Item 1. Financial Statements.

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Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts, unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenues
Services	$	2,045	$	2,011	$	4,114	$	4,061
Commodity sales	1,421		3,100		3,206		5,308
Other	35		40		69		75
Total Revenues	3,501		5,151		7,389		9,444

Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	971		2,683		2,186		4,577
Operations and maintenance	685		663		1,324		1,248
Depreciation, depletion and amortization	557		543		1,122		1,081
General and administrative	169		152		335		308
Taxes, other than income taxes	103		116		213		227

Gain on divestitures and impairments, net	(13)		(11)		(13)		(21)
Other income, net	(1)		(1)		(2)		(6)
Total Operating Costs, Expenses and Other	2,471		4,145		5,165		7,414

Operating Income	1,030		1,006		2,224		2,030

Other Income (Expense)
Earnings from equity investments	208		182		373		369

Amortization of excess cost of equity investments	(19)		(19)		(36)		(38)
Interest, net	(443)		(355)		(888)		(688)
Other, net	2		23		4		42
Total Other Expense	(252)		(169)		(547)		(315)

Income Before Income Taxes	778		837		1,677		1,715

Income Tax Expense	(168)		(184)		(364)		(378)

Net Income	610		653		1,313		1,337






Net Income Attributable to Noncontrolling Interests	(24)		(18)		(48)		(35)

Net Income Attributable to Kinder Morgan, Inc.	$	586	$	635	$	1,265	$	1,302





Class P Common Stock
Basic and Diluted Earnings Per Share	$	0.26	$	0.28	$	0.56	$	0.57

Basic and Diluted Weighted Average Shares Outstanding	2,237		2,265		2,242		2,266

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions, unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net income	$	610	$	653	$	1,313	$	1,337
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(14), $24, $(46) and $149, respectively)	49		(78)		155		(489)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $—, $(48), $15 and $(89), respectively)	(2)		157		(51)		292

Benefit plan adjustments (net of taxes of $(1), $(1), $(2) and $(5), respectively)	4		3		8		16
Total other comprehensive income (loss)	51		82		112		(181)

Comprehensive income	661		735		1,425		1,156
Comprehensive income attributable to noncontrolling interests	(24)		(18)		(48)		(35)
Comprehensive income attributable to KMI	$	637	$	717	$	1,377	$	1,121

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share and per share amounts, unaudited)


	June 30, 2023		December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents	$	497	$	745
Restricted deposits	23		49
Accounts receivable	1,284		1,840
Fair value of derivative contracts	153		231
Inventories	569		634


Other current assets	192		304
Total current assets	2,718		3,803

Property, plant and equipment, net	35,759		35,599
Investments	7,665		7,653
Goodwill	19,965		19,965
Other intangibles, net	1,696		1,809


Deferred charges and other assets	1,270		1,249
Total Assets	$	69,073	$	70,078

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,760	$	3,385
Accounts payable	1,142		1,444

Accrued interest	511		515

Fair value of derivative contracts	251		465

Other current liabilities	939		1,121
Total current liabilities	5,603		6,930

Long-term liabilities and deferred credits
Long-term debt
Outstanding	28,536		28,288

Debt fair value adjustments	96		115
Total long-term debt	28,632		28,403
Deferred income taxes	1,010		623

Other long-term liabilities and deferred credits	1,919		2,008

Total long-term liabilities and deferred credits	31,561		31,034
Total Liabilities	37,164		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, 2,228,894,500 and 2,247,681,626 shares, respectively, issued and outstanding	22		22
Additional paid-in capital	41,387		41,673
Accumulated deficit	(10,550)		(10,551)
Accumulated other comprehensive loss	(290)		(402)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,569		30,742
Noncontrolling interests	1,340		1,372
Total Stockholders’ Equity	31,909		32,114
Total Liabilities and Stockholders’ Equity	$	69,073	$	70,078

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


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)

	Six Months Ended June 30,
	2023		2022
Cash Flows From Operating Activities
Net income	$	1,313	$	1,337
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,122		1,081
Deferred income taxes	354		369
Amortization of excess cost of equity investments	36		38

Change in fair value of derivative contracts	(129)		51
Gain on divestitures and impairments, net	(13)		(21)

Earnings from equity investments	(373)		(369)
Distributions from equity investment earnings	367		348
Changes in components of working capital
Accounts receivable	573		(414)
Inventories	101		(108)
Other current assets	89		(39)
Accounts payable	(370)		499
Accrued interest, net of interest rate swaps	(6)		(53)

Other current liabilities	(132)		33
Rate reparations, refunds and other litigation reserve adjustments	(2)		(53)
Other, net	(47)		(51)
Net Cash Provided by Operating Activities	2,883		2,648

Cash Flows From Investing Activities

Acquisition of assets	(14)		—
Capital expenditures	(1,042)		(779)

Contributions to investments	(136)		(20)
Distributions from equity investments in excess of cumulative earnings	118		104

Other, net	(12)		23
Net Cash Used in Investing Activities	(1,086)		(672)

Cash Flows From Financing Activities
Issuances of debt	3,119		4,622
Payments of debt	(3,511)		(5,848)
Debt issue costs	(15)		(7)
Dividends	(1,264)		(1,247)

Repurchases of shares	(317)		(173)





Distributions to noncontrolling interests	(80)		(53)
Other, net	(3)		—
Net Cash Used in Financing Activities	(2,071)		(2,706)


Net Decrease in Cash, Cash Equivalents and Restricted Deposits	(274)		(730)
Cash, Cash Equivalents and Restricted Deposits, beginning of period	794		1,147
Cash, Cash Equivalents and Restricted Deposits, end of period	$	520	$	417


KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)

	Six Months Ended June 30,
	2023		2022
Cash and Cash Equivalents, beginning of period	$	745	$	1,140
Restricted Deposits, beginning of period	49		7
Cash, Cash Equivalents and Restricted Deposits, beginning of period	794		1,147

Cash and Cash Equivalents, end of period	497		100
Restricted Deposits, end of period	23		317
Cash, Cash Equivalents and Restricted Deposits, end of period	520		417

Net Decrease in Cash, Cash Equivalents and Restricted Deposits	$	(274)	$	(730)

Non-cash Investing and Financing Activities
Assets contributed to equity investment	$	16	$	—
ROU assets and operating lease obligations recognized including adjustments	31		(8)

Increase in property, plant and equipment from both accruals and contractor retainage	74
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	919		792
Cash paid during the period for income taxes, net	9		10

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions, unaudited)


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at March 31, 2023	2,241	$	22	$	41,575	$	(10,499)	$	(341)	$	30,757	$	1,357	$	32,114



Repurchases of shares	(12)			(204)						(204)				(204)

Restricted shares				19						19				19
Net income						586				586		24		610
Dividends						(637)				(637)				(637)
Distributions										—		(41)		(41)


Other				(3)						(3)				(3)
Other comprehensive income								51		51				51
Balance at June 30, 2023	2,229	$	22	$	41,387	$	(10,550)	$	(290)	$	30,569	$	1,340	$	31,909


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at March 31, 2022	2,267	$	23	$	41,813	$	(10,544)	$	(674)	$	30,618	$	1,089	$	31,707



Repurchases of shares	(10)			(172)						(172)				(172)

Restricted shares				13						13				13
Net income						635				635		18		653
Dividends						(631)				(631)				(631)
Distributions										—		(27)		(27)




Other comprehensive income								82		82				82
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)	$	30,545	$	1,080	$	31,625

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)

(In millions, unaudited)


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at December 31, 2022	2,248	$	22	$	41,673	$	(10,551)	$	(402)	$	30,742	$	1,372	$	32,114



Repurchases of shares	(19)			(317)						(317)				(317)

Restricted shares				34						34				34
Net income						1,265				1,265		48		1,313
Dividends						(1,264)				(1,264)				(1,264)
Distributions										—		(80)		(80)


Other				(3)						(3)				(3)
Other comprehensive income								112		112				112
Balance at June 30, 2023	2,229	$	22	$	41,387	$	(10,550)	$	(290)	$	30,569	$	1,340	$	31,909


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at December 31, 2021	2,267	$	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, 2022	2,267	23		41,795		(10,595)		(411)		30,812		1,098		31,910

Repurchases of shares	(10)			(173)						(173)				(173)
EP Trust I Preferred security conversions				1						1				1
Restricted shares				31						31				31
Net income						1,302				1,302		35		1,337
Dividends						(1,247)				(1,247)				(1,247)
Distributions										—		(53)		(53)




Other comprehensive loss								(181)		(181)				(181)
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)	$	30,545	$	1,080	$	31,625

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

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 3.8 Bcf per year of RNG generation capacity. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke and ethanol and other renewable fuels and feedstocks.

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.

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals and (vii) Energy Transition Ventures.

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

The results of our May 31, 2023 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value, with our Terminals reporting unit’s fair value in excess of its carrying value by less than 10% which was impacted by a decline in market multiples.

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	586	$	635	$	1,265	$	1,302
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)	(4)		(2)		(7)		(6)
Net Income Allocated to Class P Stockholders	$	582	$	633	$	1,258	$	1,296

Basic Weighted Average Shares Outstanding	2,237		2,265		2,242		2,266
Basic Earnings Per Share	$	0.26	$	0.28	$	0.56	$	0.57

(a)As of June 30, 2023, there were 13 million restricted stock awards outstanding.

The following table presents the maximum number of potential common stock equivalents which are antidilutive and accordingly are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.


	Three Months Ended June 30,		Six Months Ended June 30,
	2023	2022	2023	2022
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	12	13	13
Convertible trust preferred securities	3	3	3	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 six months ended June 30, 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.

3. Debt

The following table provides information on the principal amount of our outstanding debt balances:


	June 30, 2023		December 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		—
4.30% due May 2024	600		—
Trust I preferred securities, 4.75%, due March 2028(a)	111		111
Current portion of other debt	49		49
Total current portion of debt	2,760		3,385

Long-term debt (excluding current portion)
Senior notes	27,899		27,638
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	320		330

Trust I preferred securities, 4.75%, due March 2028	109		109
Other	208		211
Total long-term debt	28,536		28,288
Total debt(b)	$	31,296	$	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 June 30, 2023 and December 31, 2022, increased our total debt balances by $96 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 June 30, 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 June 30, 2023 was $3.9 billion. For the period ended June 30, 2023, we were in compliance with all required covenants.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below:


	June 30, 2023				December 31, 2022
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	31,392	$	29,845	$	31,788	$	30,070

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $203 million and $195 million as of June 30, 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 June 30, 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 six months ended June 30, 2023, we repurchased 19 million of our shares for $317 million at an average price of $16.59 per share. Subsequent to June 30, 2023 and through July 20, 2023, we repurchased less than 1 million shares for $13 million at an average price of $16.93 per share. All shares we have repurchased are canceled and are no longer outstanding.

Dividends

The following table provides information about our per share dividends:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Per share cash dividend declared for the period	$	0.2825	$	0.2775	$	0.565	$	0.555
Per share cash dividend paid in the period	0.2825		0.2775		0.56		0.5475

On July 19, 2023, our board of directors declared a cash dividend of $0.2825 per share for the quarterly period ended June 30, 2023, which is payable on August 15, 2023 to shareholders of record as of the close of business on July 31, 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 six months ended June 30, 2022.

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 reclassifications	155		8		163
Gain reclassified from accumulated other comprehensive loss	(51)		—		(51)
Net current-period change in accumulated other comprehensive loss	104		8		112
Balance as of June 30, 2023	$	(60)	$	(230)	$	(290)


	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	(489)		16		(473)
Loss reclassified from accumulated other comprehensive loss	292		—		292
Net current-period change in accumulated other comprehensive loss	(197)		16		(181)
Balance as of June 30, 2022	$	(369)	$	(223)	$	(592)

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 June 30, 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	(17.8)	MMBbl
Crude oil basis	(2.1)	MMBbl
Natural gas fixed price	(75.3)	Bcf
Natural gas basis	(61.3)	Bcf
NGL fixed price	(0.6)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.0)	MMBbl
Crude oil basis	(8.0)	MMBbl
Natural gas fixed price	(7.1)	Bcf
Natural gas basis	(91.5)	Bcf
NGL fixed price	(0.7)	MMBbl

As of June 30, 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 June 30, 2023:


	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)	$	7,400	Fair value hedge	March 2035

Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts	3,445		Mark-to-Market	December 2023

(a)The principal amount of hedged senior notes consisted of $2,050 million included in “Current portion of debt” and $5,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the three and six months ended June 30, 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 June 30, 2023:


	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$	543	Cash flow hedge	March 2027

(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.

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
	Location	Derivatives Asset				Derivatives Liability
		June 30, 2023		December 31, 2022		June 30, 2023		December 31, 2022
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	$	101	$	150	$	(78)	$	(156)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	17		6		(38)		(91)
	Subtotal	118		156		(116)		(247)
Interest rate contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	—		—		(152)		(144)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	37		39		(234)		(261)
	Subtotal	37		39		(386)		(405)
Foreign currency contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	—		—		(9)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(9)		(32)
	Subtotal	—		—		(18)		(35)
	Total	155		195		(520)		(687)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	38		80		(12)		(162)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	13		23		(1)		(19)
	Subtotal	51		103		(13)		(181)
Interest rate contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	14		1		—		—

	Subtotal	14		1		—		—
	Total	65		104		(13)		(181)
Total derivatives		$	220	$	299	$	(533)	$	(868)

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 netting		Cash collateral held(a)
	Level 1		Level 2		Level 3		Gross amount				Net amount
	(In millions)
As of June 30, 2023
Energy commodity derivative contracts(b)	$	81	$	88	$	—	$	169	$	(14)	$	—	$	155
Interest rate contracts	—		51		—		51		—		—		51

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 netting		Cash collateral posted(a)
	Level 1		Level 2		Level 3		Gross amount				Net amount
	(In millions)
As of June 30, 2023
Energy commodity derivative contracts(b)	$	(4)	$	(125)	$	—	$	(129)	$	14	$	(101)	$	(216)
Interest rate contracts	—		(386)		—		(386)		—		—		(386)
Foreign currency contracts	—		(18)		—		(18)		—		—		(18)
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 relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item
		Three Months Ended June 30,				Six Months Ended June 30,
		2023		2022		2023		2022
		(In millions)
Interest rate contracts	Interest, net	$	(99)	$	(160)	$	19	$	(476)

Hedged fixed rate debt(a)	Interest, net	$	101	$	162	$	(18)	$	482

(a)As of June 30, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $350 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended June 30,					Three Months Ended June 30,
	2023		2022			2023		2022
	(In millions)					(In millions)
Energy commodity derivative contracts	$	50	$	(70)	Revenues—Commodity sales	$	18	$	(185)

					Costs of sales	(20)		7
Interest rate contracts	—		3		Interest, net	—		—

Foreign currency contracts	13		(35)		Other, net	4		(27)
Total	$	63	$	(102)	Total	$	2	$	(205)


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,					Six Months Ended June 30,
	2023		2022			2023		2022
	(In millions)					(In millions)
Energy commodity derivative contracts	$	185	$	(569)	Revenues—Commodity sales	$	83	$	(317)

					Costs of sales	(27)		17
Interest rate contracts	—		6		Interest, net	—		—

Foreign currency contracts	16		(75)		Other, net	10		(81)
Total	$	201	$	(638)	Total	$	66	$	(381)

(a)We expect to reclassify approximately $34 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 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.

(b)During the three and six months ended June 30, 2022, we recognized approximate gains of $5 million associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).


Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended June 30,				Six Months Ended June 30,
		2023		2022		2023		2022
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	10	$	(17)	$	31	$	(26)
	Costs of sales	51		(8)		120		(99)
	Earnings from equity investments	—		—		1		(5)
Interest rate contracts	Interest, net	7		12		12		48
Total(a)		$	68	$	(13)	$	164	$	(82)

(a)The three and six months ended June 30, 2023 amounts include approximate gains of $7 million and $35 million, respectively, and the three and six months ended June 30, 2022 amounts include approximate losses of $38 million and $20 million, respectively. These gains and losses were 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 June 30, 2023 and December 31, 2022, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2023 and December 31, 2022, we had cash margins of $72 million and $1 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The cash margin balance at June 30, 2023 represents our initial margin requirements of $29 million and variation margin requirements of $101 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 June 30, 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 $52 million of additional collateral.

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 June 30, 2023
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	849	$	49	$	208	$	1	$	—	$	1,107
Fee-based services	248		246		98		10		—		602
Total services	1,097		295		306		11		—		1,709
Commodity sales
Natural gas sales	484		—		—		13		(2)		495
Product sales	233		380		9		277		(3)		896

Total commodity sales	717		380		9		290		(5)		1,391
Total revenues from contracts with customers	1,814		675		315		301		(5)		3,100
Other revenues(c)
Leasing services(d)	120		52		163		11		—		346
Derivatives adjustments on commodity sales	40		2		—		(14)		—		28
Other	17		6		—		4		—		27
Total other revenues	177		60		163		1		—		401
Total revenues	$	1,991	$	735	$	478	$	302	$	(5)	$	3,501


	Three Months Ended June 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	849	$	60	$	198	$	1	$	(1)	$	1,107
Fee-based services	234		242		96		11		—		583
Total services	1,083		302		294		12		(1)		1,690
Commodity sales
Natural gas sales	1,810		—		—		24		(6)		1,828
Product sales	410		640		7		404		13		1,474

Total commodity sales	2,220		640		7		428		7		3,302
Total revenues from contracts with customers	3,303		942		301		440		6		4,992
Other revenues(c)
Leasing services(d)	118		49		149		15		—		331
Derivatives adjustments on commodity sales	(81)		—		—		(121)		—		(202)
Other	16		5		—		9		—		30
Total other revenues	53		54		149		(97)		—		159
Total revenues	$	3,356	$	996	$	450	$	343	$	6	$	5,151


	Six Months Ended June 30, 2023
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	1,766	$	89	$	415	$	1	$	(1)	$	2,270
Fee-based services	484		486		196		20		—		1,186
Total services	2,250		575		611		21		(1)		3,456
Commodity sales
Natural gas sales	1,283		—		—		33		(4)		1,312
Product sales	507		716		13		545		(4)		1,777

Total commodity sales	1,790		716		13		578		(8)		3,089
Total revenues from contracts with customers	4,040		1,291		624		599		(9)		6,545
Other revenues(c)
Leasing services(d)	237		99		315		25		—		676
Derivatives adjustments on commodity sales	147		1		—		(34)		—		114
Other	33		12		—		9		—		54
Total other revenues	417		112		315		—		—		844
Total revenues	$	4,457	$	1,403	$	939	$	599	$	(9)	$	7,389


	Six Months Ended June 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	1,788	$	119	$	386	$	1	$	(2)	$	2,292
Fee-based services	447		476		194		24		—		1,141
Total services	2,235		595		580		25		(2)		3,433
Commodity sales
Natural gas sales	3,036		—		—		44		(10)		3,070
Product sales	752		1,066		11		752		(3)		2,578

Total commodity sales	3,788		1,066		11		796		(13)		5,648
Total revenues from contracts with customers	6,023		1,661		591		821		(15)		9,081
Other revenues(c)
Leasing services(d)	235		93		289		28		—		645
Derivatives adjustments on commodity sales	(120)		(3)		—		(220)		—		(343)
Other	31		11		—		19		—		61
Total other revenues	146		101		289		(173)		—		363
Total revenues	$	6,169	$	1,762	$	880	$	648	$	(15)	$	9,444

(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 June 30, 2023 and December 31, 2022, our contract asset balances were $34 million and $33 million, respectively. Of the contract asset balance at December 31, 2022, $20 million was transferred to accounts receivable during the six months ended June 30, 2023. As of June 30, 2023 and December 31, 2022, our contract liability balances were $231 million and $204 million, respectively. Of the contract liability balance at December 31, 2022, $50 million was recognized as revenue during the six months ended June 30, 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 June 30, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Estimated Revenue
	(In millions)
Six months ended December 31, 2023	$	2,248
2024	3,888
2025	3,187
2026	2,763
2027	2,353
Thereafter	13,588
Total	$	28,027

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.

7. Reportable Segments

Financial information by segment follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,987	$	3,363	$	4,450	$	6,156
Intersegment revenues	4		(7)		7		13

Products Pipelines	735		996		1,403		1,762

Terminals
Revenues from external customers	477		449		937		878
Intersegment revenues	1		1		2		2
CO2	302		343		599		648

Corporate and intersegment eliminations	(5)		6		(9)		(15)
Total consolidated revenues	$	3,501	$	5,151	$	7,389	$	9,444


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,255	$	1,134	$	2,750	$	2,318
Products Pipelines	285		299		469		598
Terminals	261		253		515		491
CO2	175		212		347		404


Total Segment EBDA	1,976		1,898		4,081		3,811
DD&A	(557)		(543)		(1,122)		(1,081)
Amortization of excess cost of equity investments	(19)		(19)		(36)		(38)

General and administrative and corporate charges	(179)		(144)		(358)		(289)
Interest, net	(443)		(355)		(888)		(688)

Income tax expense	(168)		(184)		(364)		(378)

Total consolidated net income	$	610	$	653	$	1,313	$	1,337


	June 30, 2023		December 31, 2022
	(In millions)
Assets
Natural Gas Pipelines	$	47,406	$	47,978
Products Pipelines	8,832		8,985
Terminals	8,292		8,357
CO2	3,505		3,449



Corporate assets(b)	1,038		1,309

Total consolidated assets	$	69,073	$	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.

8. Income Taxes

Income tax expense included on our accompanying consolidated statements of income is as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(In millions, except percentages)
Income tax expense	$	168		$	184		$	364		$	378
Effective tax rate	21.6		%	22.0		%	21.7		%	22.0		%

The effective tax rates for the three and six months ended June 30, 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 sought unspecified damages and involved 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 granted 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. The Appellate Division denied GLNG’s appeal on February 9, 2023 and denied our motion for rehearing on July 6, 2023. GLNG may pursue further recourse to the state Court of Appeals, which is the state’s highest appellate court. With respect to the counterclaims and other claims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment on June 13, 2023 and directed the clerk to enter judgment dismissing all of Eni S.p.A.’s claims. Upon entry of judgment, Eni S.p.A. may choose to take an appeal to the state Appellate Division. We intend to vigorously pursue a favorable and expeditious resolution of all claims on appeal.

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 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 appeal to the 14th Court of Appeals, where the matter remains pending. We believe that our declaration of force majeure was valid and we intend to continue 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 investigated the incident and issued its report on April 27, 2023. 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 June 30, 2023 and December 31, 2022, our total reserve for legal matters was $39 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, CO2 field and oil field, and our other operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.

We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but 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.

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 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 and others 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) and others 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. On May 3, 2023, the U.S. District Court re-opened 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 and on November 24, 2020, identified a crack in the pipeline and notified the regulatory agencies of a “confirmed release.” The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on November 26, 2020. We reported the estimated volume of gasoline released to be 8.1 Bbl. On December 2, 2020, complaints of gasoline odors were reported along the LS-16 pipeline corridor in Walnut Creek. A unified response was implemented by us along with the EPA, the California Office of Spill Prevention and Response, the California Fire Marshall, and the San Francisco Regional Water Quality Control Board. On December 8, 2020, we reported an updated estimated spill volume of up to 1,000 Bbl.

On October 28, 2021, we were informed by the California Attorney General it was contemplating criminal charges against us asserting the November 2020 discharge of gasoline affected waters of the State of California, and there was a failure to make timely notices of this discharge to appropriate state agencies. On December 16, 2021, we entered into a plea agreement with the State of California to resolve misdemeanor charges of the unintentional, non-negligent discharge of gasoline resulting from the release and the claimed failure to provide timely notices of the discharge to appropriate state agencies. Under the plea agreement, SFPP plead no-contest to two misdemeanors and paid approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and was placed on informal, unsupervised probation for a term of 18 months. On May 8, 2023, the California Attorney General confirmed SFPP had complied with the terms of the plea agreement.

Since the November 2020 release, we have cooperated fully with federal and state agencies and worked diligently to remediate the affected areas. There may be civil enforcement actions by federal and state agencies arising from the November 2020 release. Further, we anticipate 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, if any, or 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 June 30, 2023 and December 31, 2022, we have accrued a total reserve for environmental liabilities in the amount of $212 million and $221 million, respectively. In addition, as of June 30, 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.

Challenge to Federal “Good Neighbor Plan”

On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the EPA’s final action promulgating the EPA’s final rule known as the “Good Neighbor Plan” (the Plan). The Plan was published in the Federal Register as a final rule on June 5, 2023. The Plan is a federal implementation plan to address certain interstate transport requirements of the Clean Air Act for the 2015 8-hour Ozone National Ambient Air Quality Standards. We believe that the Plan is deeply flawed and that numerous meritorious bases for challenging the Plan exist. If the Plan were fully implemented, its emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. If the Plan were to remain in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to state implementation plan disapprovals and no successful challenge to the Plan), we anticipate that it would have a material impact on us. Impacts are difficult to predict, particularly given the extensive pending litigation. We would seek to mitigate the impacts, and to recover expenditures through adjustments to our rates on our regulated assets where available.

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 six months ended June 30, 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. 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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