Item 1. Financial Statements.

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Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts, unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenues
Services	$	1,928	$	1,881	$	5,734	$	5,664
Commodity sales	1,868		982		6,343		2,772
Other	28		56		108		149
Total Revenues	3,824		2,919		12,185		8,585

Operating Costs, Expenses and Other
Costs of sales	1,559		655		4,504		1,759
Operations and maintenance	614		643		1,710		1,869
Depreciation, depletion and amortization	526		539		1,595		1,636
General and administrative	174		153		490		461
Taxes, other than income taxes	106		100		324		295

Loss on impairments and divestitures, net (Note 3)	4		11		1,602		1,987
Other income, net	(3)		(1)		(6)		(2)
Total Operating Costs, Expenses and Other	2,980		2,100		10,219		8,005

Operating Income	844		819		1,966		580

Other Income (Expense)
Earnings from equity investments	169		194		392		562

Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)
Interest, net	(368)		(383)		(1,122)		(1,214)
Other, net (Note 3)	21		14		264		32
Total Other Expense	(199)		(207)		(522)		(719)

Income (Loss) Before Income Taxes	645		612		1,444		(139)

Income Tax Expense	(134)		(140)		(248)		(304)

Net Income (Loss)	511		472		1,196		(443)






Net Income Attributable to Noncontrolling Interests	(16)		(17)		(49)		(45)

Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	495	$	455	$	1,147	$	(488)





Class P Shares
Basic and Diluted Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)

Basic and Diluted Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In millions, unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net income (loss)	$	511	$	472	$	1,196	$	(443)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively)	(131)		(56)		(444)		(16)
Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively)	92		(5)		181		72
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)	—		—		—		1
Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively)	6		5		28		21
Total other comprehensive (loss) income	(33)		(56)		(235)		78

Comprehensive income (loss)	478		416		961		(365)
Comprehensive income attributable to noncontrolling interests	(16)		(17)		(49)		(45)
Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$	462	$	399	$	912	$	(410)

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except per share amounts, unaudited)


	September 30, 2021		December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents	$	102	$	1,184
Restricted deposits	177		25
Accounts receivable	1,433		1,293
Fair value of derivative contracts	199		185
Inventories	457		348


Other current assets	318		168
Total current assets	2,686		3,203

Property, plant and equipment, net	35,576		35,836
Investments	7,620		7,917
Goodwill	20,033		19,851
Other intangibles, net	1,744		2,453
Deferred income taxes	303		536

Deferred charges and other assets	1,678		2,177
Total Assets	$	69,640	$	71,973

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,822	$	2,558
Accounts payable	1,189		837

Accrued interest	332		525
Accrued taxes	284		267
Accrued contingencies	246		307

Other current liabilities	952		580
Total current liabilities	5,825		5,074

Long-term liabilities and deferred credits
Long-term debt
Outstanding	28,988		30,838

Debt fair value adjustments	1,014		1,293
Total long-term debt	30,002		32,131


Other long-term liabilities and deferred credits	2,160		2,202

Total long-term liabilities and deferred credits	32,162		34,333
Total Liabilities	37,987		39,407

Commitments and contingencies (Notes 4 and 10)
Redeemable Noncontrolling Interest	661		728
Stockholders’ Equity

Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding	23		23
Additional paid-in capital	41,788		41,756
Accumulated deficit	(10,617)		(9,936)
Accumulated other comprehensive loss	(642)		(407)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,552		31,436
Noncontrolling interests	440		402
Total Stockholders’ Equity	30,992		31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	69,640	$	71,973

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


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

	Nine Months Ended September 30,
	2021		2020
Cash Flows From Operating Activities
Net income (loss)	$	1,196	$	(443)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	1,595		1,636
Deferred income taxes	236		164
Amortization of excess cost of equity investments	56		99


Loss on impairments and divestitures, net (Note 3)	1,602		1,987
Gain on sale of interest in equity investment (Note 3)	(206)		—
Earnings from equity investments	(392)		(562)
Distributions from equity investment earnings	535		487
Changes in components of working capital
Accounts receivable	(119)		238
Inventories	(89)		41
Other current assets	(90)		14
Accounts payable	362		(107)
Accrued interest, net of interest rate swaps	(177)		(208)
Accrued taxes	15		(25)
Other current liabilities	71		(93)
Rate reparations, refunds and other litigation reserve adjustments	(97)		48
Other, net	(58)		6
Net Cash Provided by Operating Activities	4,440		3,282
Cash Flows From Investing Activities

Acquisitions of assets and investments, net of cash acquired	(1,518)		(16)
Capital expenditures	(894)		(1,351)
Proceeds from sales of investments	417		907
Contributions to investments	(36)		(365)
Distributions from equity investments in excess of cumulative earnings	121		105

Other, net	(1)		(56)
Net Cash Used in Investing Activities	(1,911)		(776)
Cash Flows From Financing Activities
Issuances of debt	4,950		3,888
Payments of debt	(6,459)		(3,991)
Debt issue costs	(20)		(23)
Dividends	(1,828)		(1,764)

Repurchases of shares	—		(50)

Contributions from investment partner and noncontrolling interests	4		11
Distributions to investment partner	(67)		(60)

Distributions to noncontrolling interests	(14)		(11)
Other, net	(25)		(13)
Net Cash Used in Financing Activities	(3,459)		(2,013)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	—		(3)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(930)		490
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	279	$	699


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

	Nine Months Ended September 30,
	2021		2020
Cash and Cash Equivalents, beginning of period	$	1,184	$	185
Restricted Deposits, beginning of period	25		24
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209
Cash and Cash Equivalents, end of period	102		632
Restricted Deposits, end of period	177		67
Cash, Cash Equivalents, and Restricted Deposits, end of period	279		699
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(930)	$	490

Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	$	35	$	15
Increase in property, plant and equipment from both accruals and contractor retainage	4
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,313		1,440
Cash paid during the period for income taxes, net	8		202

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
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)	$	30,711	$	429	$	31,140




Restricted shares	2			(5)						(5)				(5)
Net income						495				495		16		511
Distributions										—		(6)		(6)
Contributions										—		1		1
Dividends						(616)				(616)				(616)

Other comprehensive loss								(33)		(33)				(33)
Balance at September 30, 2021	2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992


	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at June 30, 2020	2,261	$	23	$	41,731	$	(9,802)	$	(199)	$	31,753	$	371	$	32,124





Restricted shares	3			5						5				5
Net income						455				455		17		472


Distributions										—		(4)		(4)
Contributions										—		2		2
Dividends						(598)				(598)				(598)



Other comprehensive loss								(56)		(56)				(56)
Balance at September 30, 2020	2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945

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
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at December 31, 2020	2,264	$	23	$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838




Restricted shares	3			32						32				32
Net income						1,147				1,147		49		1,196
Distributions										—		(14)		(14)
Contributions										—		4		4
Dividends						(1,828)				(1,828)				(1,828)
Other										—		(1)		(1)
Other comprehensive loss								(235)		(235)				(235)
Balance at September 30, 2021	2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992


	Common stock
	Issued shares	Par value		Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests		Total
Balance at December 31, 2019	2,265	$	23	$	41,745	$	(7,693)	$	(333)	$	33,742	$	344	$	34,086




Repurchases of shares	(4)			(50)						(50)				(50)
Restricted shares	3			41						41				41
Net (loss) income						(488)				(488)		45		(443)


Distributions										—		(11)		(11)
Contributions										—		8		8
Dividends						(1,764)				(1,764)				(1,764)



Other comprehensive income								78		78				78
Balance at September 30, 2020	2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945

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 83,000 miles of pipelines, 144 terminals, and 700 billion cubic feet of working natural gas storage capacity. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.

Basis of Presentation

General

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

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2020 Form 10-K.

The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For our May 31, 2021 evaluation, we grouped our businesses into six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; and (vi) Terminals. See Note 3 for results of our May 31, 2021 goodwill impairment test.

Earnings per Share

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

The following table sets forth the allocation of net income (loss) available to shareholders of Class P shares and participating securities:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders	$	495	$	455	$	1,147	$	(488)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(4)		(3)		(10)		(9)
Net Income (Loss) Allocated to Class P Stockholders	$	491	$	452	$	1,137	$	(497)

Basic Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263
Basic Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)

(a)As of September 30, 2021, there were approximately 13 million restricted stock awards outstanding.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	3	3	3	3

2. Acquisitions

As of September 30, 2021, our preliminary allocation of the purchase price for significant acquisitions completed during the nine months ended September 30, 2021 are detailed below.


					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Deferred charges & other		Goodwill		Current liabilities		Long-term liabilities
			(In millions)
(1)	8/21	Kinetrex Energy	$	318	$	17	$	49	$	262	$	64	$	(6)	$	(68)
(2)	7/21	Stagecoach Gas Services LLC	1,228		52		1,041		23		118		(6)		—

Pro Forma Information

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

(1) Kinetrex Energy Acquisition

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

(2) Stagecoach Acquisition

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

Goodwill

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

Changes in the amounts of our goodwill for the nine months ended September 30, 2021 are summarized by reporting unit as follows:


	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		Products Pipelines		Products Pipelines Terminals		Terminals		Energy Transition Ventures		Total
	(In millions)


Goodwill as of December 31, 2020	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	—	$	19,851
Acquisitions	118		—		—		—		—		—		64		182


Goodwill as of September 30, 2021	$	14,367	$	2,343	$	928	$	1,378	$	151	$	802	$	64	$	20,033

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

We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)	$	—	$	—	$	1,600	$	—
Impairment of goodwill(a)	—		—		—		1,000
Gain on sale of interest in NGPL Holdings LLC(a)	—		—		(206)		—
Loss on write-down of related party note receivable(a)	—		—		117		—
Loss (gain) on divestitures of long-lived assets and other write-downs	—		11		(1)		11
Products Pipelines
Impairment of long-lived and intangible assets	—		—		—		21

Terminals
Impairment of long-lived and intangible assets	14		—		14		5

CO2
Impairment of goodwill(a)	—		—		—		600
Impairment of long-lived assets(a)	—		—		—		350
Gain on divestitures of long-lived assets, net	(11)		—		(8)		—
Other loss (gain) on divestitures of long-lived assets, net	1		—		(3)		—
Pre-tax loss on impairments, divestitures and other write-downs, net	$	4	$	11	$	1,513	$	1,987

(a)See below for a further discussion of these items.

Impairments

Long-lived Assets

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

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

Goodwill

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

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

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

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

Sale of an Interest in NGPL Holdings

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

Other Write-downs

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

4. Debt

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


	September 30, 2021		December 31, 2020
	(In millions, unless otherwise stated)
Current portion of debt

$3.5 billion credit facility due August 20, 2026(a)	$	—	$	—
$500 million credit facility due November 16, 2023(a)	—		—
Commercial paper notes	160		—
Current portion of senior notes
5.00%, due February 2021(b)	—		750
3.50%, due March 2021(b)	—		750
5.80%, due March 2021(b)	—		400
5.00%, due October 2021(c)	—		500
8.625%, due January 2022	260		—
4.15%, due March 2022	375		—
1.50%, due March 2022(d)	869		—
3.95% due September 2022	1,000		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	47		47
Total current portion of debt	2,822		2,558

Long-term debt (excluding current portion)
Senior notes	28,306		30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035	353		364

Trust I preferred securities, 4.75%, due March 2028	110		110
Other	219		223
Total long-term debt	28,988		30,838
Total debt(e)	$	31,810	$	33,396

(a)On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.

(b)We repaid the principal amounts on these senior notes during the first quarter of 2021.

(c)These notes were repaid on July 1, 2021.

(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The September 30, 2021 balance is reported above at the exchange rate of 1.1580 U.S. dollars per Euro. As of September 30, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $54 million related to these notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance sheets. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 6 “Risk Management—Foreign Currency Risk Management”).

(e)Excludes our “Debt fair value adjustments” which, as of September 30, 2021 and December 31, 2020, increased our total debt balances by $1,014 million and $1,293 million, respectively.

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

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

Credit Facilities and Restrictive Covenants

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

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

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

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

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

Fair Value of Financial Instruments

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


	September 30, 2021				December 31, 2020
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
	(In millions)
Total debt	$	32,824	$	37,797	$	34,689	$	39,622

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

5. Stockholders’ Equity

Class P Stock

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

Dividends

The following table provides information about our per share dividends:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.81	$	0.7875
Per share cash dividend paid in the period	0.27		0.2625		0.8025		0.775

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

Accumulated Other Comprehensive Loss

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:


	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2020	$	(13)	$	—	$	(394)	$	(407)
Other comprehensive (loss) gain before reclassifications	(444)		—		28		(416)
Loss reclassified from accumulated other comprehensive loss	181		—		—		181
Net current-period change in accumulated other comprehensive loss	(263)		—		28		(235)
Balance as of September 30, 2021	$	(276)	$	—	$	(366)	$	(642)


	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2019	$	(7)	$	—	$	(326)	$	(333)
Other comprehensive (loss) gain before reclassifications	(16)		1		21		6
Loss reclassified from accumulated other comprehensive loss	72		—		—		72
Net current-period change in accumulated other comprehensive (loss) income	56		1		21		78
Balance as of September 30, 2020	$	49	$	1	$	(305)	$	(255)

6. Risk Management

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

Energy Commodity Price Risk Management

As of September 30, 2021, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:


	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price	(15.9)	MMBbl
Crude oil basis	(6.4)	MMBbl
Natural gas fixed price	(29.5)	Bcf
Natural gas basis	(27.1)	Bcf
NGL fixed price	(1.0)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.4)	MMBbl
Crude oil basis	(8.7)	MMBbl
Natural gas fixed price	(8.7)	Bcf
Natural gas basis	(22.8)	Bcf
NGL fixed price	(1.9)	MMBbl

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

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2021:


	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	7,100	Fair value hedge	March 2035
Variable-to-fixed interest rate contracts	250		Cash flow hedge	January 2023
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts	6,250		Mark-to-Market	December 2022

(a)The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

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

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, 2021:


	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$	1,358	Cash flow hedge	March 2027

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

The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:


Fair Value of Derivative Contracts
		Derivatives Asset				Derivatives Liability
		September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	13	$	42	$	(256)	$	(33)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		33		(96)		(8)
Subtotal		14		75		(352)		(41)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	127		119		(4)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	350		575		(14)		(7)
Subtotal		477		694		(18)		(10)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	49		—		(6)		(6)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		138		—		—
Subtotal		69		138		(6)		(6)
Total		560		907		(376)		(57)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	10		24		(63)		(21)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		—		(3)		—
Subtotal		14		24		(66)		(21)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		—		—
Subtotal		1		—		(1)		—



Total		15		24		(67)		(21)
Total derivatives		$	575	$	931	$	(443)	$	(78)

The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.


	Balance sheet asset fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
	(In millions)
As of September 30, 2021
Energy commodity derivative contracts(a)	$	15	$	13	$	—	$	28	$	(26)	$	—	$	2
Interest rate contracts	—		478		—		478		(9)		—		469
Foreign currency contracts	—		69		—		69		(6)		—		63
As of December 31, 2020
Energy commodity derivative contracts(a)	$	6	$	93	$	—	$	99	$	(35)	$	—	$	64
Interest rate contracts	—		694		—		694		(2)		—		692
Foreign currency contracts	—		138		—		138		(6)		—		132


	Balance sheet liability fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral posted(b)		Net amount
	(In millions)
As of September 30, 2021
Energy commodity derivative contracts(a)	$	(111)	$	(307)	$	—	$	(418)	$	26	$	135	$	(257)
Interest rate contracts	—		(19)		—		(19)		9		—		(10)
Foreign currency contracts	—		(6)		—		(6)		6		—		—
As of December 31, 2020
Energy commodity derivative contracts(a)	$	(7)	$	(56)	$	—	$	(63)	$	35	$	(8)	$	(36)
Interest rate contracts	—		(10)		—		(10)		2		—		(8)
Foreign currency contracts	—		(6)		—		(6)		6		—		—

(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.

(b)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of operations and comprehensive income (loss):


Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item
		Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	(39)	$	(50)	$	(228)	$	409

Hedged fixed rate debt(a)	Interest, net	$	39	$	50	$	229	$	(418)

(a)As of September 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $473 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


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 September 30,					Three Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(140)	$	(143)	Revenues—Commodity sales	$	(94)	$	(47)

					Costs of sales	8		(7)
Interest rate contracts	1		—		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(33)		70		Other, net	(34)		61
Total	$	(172)	$	(73)	Total	$	(120)	$	6


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2021		2020			2021		2020
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(514)	$	(29)	Revenues—Commodity sales	$	(167)	$	(145)

					Costs of sales	10		(12)
Interest rate contracts	3		(9)		Earnings from equity investments(c)	—		(1)
Foreign currency contracts	(68)		17		Other, net	(79)		64
Total	$	(579)	$	(21)	Total	$	(236)	$	(94)

(a)We expect to reclassify approximately $181 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2021 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

(b)During the nine months ended September 30, 2021, we recognized gains of $6 million associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).

(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).


Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(40)	$	87	$	(703)	$	353
	Costs of sales	(7)		12		154		18
	Earnings from equity investments	(2)		—		(4)		—
Total(a)		$	(49)	$	99	$	(553)	$	371

(a)The three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480 million, respectively, and the three and nine months ended September 30, 2020 amounts include approximate gains of $96 million and $349 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

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

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

7. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:


	Three Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	836	$	66	$	181	$	1	$	(2)	$	1,082
Fee-based services	190		244		93		10		—		537
Total services	1,026		310		274		11		(2)		1,619
Commodity sales
Natural gas sales	1,097		—		—		7		(3)		1,101
Product sales	372		247		8		279		(11)		895

Total commodity sales	1,469		247		8		286		(14)		1,996
Total revenues from contracts with customers	2,495		557		282		297		(16)		3,615
Other revenues(c)
Leasing services(d)	119		42		140		15		—		316
Derivatives adjustments on commodity sales	(71)		—		—		(63)		—		(134)
Other	12		6		—		8		1		27
Total other revenues	60		48		140		(40)		1		209
Total revenues	$	2,555	$	605	$	422	$	257	$	(15)	$	3,824


	Three Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	818	$	69	$	185	$	1	$	(2)	$	1,071
Fee-based services	173		228		91		8		3		503
Total services	991		297		276		9		1		1,574
Commodity sales
Natural gas sales	507		—		—		1		(2)		506
Product sales	158		97		5		180		(5)		435

Total commodity sales	665		97		5		181		(7)		941
Total revenues from contracts with customers	1,656		394		281		190		(6)		2,515
Other revenues(c)
Leasing services(d)	119		42		143		13		—		317
Derivatives adjustments on commodity sales	(6)		—		—		46		—		40
Other	40		6		—		2		(1)		47
Total other revenues	153		48		143		61		(1)		404
Total revenues	$	1,809	$	442	$	424	$	251	$	(7)	$	2,919


	Nine Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,501	$	191	$	570	$	1	$	(2)	$	3,261
Fee-based services	544		709		258		35		—		1,546
Total services	3,045		900		828		36		(2)		4,807
Commodity sales
Natural gas sales	5,090		—		—		9		(11)		5,088
Product sales	840		529		20		766		(34)		2,121

Total commodity sales	5,930		529		20		775		(45)		7,209
Total revenues from contracts with customers	8,975		1,429		848		811		(47)		12,016
Other revenues(c)
Leasing services(d)	356		128		427		42		—		953
Derivatives adjustments on commodity sales	(726)		(1)		—		(143)		—		(870)
Other	51		16		—		19		—		86
Total other revenues	(319)		143		427		(82)		—		169
Total revenues	$	8,656	$	1,572	$	1,275	$	729	$	(47)	$	12,185


	Nine Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,479	$	215	$	563	$	1	$	(2)	$	3,256
Fee-based services	523		670		307		31		1		1,532
Total services	3,002		885		870		32		(1)		4,788
Commodity sales
Natural gas sales	1,385		—		—		1		(5)		1,381
Product sales	396		255		11		546		(22)		1,186

Total commodity sales	1,781		255		11		547		(27)		2,567
Total revenues from contracts with customers	4,783		1,140		881		579		(28)		7,355
Other revenues(c)
Leasing services(d)	346		126		404		34		—		910
Derivatives adjustments on commodity sales	35		—		—		173		—		208
Other	91		16		—		6		(1)		112
Total other revenues	472		142		404		213		(1)		1,230
Total revenues	$	5,255	$	1,282	$	1,285	$	792	$	(29)	$	8,585

(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (see note (c)).

(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.

(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 6 for additional information related to our derivative contracts.

(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

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

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2021	$	1,178
2022	4,022
2023	3,186
2024	2,711
2025	2,277
Thereafter	14,018
Total	$	27,392

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

8. Reportable Segments

Financial information by segment follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,541	$	1,803	$	8,611	$	5,229
Intersegment revenues	14		6		45		26

Products Pipelines	605		442		1,572		1,282

Terminals
Revenues from external customers	421		423		1,273		1,282
Intersegment revenues	1		1		2		3
CO2	257		251		729		792

Corporate and intersegment eliminations	(15)		(7)		(47)		(29)
Total consolidated revenues	$	3,824	$	2,919	$	12,185	$	8,585


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,069	$	1,091	$	2,602	$	2,284
Products Pipelines	279		223		792		719
Terminals	216		246		689		732
CO2	163		156		599		(453)


Total Segment EBDA	1,727		1,716		4,682		3,282
DD&A	(526)		(539)		(1,595)		(1,636)
Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)

General and administrative and corporate charges	(167)		(150)		(465)		(472)
Interest, net	(368)		(383)		(1,122)		(1,214)

Income tax expense	(134)		(140)		(248)		(304)

Total consolidated net income (loss)	$	511	$	472	$	1,196	$	(443)


	September 30, 2021		December 31, 2020
	(In millions)
Assets
Natural Gas Pipelines	$	47,576	$	48,597
Products Pipelines	9,118		9,182
Terminals	8,507		8,639
CO2	2,808		2,478



Corporate assets(b)	1,631		3,077

Total consolidated assets	$	69,640	$	71,973

(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

9. Income Taxes

Income tax expense included in our accompanying consolidated statements of operations is as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(In millions, except percentages)
Income tax expense	$	134		$	140		$	248		$	304
Effective tax rate	20.8		%	22.9		%	17.2		%	(218.7)		%

The effective tax rate for the three months ended September 30, 2021 is slightly lower than the statutory federal rate of 21% primarily due to dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

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

The effective tax rate for the nine months ended September 30, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus, NGPL Holdings and PPL, partially offset by state income taxes.

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

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

10. Litigation and Environmental

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

SFPP FERC Proceedings

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

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

Gulf LNG Facility Disputes

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

impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

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

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

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

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

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

Freeport LNG Winter Storm Litigation

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

Pipeline Integrity and Releases

From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with

these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

General

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

Environmental Matters

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

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

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

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated by the EPA to be more than $3 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around October 2023. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

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

Uranium Mines in Vicinity of Cameron, Arizona

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

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

EPEC Polymers, Inc. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River in New Jersey. EPEC entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. EPEC is part of a joint defense group of approximately 44 cooperating parties which is directing and funding the AOC work required by the EPA. We have established a reserve for the anticipated cost of compliance with these two AOCs. On March 4, 2016, the EPA issued a Record of Decision (ROD) for the lower eight miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020 and certain PRPs, including EPEC, are engaged in discussions with the EPA as a result thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the upper nine mile ROD. Until the ongoing discussions with the EPA conclude, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the Site, will have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

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

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. The defendants appealed that decision. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing. On August 5, 2021, the Fifth Circuit remanded the case to the U.S. District Court to

determine whether there is federal officer jurisdiction. The case remains effectively stayed pending a ruling by the U.S. District Court on the federal officer issue. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

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

Louisiana Landowner Coastal Erosion Litigation

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

General

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

11. Recent Accounting Pronouncements

Reference Rate Reform (Topic 848)

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

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

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

ASU No. 2020-06

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

ASU No. 2021-05

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

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