods were partially offset by associated tax benefits. The year-to-date increase was also impacted by higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals business segment.

Certain Items Affecting Consolidated Earnings Results
Three Months Ended September 30,
20212020
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$1,069 $21 $1,090 $1,091 $(9)$1,082 $8 
Products Pipelines279 1 280 223 46 269 11 
Terminals216 17 233 246 — 246 (13)
CO2
163 (9)154 156 (2)154 — 
Total Segment EBDA(a)1,727 30 1,757 1,716 35 1,751 6 
DD&A and amortization of excess cost of equity investments(547)— (547)(571)— (571)24 
General and administrative and corporate charges(a)(167)— (167)(150)11 (139)(28)
Interest, net(a)(368)(8)(376)(383)(8)(391)15 
Income before income taxes645 22 667 612 38 650 17 
Income tax expense(b)(134)(12)(146)(140)(8)(148)2 
Net income511 10 521 472 30 502 19 
Net income attributable to noncontrolling interests(a)(16)— (16)(17)— (17)1 
Net income attributable to Kinder Morgan, Inc.$495 $10 $505 $455 $30 $485 $20 

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Nine Months Ended September 30,
20212020
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$2,602 $1,646 $4,248 $2,284 $993 $3,277 $971 
Products Pipelines792 44 836 719 50 769 67 
Terminals689 17 706 732 — 732 (26)
CO2
599 (3)596 (453)938 485 111 
Total Segment EBDA(a)4,682 1,704 6,386 3,282 1,981 5,263 1,123 
DD&A and amortization of excess cost of equity investments(1,651)— (1,651)(1,735)— (1,735)84 
General and administrative and corporate charges(a)(465)— (465)(472)36 (436)(29)
Interest, net(a)(1,122)(17)(1,139)(1,214)(8)(1,222)83 
Income (loss) before income taxes1,444 1,687 3,131 (139)2,009 1,870 1,261 
Income tax expense(b)(248)(439)(687)(304)(114)(418)(269)
Net income (loss)1,196 1,248 2,444 (443)1,895 1,452 992 
Net income attributable to noncontrolling interests(a)(49)— (49)(45)— (45)(4)
Net income (loss) attributable to Kinder Morgan, Inc.$1,147 $1,248 $2,395 $(488)$1,895 $1,407 $988 
(a)For a more detailed discussion of Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(b)The combined net effect of the income tax Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

Net income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) increased by $20 million and $988 million for the three and nine months ended September 30, 2021, respectively, as compared to the respective prior year periods. The third quarter increase was primarily due to higher earnings from our Products Pipelines and Natural Gas Pipelines business segments and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment. The year-to-date increase was impacted by higher earnings from our Natural Gas Pipelines and CO2 business segments primarily related to the February 2021 winter storm, and therefore largely nonrecurring, higher earnings from our Products Pipelines business segment and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment.

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Non-GAAP Financial Measures

Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Three Months Ended
September 30,		Nine Months Ended September 30,
2021202020212020
(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)$495 $455 $1,147 $(488)
Total Certain Items10 30 1,248 1,895 
Adjusted Earnings(a)505 485 2,395 1,407 
DD&A and amortization of excess cost of equity investments for DCF(b)612 662 1,854 2,012 
Income tax expense for DCF(a)(b)165 171 754 484 
Cash taxes(b)(12)(49)(56)(57)
Sustaining capital expenditures(b)(241)(177)(558)(477)
Other items(c)(16)(7)(22)(22)
DCF$1,013 $1,085 $4,367 $3,347 

Adjusted Segment EBDA to Adjusted EBITDA to DCF
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions, except per share amounts)
Natural Gas Pipelines$1,090 $1,082 $4,248 $3,277 
Products Pipelines280 269 836 769 
Terminals233 246 706 732 
CO2
154 154 596 485 
Adjusted Segment EBDA(a)1,757 1,751 6,386 5,263 
General and administrative and corporate charges(a)(167)(139)(465)(436)
Joint venture DD&A and income tax expense(a)(b)84 114 270 343 
Net income attributable to noncontrolling interests(a)(16)(17)(49)(45)
Adjusted EBITDA1,658 1,709 6,142 5,125 
Interest, net(a)(376)(391)(1,139)(1,222)
Cash taxes(b)(12)(49)(56)(57)
Sustaining capital expenditures(b)(241)(177)(558)(477)
Other items(c)(16)(7)(22)(22)
DCF$1,013 $1,085 $4,367 $3,347 
Adjusted Earnings per share$0.22 $0.21 $1.05 $0.62 
Weighted average shares outstanding for dividends(d)2,279 2,276 2,278 2,276 
DCF per share$0.44 $0.48 $1.92 $1.47 
Declared dividends per share$0.27 $0.2625 $0.81 $0.7875 
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.
(b)Includes or represents DD&A, 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.
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Reconciliation of Net Income (Loss) Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)(a)$495 $455 $1,147 $(488)
Certain Items:
Fair value amortization(7)(5)(15)(17)
Legal, environmental and taxes other than income tax reserves— 46 112 38 
Change in fair value of derivative contracts(b)22 (6)64 (10)
Loss on impairments, divestitures and other write-downs, net(c)4 11 1,515 382 
Loss on impairments of goodwill(d)— — — 1,600 
COVID-19 costs— 11 — 11 
Income tax Certain Items(12)(8)(439)(114)
Other3 (19)11 5 
Total Certain Items(e)10 30 1,248 1,895 
DD&A and amortization of excess cost of equity investments547 571 1,651 1,735 
Income tax expense(f)146 148 687 418 
Joint venture DD&A and income tax expense(f)(g)84 114 270 343 
Interest, net(f)376 391 1,139 1,222 
Adjusted EBITDA$1,658 $1,709 $6,142 $5,125 
(a)In prior periods, Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.
(b)Gains or losses are reflected in our DCF when realized.
(c)Three and nine months ended September 30, 2021 amounts include a non-cash impairment of $14 million related to the reclassification of an asset to held for sale within our Terminals business segment, offset partially by a gain of $10 million on the sale of assets within our CO2 business segment. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from lower expectations regarding the volumes and rates associated with re-contracting and a write-down of $117 million, reported within “Earnings from equity investments” on the accompanying consolidated statement of operations, on a long-term subordinated note receivable from an equity investee, Ruby, offset partially by a pre-tax gain of $206 million, reported within “Other, net” on the accompanying consolidated statement of operations, associated with the sale of a partial interest in our equity investment in NGPL Holdings. Nine months ended September 30, 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment. Except as otherwise noted above, these amounts are reported within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of operations.
(d)Nine months ended September 30, 2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, respectively.
(e)Three months ended September 30, 2021 and 2020 amounts include $2 million and $(4) million, respectively, and nine months ended September 30, 2021 and 2020 amounts include $129 million and $(4) million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.
(f)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
(g)Represents joint venture DD&A and income tax expense. See tables included in “—Supplemental Information” below.

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Supplemental Information
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions)
DD&A (GAAP)$526 $539 $1,595 $1,636 
Amortization of excess cost of equity investments (GAAP)21 32 56 99 
DD&A and amortization of excess cost of equity investments547 571 1,651 1,735 
Joint venture DD&A65 91 203 277 
DD&A and amortization of excess cost of equity investments for DCF$612 $662 $1,854 $2,012 
Income tax expense (GAAP)$134 $140 $248 $304 
Certain Items12 8 439 114 
Income tax expense(a)146 148 687 418 
Unconsolidated joint venture income tax expense(a)(b)19 23 67 66 
Income tax expense for DCF(a)$165 $171 $754 $484 
Additional joint venture information
Unconsolidated joint venture DD&A$76 $101 $236 $306 
Less: Consolidated joint venture partners’ DD&A11 10 33 29 
Joint venture DD&A65 91 203 277 
Unconsolidated joint venture income tax expense(a)(b)19 23 67 66 
Joint venture DD&A and income tax expense(a)$84 $114 $270 $343 
Unconsolidated joint venture cash taxes(b)$(13)$(41)$(47)$(51)
Unconsolidated joint venture sustaining capital expenditures$(29)$(32)$(81)$(84)
Less: Consolidated joint venture partners’ sustaining capital expenditures(2)(2)(5)(4)
Joint venture sustaining capital expenditures$(27)$(30)$(76)$(80)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments.

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Segment Earnings Results

Natural Gas Pipelines
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions, except operating statistics)
Revenues$2,555 $1,809 $8,656 $5,255 
Operating expenses(1,634)(878)(4,981)(2,455)
Loss on impairments and divestitures, net— (11)(1,599)(1,011)
Other income— — 2 1 
Earnings from equity investments144 169 311 484 
Other, net4 2 213 10 
Segment EBDA1,069 1,091 2,602 2,284 
Certain Items(a)21 (9)1,646 993 
Adjusted Segment EBDA$1,090 $1,082 $4,248 $3,277 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$8 $971 
Volumetric data(b)
Transport volumes (BBtu/d)38,527 37,475 38,593 37,887 
Sales volumes (BBtu/d)2,616 2,382 2,480 2,330 
Gathering volumes (BBtu/d)2,808 2,925 2,662 3,109 
NGLs (MBbl/d)29 22 30 27 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $21 million and $1,646 million for the three and nine months ended September 30, 2021, respectively, and $(9) million and $993 million for the three and nine months ended September 30, 2020, respectively. 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 resulting from lower expectations regarding the volumes and rates associated with re-contracting 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. Three and nine months ended September 30, 2020 amounts both include an increase in revenues of $(14) million of amortization of regulatory liabilities, largely offset by non-cash amounts related to mark-to-market derivative contracts. Nine months ended September 30, 2020 amount also includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit.
Other
(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented. Volumes for acquired pipelines are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

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Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Midstream$29 11%
East Region8 1%
West Region(29)(11)%
Total Natural Gas Pipelines$8 1 %

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Midstream$998 123%
East Region25 1%
West Region(52)(7)%
Total Natural Gas Pipelines$971 30 %

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:
•$29 million (11%) and $998 million (123%) increases, respectively, in Midstream were primarily due to (i) higher equity earnings due to the Permian Highway Pipeline being placed in service in January 2021; (ii) higher sales margins driven by higher commodity prices on our Texas intrastate natural gas pipeline operations; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets. The year-to-date increase was also impacted by higher commodity prices as a result of the February 2021 winter storm on our South Texas assets and Texas intrastate natural gas pipeline operations partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations on our Oklahoma assets. Overall Midstream’s revenues increased primarily due to higher commodity prices which was partially offset by corresponding increases in costs of sales;
•$8 million (1%) and $25 million (1%) increases, respectively, in the East Region were primarily due to our July 2021 acquisition of the Stagecoach assets partially offset by lower earnings on Fayetteville Express Pipeline LLC driven by lower revenues resulting from contract expirations. The year-to-date increase was also impacted by higher earnings from TGP due to weather-driven increases in reservation and park and loan revenues mostly during the first quarter of 2021 and increased earnings from Elba Liquefaction Company, L.L.C. resulting from the liquefaction units of the Elba Liquefaction project being fully operational as of August 2020; and
•$29 million (11%) and $52 million (7%) decreases, respectively, in the West Region were primarily due to lower earnings from Wyoming Interstate Company, LLC, Colorado Interstate Gas Company, L.L.C. and Cheyenne Plains Gas Pipeline Company, L.L.C. driven by lower revenues due to contract expirations and lower equity earnings from Ruby. The third quarter decrease was also impacted by lower earnings from EPNG driven by lower park and loan revenues.

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

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Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
West Coast Refined Products$17 15 %
Southeast Refined Products6 10 %
Crude and Condensate(12)(12)%
Total Products Pipelines$11 4 %

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
West Coast Refined Products$38 11 %
Southeast Refined Products39 25 %
Crude and Condensate(10)(4)%
Total Products Pipelines$67 9 %

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:
•$17 million (15%) and $38 million (11%) increases, respectively, in West Coast Refined Products were primarily due to increased earnings on Pacific (SFPP), and to a lesser extent, on Calnev Pipe Line LLC and West Coast terminals driven by higher revenues from the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expense primarily as a result of higher integrity management spending on SFPP;
•$6 million (10%) and $39 million (25%) increases, respectively, in Southeast Refined Products were primarily due to South East Terminals resulting from increased revenues from higher volumes driven by continued recovery of volumes from 2020. The year-to-date increase was also driven by higher 2021 earnings at our Transmix processing operations primarily due to higher prices and first quarter 2020 unfavorable inventory adjustments, and an increase in equity earnings from Products (SE) Pipe Line primarily due to product net gains resulting from higher prices; and
•$12 million (12%) and $10 million (4%) decreases, respectively, in Crude and Condensate were primarily due to decreased earnings from the Bakken Crude assets and KM Condensate Processing Facility (KMCC - Splitter) partially offset by increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC). The Bakken Crude assets’ decreased earnings were driven by lower volumes, contracts renewed at lower average rates, and contract expirations partially offset by lower field operating expenses. KMCC - Splitter’s decreased earnings were driven by higher field maintenance expenses. KMCC’s increased earnings were primarily due to higher deficiency revenues and lower field operating expense partially offset by contract expirations. Bakken Crude assets’ and KMCC’s year-to-date changes respectively, were also impacted by first quarter 2020 unfavorable inventory valuation adjustments. In addition, increased marketing activities within KMCC have resulted in third quarter and year-to-date increases in revenues with corresponding increases in cost of sales.
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Terminals
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions, except operating statistics)
Revenues$422 $424 $1,275 $1,285 
Operating expenses(200)(185)(588)(570)
Loss on impairments and divestitures, net(14)— (14)(5)
Other income4 — 4 — 
Earnings from equity investments3 7 10 19 
Other, net1 — 2 3 
Segment EBDA216 246 689 732 
Certain Items(a)17 — 17 — 
Adjusted Segment EBDA$233 $246 $706 $732 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$(13)$(26)
Volumetric data(b)
Liquids leasable capacity (MMBbl)79.9 79.6 79.9 79.6 
Liquids utilization %(c)94.2 %96.3 %94.2 %96.3 %
Bulk transload tonnage (MMtons)13.5 11.3 38.1 35.4 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $17 million for both three and nine months ended September 30, 2021 primarily resulting from a pre-tax non-cash impairment loss of $14 million related to the reclassification of an asset to held for sale.
Other
(b)Volumes for assets sold are excluded for all periods presented.
(c)The ratio of our tankage capacity in service to tankage capacity available for service.

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Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Marine operations$(15)(29)%
Gulf Central5 19 %
Mid Atlantic4 40 %
Northeast(2)(7)%
All others (including intrasegment eliminations)(5)(4)%
Total Terminals$(13)(5)%

Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Marine operations$(39)(25)%
Gulf Central(7)(8)%
Mid Atlantic8 21 %
Northeast9 13 %
All others (including intrasegment eliminations)3 1 %
Total Terminals$(26)(4)%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:
•$15 million (29%) and $39 million (25%) decreases, respectively, in Marine operations were primarily due to lower fleet utilization and average charter rates;
•$5 million (19%) increase and $7 million (8%) decrease, respectively, in the Gulf Central terminals. The third quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol, petroleum coke, and coal volumes. The year-to-date decrease in earnings was primarily driven by unfavorable petroleum coke volumes due to refinery outages associated with the February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC;
•$4 million (40%) and $8 million (21%) increases, respectively, in the Mid Atlantic terminals were primarily due to higher coal volumes at our Pier IX facility; and
•$2 million (7%) decrease and $9 million (13%) increase, respectively, in the Northeast terminals. The year-to-date increase was primarily driven by increased revenues associated with higher throughput levels and new contracts.
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CO2
Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
(In millions, except operating statistics)
Revenues$257 $251 $729 $792 
Operating expenses(112)(99)(161)(312)
Gain (loss) on impairments and divestitures, net11 — 8 (950)
Earnings from equity investments7 4 23 17 
Segment EBDA163 156 599 (453)
Certain Items(a)(9)(2)(3)938 
Adjusted Segment EBDA$154 $154 $596 $485 
Change from prior periodIncrease/(Decrease)
Adjusted Segment EBDA$— $111 
Volumetric data
SACROC oil production20.1 21.2 19.9 22.1 
Yates oil production6.5 6.4 6.5 6.7 
Katz and Goldsmith oil production2.1 2.6 2.3 2.8 
Tall Cotton oil production1.1 1.4 1.0 1.9 
Total oil production, net (MBbl/d)(b)29.8 31.6 29.7 33.5 
NGL sales volumes, net (MBbl/d)(b)9.7 9.1 9.3 9.4 
CO2 sales volumes, net (Bcf/d)
0.4 0.4 0.4 0.5 
Realized weighted average oil price ($ per Bbl)$53.03 $54.83 $52.21 $53.28 
Realized weighted average NGL price ($ per Bbl)$28.01 $17.65 $23.73 $17.77 
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $(9) million and $(3) million for the three and nine months ended September 30, 2021, respectively, and $(2) million and $938 million for the three and nine months ended September 30, 2020, respectively. Nine month 2020 amount primarily resulted from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on our oil and gas producing assets.
Other
(b)Net of royalties and outside working interests.

Below are the changes in Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021 versus Three Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$(42)(40)%
Source and Transportation activities40 82 %
Subtotal(2)(1)%
Energy Transition Ventures2 n/a
Total CO2
$— — %

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Nine Months Ended September 30, 2021 versus Nine Months Ended September 30, 2020

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$73 23 %
Source and Transportation activities36 22 %
Subtotal109 22 %
Energy Transition Ventures2 n/a
Total CO2
$111 23 %
n/a - not applicable

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

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

Remaining 20212022202320242025
Crude Oil(a)
Price ($ per Bbl)$50.38 $53.41 $51.70 $50.97 $52.19 
Volume (MBbl/d)25.70 17.00 11.20 5.90 2.85 
NGLs
Price ($ per Bbl)$36.39 $47.76 
Volume (MBbl/d)6.03 2.56 
Midland-to-Cushing Basis Spread
Price ($ per Bbl)$0.26 $0.59 
Volume (MBbl/d)24.55 14.00 
(a)Includes West Texas Intermediate hedges.

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

Three Months Ended
September 30,		Earnings
increase/(decrease)
20212020
(In millions, except percentages)
DD&A (GAAP)$(526)$(539)$13 2 %
General and administrative (GAAP)$(174)$(153)$(21)(14)%
Corporate benefit7 3 4 133 %
Certain Items(a)— 11 (11)(100)%
General and administrative and corporate charges(b)$(167)$(139)$(28)(20)%
Interest, net (GAAP)$(368)$(383)$15 4 %
Certain Items(c)(8)(8)— — %
Interest, net(b)$(376)$(391)$15 4 %
Net income attributable to noncontrolling interests (GAAP)$(16)$(17)$1 6 %
Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)$(16)$(17)$1 6 %

Nine Months Ended September 30,Earnings
increase/(decrease)
20212020
(In millions, except percentages)
DD&A (GAAP)$(1,595)$(1,636)$41 3 %
General and administrative (GAAP)$(490)$(461)$(29)(6)%
Corporate benefit (charges)25 (11)36 327 %
Certain Items(a)— 36 (36)(100)%
General and administrative and corporate charges(b)$(465)$(436)$(29)(7)%
Interest, net (GAAP)$(1,122)$(1,214)$92 8 %
Certain Items(c)(17)(8)(9)(113)%
Interest, net(b)$(1,139)$(1,222)$83 7 %
Net income attributable to noncontrolling interests (GAAP)$(49)$(45)$(4)(9)%
Certain Items(d)— — — — %
Net income attributable to noncontrolling interests(b)$(49)$(45)$(4)(9)%
Certain items
(a)Three and nine month 2020 amounts both include an increase in expense of $11 million related to costs incurred associated with COVID-19 mitigation. Nine month 2020 amount also includes an increase in expense of $23 million associated with the non-cash fair value adjustment of and the dividend accrual prior to the sale of our investment in Pembina common stock.
(b)Amounts are adjusted for Certain Items.
(c)Three and nine month 2021 amounts include decreases in interest expense of $7 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and nine month 2020 amounts include (i) decreases in interest expense of $5 million and $17 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) a decrease in expense of $3 million and an increase in expense of $11 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.
(d)Three and nine months ended September 30, 2021 and 2020 amounts each include less than $1 million of noncontrolling interests associated with Certain Items.
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General and administrative expenses and corporate charges adjusted for Certain Items for the three and nine months ended September 30, 2021 when compared with the respective prior year periods increased $28 million and $29 million, respectively, primarily due to lower capitalized costs of $18 million and $41 million, respectively, reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment, non-recurring cost savings realized in the 2020 period as a result of the global pandemic of $10 million and $17 million, respectively, and higher benefit-related costs of $10 million and $16 million, respectively, partially offset by $12 million and $36 million, respectively, of cost savings in the 2021 period associated with organizational efficiency efforts, and lower pension costs of $4 million and $14 million, respectively.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our consolidated interest expense, net adjusted for Certain Items for the three and nine months ended September 30, 2021 when compared with the respective prior year periods decreased $15 million and $83 million, respectively, primarily due to lower long-term debt balances, lower LIBOR rates, and lower long-term interest rates, partially offset by lower capitalized interest.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of September 30, 2021 and December 31, 2020, approximately 15% and 16%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The percentage at September 30, 2021 includes our variable-to-fixed interest rate derivative contracts not designated as hedging instruments which hedge our exposure through 2021. For more information on our interest rate swaps, see Note 6 “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.

Income Taxes

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

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

Liquidity and Capital Resources

General

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

We have consistently generated substantial cash flows from operations, providing a source of funds of $4,440 million and $3,282 million in the first nine months of 2021 and 2020, respectively. The period-to-period increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.

Our board of directors declared a quarterly dividend of $0.27 per share for the third quarter of 2021, consistent with the dividend declared for the previous quarter. We expect to fully fund our dividend payments as well as our discretionary spending for 2021 without funding from the capital markets.
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On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million which were used to repay maturing senior notes.

On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 and amended our existing facility (the “Existing Facility”) to reduce the borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder (together, the “Credit Facilities”).

Short-term Liquidity

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

As of September 30, 2021, our $2,822 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through cash on hand, credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2020 was $2,558 million.

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

Counterparty Creditworthiness

Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices, or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. The balance of our allowance for credit losses as of September 30, 2021 and December 31, 2020, was $2 million and $26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets.

Capital Expenditures

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

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

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

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2020 in our 2020 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2021 and December 31, 2020 were $201 million and $141 million, respectively. The increase of $60 million was primarily driven by capital commitments related to our Terminals business segment.

Cash Flows

Operating Activities

Cash provided by operating activities increased $1,158 million in the nine months ended September 30, 2021 compared to the respective 2020 period primarily due to:

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

Investing Activities

Cash used in investing activities increased $1,135 million for the nine months ended September 30, 2021 compared to the respective 2020 period primarily attributable to:

•a $1,502 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,197 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 2 “Acquisitions” to our consolidated financial statements for further information regarding these transactions; and
•a $490 million decrease in cash primarily due to $412 million of net proceeds received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period, versus the $907 million of proceeds received from the sale of Pembina shares in the 2020 period. See Note 3 “Losses and Gains on Impairments, Divestitures and Other Write-downs” to our consolidated financial statements for further information regarding the transaction of the sale of an interest in NGPL Holdings; partially offset by,
•a $457 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and
•a $329 million decrease in cash used for contributions to equity investees driven primarily by lower contributions to Permian Highway Pipeline LLC and SNG in the 2021 period compared with the 2020 period.

Financing Activities

Cash used in financing activities increased $1,446 million for the nine months ended September 30, 2021 compared to the respective 2020 period primarily attributable to:

•a $1,403 million net increase in cash used related to debt activity as a result of higher net debt payments in the 2021 period compared to the 2020 period.

Dividends

We expect to declare dividends of $1.08 per share on our stock for 2021. The table below reflects our 2021 dividends declared:
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2021$0.27 April 21, 2021April 30, 2021May 17, 2021
June 30, 20210.27 July 21, 2021August 2, 2021August 16, 2021
September 30, 20210.27 October 20, 2021November 1, 2021November 15, 2021

The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2020 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.

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

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Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

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

In lieu of providing separate financial statements for subsidiary issuers and guarantors, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.  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, 2021.”

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

Excluding fair value adjustments, as of September 30, 2021 and December 31, 2020, the Obligated Group had $30,994 million and $32,563 million, respectively, of Guaranteed Notes outstanding.

Summarized combined balance sheet and income statement information for the Obligated Group follows:
Summarized Combined Balance Sheet InformationSeptember 30, 2021December 31, 2020
(In millions)
Current assets$2,412 $2,957 
Current assets - affiliates1,118 1,151 
Noncurrent assets62,129 61,783 
Noncurrent assets - affiliates507 616 
Total Assets$66,166 $66,507 
Current liabilities$5,390 $4,528 
Current liabilities - affiliates1,269 1,209 
Noncurrent liabilities31,803 33,907 
Noncurrent liabilities - affiliates1,006 1,078 
Total Liabilities39,468 40,722 
Redeemable noncontrolling interest661 728 
Kinder Morgan, Inc.’s stockholders’ equity26,037 25,057 
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity
$66,166 $66,507 
Summarized Combined Income Statement InformationThree Months Ended September 30, 2021Nine Months Ended September 30, 2021
(In millions)
Revenues$3,472 $11,211 
Operating income699 1,697 
Net income373 937 

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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, 2020, in Item 7A in our 2020 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 6 “Risk Management” to our consolidated financial statements.

Item 4.  Controls and Procedures.

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

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2020 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 6 “Risk Management” to our consolidated financial statements.

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

None. 

Item 3.  Defaults Upon Senior Securities.

None. 

Item 4.  Mine Safety Disclosures.

The Company does not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. The Company has not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended September 30, 2021.

Item 5.  Other Information.

Effective October 20, 2021, our board of directors approved the Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (the “Amended Director Plan”), which amends and restates the previous Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors dated January 1, 2015, as
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amended (the “Previous Plan”). The Amended Director Plan amends and restates the Previous Plan to increase the number of shares available for issuance under the Amended Director Plan.

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

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

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

•the total cash compensation awarded to such director and

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

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

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

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Item 6.  Exhibits.
Exhibit
Number                     Description
10.1 
10.2 *
10.3 *
10.4 
10.5 
22.1 
31.1 
31.2 
32.1 
32.2 
101 
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Operations for the three and nine months ended September 30, 2021 and 2020; (ii) our Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2021 and 2020; (iii) our Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2021 and 2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2021 and 2020; and (vi) the notes to our Consolidated Financial Statements.
104 Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.
_______
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
KINDER MORGAN, INC.
Registrant
Date:October 22, 2021By:/s/ David P. Michels
David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)
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