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KINDER MORGAN, INC. - Quarter Report: 2022 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, 2022

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-20220930_g1.gif

KINDER MORGAN, INC.
(Exact name of registrant as specified in its charter)
 
Delaware80-0682103
(State or other jurisdiction of
incorporation or organization)		(I.R.S. Employer
Identification No.)
1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713-369-9000

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class P Common StockKMINew York Stock Exchange
2.250% Senior Notes due 2027KMI 27 ANew York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No ☐

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 20, 2022, the registrant had 2,247,742,071 shares of Class P common stock 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 dayFERC=Federal Energy Regulatory Commission
Bbl=barrelsGAAP=U.S. Generally Accepted Accounting Principles
BBtu=billion British Thermal Units LLC=limited liability company
Bcf=billion cubic feetLIBOR=London Interbank Offered Rate
CERCLA=Comprehensive Environmental Response, Compensation and Liability ActMBbl=thousand barrels
MMBbl=million barrels
CO2
=
carbon dioxide or our CO2 business segment
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
PHMSA=Pipeline and Hazardous Materials Safety Administration
EBITDA=earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investmentsROU=Right-of-Use
U.S.=United States of America
EPA=U.S. Environmental Protection AgencyWTI=West Texas Intermediate
FASB=Financial Accounting Standards Board


2

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “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 and capital projects, including expected completion timing and benefits of 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 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 and Results of Operations” and Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” in this report, as well as “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021 (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 INCOME
(In millions, except per share amounts, unaudited)

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


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions, unaudited)
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Net income$595 $511 $1,932 $1,196 
Other comprehensive income (loss), net of tax  
Net unrealized gain (loss) from derivative instruments (net of taxes of $(40), $41, $109 and $135, respectively)
123 (131)(366)(444)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $(29), $(28), $(118), and $(55), respectively)
104 92 396 181 
Benefit plan adjustments (net of taxes of $(1), $(2), $(6) and $(7), respectively)
2 6 18 28 
Total other comprehensive income (loss) 229 (33)48 (235)
Comprehensive income824 478 1,980 961 
Comprehensive income attributable to noncontrolling interests(19)(16)(54)(49)
Comprehensive income attributable to KMI$805 $462 $1,926 $912 
The accompanying notes are an integral part of these consolidated financial statements.
5


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

September 30, 2022December 31, 2021
ASSETS
Current Assets
Cash and cash equivalents$483 $1,140 
Restricted deposits240 7 
Accounts receivable1,873 1,611 
Fair value of derivative contracts194 220 
Inventories715 562 
Other current assets314 289 
Total current assets3,819 3,829 
Property, plant and equipment, net 35,534 35,653 
Investments7,465 7,578 
Goodwill19,965 19,914 
Other intangibles, net1,875 1,678 
Deferred income taxes— 115 
Deferred charges and other assets1,334 1,649 
Total Assets$69,992 $70,416 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt $2,634 $2,646 
Accounts payable1,579 1,259 
Accrued interest327 504 
Accrued taxes297 270 
Fair value of derivative contracts501 178 
Other current liabilities810 964 
Total current liabilities6,148 5,821 
Long-term liabilities and deferred credits
Long-term debt
Outstanding
29,000 29,772 
Debt fair value adjustments
107 902 
Total long-term debt29,107 30,674 
Deferred income taxes442 — 
Other long-term liabilities and deferred credits2,160 2,000 
Total long-term liabilities and deferred credits31,709 32,674 
Total Liabilities37,857 38,495 
Commitments and contingencies (Notes 4 and 10)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,249,727,830 and 2,267,391,527 shares, respectively, issued and outstanding
23 23 
Additional paid-in capital41,689 41,806 
Accumulated deficit(10,593)(10,595)
Accumulated other comprehensive loss(363)(411)
Total Kinder Morgan, Inc.’s stockholders’ equity30,756 30,823 
Noncontrolling interests1,379 1,098 
Total Stockholders’ Equity32,135 31,921 
Total Liabilities and Stockholders’ Equity$69,992 $70,416 
The accompanying notes are an integral part of these consolidated financial statements.
6


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
20222021
Cash Flows From Operating Activities
Net income$1,932 $1,196 
Adjustments to reconcile net income to net cash provided by operating activities 
Depreciation, depletion and amortization1,632 1,595 
Deferred income taxes499 236 
Amortization of excess cost of equity investments57 56 
Change in fair market value of derivative contracts45 60 
(Gain) loss on divestitures and impairments, net (30)1,602 
Gain on sale of interest in equity investment (Note 2)— (206)
Earnings from equity investments(564)(392)
Distributions from equity investment earnings548 535 
Changes in components of working capital
Accounts receivable(260)(119)
Inventories(165)(89)
Other current assets(60)(90)
Accounts payable347 362 
Accrued interest, net of interest rate swaps(160)(177)
Accrued taxes27 15 
Other current liabilities2 71 
Rate reparations, refunds and other litigation reserve adjustments(189)(97)
Other, net(98)(118)
Net Cash Provided by Operating Activities3,563 4,440 
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 2)(488)(1,518)
Capital expenditures(1,144)(894)
Proceeds from sales of investments (Note 2)4 417 
Contributions to investments(60)(36)
Distributions from equity investments in excess of cumulative earnings126 121 
Other, net17 (1)
Net Cash Used in Investing Activities(1,545)(1,911)
Cash Flows From Financing Activities
Issuances of debt 8,898 4,950 
Payments of debt (9,569)(6,459)
Debt issue costs(21)(20)
Dividends(1,876)(1,828)
Repurchases of shares(333)— 
Proceeds from sale of noncontrolling interests (Note 2)557 — 
Contributions from noncontrolling interests1 4 
Distributions to investment partner— (67)
Distributions to noncontrolling interests(85)(14)
Other, net(14)(25)
Net Cash Used in Financing Activities(2,442)(3,459)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits(424)(930)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,147 1,209 
Cash, Cash Equivalents, and Restricted Deposits, end of period$723 $279 
Cash and Cash Equivalents, beginning of period$1,140 $1,184 
Restricted Deposits, beginning of period7 25 
Cash, Cash Equivalents, and Restricted Deposits, beginning of period1,147 1,209 
7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
20222021
Cash and Cash Equivalents, end of period483 102 
Restricted Deposits, end of period240 177 
Cash, Cash Equivalents, and Restricted Deposits, end of period723 279 
Net Decrease in Cash, Cash Equivalents and Restricted Deposits$(424)$(930)
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments$19 $35 
Increase in property, plant and equipment from both accruals and contractor retainage23 4 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)1,278 1,313 
Cash paid during the period for income taxes, net12 8 
The accompanying notes are an integral part of these consolidated financial statements.
8

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions, unaudited)
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at June 30, 20222,257 $23 $41,654 $(10,540)$(592)$30,545 $1,080 $31,625 
Repurchases of shares(9)(160)(160)(160)
Restricted shares
2 5 5 5 
Net income576 576 19 595 
Distributions
— (32)(32)
Contributions
— 1 1 
Impact of change in ownership interest in subsidiary190 190 311 501 
Dividends(629)(629)(629)
Other comprehensive income229 229 229 
Balance at September 30, 20222,250 $23 $41,689 $(10,593)$(363)$30,756 $1,379 $32,135 
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at June 30, 20212,265$23 $41,793 $(10,496)$(609)$30,711 $429 $31,140 
Restricted 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 stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at December 31, 20212,267 $23 $41,806 $(10,595)$(411)$30,823 $1,098 $31,921 
Impact of adoption of ASU 2020-06 (Note 5)
(11)(11)(11)
Balance at January 1, 20222,267 23 41,795 (10,595)(411)30,812 1,098 31,910 
Repurchases of shares(19)(333)(333)(333)
EP Trust I Preferred security conversions1 1 1 
Restricted shares
2 36 36 36 
Net income1,878 1,878 54 1,932 
Distributions
— (85)(85)
Contributions
— 1 1 
Impact of change in ownership interest in subsidiary190 190 311 501 
Dividends
(1,876)(1,876)(1,876)
Other comprehensive income48 48 48 
Balance at September 30, 20222,250 $23 $41,689 $(10,593)$(363)$30,756 $1,379 $32,135 
Common stockAdditional
paid-in
capital		Accumulated
deficit		Accumulated
other
comprehensive
loss		Stockholders’
equity
attributable
to KMI		Non-controlling
interests		Total
Issued sharesPar value
Balance at December 31, 20202,264$23 $41,756 $(9,936)$(407)$31,436 $402 $31,838 
Restricted shares
332 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 
The accompanying notes are an integral part of these consolidated financial statements.
9


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

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines, 141 terminals, 700 Bcf of working natural gas storage capacity and 2.2 Bcf per year of renewable natural gas generation capacity. Our pipelines transport natural gas, refined petroleum products, renewable fuels, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, renewable fuel feedstocks, chemicals, ethanol, 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 2021 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, 2022 evaluation, we grouped our businesses into seven reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals and (vii) Energy Transition Ventures.

The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions, general economic conditions and the related demand for products handled or transported by our assets. Changes to any one or a combination of these factors would result in a change to the reporting unit fair values, which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.

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

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.
10



The following table sets forth the allocation of net income available to shareholders of Class P common stock and participating securities:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except per share amounts)
Net Income Available to Stockholders$576 $495 $1,878 $1,147 
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)(4)(4)(9)(10)
Net Income Allocated to Class P Stockholders$572 $491 $1,869 $1,137 
Basic Weighted Average Shares Outstanding2,253 2,267 2,262 2,265 
Basic Earnings Per Share$0.25 $0.22 $0.83 $0.50 
(a)As of September 30, 2022, there were 13 million restricted stock awards outstanding.

The following table presents the maximum number of potential common stock equivalents which are antidilutive and accordingly are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions on a weighted average basis)
Unvested restricted stock awards13 13 13 13 
Convertible trust preferred securities3 3 3 3 

2. Acquisitions and Divestitures

Business Combinations

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

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

(1) North American Natural Resources Acquisition

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

11


(2) Mas CanAm Acquisition

On July 19, 2022, we completed an acquisition of three landfill assets from Mas CanAm, LLC, comprising a renewable natural gas facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for $358 million including a preliminary purchase price adjustment for working capital. Other long-term assets within the purchase price allocation reflects an intangible related to a customer contract with an amortization period of approximately 17 years.

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, 2022 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

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/or our expected ability to grow the business we acquired by leveraging our pre-existing business experience. We apply a look through method of recording deferred income 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, 2022 are summarized by reporting unit as follows:
Natural Gas Pipelines RegulatedNatural Gas Pipelines Non-Regulated
CO2
Products PipelinesProducts Pipelines TerminalsTerminals
CO2 – Energy Transition Ventures
Total
(In millions)
Goodwill as of December 31, 2021$14,249 $2,343 $928 $1,378 $151 $802 $63 $19,914 
Acquisitions(a)— — — — — — 51 51 
Goodwill as of September 30, 2022
$14,249 $2,343 $928 $1,378 $151 $802 $114 $19,965 
(a)Includes goodwill arising from our acquisition of NANR and a $10 million purchase price adjustment related to our 2021 acquisition of Kinetrex that was attributed to long-term deferred tax liabilities.

Divestitures

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

On September 26, 2022, we completed the sale of a 25.5% ownership interest in Elba Liquefaction Company L.L.C. (ELC). We received net proceeds of $557 million which were used to reduce short-term borrowings. As we continue to have a controlling financial interest in ELC, we recorded an increase of $190 million to “Additional paid in capital” for the impact of the change in our ownership interest in ELC, which is reflected on our accompanying consolidated statements of stockholders’ equity for the three and nine months ended September 30, 2022. We continue to own a 25.5% interest in and operate ELC.

We continue to consolidate ELC. We have determined that ELC is a variable interest entity and Southern Liquefaction Company, LLC (SLC), which is indirectly controlled by us, is the primary beneficiary because it has the ability to direct the activities that most significantly impact ELC’s economic performance and the right to receive benefits and the obligation to absorb losses. In addition to being the operator of ELC, the evaluation of ELC as a variable interest entity and SLC as the primary beneficiary included consideration of the following: (i) a liquefaction service agreement between ELC and its customer was designed for recovery by ELC of actual costs for operating and maintaining ELC’s facilities, which reduces the risk for all equity owners to absorb losses resulting from cost variability; and (ii) substantially all ELC’s activities involve KMI subsidiaries under common control that provide services for and benefit from the operations of ELC.
12



The following table shows the carrying amount and classification of ELC’s assets and liabilities in our consolidated balance sheet:
September 30, 2022
(In millions)
Assets
Current assets$43 
Property, plant and equipment, net 1,207 
Deferred charges and other assets6 
Liabilities
Current liabilities$28 
Other long-term liabilities and deferred credits5 

We receive distributions from ELC, indirectly, through our interest in SLC, but otherwise, the assets of ELC cannot be used to settle our obligations. ELC’s creditors have no recourse against our general credit and the obligations of ELC may only be settled using the assets of ELC. ELC does not guarantee our debt or other similar commitments.

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. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” on our accompanying consolidated statement of income for the nine months ended September 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

3. Losses on Impairments and Other Write-downs

Long-lived Asset Impairment

During the second quarter of 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. We utilized an income approach to estimate fair value and compared it to the carrying value. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates, a Level 3 input. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the nine months ended September 30, 2021.

Investment in Ruby

During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, which is included within “Earnings from equity investments” on our accompanying consolidated statement of income for the nine months ended September 30, 2021. The write-down was driven by the impairment recognized by Ruby of its assets.

Ruby Chapter 11 Bankruptcy Filing

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



4. Debt

The following table provides information on the principal amount of our outstanding debt balances:
September 30, 2022December 31, 2021
(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026
$— $— 
$500 million credit facility due November 16, 2023
— — 
Commercial paper notes— — 
Current portion of senior notes
8.625%, due January 2022(a)
— 260 
4.15%, due March 2022(a)
— 375 
1.50%, due March 2022(a)(b)
— 853 
3.95% due September 2022(c)
— 1,000 
3.15% due January 2023
1,000 — 
Floating rate, due January 2023(d)250 — 
3.45% due February 2023
625 — 
3.50% due September 2023
600 — 
Trust I preferred securities, 4.75%, due March 2028
111 111 
Current portion of other debt48 47 
Total current portion of debt2,634 2,646 
Long-term debt (excluding current portion)
Senior notes28,343 29,097 
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035
336 348 
Trust I preferred securities, 4.75%, due March 2028
109 110 
Other212 217 
Total long-term debt29,000 29,772 
Total debt(e)$31,634 $32,418 
(a)We repaid the principal amount of these senior notes during the first quarter of 2022.
(b)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The December 31, 2021 balance is reported above at the exchange rate of 1.1370 U.S. dollars per Euro. As of December 31, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $38 million related to these notes, which was offset by a corresponding change in the value of cross-currency swaps reflected in “Current Assets—Fair value of derivative contracts” and “Current Liabilities—Fair value of derivative contracts” on our accompanying consolidated balance sheet. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 6 “Risk Management—Foreign Currency Risk Management”).
(c)We repaid the principal amount of these senior notes on June 1, 2022.
(d)These senior notes have an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge (see Note 6 “Risk Management—Interest Rate Risk Management”).
(e)Excludes our “Debt fair value adjustments” which, as of September 30, 2022 and December 31, 2021, increased our total debt balances by $107 million and $902 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 23, 2022, EPNG issued in a private offering $300 million aggregate principal amount of 3.50% senior notes due 2032 and received net proceeds of $298 million after discount and issuance costs. These notes are guaranteed through the cross guarantee agreement discussed above.

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

14


Credit Facilities and Restrictive Covenants

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

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below: 
September 30, 2022December 31, 2021
Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Total debt$31,741 $29,188 $33,320 $37,775 
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $203 million and $218 million as of September 30, 2022 and December 31, 2021, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2022 and December 31, 2021.

5. Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. During the nine months ended September 30, 2022, we repurchased approximately 19 million of our shares for $333 million at an average price of $16.97 per share. Subsequent to September 30, 2022 and through October 20, 2022, we repurchased 2 million of our shares for $34 million at an average price of $16.75 per share, and since December 2017, in total, we have repurchased 54 million of our shares under the program at an average price of $17.40 per share for $942 million.

Dividends

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

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

Adoption of Accounting Pronouncement

On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share 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. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the nine months ended September 30, 2022.
15



Accumulated Other Comprehensive Loss

Changes in the components of our “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as follows:
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2021$(172)$(239)$(411)
Other comprehensive (loss) gain before reclassifications(366)18 (348)
Loss reclassified from accumulated other comprehensive loss396 — 396 
Net current-period change in accumulated other comprehensive loss30 18 48 
Balance as of September 30, 2022$(142)$(221)$(363)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments		Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2020$(13)$(394)$(407)
Other comprehensive (loss) gain before reclassifications(444)28 (416)
Loss reclassified from accumulated other comprehensive loss181 — 181 
Net current-period change in accumulated other comprehensive loss(263)28 (235)
Balance as of September 30, 2021$(276)$(366)$(642)

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.

Energy Commodity Price Risk Management

As of September 30, 2022, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price(19.4)MMBbl
Crude oil basis(6.0)MMBbl
Natural gas fixed price(50.8)Bcf
Natural gas basis(28.0)Bcf
NGL fixed price(0.7)MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(1.2)MMBbl
Crude oil basis(9.0)MMBbl
Natural gas fixed price(7.5)Bcf
Natural gas basis(37.8)Bcf
NGL fixed price(0.8)MMBbl

16


As of September 30, 2022, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2026.

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, 2022:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)$7,500 Fair value hedgeMarch 2035
Variable-to-fixed interest rate contracts250 Cash flow hedgeJanuary 2023
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts5,100 Mark-to-MarketDecember 2022
(a)The principal amount of hedged senior notes consisted of $700 million included in “Current portion of debt” and $6,800 million included in “Long-term debt” on our accompanying consolidated balance sheet.
(b)During the three and nine months ended September 30, 2022, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 11 “Recent Accounting Pronouncements” for further information on Topic 848.

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, 2022:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$543 Cash flow hedgeMarch 2027
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.

17


Impact of Derivative Contracts on Our Consolidated Financial Statements

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

18


The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
Balance sheet asset
fair value measurements by level		Contracts available for nettingCash collateral held(b)
Level 1Level 2Level 3Gross amountNet amount
(In millions)
As of September 30, 2022
Energy commodity derivative contracts(a)$63 $138 $— $201 $(169)$— $32 
Interest rate contracts— 78 — 78 — — 78 
As of December 31, 2021
Energy commodity derivative contracts(a)$56 $20 $— $76 $(53)$(20)$3 
Interest rate contracts— 397 — 397 (9)— 388 
Foreign currency contracts— 41 — 41 (3)— 38 
Balance sheet liability
fair value measurements by level		Contracts available for nettingCash collateral posted(b)
Level 1Level 2Level 3Gross amountNet amount
(In millions)
As of September 30, 2022
Energy commodity derivative contracts(a)$(127)$(342)$— $(469)$169 $135 $(165)
Interest rate contracts— (422)— (422)— — (422)
Foreign currency contracts— (68)— (68)— — (68)
As of December 31, 2021
Energy commodity derivative contracts(a)$(15)$(257)$— $(272)$53 $— $(219)
Interest rate contracts— (18)— (18)9 — (9)
Foreign currency contracts— (3)— (3)3 — — 
(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
(b)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

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

19


Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Three Months Ended
September 30,		Three Months Ended
September 30,
2022202120222021
(In millions)(In millions)
Energy commodity derivative contracts
$195 $(140)
Revenues—Commodity sales
$(116)$(94)
Costs of sales
17 8 
Interest rate contracts
— 1 Interest, net— — 
Foreign currency contracts
(32)(33)
Other, net
(34)(34)
Total$163 $(172)Total$(133)$(120)

Derivatives in cash flow hedging relationshipsGain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)(In millions)
Energy commodity derivative contracts
$(375)$(514)
Revenues—Commodity sales
$(433)$(167)
Costs of sales
34 10 
Interest rate contracts
7 3 Interest, net— — 
Foreign currency contracts
(107)(68)
Other, net
(115)(79)
Total$(475)$(579)Total$(514)$(236)
(a)We expect to reclassify approximately $124 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2022 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the nine months ended September 30, 2022 and 2021, we recognized approximate gains of $34 million and $6 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).

Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$44 $(40)$18 $(703)
Costs of sales
(30)(7)(129)154 
Earnings from equity investments(7)(2)(11)(4)
Interest rate contractsInterest, net(20)— 28 — 
Total(a)$(13)$(49)$(94)$(553)
(a)The three and nine months ended September 30, 2022 amounts include approximate losses of $19 million and $39 million, respectively, and the three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

20


Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, 2022 and December 31, 2021, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2022, we had cash margins of $223 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2021, we had cash margins of $14 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at September 30, 2022 represents our initial margin requirements of $88 million and variation margin requirements of $135 million posted by us with our counterparties. 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, 2022, 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 $100 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, 2022
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from customers(a)
Services
Firm services(b)$845 $57 $199 $— $— $1,101 
Fee-based services243 247 106 11 — 607 
Total services1,088 304 305 11 — 1,708 
Commodity sales
Natural gas sales1,902 — — 24 (7)1,919 
Product sales389 511 11 353 (1)1,263 
Total commodity sales2,291 511 11 377 (8)3,182 
Total revenues from customers3,379 815 316 388 (8)4,890 
Other revenues(c)
Leasing services(d)120 51 141 16 — 328 
Derivatives adjustments on commodity sales(12)— — (60)— (72)
Other18 6 — 7 — 31 
Total other revenues126 57 141 (37)— 287 
Total revenues$3,505 $872 $457 $351 $(8)$5,177 
21


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


Nine Months Ended September 30, 2021
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from customers(a)
Services
Firm services(b)$2,501 $191 $570 $1 $(2)$3,261 
Fee-based services544 709 258 35 — 1,546 
Total services3,045 900 828 36 (2)4,807 
Commodity sales
Natural gas sales5,090 — — 9 (11)5,088 
Product sales840 529 20 766 (34)2,121 
Total commodity sales5,930 529 20 775 (45)7,209 
Total revenues from customers8,975 1,429 848 811 (47)12,016 
Other revenues(c)
Leasing services(d)356 128 427 42 — 953 
Derivatives adjustments on commodity sales
(726)(1)— (143)— (870)
Other51 16 — 19 — 86 
Total other revenues(319)143 427 (82)— 169 
Total revenues$8,656 $1,572 $1,275 $729 $(47)$12,185 
(a)Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and 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 “Risk Management” 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, 2022 and December 31, 2021, our contract asset balances were $57 million and $39 million, respectively. Of the contract asset balance at December 31, 2021, $29 million was transferred to accounts receivable during the nine months ended September 30, 2022. As of September 30, 2022 and December 31, 2021, our contract liability balances were $204 million and $212 million, respectively. Of the contract liability balance at December 31, 2021, $77 million was recognized as revenue during the nine months ended September 30, 2022.

23


Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, 2022 that we will invoice or transfer from contract liabilities and recognize in future periods:
YearEstimated Revenue
(In millions)
Three months ended December 31, 2022$1,157 
20234,055 
20243,244 
20252,685 
20262,357 
Thereafter14,007 
Total$27,505 

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

8.  Reportable Segments

Financial information by segment follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers$3,497 $2,541 $9,653 $8,611 
Intersegment revenues8 14 21 45 
Products Pipelines872 605 2,634 1,572 
Terminals
Revenues from external customers457 421 1,335 1,273 
Intersegment revenues— 1 2 2 
CO2
351 257 999 729 
Corporate and intersegment eliminations(8)(15)(23)(47)
Total consolidated revenues$5,177 $3,824 $14,621 $12,185 
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Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions)
Segment EBDA(a)
Natural Gas Pipelines$1,135 $1,069 $3,453 $2,602 
Products Pipelines257 279 855 792 
Terminals240 216 731 689 
CO2
215 163 619 599 
Total Segment EBDA1,847 1,727 5,658 4,682 
DD&A(551)(526)(1,632)(1,595)
Amortization of excess cost of equity investments(19)(21)(57)(56)
General and administrative and corporate charges(149)(167)(438)(465)
Interest, net (399)(368)(1,087)(1,122)
Income tax expense(134)(134)(512)(248)
Total consolidated net income$595 $511 $1,932 $1,196 
September 30, 2022December 31, 2021
(In millions)
Assets
Natural Gas Pipelines$47,872 $47,746 
Products Pipelines8,994 9,088 
Terminals8,362 8,513 
CO2
3,470 2,843 
Corporate assets(b)1,294 2,226 
Total consolidated assets$69,992 $70,416 
(a)Includes revenues, earnings from equity investments, operating expenses, (gain) loss on divestitures and impairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, 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 on our accompanying consolidated statements of income is as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
(In millions, except percentages)
Income tax expense$134 $134 $512 $248 
Effective tax rate18.4 %20.8 %20.9 %17.2 %

The effective tax rate for the three and nine months ended September 30, 2022 is lower than the statutory federal rate of 21% primarily due to the recognition of additional 2021 enhanced oil recovery credits from our initial estimate, the adjustment to the deferred tax liability as a result of the reduction in the state tax rate and dividend-received deductions from our investments in Florida Gas Pipeline (Citrus), NGPL Holdings and Products (SE) Pipe Line Company (PPL), partially offset by state income taxes.

The effective tax rate for the three months ended September 30, 2021 is lower than the statutory federal rate of 21% primarily due to 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, 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.

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 the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

EPNG FERC Proceeding

On April 21, 2022, EPNG was notified by the FERC of the commencement of a rate proceeding against it pursuant to Section 5 of the Natural Gas Act. This proceeding sets the matter for hearing to determine whether EPNG’s current rates remain just and reasonable. A proceeding under Section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. Unless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in the second quarter of 2023. We are engaged actively in settlement discussions and anticipate joining with FERC Trial Staff and other active participants in the proceeding in filing an unopposed motion to suspend the procedural schedule to enable the parties to prepare documents necessary to document a settlement in principle that would fully resolve the proceeding. We do not believe that the ultimate resolution of this proceeding will have a material adverse impact to 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.  The Notice of Arbitration sought declaratory and monetary relief based upon Eni USA’s assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 “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. 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. In response to the foregoing lawsuit, Eni S.p.A. filed counterclaims under the terminal use agreement and claims under a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing claims asserted by Eni S.p.A seek unspecified damages and involve the same allegations as the claims which were resolved conclusively in the arbitrations with Eni USA described above and with GLNG’s remaining customer as described below. On January 4, 2022, the trial court entered a decision granting Eni S.p.A’s motion for summary judgment on the claims asserted by GLNG to enforce the Guarantee Agreement. GLNG filed an interlocutory appeal of the decision. Pending resolution of GLNG’s appeal and further proceedings in the trial court, the foregoing counterclaims and other claims asserted by Eni S.p.A under the terminal use agreement and parent direct agreement remain pending in the trial court.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a 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. On July 15, 2021, the arbitration tribunal delivered an Award on the merits of all
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claims submitted to the tribunal and denied all of ALSS’s claims with prejudice. On November 23, 2021, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award.

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

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA produced in three North Dakota counties.  CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a 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 filed an amended petition in which it asserted that Hiland Partners’ failure to construct certain facilities by specific dates nullified the release contained in the settlement agreement. CLR’s amended petition asserted 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 was not allowed to deduct third-party processing fees from the gas purchase price. CLR sought damages in excess of $276 million. On September 14, 2022, the parties entered into a confidential settlement agreement, including an unconditional release and dismissal of the litigation with prejudice.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed suit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. We believe that our declaration of force majeure was valid and we intend to vigorously defend this case.

Pipeline Integrity and Releases

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

Arizona Line 2000 Rupture

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

General

As of September 30, 2022 and December 31, 2021, our total reserve for legal matters was $42 million and $231 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,
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terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.

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, crude oil, NGL, natural gas or CO2.

PHMSA Enforcement Matter for KMLT Midwest Terminals

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

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

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 to be more than $2.8 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 in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.

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
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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 obligates EPEC 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 December 2013, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In April 2015, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. In May 2018, the case was removed for a second time to the U.S. District Court. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court. The case has been effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal court and ordered to be remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. The defendants to those consolidated cases pursued an appeal of the remand decisions to the United States Court of Appeals for the Fifth Circuit to determine whether there is federal officer jurisdiction. On October 17, 2022, the United States Court of Appeals ordered those consolidated cases to be remanded to the state district courts. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.

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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 intend to vigorously defend this case.

Products Pipeline Incident, Walnut Creek, California

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

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

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

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of September 30, 2022 and December 31, 2021, we have accrued a total reserve for environmental liabilities in the amount of $227 million and $243 million, respectively. In addition, as of September 30, 2022 and December 31, 2021, we had receivables of $11 million and $12 million, respectively, recorded for expected cost recoveries that have been deemed probable.

11. Recent Accounting Pronouncements

Accounting Standards Updates

Reference Rate Reform (Topic 848)

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

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

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

During the nine months ended September 30, 2022 we amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. These agreements contain a combined notional principal amount of $1,725 million and convert a portion of our fixed rate debt to variable rates through March 2035. Concurrent with these amendments, we elected certain of the optional expedients provided in Topic 848 which allow us to maintain our prior designation of fair value hedge accounting to these agreements. As we continue to amend our interest rate swap agreements to transition from LIBOR to SOFR, we will assess whether such amendments qualify for any of the optional expedients in Topic 848 and, should they qualify, whether we wish to elect any such optional expedients. See Note 6“Risk Management—Interest Rate Risk Management” for more information on our interest rate risk management activities.
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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 2021 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2021 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2021 Form 10-K; and (iv) “Risk Factors” in Part I, Item 1A of our 2021 Form 10-K.

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

On September 27, 2022, we completed the sale of a 25.5% ownership interest in Elba Liquefaction Company L.L.C. (ELC). We received net proceeds of $557 million which were used to reduce short-term borrowings. As we continue to have a controlling financial interest in and consolidate ELC, we recorded an increase of $190 million to “Additional paid in capital” for the impact of the change in our ownership interest in ELC, which is reflected on our accompanying consolidated statements of stockholders’ equity for the three and nine months ended September 30, 2022. We continue to own a 25.5% interest in and operate ELC. See Note 2 “Acquisitions and Divestitures” for additional information regarding ELC.

North American Natural Resources Acquisition

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

Mas CanAm Acquisition

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

2022 Dividends and Discretionary Capital

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

The expectations for 2022 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 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.

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GAAP Financial Measures

The Consolidated Earnings Results for the three and nine months ended September 30, 2022 and 2021 present Segment EBDA and Net income attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the 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 attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, 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 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 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 attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

DCF

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

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

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the 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, 2022, by subtracting the following amounts from our debt balance of $31,741 million: (i) cash and cash equivalents of $483 million; and (ii) debt fair value adjustments of $107 million; and excluding the foreign exchange impact on Euro-denominated bonds of $(53) million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt is a non-GAAP financial measure that management believes is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents.

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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,
20222021Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines$1,135$1,069$666%
Products Pipelines257279(22)(8)%
Terminals2402162411%
CO2
2151635232%
Total Segment EBDA1,8471,7271207%
DD&A(551)(526)(25)(5)%
Amortization of excess cost of equity investments(19)(21)210%
General and administrative and corporate charges(149)(167)1811%
Interest, net(399)(368)(31)(8)%
Income before income taxes7296458413%
Income tax expense