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

F O R M  10-Q  

☑  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2023

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
image0a30a07.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 April 20, 2023, the registrant had 2,241,213,694 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 investmentsRNG=Renewable natural gas
ROU=Right-of-Use
EPA=U.S. Environmental Protection AgencyU.S.=United States of America
FASB=Financial Accounting Standards BoardWTI=West Texas Intermediate


2

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, our anticipated dividends 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,” Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Part II, Item 1A. “Risk Factors” 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, 2022 (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
March 31,
20232022
Revenues 
Services$2,069 $2,050 
Commodity sales1,785 2,208 
Other34 35 
Total Revenues
3,888 4,293 
Operating Costs, Expenses and Other 
Costs of sales (exclusive of items shown separately below)1,215 1,894 
Operations and maintenance639 585 
Depreciation, depletion and amortization565 538 
General and administrative166 156 
Taxes, other than income taxes110 111 
Gain on divestitures and impairments, net— (10)
Other income, net(1)(5)
Total Operating Costs, Expenses and Other
2,694 3,269 
Operating Income1,194 1,024 
Other Income (Expense) 
Earnings from equity investments165 187 
Amortization of excess cost of equity investments(17)(19)
Interest, net(445)(333)
Other, net 2 19 
Total Other Expense
(295)(146)
Income Before Income Taxes899 878 
Income Tax Expense (196)(194)
Net Income703 684 
Net Income Attributable to Noncontrolling Interests(24)(17)
Net Income Attributable to Kinder Morgan, Inc.$679 $667 
Class P Common Stock
Basic and Diluted Earnings Per Share$0.30 $0.29 
Basic and Diluted Weighted Average Shares Outstanding2,247 2,267 
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
March 31,
20232022
Net income$703 $684 
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(32) and $125, respectively)
106 (411)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $15 and $(41), respectively)
(49)135 
Benefit plan adjustments (net of taxes of $(1) and $(4), respectively)
4 13 
Total other comprehensive income (loss) 61 (263)
Comprehensive income764 421 
Comprehensive income attributable to noncontrolling interests(24)(17)
Comprehensive income attributable to KMI$740 $404 
The accompanying notes are an integral part of these consolidated financial statements.
5


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

March 31, 2023December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents$416 $745 
Restricted deposits22 49 
Accounts receivable1,321 1,840 
Fair value of derivative contracts164 231 
Inventories589 634 
Other current assets184 304 
Total current assets2,696 3,803 
Property, plant and equipment, net 35,639 35,599 
Investments7,616 7,653 
Goodwill19,965 19,965 
Other intangibles, net1,743 1,809 
Deferred charges and other assets1,272 1,249 
Total Assets$68,931 $70,078 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt $2,160 $3,385 
Accounts payable1,087 1,444 
Accrued interest351 515 
Fair value of derivative contracts344 465 
Other current liabilities833 1,121 
Total current liabilities4,775 6,930 
Long-term liabilities and deferred credits
Long-term debt
Outstanding
29,139 28,288 
Debt fair value adjustments
207 115 
Total long-term debt29,346 28,403 
Deferred income taxes831 623 
Other long-term liabilities and deferred credits1,865 2,008 
Total long-term liabilities and deferred credits32,042 31,034 
Total Liabilities36,817 37,964 
Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,241,158,000 and 2,247,681,626 shares, respectively, issued and outstanding
22 22 
Additional paid-in capital41,575 41,673 
Accumulated deficit(10,499)(10,551)
Accumulated other comprehensive loss(341)(402)
Total Kinder Morgan, Inc.’s stockholders’ equity30,757 30,742 
Noncontrolling interests1,357 1,372 
Total Stockholders’ Equity32,114 32,114 
Total Liabilities and Stockholders’ Equity$68,931 $70,078 
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)
Three Months Ended March 31,
20232022
Cash Flows From Operating Activities
Net income$703 $684 
Adjustments to reconcile net income to net cash provided by operating activities 
Depreciation, depletion and amortization565 538 
Deferred income taxes190 190 
Amortization of excess cost of equity investments17 19 
Change in fair value of derivative contracts(66)77 
Gain on divestitures and impairments, net — (10)
Earnings from equity investments(165)(187)
Distributions from equity investment earnings188 165 
Changes in components of working capital
Accounts receivable536 (51)
Inventories88 (34)
Other current assets93 (14)
Accounts payable(368)55 
Accrued interest, net of interest rate swaps(162)(188)
Other current liabilities(236)(98)
Rate reparations, refunds and other litigation reserve adjustments2 (68)
Other, net(52)6 
Net Cash Provided by Operating Activities1,333 1,084 
Cash Flows From Investing Activities
Capital expenditures(507)(407)
Contributions to investments(45)(11)
Distributions from equity investments in excess of cumulative earnings61 50 
Other, net(17)(3)
Net Cash Used in Investing Activities(508)(371)
Cash Flows From Financing Activities
Issuances of debt 2,794 1,588 
Payments of debt (3,180)(2,453)
Debt issue costs(13)(4)
Dividends(627)(616)
Repurchases of shares(113)(1)
Distributions to noncontrolling interests(39)(26)
Other, net(3)— 
Net Cash Used in Financing Activities(1,181)(1,512)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits(356)(799)
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 
Cash, Cash Equivalents and Restricted Deposits, end of period$438 $348 
7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Three Months Ended March 31,
20232022
Cash and Cash Equivalents, beginning of period$745 $1,140 
Restricted Deposits, beginning of period49 7 
Cash, Cash Equivalents and Restricted Deposits, beginning of period794 1,147 
Cash and Cash Equivalents, end of period416 84 
Restricted Deposits, end of period22 264 
Cash, Cash Equivalents and Restricted Deposits, end of period438 348 
Net Decrease in Cash, Cash Equivalents and Restricted Deposits$(356)$(799)
Non-cash Investing and Financing Activities
Assets contributed to equity investment$16 $— 
ROU assets and operating lease obligations recognized including adjustments11 3 
Increase in property, plant and equipment from both accruals and contractor retainage15 
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)617 561 
Cash paid during the period for income taxes, net1 1 
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 December 31, 20222,248 $22 $41,673 $(10,551)$(402)$30,742 $1,372 $32,114 
Repurchases of shares(7)(113)(113)(113)
Restricted shares
15 15 15 
Net income679 679 24 703 
Dividends
(627)(627)(627)
Distributions
— (39)(39)
Other comprehensive income61 61 61 
Balance at March 31, 20232,241 $22 $41,575 $(10,499)$(341)$30,757 $1,357 $32,114 
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 4)(11)(11)(11)
Balance at January 1, 20222,26723 41,795 (10,595)(411)30,812 1,098 31,910 
Repurchases of shares(1)(1)(1)
EP Trust I Preferred security conversions1 1 1 
Restricted shares18 18 18 
Net income667 667 17 684 
Dividends(616)(616)(616)
Distributions— (26)(26)
Other comprehensive loss(263)(263)(263)
Balance at March 31, 20222,267$23 $41,813 $(10,544)$(674)$30,618 $1,089 $31,707 
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 82,000 miles of pipelines, 140 terminals, 700 Bcf of working natural gas storage capacity and 2.3 Bcf per year of RNG 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 2022 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.

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.

The following table sets forth the allocation of net income available to shareholders of Class P common stock and participating securities:
Three Months Ended
March 31,
20232022
(In millions, except per share amounts)
Net Income Available to Stockholders$679 $667 
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)(4)(4)
Net Income Allocated to Class P Stockholders$675 $663 
Basic Weighted Average Shares Outstanding2,247 2,267 
Basic Earnings Per Share$0.30 $0.29 
(a)As of March 31, 2023, there were 13 million restricted stock awards outstanding.
10



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
March 31,
20232022
(In millions on a weighted average basis)
Unvested restricted stock awards13 13 
Convertible trust preferred securities3 3 

2. Losses on Impairments

Impairments

During the first quarter of 2023, we recognized an impairment of $67 million related to our investment in Double Eagle Pipeline LLC (Double Eagle). The impairment was driven by lower expected renewal rates on contracts that expire in the second half of 2023. The impairment is recognized on our accompanying consolidated statement of income for the three months ended March 31, 2023 within “Earnings from equity investments.” Our investment in Double Eagle and associated earnings is included within our Products Pipelines business segment.

Ruby Chapter 11 Bankruptcy

On January 13, 2023, the bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby, which involved payment of Ruby’s outstanding senior notes with the proceeds from the sale of Ruby to Tallgrass, a settlement by KMI and Pembina of certain potential causes of action relating to the bankruptcy, and cash on hand. Our payment to the bankruptcy estate, net of payments received in respect of a long-term subordinated note receivable from Ruby, was approximately $28.5 million which was accrued for as of December 31, 2022. Consummation of the settlement and the sale of Ruby to Tallgrass occurred on January 13, 2023. 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.

11


3. Debt

The following table provides information on the principal amount of our outstanding debt balances:
March 31, 2023December 31, 2022
(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2027
$— $— 
$500 million credit facility due November 16, 2023
— — 
Commercial paper notes— — 
Current portion of senior notes
3.15% due January 2023
— 1,000 
Floating rate, due January 2023— 250 
3.45% due February 2023
— 625 
3.50% due September 2023
600 600 
5.625% due November 2023
750 750 
4.15% due February 2024
650 — 
Trust I preferred securities, 4.75%, due March 2028(a)
111 111 
Current portion of other debt49 49 
Total current portion of debt2,160 3,385 
Long-term debt (excluding current portion)
Senior notes28,495 27,638 
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035
326 330 
Trust I preferred securities, 4.75%, due March 2028
109 109 
Other209 211 
Total long-term debt29,139 28,288 
Total debt(b)$31,299 $31,673 
(a)Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders.
(b)Excludes our “Debt fair value adjustments” which, as of March 31, 2023 and December 31, 2022, increased our total debt balances by $207 million and $115 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 January 31, 2023, we issued in a registered offering $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.

Credit Facilities and Restrictive Covenants

As of March 31, 2023, 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 March 31, 2023 was $3.9 billion. For the period ended March 31, 2023, we were in compliance with all required covenants.

12


Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below: 
March 31, 2023December 31, 2022
Carrying
value		Estimated
fair value(a)		Carrying
value		Estimated
fair value(a)
(In millions)
Total debt$31,506 $30,483 $31,788 $30,070 
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $198 million and $195 million as of March 31, 2023 and December 31, 2022, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, 2023 and December 31, 2022.

4. 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. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion. During the three months ended March 31, 2023, we repurchased 7 million of our shares for $113 million at an average price of $16.62 per share.

Dividends

The following table provides information about our per share dividends:
Three Months Ended
March 31,
20232022
Per share cash dividend declared for the period$0.2825 $0.2775 
Per share cash dividend paid in the period0.2775 0.27 

On April 19, 2023, our board of directors declared a cash dividend of $0.2825 per share for the quarterly period ended March 31, 2023, which is payable on May 15, 2023 to shareholders of record as of the close of business on May 1, 2023.

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 Subtopic 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 three months ended March 31, 2022.

13


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, 2022
$(164)$(238)$(402)
Other comprehensive gain before reclassifications106 4 110 
Gain reclassified from accumulated other comprehensive loss(49)— (49)
Net current-period change in accumulated other comprehensive loss57 4 61 
Balance as of March 31, 2023$(107)$(234)$(341)
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)$(411)
Other comprehensive (loss) gain before reclassifications(411)13 (398)
Loss reclassified from accumulated other comprehensive loss135 — 135 
Net current-period change in accumulated other comprehensive loss(276)13 (263)
Balance as of March 31, 2022$(448)$(226)$(674)

5.  Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

Energy Commodity Price Risk Management

As of March 31, 2023, 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(17.9)MMBbl
Crude oil basis(3.2)MMBbl
Natural gas fixed price(76.7)Bcf
Natural gas basis(64.0)Bcf
NGL fixed price(0.7)MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price(1.2)MMBbl
Crude oil basis(10.8)MMBbl
Natural gas fixed price(7.1)Bcf
Natural gas basis(49.8)Bcf
NGL fixed price(0.9)MMBbl

14


As of March 31, 2023, 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 2027.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of March 31, 2023:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)$7,400 Fair value hedgeMarch 2035
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts3,445 Mark-to-MarketDecember 2023
(a)The principal amount of hedged senior notes consisted of $1,450 million included in “Current portion of debt” and $5,950 million included in “Long-term debt” on our accompanying consolidated balance sheet.
(b)During the three months ended March 31, 2023, 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 10 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 March 31, 2023:
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.

15


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
March 31,
2023		December 31,
2022		March 31,
2023		December 31,
2022
LocationFair valueFair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)$119 $150 $(132)$(156)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)13 6 (58)(91)
Subtotal132 156 (190)(247)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)1 — (138)(144)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)48 39 (160)(261)
Subtotal49 39 (298)(405)
Foreign currency contracts
Fair value of derivative contracts/(Fair value of derivative contracts)— — (12)(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)— — (19)(32)
Subtotal— — (31)(35)
Total181 195 (519)(687)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)37 80 (62)(162)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)13 23 (4)(19)
Subtotal50 103 (66)(181)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)7 1 — — 
Total57 104 (66)(181)
Total derivatives$238 $299 $(585)$(868)



16


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(a)
Level 1Level 2Level 3Gross amountNet amount
(In millions)
As of March 31, 2023
Energy commodity derivative contracts(b)$110 $72 $— $182 $(87)$— $95 
Interest rate contracts— 56 — 56 — — 56 
As of December 31, 2022
Energy commodity derivative contracts(b)$115 $144 $— $259 $(186)$— $73 
Interest rate contracts— 40 — 40 — — 40 
Balance sheet liability
fair value measurements by level		Contracts available for nettingCash collateral posted(a)
Level 1Level 2Level 3Gross amountNet amount
(In millions)
As of March 31, 2023
Energy commodity derivative contracts(b)$(25)$(231)$— $(256)$87 $(43)$(212)
Interest rate contracts— (298)— (298)— — (298)
Foreign currency contracts— (31)— (31)— — (31)
As of December 31, 2022
Energy commodity derivative contracts(b)$(23)$(405)$— $(428)$186 $(30)$(272)
Interest rate contracts— (405)— (405)— — (405)
Foreign currency contracts— (35)— (35)— — (35)
(a)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.
(b)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.

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
March 31,
20232022
(In millions)
Interest rate contracts
Interest, net$118 $(317)
Hedged fixed rate debt(a)
Interest, net$(118)$320 
(a)As of March 31, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $249 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


17



Derivatives in cash flow hedging relationships		Gain/(loss)
recognized in OCI on derivative(a)		LocationGain/(loss) reclassified from Accumulated OCI
into income
Three Months Ended
March 31,		Three Months Ended
March 31,
2023202220232022
(In millions)(In millions)
Energy commodity derivative contracts
$135 $(499)
Revenues—Commodity sales
$64 $(132)
Costs of sales
(7)9 
Interest rate contracts
— 3 Interest, net— — 
Foreign currency contracts
3 (40)
Other, net
7 (53)
Total$138 $(536)Total$64 $(176)
(a)We expect to reclassify approximately $66 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of March 31, 2023 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.
Derivatives not designated as accounting hedgesLocationGain/(loss) recognized in income on derivatives
Three Months Ended
March 31,
20232022
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$22 $(9)
Costs of sales
69 (91)
Earnings from equity investments1 (5)
Interest rate contractsInterest, net5 36 
Total(a)$97 $(69)
(a)The three months ended March 31, 2023 and 2022 amounts include approximate gains of $28 million and $18 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of March 31, 2023 and December 31, 2022, we had no outstanding letters of credit supporting our commodity price risk management program. As of March 31, 2023, we had cash margins of $5 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2022, we had cash margins of $1 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The cash margin balance at March 31, 2023 represents our initial margin requirements of $48 million and variation margin requirements of $43 million posted by 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 March 31, 2023, 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 $88 million of additional collateral.

18


6. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
Three Months Ended March 31, 2023
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$917 $40 $207 $— $(1)$1,163 
Fee-based services236 240 98 10 — 584 
Total services1,153 280 305 10 (1)1,747 
Commodity sales
Natural gas sales799 — — 20 (2)817 
Product sales274 336 4 268 (1)881 
Total commodity sales1,073 336 4 288 (3)1,698 
Total revenues from contracts with customers2,226 616 309 298 (4)3,445 
Other revenues(c)
Leasing services(d)117 47 152 14 — 330 
Derivatives adjustments on commodity sales107 (1)— (20)— 86 
Other16 6 — 5 — 27 
Total other revenues240 52 152 (1)— 443 
Total revenues$2,466 $668 $461 $297 $(4)$3,888 
Three Months Ended March 31, 2022
Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)$939 $59 $188 $— $(1)$1,185 
Fee-based services213 234 98 13 — 558 
Total services1,152 293 286 13 (1)1,743 
Commodity sales
Natural gas sales1,226 — — 20 (4)1,242 
Product sales342 426 4 348 (16)1,104 
Total commodity sales1,568 426 4 368 (20)2,346 
Total revenues from contracts with customers2,720 719 290 381 (21)4,089 
Other revenues(c)
Leasing services(d)117 44 140 13 — 314 
Derivatives adjustments on commodity sales
(39)(3)— (99)— (141)
Other15 6 — 10 — 31 
Total other revenues93 47 140 (76)— 204 
Total revenues$2,813 $766 $430 $305 $(21)$4,293 
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(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 5 for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

As of March 31, 2023 and December 31, 2022, our contract asset balances were $26 million and $33 million, respectively. Of the contract asset balance at December 31, 2022, $14 million was transferred to accounts receivable during the three months ended March 31, 2023. As of March 31, 2023 and December 31, 2022, our contract liability balances were $228 million and $204 million, respectively. Of the contract liability balance at December 31, 2022, $35 million was recognized as revenue during the three months ended March 31, 2023.

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of March 31, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods:
YearEstimated Revenue
(In millions)
Nine months ended December 31, 2023$3,260 
20243,633 
20252,967 
20262,581 
20272,215 
Thereafter13,095 
Total$27,751 

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.

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7.  Reportable Segments

Financial information by segment follows:
Three Months Ended
March 31,
20232022
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers$2,463 $2,793 
Intersegment revenues3 20 
Products Pipelines668 766 
Terminals
Revenues from external customers460 429 
Intersegment revenues1 1 
CO2
297 305 
Corporate and intersegment eliminations(4)(21)
Total consolidated revenues$3,888 $4,293 
Three Months Ended
March 31,
20232022
(In millions)
Segment EBDA(a)
Natural Gas Pipelines$1,495 $1,184 
Products Pipelines184 299 
Terminals254 238 
CO2
172 192 
Total Segment EBDA2,105 1,913 
DD&A(565)(538)
Amortization of excess cost of equity investments(17)(19)
General and administrative and corporate charges(179)(145)
Interest, net (445)(333)
Income tax expense(196)(194)
Total consolidated net income$703 $684 
March 31, 2023December 31, 2022
(In millions)
Assets
Natural Gas Pipelines$47,351 $47,978 
Products Pipelines8,836 8,985 
Terminals8,328 8,357 
CO2
3,465 3,449 
Corporate assets(b)951 1,309 
Total consolidated assets$68,931 $70,078 
(a)Includes revenues, earnings from equity investments, operating expenses, gain 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, 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.

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8.  Income Taxes

Income tax expense included on our accompanying consolidated statements of income is as follows:
Three Months Ended
March 31,
20232022
(In millions, except percentages)
Income tax expense$196 $194 
Effective tax rate21.8 %22.1 %

The effective tax rates for the three months ended March 31, 2023 and 2022 are higher than the statutory federal rate of 21% primarily due to state income taxes, partially offset by dividend-received deductions from our investments in Florida Gas Pipeline, NGPL Holdings and Products (SE) Pipe Line Company.

9.   Litigation and Environmental

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

Gulf LNG Facility Disputes

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 (Guarantee) entered into by Eni S.p.A. on December 10, 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). The suit to enforce the Guarantee against Eni S.p.A. was filed after an arbitration tribunal delivered an award on June 29, 2018 which called for the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response to GLNG’s lawsuit to enforce the Guarantee, Eni S.p.A. filed counterclaims and other claims based on the terminal use agreement and a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing counterclaims asserted by Eni S.p.A seek unspecified damages and involve the same substantive allegations which were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A. 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. GLNG filed an appeal of the trial court’s decision to the state Appellate Division. On February 9, 2023, the Appellate Division denied GLNG’s appeal. GLNG is seeking rehearing from the Appellate Division. If necessary, further recourse may be pursued to the state Court of Appeals, which is the state’s highest appellate court. 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 based on the terminal use agreement and parent direct agreement remain pending in the trial court. We vigorously dispute that the foregoing counterclaims and other claims asserted by Eni S.p.A. have any merit, particularly since they were dismissed with prejudice in previous arbitrations involving both Eni USA and ALSS. We intend to vigorously pursue our appeal to enforce the Guarantee and are seeking summary judgment on any remaining counterclaims or other claims asserted by Eni S.p.A.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit 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
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needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On November 21, 2022, Freeport filed a notice of intent to appeal the trial court’s decision. We believe that our declaration of force majeure was valid and we intend to vigorously defend this case.

Pension Plan Litigation

On February 22, 2021, Kinder Morgan Retirement Plan A participants Curtis Pedersen and Beverly Leutloff filed a purported class action lawsuit under the Employee Retirement Income Security Act of 1974 (ERISA). The named plaintiffs were hired initially by the ANR Pipeline Company (ANR) in the late 1970s. Following a series of corporate acquisitions, plaintiffs became participants in pension plans sponsored by the Coastal Corporation (Coastal), El Paso Corporation (El Paso) and our company by virtue of our acquisition of El Paso in 2012 and our assumption of certain of El Paso’s pension plan obligations. The lawsuit, which was filed initially in federal court in Michigan and then transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590), alleges that the series of foregoing transactions resulted in changes to plaintiffs’ retirement benefits which are now contested on a purported class-wide basis in the lawsuit. The complaint asserts six claims that fall within three primary theories of liability. Claims I, II, and III all seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. These claims challenge plan provisions which are alleged to constitute impermissible “backloading” or “cutback” of benefits. Claims IV and V allege that former participants in the ANR plans should be eligible for unreduced benefits at younger ages than the plans currently provide. Claim VI asserts that actuarial assumptions used to calculate reduced early retirement benefits for current or former ANR employees are outdated and therefore unreasonable. The complaint alleges that the purported class includes over 10,000 individuals. The lawsuit is in the early stages of discovery and no class has been certified. Plaintiffs seek to recover early retirement benefits as well as declaratory and injunctive relief, but have not pleaded, disclosed or otherwise specified a calculation of alleged damages. Accordingly, the extent of our potential liability for past or future benefits, if any, remains to be determined. We believe that none of the claims are valid and 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. EPNG completed the physical work on Line 2000 in accordance with PHMSA’s requirements and returned the pipeline to commercial service in February 2023. 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 March 31, 2023 and December 31, 2022, our total reserve for legal matters was $43 million and $70 million, respectively.

Environmental Matters

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

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 alleged violations of Department of Transportation regulations, proposed a penalty of approximately $455,000 and sought a compliance agreement relating to certain of the alleged violations. On February 3, 2023, PHMSA and KMLT entered into a Consent Agreement resolving the allegations in the NOPV. Also on February 3, 2023, PHMSA issued a Consent Order approving the Consent Agreement, thereby concluding this matter.

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 December 2024. 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, NRD claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.

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. 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, engaged in discussions with the EPA as a result thereof. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. At that time, the cleanup plan in the ROD was estimated to cost $440 million. No timeline for the cleanup has been established. On December 16, 2022, the United States Department of
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Justice (DOJ) and EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, to resolve their collective liability at the Site. The total amount of the settlement is $150 million. Also on December 16, 2022, the DOJ on behalf of the EPA filed a Complaint against the 85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and a Consent Decree in the U.S. District Court for the District of New Jersey. We believe our share of the costs to resolve this matter, including our share of the settlement with EPA and the costs to remediate the Site, if any, will not 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. The case was 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 subsequently remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. 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.

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 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. 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.

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,
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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 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 March 31, 2023 and December 31, 2022, we have accrued a total reserve for environmental liabilities in the amount of $218 million and $221 million, respectively. In addition, as of March 31, 2023 and December 31, 2022, we had receivables of $11 million and $12 million, respectively, recorded for expected cost recoveries that have been deemed probable.

10. 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). 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 Topic 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.

On December 21, 2022, the FASB issued ASU No. 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848.” This ASU defers the sunset date of Topic 848 from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the optional expedients and exceptions in Topic 848.

The guidance was effective upon issuance.

During the three months ended March 31, 2023 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 $1,225 million and convert a portion of our fixed rate debt to variable rates through February 2028. 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. See Note 5 “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 2022 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2022 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2022 Form 10-K; and (iv) “Risk Factors” in Part II, Item 1A of this report and Part I, Item 1 in our 2022 Form 10-K.

2023 Dividends and Discretionary Capital

We expect to declare dividends of $1.13 per share for 2023, a 2% increase from the 2022 declared dividends of $1.11 per share. We expect to invest $2.2 billion in expansion projects, acquisitions, and contributions to joint ventures during 2023.

The expectations for 2023 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 Net income attributable to Kinder Morgan, Inc. and Segment EBDA (as presented in Note 7 “Reportable Segments”) along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA and Net Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the three months ended March 31, 2023 and 2022 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with GAAP, and Segment EBDA, which is disclosed in Note 7 “Reportable Segments” pursuant to FASB ASC 280. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. 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 our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, 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 most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings,” “—Non-GAAP Financial Measures—Reconciliation of Net Income
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Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below). The following table summarizes our Certain Items for the three months ended March 31, 2023 and 2022, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.

Three Months Ended March 31,
20232022
(In millions)
Certain Items
Fair value amortization$(4)$(4)
Change in fair value of derivative contracts(a)(68)82 
Loss on impairment67 — 
Income tax Certain Items(b)1 (20)
Other— 7 
Total Certain Items(c)(d)$(4)$65 
(a)Gains or losses are reflected when realized.
(b)Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the investees by the joint ventures which are also taxable entities.
(c)2023 and 2022 amounts include the following amounts included within “Earnings from equity investments” on our accompanying consolidated statements of income: (i) $(2) million and $5 million, respectively, included within “Change in fair value of derivative contracts” and (ii) for the 2023 period only, $67 million included within “Loss on impairment” for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 2 “Losses on Impairments—Impairments”).
(d)2023 and 2022 amounts include, in the aggregate, $(8) million and $(44) million, respectively, included within “Interest, net” on the accompanying consolidated statements of income which consist of $(4) million in each period of “Fair value amortization” and $(4) million and $(40) million, respectively, of “Change in fair value of derivative contracts.”

Adjusted Earnings

Adjusted Earnings is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. 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. to Adjusted Earnings” below.

DCF

DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items, and further for DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure used by us, investors and other external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate economic earnings after paying interest expense, paying cash taxes and expending sustaining capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF is also used by us, investors, and other external users to compare the performance of companies across our industry. DCF per share serves as the primary financial performance target for purposes of annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. 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. 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, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. 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. See “—Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment EBDA” below.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A and amortization of excess cost of equity investments, income tax expense and interest. 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, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. 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; further, we remove the portion of these adjustments attributable to non-controlling interests. (See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of March 31, 2023, by subtracting the following amounts from our debt balance of $31,506 million: (i) cash and cash equivalents of $416 million; (ii) debt fair value adjustments of $207 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $(1) million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors and other external users of our financial information to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is total debt.

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Consolidated Earnings Results

The following tables summarize the key components of our consolidated earnings results.

Three Months Ended
March 31,
20232022Earnings
increase/(decrease)
(In millions, except percentages)
Revenues$3,888 $4,293 $(405)(9)%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)(1,215)(1,894)679 36 %
Operations and maintenance(639)(585)(54)(9)%
DD&A(565)(538)(27)(5)%
General and administrative(166)(156)(10)(6)%
Taxes, other than income taxes(110)(111)1 1 %
Gain on divestitures and impairments, net— 10 (10)(100)%
Other income, net1 5 (4)(80)%
Total Operating Costs, Expenses and Other(2,694)(3,269)575 18 %
Operating Income1,194 1,024 170 17 %
Other Income (Expense)
Earnings from equity investments165 187 (22)(12)%
Amortization of excess cost of equity investments(17)(19)2 11 %
Interest, net(445)(333)(112)(34)%
Other, net2 19 (17)(89)%
Total Other Expense(295)(146)(149)(102)%
Income Before Income Taxes899 878 21 2 %
Income Tax Expense(196)(194)(2)(1)%
Net Income703 684 19 3 %
Net Income Attributable to Noncontrolling Interests(24)(17)(7)(41)%
Net Income Attributable to Kinder Morgan, Inc.$679 $667 $12 2 %
Basic and diluted earnings per share$0.30 $0.29 $0.01 3 %
Basic and diluted weighted average shares outstanding 2,247 2,267 (20)(1)%
Declared dividends per share$0.2825 $0.2775 $0.005 2 %

Below is a discussion of significant changes in our Consolidated Earnings Results for the comparable three-month periods ended March 31, 2023 and 2022:

Revenues

Revenues decreased $405 million in 2023 compared to 2022. The decrease was primarily due to lower commodity sales driven by lower commodity prices and volumes.

Operating Costs, Expenses and Other

Costs of sales

Costs of sales decreased $679 million in 2023 compared to 2022. The decrease was primarily due to lower commodity prices and volumes. The decrease was further impacted by the period-over-period change related to the impacts of non-cash mark-to-market derivative contracts used to hedge forecasted commodity purchases.

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Other Income (Expense)

Interest, net

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our interest expense, net increased $112 million in 2023 compared to 2022. The increase was primarily due to higher realized SOFR rates associated with interest rate swaps and changes in fair value of interest rate swaps.
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Non-GAAP Financial Measures

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings
Three Months Ended
March 31,
20232022
(In millions, except per share amounts)
Net income attributable to Kinder Morgan, Inc.$679 $667 
Certain Items(a)
Fair value amortization(4)(4)
Change in fair value of derivative contracts(68)82 
Loss on impairment67 — 
Income tax Certain Items1 (20)
Other— 7 
Total Certain Items(4)65 
Adjusted Earnings$675 $732 
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF
Net income attributable to Kinder Morgan, Inc. $679 $667 
Total Certain Items(b)(4)65 
DD&A565 538 
Amortization of excess cost of equity investments17 19 
Income tax expense(c)195 214 
Cash taxes(1)(1)
Sustaining capital expenditures(156)(115)
Amounts from joint ventures
Unconsolidated joint venture DD&A81 77 
Remove consolidated joint venture partners’ DD&A(16)(11)
Unconsolidated joint venture income tax expense(d)(e)26 21 
Unconsolidated joint venture cash taxes(d)— — 
Unconsolidated joint venture sustaining capital expenditures(29)(12)
Remove consolidated joint venture partners’ sustaining capital expenditures2 2 
Other items(f)15 (9)
DCF$1,374 $1,455 
Adjusted Earnings per share$0.30 $0.32 
Weighted average shares outstanding for dividends(g)2,260 2,280 
DCF per share$0.61 $0.64 
Declared dividends per share$0.2825 $0.2775 
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(b)See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings” for a detailed listing.
(c)To avoid duplication, 2023 and 2022 adjustments for income tax expense exclude $1 million and $(20) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(d)Associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments.
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(e)Includes the tax provision on Certain Items recognized by the investees that are taxable entities. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(f)Includes non-cash pension expense, non-cash compensation associated with our restricted stock program and pension contributions.
(g)Includes restricted stock awards that participate in dividends.

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA
Three Months Ended
March 31,
20232022
(In millions)
Net income attributable to Kinder Morgan, Inc.$679 $667 
Certain Items(a)
Fair value amortization(4)(4)
Change in fair value of derivative contracts(68)82 
Loss on impairment67 — 
Income tax Certain Items1 (20)
Other— 7 
Total Certain Items(4)65 
DD&A 565 538 
Amortization of excess cost of equity investments17 19 
Income tax expense(b)195 214 
Interest, net(c)453 377 
Amounts from joint ventures
Unconsolidated joint venture DD&A81 77 
Remove consolidated joint venture partners’ DD&A(16)(11)
Unconsolidated joint venture income tax expense(d)26 21 
Adjusted EBITDA$1,996 $1,967 
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(b)To avoid duplication, 2023 and 2022 adjustments for income tax expense exclude $1 million and $(20) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(c)To avoid duplication, 2023 and 2022 adjustments for interest, net exclude $(8) million and $(44) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.
(d)Includes that tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.

Below is a discussion of significant changes in our Adjusted Earnings, DCF and Adjusted EBITDA for the comparable three-month periods ended March 31, 2023 and 2022:
Change from prior periodIncrease/(Decrease)
(In millions)
Adjusted Earnings$(57)
DCF$(81)
Adjusted EBITDA$29 

Adjusted Earnings decreased $57 million in 2023 compared to 2022 and was driven by an increase in interest expense partially offset by favorable margins primarily from our Natural Gas Pipelines business segment. These items also affected DCF. The $81 million decrease in DCF in 2023 compared to 2022 was further impacted by an increase in sustaining capital expenditures. Adjusted EBITDA increased $29 million in 2023 compared to 2022, which was also driven by favorable margins from our Natural Gas Pipelines business segment.
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General and Administrative and Corporate Charges
Three Months Ended
March 31,		Earnings
increase/(decrease)
20232022
(In millions, except percentages)
General and administrative$(166)$(156)$(10)(6)%
Corporate (charges) benefit(13)11 (24)(218)%
General and administrative and corporate charges$(179)$(145)$(34)(23)%

We had unfavorable changes of $10 million in general and administrative expenses and $24 million in our corporate (charges) benefit for the three months ended March 31, 2023 when compared with the respective prior year period. The combined changes were primarily due to higher pension costs of $22 million and higher labor and benefit-related costs of $9 million.

Reconciliation of Segment EBDA to Adjusted Segment EBDA
Three Months Ended
March 31,
20232022
(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA$1,495 $1,184 
Certain Items(b)
Change in fair value of derivative contracts(65)106 
Other— 7 
Natural Gas Pipelines Adjusted Segment EBDA$1,430 $1,297 
Products Pipelines Segment EBDA$184 $299 
Certain Items(b)
Loss on impairment67 — 
Products Pipelines Adjusted Segment EBDA$251 $299 
Terminals Segment EBDA$254 $238 
CO2 Segment EBDA
$172 $192 
Certain Items(b)
Change in fair value of derivative contracts1 16 
CO2 Adjusted Segment EBDA
$173 $208 
(a)Includes revenues, earnings from equity investments, operating expenses, gain 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. See “—Overview—GAAP Financial Measures” above.
(b)See “—Overview—Non-GAAP Financial Measures—Certain Items” above.
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Segment Earnings Results

Natural Gas Pipelines
Three Months Ended
March 31,
20232022
(In millions, except operating statistics)
Revenues$2,466 $2,813 
Operating expenses(1,177)(1,784)
Other income1 1 
Earnings from equity investments200 154 
Other, net5 — 
Segment EBDA1,495 1,184 
Certain Items:
Change in fair value of derivative contracts(65)106 
Other— 7 
Certain Items(a)(65)113 
Adjusted Segment EBDA$1,430 $1,297 
Change from prior periodIncrease/(Decrease)
Segment EBDA$311 
Adjusted Segment EBDA$133 
Volumetric data(b)
Transport volumes (BBtu/d)40,400 39,319 
Sales volumes (BBtu/d)2,117 2,515 
Gathering volumes (BBtu/d)3,325 2,817 
NGLs (MBbl/d)35 32 
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 Certain Items of $(63) million and $(2) million are associated with our Midstream and East businesses, respectively. 2022 Certain Items of $101 million, $7 million and $5 million are associated with our Midstream, West and East businesses, respectively. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.

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Below are the changes in Segment EBDA in the comparable three-month periods ended March 31, 2023 and 2022:

Three Months Ended March 31, 2023 versus Three Months Ended March 31, 2022

20232022increase/
(decrease)
(In millions)
Midstream$540 $283 $257 
East696 647 49 
West259 254 5 
Total Natural Gas Pipelines Segment EBDA$1,495 $1,184 $311 

The changes in Segment EBDA for our Natural Gas Pipelines business segment in the comparable three-month periods ended March 31, 2023 and 2022 are explained by the following discussion:
•A $257 million (91%) increase in Midstream was affected by period-over-period decreases in costs of sales and, to a lesser extent, in revenues related to the impacts of non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, which we treated as Certain Items.

In addition, Midstream was favorably impacted by higher sales margins on our Texas intrastate natural gas pipeline operations largely driven by realized gains on sales hedges partially offset by lower sales volumes, higher volumes on our KinderHawk assets and higher gas sales margins driven by higher weather-related prices on our Altamont asset, partially offset by lower deficiency revenues and lower service fee revenues as a result of a renegotiated contract at a lower price on our South Texas assets. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

•A $49 million (8%) increase in the East Region was primarily due to higher equity earnings from Midcontinent Express Pipeline LLC, driven by new customer contracts entered into in the later part of 2022, and higher revenues as a result of increased demand in park and loan services due to favorable pricing on our Stagecoach assets.

•A $5 million (2%) increase in the West Region was primarily due to higher earnings from EPNG due to an increase in gas sales margin and the return of a pipeline to service, partially offset by lower revenues from Cheyenne Plains Gas Pipeline Company, L.L.C. due to the expiration of a customer contract in December 2022 and lower revenues from Colorado Interstate Gas Company, L.L.C. and Wyoming Interstate Company, L.L.C. resulting from rate case settlements effective April 2022.

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Products Pipelines
Three Months Ended
March 31,
20232022
(In millions, except operating statistics)
Revenues$668 $766 
Operating expenses(440)(497)
Gain on divestitures and impairments, net— 12 
(Loss) earnings from equity investments(44)18 
Segment EBDA184 299 
Certain Items:
Loss on impairment67 — 
Certain Items(a)67 — 
Adjusted Segment EBDA$251 $299 
Change from prior periodIncrease/(Decrease)
Segment EBDA$(115)
Adjusted Segment EBDA$(48)
Volumetric data(b)
Gasoline(c)948 940 
Diesel fuel328 369 
Jet fuel271 242 
Total refined product volumes1,547 1,551 
Crude and condensate460 486 
Total delivery volumes (MBbl/d)2,007 2,037 
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 Certain Item of $67 million is associated with our Crude and Condensate business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

Below are the changes in Segment EBDA in the comparable three-month periods ended March 31, 2023 and 2022:

Three Months Ended March 31, 2023 versus Three Months Ended March 31, 2022

20232022increase/
(decrease)
(In millions)
Crude and Condensate$5 $89 $(84)
West Coast Refined Products108 137 (29)
Southeast Refined Products71 73 (2)
Total Products Pipelines Segment EBDA$184 $299 $(115)

The changes in Segment EBDA for our Products Pipelines business segment in the comparable three-month periods ended March 31, 2023 and 2022 are explained by the following discussion:
•An $84 million (94%) decrease in Crude and Condensate was affected by a $67 million reduction to equity earnings for a non-cash impairment related to our investment in Double Eagle Pipeline LLC, which we treated as a Certain Item.
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In addition, Crude and Condensate was unfavorably impacted by lower earnings from lower volumes on our Double H pipeline and from our Kinder Morgan Crude & Condensate pipeline driven primarily by a decrease in revenues as a result of re-contracting at lower rates and lower deficiency revenues. Our Crude and Condensate business also had lower revenues with a corresponding decrease in costs of sales, resulting from decreased commodity pricing.

•A $29 million (21%) decrease in West Coast Refined Products was primarily due to lower earnings on our Pacific operations resulting from net changes in product gains and losses affecting operating costs and a gain on sale of land in the 2022 period at Calnev.

•A $2 million (3%) decrease in Southeast Refined Products was primarily due to lower earnings at our Transmix processing operations primarily due to lower prices, partially offset by higher volumes and rate escalations across numerous assets.

Terminals
Three Months Ended
March 31,
20232022
(In millions, except operating statistics)
Revenues$461 $430 
Operating expenses(210)(199)
Loss on divestitures and impairments, net
— (3)
Other income— 4 
Earnings from equity investments2 4 
Other, net1 2 
Segment EBDA$254 $238 
Change from prior periodIncrease/(Decrease)
Segment EBDA$16 
Volumetric data(a)
Liquids leasable capacity (MMBbl)78.3 78.2 
Liquids leased capacity %(b)92.8 %90.6 %
Bulk transload tonnage (MMtons)13.4 13.0 
(a)Volumes for facilities divested, idled and/or held for sale are excluded for all periods presented.
(b)The ratio of our tankage capacity in service to liquids leasable capacity.

For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical business grouping below and included within the All others group.

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Below are the changes in Segment EBDA in the comparable three-month periods ended March 31, 2023 and 2022:

Three Months Ended March 31, 2023 versus Three Months Ended March 31, 2022

20232022increase/
(decrease)
(In millions)
Gulf Central$38 $32 $6 
Marine operations41 38 3 
Mid Atlantic26 23 3 
Northeast25 22 3 
All others (including intrasegment eliminations)124 123 1 
Total Terminals Segment EBDA$254 $238 $16 

The changes in Segment EBDA for our Terminals business segment in the comparable three-month periods ended March 31, 2023 and 2022 are explained by the following discussion:
•A $6 million (19%) increase in the Gulf Central terminals was primarily due to higher revenues resulting from contractual rate escalations and higher volumes for petroleum coke handling activities.

•A $3 million (8%) increase in Marine operations was primarily due to higher average charter rates.

•A $3 million (13%) increase in the Mid Atlantic terminals was primarily due to higher revenues resulting from increased effective handling rates on export coal volumes at our Pier IX facility.

•A $3 million (14%) increase in the Northeast terminals was primarily driven by increased revenues associated with higher utilization at our Carteret facility.

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CO2
Three Months Ended
March 31,
20232022
(In millions, except operating statistics)
Revenues$297 $305 
Operating expenses(132)(125)
Gain on divestitures and impairments, net— 1 
Earnings from equity investments7 11 
Segment EBDA172 192 
Certain Items:
Change in fair value of derivative contracts1 16 
Certain Items(a)1 16 
Adjusted Segment EBDA$173 $208 
Change from prior periodIncrease/(Decrease)
Segment EBDA$(20)
Adjusted Segment EBDA$(35)
Volumetric data
SACROC oil production18.90 19.27 
Yates oil production6.74 6.79 
Other2.61 2.91 
Total oil production, net (MBbl/d)(b)28.25 28.97 
NGL sales volumes, net (MBbl/d)(b)8.16 9.41 
CO2 sales volumes, net (Bcf/d)
0.36 0.37 
Realized weighted average oil price ($ per Bbl)$67.15 $66.90 
Realized weighted average NGL price ($ per Bbl)$34.06 $43.68 
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 and 2022 Certain Items are associated with our Oil and Gas Producing activities. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Net of royalties and outside working interests.

Below are the changes in Segment EBDA in the comparable three-month periods ended March 31, 2023 and 2022:

Three Months Ended March 31, 2023 versus Three Months Ended March 31, 2022

20232022increase/
(decrease)
(In millions)
Source and Transportation activities$49 $62 $(13)
Oil and Gas Producing activities118 126 (8)
Subtotal167 188 (21)
Energy Transition Ventures5 4 1 
Total CO2 Segment EBDA
$172 $192 $(20)

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The changes in Segment EBDA for our CO2 business segment in the comparable three-month periods ended March 31, 2023 and 2022 are explained by the following discussion:
•A $13 million (21%) decrease in Source and Transportation activities primarily due to higher operating expenses and a decrease in revenues related to lower CO2 sales prices and volumes.

•An $8 million (6%) decrease in Oil and Gas Producing activities primarily due to a decrease in revenues related to lower realized NGL prices and lower NGL and crude oil volumes which was largely driven by an extended outage at SACROC.

In addition, Oil and Gas Producing activities was affected by a favorable change period-over-period in revenues related to non-cash mark-to-market derivative hedge contracts which we treated as Certain Items.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to a lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of March 31, 2023:

Remaining 20232024202520262027
Crude Oil(a)
Price ($ per Bbl)$64.67 $62.45 $61.98 $65.32 $62.23 
Volume (MBbl/d)23.57 15.50 10.05 5.30 0.50 
NGLs
Price ($ per Bbl)$55.11 $36.23 
Volume (MBbl/d)3.82 0.04 
Midland-to-Cushing Basis Spread
Price ($ per Bbl)$1.00 $1.15 
Volume (MBbl/d)21.00 2.75 
Argus Calendar Month Average Basis Spread
Price ($ per Bbl)$0.91 $0.43 
Volume (MBbl/d)21.25 2.50 
(a)Includes West Texas Intermediate hedges.

Liquidity and Capital Resources

General

As of March 31, 2023, we had $416 million of “Cash and cash equivalents,” a decrease of $329 million from December 31, 2022. Additionally, as of March 31, 2023, we had borrowing capacity of approximately $3.9 billion under our credit facilities (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flows from operations, providing a source of funds of $1,333 million and $1,084 million in the first three months of 2023 and 2022, respectively. The period-to-period increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our expansion capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of March 31, 2023 and December 31, 2022, approximately 13% and 20%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The percentage at March 31, 2023 and December 31,
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2022 includes $3,445 million and $1,250 million, respectively, of variable-to-fixed interest rate derivative contracts which expire in December 2023. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Our board of directors declared a quarterly dividend of $0.2825 per share for the first quarter of 2023, a 2% increase over the dividend declared for the first quarter of 2022.

On January 31, 2023, we issued in a registered offering $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.

During the first quarter, upon maturity, we repaid our 3.15% senior notes, our floating rate senior notes and our 3.45% senior notes.

Short-term Liquidity

As of March 31, 2023, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion of credit facilities with an available capacity of approximately $3.9 billion and an associated $3.5 billion commercial paper program. The loan commitments under our credit facilities can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our credit facilities and letters of credit reduce borrowings allowed under our $3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facilities and, as previously discussed, have consistently generated strong cash flows from operations.

As of March 31, 2023, our $2,160 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2022 was $3,385 million.

We had working capital (defined as current assets less current liabilities) deficits of $2,079 million and $3,127 million as of March 31, 2023 and December 31, 2022, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $1,048 million favorable change from year-end 2022 was primarily due to (i) a $1,225 million decrease in senior notes that mature in the next twelve months; (ii) a $288 million decrease in other current liabilities, primarily related to reductions in property tax and bonus accruals and exchange gas payables; (iii) a $164 million decrease in accrued interest; and (iv) favorable short-term fair value adjustments on derivative contracts of $54 million; partially offset by (i) a $329 million decrease in cash and cash equivalents which was used to repay a portion of senior notes that matured in the first quarter of 2023; (ii) a $162 million net unfavorable change in our accounts receivables and payables; (iii) a $120 million decrease in other current assets, primarily in exchange gas receivables and regulatory assets; and (iv) a $45 million decrease in inventories, primarily associated with gas in underground storage. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. Additionally, we distinguish between capital expenditures as follows:
Type of ExpenditurePhysical Determination of Expenditure
Sustaining capital expenditures
•Investments to maintain the operational integrity and extend the useful life of our assets
Expansion capital expenditures (discretionary capital expenditures)
•Investments to expand throughput or capacity from that which existed immediately prior to the making or acquisition of additions or improvements

Budgeting of maintenance capital expenditures, which we refer to as sustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those sustaining capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We
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may budget for and make additional sustaining capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures generally occurs periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal, but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion and amortization over the remaining useful lives of the impacted or resulting assets.

Generally, the determination of whether a capital expenditure is classified as sustaining or as expansion is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted in calculating DCF, while those classified as sustaining capital expenditures are.

Our capital expenditures for the three months ended March 31, 2023, and the amount we expect to spend for the remainder of 2023 to sustain our assets and expand our business are as follows:
Three Months Ended
March 31, 2023
2023 Remaining
Total 2023
(In millions)
Capital expenditures:
Sustaining capital expenditures$156 $718 $874 
Expansion capital expenditures368 1,617 1,985 
Accrued capital expenditures, contractor retainage and other(17)— — 
Capital expenditures$507 $2,335 $2,859 
Add:
Sustaining capital expenditures of unconsolidated joint ventures(a)$29 $130 $159 
Investments in unconsolidated joint ventures(b)44 200 244 
Less: Consolidated joint venture partners’ sustaining capital expenditures(2)(9)(11)
Accrued capital expenditures, contractor retainage and other17 — — 
Total capital investments$595 $2,656 $3,251 
(a)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
(b)Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.

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Our capital investments consist of the following:
Three Months Ended
March 31, 2023
2023 RemainingTotal 2023
(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment$156 $718 $874 
Sustaining capital expenditures of unconsolidated joint ventures(a)29 130 159 
Less: Consolidated joint venture partners’ sustaining capital expenditures(2)(9)(11)
Total sustaining capital investments183 839 1,022 
Expansion capital investments
Capital expenditures for property, plant and equipment368 1,617 1,985 
Investments in unconsolidated joint ventures(b)44 200 244 
Total expansion capital investments412 1,817 2,229 
Total capital investments$595 $2,656 $3,251 
(a)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
(b)Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2022 in our 2022 Form 10-K.

Commitments for the purchase of property, plant and equipment as of March 31, 2023 and December 31, 2022 were $322 million and $527 million, respectively. The decrease of $205 million was primarily driven by capital commitments related to our Terminals and Products Pipelines segments.

Cash Flows

The following table summarizes our net cash flows provided by (used in) operating, investing and financing activities between 2023 and 2022.
Three Months Ended
March 31,
20232022Changes
(In millions)
Net Cash Provided by (Used in)
Operating activities$1,333 $1,084 $249 
Investing activities(508)(371)(137)
Financing activities(1,181)(1,512)331 
Net Decrease in Cash, Cash Equivalents and Restricted Deposits$(356)$(799)$443 

Operating Activities

$249 million more cash provided by operating activities in the comparable three-month periods ended March 31, 2023 and 2022 is explained by the following discussion:

•a $316 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities. The increase was primarily driven by (i) net favorable changes related to the timing of accounts receivable collections and trade payable payments, largely in our Natural Gas business segment; and (ii) a decrease in inventories primarily driven by higher settlements associated with commodity hedges related to gas in underground storage; partially offset by,
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•a $67 million decrease in cash after adjusting the $19 million increase in net income by $86 million for the combined effects of the period-to-period net changes in non-cash items.

Investing Activities

$137 million more cash used in investing activities in the comparable three-month periods ended March 31, 2023 and 2022 is explained by the following discussion:

•a $100 million increase in capital expenditures primarily driven by the expansion projects in our Natural Gas business segment.

Financing Activities

$331 million less cash used in financing activities in the comparable three-month periods ended March 31, 2023 and 2022 is explained by the following discussion:

•a $470 million net decrease in cash used related to debt activity as a result of lower net debt payments in the 2023 period compared to the 2022 period; partially offset by,
•a $112 million increase in cash used for share repurchases under our share buy-back program.

Dividends

We expect to declare dividends of $1.13 per share on our stock for 2023. The table below reflects our 2023 dividends declared:
Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2023$0.2825 April 19, 2023May 1, 2023May 15, 2023

The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2022 Form 10-K. All of these matters will be taken into consideration by our board of directors when declaring dividends.

Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.
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Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

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

In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.  Also, see Exhibit 10.1 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of March 31, 2023.”

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

Excluding fair value adjustments, as of March 31, 2023 and December 31, 2022, the Obligated Group had $30,519 million and $30,886 million, respectively, of Guaranteed Notes outstanding.

Summarized combined balance sheet and income statement information for the Obligated Group follows:
Summarized Combined Balance Sheet InformationMarch 31, 2023December 31, 2022
(In millions)
Current assets$2,397 $3,514 
Current assets - affiliates587 618 
Noncurrent assets61,489 61,523 
Noncurrent assets - affiliates520 516 
Total Assets$64,993 $66,171 
Current liabilities$4,456 $6,612 
Current liabilities - affiliates639 707 
Noncurrent liabilities31,679 30,668 
Noncurrent liabilities - affiliates1,137 1,096 
Total Liabilities37,911 39,083 
Kinder Morgan, Inc.’s stockholders’ equity27,082 27,088 
Total Liabilities and Stockholders’ Equity$64,993 $66,171 
Summarized Combined Income Statement InformationThree Months Ended
March 31, 2023
(In millions)
Revenues$3,613 
Operating income1,108 
Net income613 

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2022, in Part II, Item 7A in our 2022 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 4.  Controls and Procedures.

As of March 31, 2023, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended March 31, 2023 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

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

Item 1A. Risk Factors.

Other than the following updated risk factor, there have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2022 Form 10-K. For more information on our risk management activities, refer to Part I, Item 1, Note 5 “Risk Management” to our consolidated financial statements.

New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.

Our assets and operations are subject to extensive regulation and oversight by federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these authorities, have the potential to adversely affect our profitability. Additional regulatory burdens and uncertainties will be created if and to the extent that more stringent energy and environmental and pipeline safety policies are enacted. Overall, we have seen an increase in the efforts of regulatory authorities to issue new regulations and guidance and to interpret existing laws and regulations in ways that promote the use of renewable energy sources and further protection of the environment, call upon companies to increase monitoring and emissions reduction efforts, and increase investigations and enforcement actions for potential violations of environmental laws. For example, in November 2021, the EPA proposed a rule containing standards of performance for GHG emissions, in the form of methane limitations, and volatile organic compound emissions for crude oil and natural gas sources, including the production, processing, transmission and storage segments. In November 2022, the EPA announced a supplemental proposal expanding on the November 2021 proposed rule aimed at achieving more comprehensive emissions reductions from oil and natural gas sources.

These types of proposals, if finalized, would affect our assets and operations indirectly, such as by increasing the costs associated with the production of natural gas and liquids that we transport, or directly, such as by increasing significantly our capital and operating costs associated with impacted equipment.

On March 15, 2023, the EPA announced finalization of its Good Neighbor Plan (the “Plan”) indicating the Plan will significantly cut nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is significantly contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be
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issuing prescriptive emission standards for several sectors, including new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. If the Plan is published in the Federal Register as a final rule, in the form announced by the EPA, those standards will require the installation of more stringent air pollution controls on hundreds of our existing internal combustion engines. The Plan is scheduled to take effect in 2026 and will apply to all impacted engines unless compliance schedule extensions are granted by the EPA, which would need to be supported by us and considered by the EPA on an engine-by-engine basis. The Plan could have material financial impacts on our Natural Gas business segment in relation to the costs necessary to comply with the Plan, the timing of compliance, equipment shortages, potential operational disruptions, and the availability of and costs associated with the purchase of offsets.

These and other initiatives of regulatory authorities may affect our assets and operations directly or indirectly, such as by preventing or delaying the exploration for and production of natural gas and liquids that we transport or expanding regulation of existing infrastructure or new sources that are not currently regulated.

Regulation affects almost every part of our business. In addition to environmental and pipeline safety matters, we are subject to regulations extending to such matters as (i) federal, state and local taxation; (ii) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the integrity, safety and security (including against cyber-attacks) of facilities and operations; (vii) the acquisition of other businesses; (viii) the acquisition, extension, disposition or abandonment of services or facilities; (ix) reporting and information posting requirements; (x) the maintenance of accounts and records; and (xi) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to our income, operations, assets or another aspect of our business could have a material adverse impact on our earnings, cash flow, financial condition and results of operations. For more information, see Items 1 and 2. “Business and Properties—Narrative Description of Business—Industry Regulation” in our 2022 Form 10-K.

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

Our Purchases of Our Class P Stock
(During the quarter ended March 31, 2023)
Settlement PeriodTotal number of securities purchased(a)Average price paid per security(b)Total number of securities purchased as part of publicly announced plans(a)Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs(a)
January 1 to January 31, 2023— $— — $2,057,284,126 
February 1 to February 28, 2023— — — 2,057,284,126 
March 1 to March 31, 20236,810,307 16.62 6,810,307 1,944,068,674 
Total6,810,307 $16.62 6,810,307 $1,944,068,674 
(a)On July 19, 2017, our board of directors approved a $2 billion common share buy-back program. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion from $2 billion. After repurchase, the shares are canceled and no longer outstanding.
(b)Amount includes any commission or other costs to repurchase shares.

Item 3.  Defaults Upon Senior Securities.

None. 

Item 4.  Mine Safety Disclosures.

Except for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank). We have not received any specified health and safety
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violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended March 31, 2023.

Item 5.  Other Information.

None.
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Item 6.  Exhibits.
Exhibit NumberDescription
4.1 
10.1 
22.1 
31.1 
31.2 
32.1 
32.2 
101 
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the three months ended March 31, 2023 and 2022; (ii) our Consolidated Statements of Comprehensive Income for the three months ended March 31, 2023 and 2022; (iii) our Consolidated Balance Sheets as of March 31, 2023 and December 31, 2022; (iv) our Consolidated Statements of Cash Flows for the three months ended March 31, 2023 and 2022; (v) our Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 2023 and 2022; and (vi) the notes to our Consolidated Financial Statements.
104 Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
KINDER MORGAN, INC.
Registrant
Date:April 21, 2023By:/s/ David P. Michels
David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)
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