You should keep these risk factors in mind when considering forward-looking statements. These risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts, unaudited)
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Revenues
Services
$
2,215
$
2,087
$
6,625
$
6,201
Commodity sales
1,441
1,785
4,307
4,991
Other
43
35
181
104
Total Revenues
3,699
3,907
11,113
11,296
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)
1,024
1,405
3,098
3,591
Operations and maintenance
790
738
2,211
2,062
Depreciation, depletion and amortization
587
561
1,758
1,683
General and administrative
176
162
530
497
Taxes, other than income taxes
107
106
327
319
Loss (gain) on divestitures, net
1
(3)
(76)
(16)
Other income, net
(1)
—
(11)
(2)
Total Operating Costs, Expenses and Other
2,684
2,969
7,837
8,134
Operating Income
1,015
938
3,276
3,162
Other Income (Expense)
Earnings from equity investments
211
234
662
607
Amortization of excess cost of equity investments
(12)
(18)
(37)
(54)
Interest, net
(466)
(457)
(1,402)
(1,345)
Other, net
16
3
17
7
Total Other Expense
(251)
(238)
(760)
(785)
Income Before Income Taxes
764
700
2,516
2,377
Income Tax Expense
(113)
(145)
(490)
(509)
Net Income
651
555
2,026
1,868
Net Income Attributable to Noncontrolling Interests
(26)
(23)
(80)
(71)
Net Income Attributable to Kinder Morgan, Inc.
$
625
$
532
$
1,946
$
1,797
Class P Common Stock
Basic and Diluted Earnings Per Share
$
0.28
$
0.24
$
0.87
$
0.80
Basic and Diluted Weighted Average Shares Outstanding
2,221
2,230
2,220
2,238
The accompanying notes are an integral part of these consolidated financial statements.
4
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions, unaudited)
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Net income
$
651
$
555
$
2,026
$
1,868
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(30), $45, $(6) and $(1), respectively)
99
(153)
18
2
Reclassification into earnings of net derivative instruments (gain) loss to net income (net of taxes of $4, $(6), $(3) and $9, respectively)
(13)
22
9
(29)
Benefit plan adjustments (net of taxes of $—, $(2), $(4) and $(4), respectively)
1
3
15
11
Total other comprehensive income (loss)
87
(128)
42
(16)
Comprehensive income
738
427
2,068
1,852
Comprehensive income attributable to noncontrolling interests
(26)
(23)
(80)
(71)
Comprehensive income attributable to KMI
$
712
$
404
$
1,988
$
1,781
The accompanying notes are an integral part of these consolidated financial statements.
5
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts, unaudited)
September 30, 2024
December 31, 2023
ASSETS
Current Assets
Cash and cash equivalents
$
108
$
83
Restricted deposits
25
13
Accounts receivable
1,265
1,588
Fair value of derivative contracts
75
126
Inventories
526
525
Other current assets
178
207
Total current assets
2,177
2,542
Property, plant and equipment, net
37,709
37,297
Investments
7,882
7,874
Goodwill
20,084
20,121
Other intangibles, net
1,809
1,957
Deferred charges and other assets
1,218
1,229
Total Assets
$
70,879
$
71,020
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt
$
1,984
$
4,049
Accounts payable
1,256
1,366
Accrued interest
361
513
Accrued taxes
286
272
Fair value of derivative contracts
117
205
Other current liabilities
727
816
Total current liabilities
4,731
7,221
Long-term liabilities and deferred credits
Long-term debt
Outstanding
29,825
27,880
Debt fair value adjustments
222
187
Total long-term debt
30,047
28,067
Deferred income taxes
1,853
1,388
Other long-term liabilities and deferred credits
2,502
2,615
Total long-term liabilities and deferred credits
34,402
32,070
Total Liabilities
39,133
39,291
Commitments and contingencies (Notes 4 and 10)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,221,626,124and 2,219,729,644 shares, respectively, issued and outstanding
22
22
Additional paid-in capital
41,217
41,190
Accumulated deficit
(10,658)
(10,689)
Accumulated other comprehensive loss
(175)
(217)
Total Kinder Morgan, Inc.’s stockholders’ equity
30,406
30,306
Noncontrolling interests
1,340
1,423
Total Stockholders’ Equity
31,746
31,729
Total Liabilities and Stockholders’ Equity
$
70,879
$
71,020
The accompanying notes are an integral part of these consolidated financial statements.
6
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
2024
2023
Cash Flows From Operating Activities
Net income
$
2,026
$
1,868
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization
1,758
1,683
Deferred income taxes
454
495
Amortization of excess cost of equity investments
37
54
Change in fair value of derivative contracts
32
(93)
Gain on divestitures, net
(76)
(16)
Earnings from equity investments
(662)
(607)
Distributions of equity investment earnings
600
572
Changes in components of working capital
Accounts receivable
300
351
Inventories
2
130
Other current assets
(2)
89
Accounts payable
(107)
(115)
Accrued interest, net of interest rate swaps
(138)
(131)
Accrued taxes
15
21
Other current liabilities
(68)
(105)
Other, net
(46)
(27)
Net Cash Provided by Operating Activities
4,125
4,169
Cash Flows From Investing Activities
Acquisition of assets (Note 2)
(58)
(13)
Capital expenditures
(1,857)
(1,689)
Contributions to investments
(93)
(179)
Distributions from equity investments in excess of cumulative earnings
117
166
Other, net
33
(18)
Net Cash Used in Investing Activities
(1,858)
(1,733)
Cash Flows From Financing Activities
Issuances of debt
8,803
4,373
Payments of debt
(8,937)
(5,051)
Debt issue costs
(31)
(18)
Dividends
(1,915)
(1,898)
Repurchases of shares
(7)
(390)
Contributions from noncontrolling interests
—
1
Distributions to noncontrolling interests
(123)
(121)
Other, net
(20)
(29)
Net Cash Used in Financing Activities
(2,230)
(3,133)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits
37
(697)
Cash, Cash Equivalents and Restricted Deposits, beginning of period
96
794
Cash, Cash Equivalents and Restricted Deposits, end of period
$
133
$
97
7
KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
2024
2023
Cash and Cash Equivalents, beginning of period
$
83
$
745
Restricted Deposits, beginning of period
13
49
Cash, Cash Equivalents and Restricted Deposits, beginning of period
96
794
Cash and Cash Equivalents, end of period
108
80
Restricted Deposits, end of period
25
17
Cash, Cash Equivalents and Restricted Deposits, end of period
133
97
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits
$
37
$
(697)
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments
$
31
$
38
Assets contributed to equity investment
—
16
Net increase in property, plant and equipment from both accruals and contractor retainage
11
104
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)
1,542
1,505
Cash paid during the period for income taxes, net
26
10
The accompanying notes are an integral part of these consolidated financial statements.
8
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions, unaudited)
Common stock
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 June 30, 2024
2,219
$
22
$
41,218
$
(10,640)
$
(262)
$
30,338
$
1,356
$
31,694
Restricted shares
3
(1)
(1)
(1)
Net income
625
625
26
651
Dividends
(643)
(643)
(643)
Distributions
—
(42)
(42)
Other comprehensive income
87
87
87
Balance at September 30, 2024
2,222
$
22
$
41,217
$
(10,658)
$
(175)
$
30,406
$
1,340
$
31,746
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 June 30, 2023
2,229
$
22
$
41,387
$
(10,550)
$
(290)
$
30,569
$
1,340
$
31,909
Repurchases of shares
(4)
(73)
(73)
(73)
Restricted shares
3
(8)
(8)
(8)
Net income
532
532
23
555
Dividends
(634)
(634)
(634)
Distributions
—
(41)
(41)
Contributions
—
1
1
Other comprehensive loss
(128)
(128)
(128)
Balance at September 30, 2023
2,228
$
22
$
41,306
$
(10,652)
$
(418)
$
30,258
$
1,323
$
31,581
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, 2023
2,220
$
22
$
41,190
$
(10,689)
$
(217)
$
30,306
$
1,423
$
31,729
Repurchases of shares
(1)
(7)
(7)
(7)
Restricted shares
3
34
34
34
Net income
1,946
1,946
80
2,026
Dividends
(1,915)
(1,915)
(1,915)
Distributions
—
(123)
(123)
Acquisition adjustment (Note 2)
—
(38)
(38)
Other
—
(2)
(2)
Other comprehensive income
42
42
42
Balance at September 30, 2024
2,222
$
22
$
41,217
$
(10,658)
$
(175)
$
30,406
$
1,340
$
31,746
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
(23)
(390)
(390)
(390)
Restricted shares
3
26
26
26
Net income
1,797
1,797
71
1,868
Dividends
(1,898)
(1,898)
(1,898)
Distributions
—
(121)
(121)
Contributions
—
1
1
Other
(3)
(3)
(3)
Other comprehensive loss
(16)
(16)
(16)
Balance at September 30, 2023
2,228
$
22
$
41,306
$
(10,652)
$
(418)
$
30,258
$
1,323
$
31,581
The accompanying notes are an integral part of these consolidated financial statements.
9
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 79,000 miles of pipelines, 139 terminals, 702 Bcf of working natural gas storage capacity and have RNG generation capacity of approximately 6.1 Bcf per year of gross production. 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 2023 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, 2024 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, which include assumptions primarily involving management’s judgments and estimates. For all reporting units other than our Energy Transition Ventures reporting unit, we estimated fair value based on a market approach utilizing forecasted earnings before interest, income taxes, DD&A expenses, including amortization of excess cost of equity investments, (EBITDA) and the enterprise value to estimated EBITDA multiples of comparable companies for each of our reporting units. The value of each reporting unit was determined from the perspective of a market participant in an orderly transaction between market participants at the measurement date. For Energy Transition Ventures, we estimated fair value based on an income approach, which includes assumptions regarding future cash flows based primarily 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, 2024 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value. Subsequent to our annual goodwill impairment test, we have not identified any triggers requiring further impairment analysis.
10
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 undistributed earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock units or restricted stock 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 September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions, except per share amounts)
Net Income Available to Stockholders
$
625
$
532
$
1,946
$
1,797
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)
(4)
(4)
(11)
(11)
Net Income Allocated to Common Stockholders
$
621
$
528
$
1,935
$
1,786
Basic Weighted Average Shares Outstanding
2,221
2,230
2,220
2,238
Basic Earnings Per Share
$
0.28
$
0.24
$
0.87
$
0.80
(a)As of September 30, 2024, there were 13 million restricted stock awards outstanding.
The following table presents the maximum number of potential common stock equivalents which are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions on a weighted average basis)
Unvested restricted stock awards
14
13
13
13
Convertible trust preferred securities
3
3
3
3
2. Acquisitions and Divestitures
Acquisitions
As of September 30, 2024, our preliminary allocation of the purchase price for acquisitions are detailed below.
Assignment of Purchase Price
Ref
Acquisition
Purchase price
Current assets
Property, plant & equipment
Other long-term assets
Current liabilities
Long-term liabilities
Non-controlling interest
Resulting goodwill
(In millions)
(1)
North McElroy Unit
$
60
$
1
$
101
$
—
$
—
$
(42)
$
—
$
—
(2)
STX Midstream(a)
1,829
25
1,199
549
(6)
—
(66)
128
(a)The purchase price allocation for the STX Midstream acquisition is preliminary.
(1) North McElroy Unit Acquisition
On June 10, 2024, we completed the acquisition of AVAD Energy Partners’ interest in North McElroy Unit, which is an existing waterflood located in Crane County, Texas for a purchase price of $60 million. The acquired long-term liabilities consist of asset retirement obligations. The acquired assets are included in our CO2 business segment.
11
(2) South Texas Midstream Pipeline System (STX Midstream) Acquisition
On December 28, 2023, we completed the acquisition of STX Midstream from NextEra Energy Partners for a purchase price of $1,829 million, including purchase price adjustments for working capital. During the nine months ended September 30, 2024, the Company identified an adjustment of $38 million to the calculation of noncontrolling interest in addition to measurement period adjustments of $10 million, resulting in a net $28 million decrease to goodwill. The acquired assets are included in our Natural Gas Pipelines business segment.
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 of each year preceding each transaction is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.
Divestitures
CO2 Divestiture
In June 2024, we divested our interests in the Katz Unit, Goldsmith Landreth San Andres Unit, Tall Cotton Field and Reinecke Unit, along with certain shallow interests in the Diamond M Field, all located in the Permian Basin, and received a leasehold interest in an undeveloped leasehold directly adjacent to the SACROC Unit. In addition to the leasehold interest, we received $19 million of cash proceeds from this divestiture, net of working capital adjustments, which is reported as an investing activity within “Other, net” on our accompanying consolidated statement of cash flows, and recorded a gain of $41 million, which is reported within “Loss (gain) on divestitures, net” on our accompanying consolidated statement of income and includes the effect of a $33 million reduction in our asset retirement obligations that were transferred to the buyer. The assets were included in our CO2 business segment.
Goodwill
Changes in the amounts of our goodwill for the nine months ended September 30, 2024 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, 2023
$
14,249
$
2,499
$
928
$
1,378
$
151
$
802
$
114
$
20,121
Acquisition(a)
—
(28)
—
—
—
—
—
(28)
Divestitures(b)
—
—
(9)
—
—
—
—
(9)
Goodwill as of
September 30, 2024
$
14,249
$
2,471
$
919
$
1,378
$
151
$
802
$
114
$
20,084
(a)Reflects adjustment to purchase price allocation related to the December 2023 STX Midstream acquisition.
(b)Associated with our CO2 business segment assets that were divested in June 2024.
3. 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 expired in the second half of 2023. The impairment is recognized on our accompanying consolidated statement of income for the three months ended March 31, 2023 within “Earnings from equity investments.” Our investment in Double Eagle and associated earnings is included within our Products Pipelines business segment.
12
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 Energy LP, a settlement by KMI and Pembina Pipeline Corporation 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.
4. Debt
The following table provides information on the principal amount of our outstanding debt balances:
September 30, 2024
December 31, 2023
(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2027
$
—
$
—
Commercial paper notes(a)
307
1,989
Current portion of senior notes
4.15% due February 2024
—
650
4.30% due May 2024
—
600
4.25% due September 2024
—
650
4.30% due June 2025
1,500
—
Trust I preferred securities, 4.75%, due March 2028(b)
111
111
Current portion of other debt
66
49
Total current portion of debt
1,984
4,049
Long-term debt (excluding current portion)
Senior notes
29,260
27,255
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035
294
311
Trust I preferred securities, 4.75%, due March 2028
110
110
Other
161
204
Total long-term debt
29,825
27,880
Total debt(c)
$
31,809
$
31,929
(a)Weighted average interest rate on borrowings at September 30, 2024 and December 31, 2023 was 4.98% and 5.68%, respectively.
(b)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.
(c)Excludes our “Debt fair value adjustments” which, as of September 30, 2024 and December 31, 2023, increased our total debt balances by $222 million and $187 million, respectively.
On February 1, 2024, we issued, in a registered offering, two series of senior notes consisting of $1,250 million aggregate principal amount of 5.00% senior notes due 2029 and $1,000 million aggregate principal amount of 5.40% senior notes due 2034 and received combined net proceeds of $2,230 million.
On July 31, 2024, we issued, in a registered offering, two series of senior notes consisting of $500 million aggregate principal amount of 5.10% senior notes due 2029 and $750 million aggregate principal amount of 5.95% senior notes due 2054 and received combined net proceeds of $1,235 million.
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.
Credit Facilities and Restrictive Covenants
As of September 30, 2024, we had no borrowings outstanding under our credit facility, $307 million borrowings outstanding under our commercial paper program and $57 million in letters of credit. Our availability under our credit facility
13
as of September 30, 2024 was $3.1 billion. For the periods ended September 30, 2024 and 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:
September 30, 2024
December 31, 2023
Carrying value
Estimated fair value(a)
Carrying value
Estimated fair value(a)
(In millions)
Total debt
$
32,031
$
31,980
$
32,116
$
31,370
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $213 million and $207 million as of September 30, 2024 and December 31, 2023, respectively.
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2024 and December 31, 2023.
5. Stockholders’ Equity
Class P Common Stock
We have a board-approved share buy-back program that authorizes share repurchase of up to $3 billion. During the nine months ended September 30, 2024, we repurchased less than 1 million of our shares for $7 million at an average price of $16.50 per share.
Dividends
The following table provides information about our per share dividends:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Per share cash dividend declared for the period
$
0.2875
$
0.2825
$
0.8625
$
0.8475
Per share cash dividend paid in the period
0.2875
0.2825
0.8575
0.8425
On October 16, 2024, our board of directors declared a cash dividend of $0.2875 per share for the quarterly period ended September 30, 2024, which is payable on November 15, 2024 to shareholders of record as of the close of business on October 31, 2024.
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, 2023
$
(44)
$
(173)
$
(217)
Other comprehensive gain before reclassifications
18
15
33
Loss reclassified from accumulated other comprehensive loss
9
—
9
Net current-period change in accumulated other comprehensive loss
27
15
42
Balance as of September 30, 2024
$
(17)
$
(158)
$
(175)
14
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
2
11
13
Gain reclassified from accumulated other comprehensive loss
(29)
—
(29)
Net current-period change in accumulated other comprehensive loss
(27)
11
(16)
Balance as of September 30, 2023
$
(191)
$
(227)
$
(418)
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, 2024, 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
(16.9)
MMBbl
Natural gas fixed price
(63.8)
Bcf
Natural gas basis
(42.4)
Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price
(1.0)
MMBbl
Crude oil basis
(2.0)
MMBbl
Natural gas fixed price
(3.8)
Bcf
Natural gas basis
(63.0)
Bcf
NGL fixed price
(1.4)
MMBbl
As of September 30, 2024, 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 2028.
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, 2024:
Notional amount
Accounting treatment
Maximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)
$
4,750
Fair value hedge
March 2035
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts(b)
$
1,500
Mark-to-Market
December 2025
(a)The principal amount of hedged senior notes consisted of $1,500 million included in “Current portion of debt” and $3,250 million included in “Long-term debt” on our accompanying consolidated balance sheets.
(b)Contracts have an effective date of December 31, 2024.
15
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, 2024:
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.
16
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
September 30, 2024
December 31, 2023
September 30, 2024
December 31, 2023
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
$
46
$
77
$
(32)
$
(75)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
12
12
(13)
(29)
Subtotal
58
89
(45)
(104)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
3
—
(64)
(120)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
37
37
(101)
(158)
Subtotal
40
37
(165)
(278)
Foreign currency contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
—
—
(6)
(2)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
7
—
—
(2)
Subtotal
7
—
(6)
(4)
Total
105
126
(216)
(386)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
26
49
(10)
(8)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
3
3
(5)
(1)
Subtotal
29
52
(15)
(9)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
—
—
(5)
—
Subtotal
—
—
(5)
—
Total
29
52
(20)
(9)
Total derivatives
$
134
$
178
$
(236)
$
(395)
17
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 September 30, 2024
Energy commodity derivative contracts(b)
$
26
$
61
$
—
$
87
$
(12)
$
—
$
75
Interest rate contracts
—
40
—
40
—
—
40
Foreign currency contracts
—
7
—
7
—
—
7
As of December 31, 2023
Energy commodity derivative contracts(b)
$
65
$
75
$
—
$
140
$
(16)
$
—
$
124
Interest rate contracts
—
38
—
38
—
—
38
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 September 30, 2024
Energy commodity derivative contracts(b)
$
(6)
$
(55)
$
—
$
(61)
$
12
$
(28)
$
(77)
Interest rate contracts
—
(170)
—
(170)
—
—
(170)
Foreign currency contracts
—
(5)
—
(5)
—
—
(5)
As of December 31, 2023
Energy commodity derivative contracts(b)
$
(17)
$
(96)
$
—
$
(113)
$
16
$
(85)
$
(182)
Interest rate contracts
—
(278)
—
(278)
—
—
(278)
Foreign currency contracts
—
(4)
—
(4)
—
—
(4)
(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 September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Interest rate contracts
Interest, net
$
160
$
(74)
$
105
$
(55)
Hedged fixed rate debt(a)
Interest, net
$
(160)
$
77
$
(104)
$
59
(a)As of September 30, 2024, the cumulative amount of fair value hedging adjustments resulted in a decrease of $132 million in the carrying value of our hedged fixed rate debt balance and is included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.
18
Derivatives in cash flow hedging relationships
Gain/(loss) recognized in OCI on derivative(a)
Location
Gain/(loss) reclassified from Accumulated OCI into income
Three Months Ended September 30,
Three Months Ended September 30,
2024
2023
2024
2023
(In millions)
(In millions)
Energy commodity derivative contracts
$
110
$
(188)
Revenues—Commodity sales
$
2
$
16
Costs of sales
(6)
(27)
Foreign currency contracts
19
(10)
Other, net
21
(17)
Total
$
129
$
(198)
Total
$
17
$
(28)
Derivatives in cash flow hedging relationships
Gain/(loss) recognized in OCI on derivative(a)
Location
Gain/(loss) reclassified from Accumulated OCI into income
Nine Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
(In millions)
Energy commodity derivative contracts
$
5
$
(3)
Revenues—Commodity sales
$
(6)
$
98
Costs of sales
(15)
(54)
Interest rate contracts
13
—
Interest, net
4
—
Foreign currency contracts
6
6
Other, net
5
(6)
Total
$
24
$
3
Total
$
(12)
$
38
(a)We expect to reclassify approximately $7 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2024 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
Derivatives not designated as accounting hedges
Location
Gain/(loss) recognized in income on derivatives
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$
21
$
(21)
$
13
$
11
Costs of sales
(9)
(4)
(41)
116
Earnings from equity investments
1
—
—
1
Interest rate contracts
Interest, net
(5)
(6)
(7)
6
Total(a)
$
8
$
(31)
$
(35)
$
134
(a)The three and nine months ended September 30, 2024 amounts include approximate losses of $12 million and $1 million, respectively, and the three and nine months ended September 30, 2023 amounts include approximate gains of $9 million and $45 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, 2024 and December 31, 2023, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2024 and December 31, 2023, we had cash margins of $12 million and $63 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 September 30, 2024 represents the initial margin requirements of $16 million and variation margin requirements of $28 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with
19
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, 2024, 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 $23 million of additional collateral.
7. Revenue Recognition
Disaggregation of Revenues
The following tables present our revenues disaggregated by segment, revenue source and type of revenue for each revenue source:
Three Months Ended September 30, 2024
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
949
$
59
$
211
$
1
$
(1)
$
1,219
Fee-based services
270
265
111
9
(1)
654
Total services
1,219
324
322
10
(2)
1,873
Commodity sales
Natural gas sales
561
—
—
43
(2)
602
Product sales
221
330
9
254
(1)
813
Total commodity sales
782
330
9
297
(3)
1,415
Total revenues from contracts with customers
2,001
654
331
307
(5)
3,288
Other revenues(c)
Leasing services(d)
115
50
167
19
—
351
Derivatives adjustments on commodity sales
34
—
—
(11)
—
23
Other
26
7
—
4
—
37
Total other revenues
175
57
167
12
—
411
Total revenues
$
2,176
$
711
$
498
$
319
$
(5)
$
3,699
20
Three Months Ended September 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
$
211
$
—
$
(1)
$
1,108
Fee-based services
268
264
102
9
(1)
642
Total services
1,117
313
313
9
(2)
1,750
Commodity sales
Natural gas sales
689
—
—
28
(5)
712
Product sales
281
495
10
291
(2)
1,075
Total commodity sales
970
495
10
319
(7)
1,787
Total revenues from contracts with customers
2,087
808
323
328
(9)
3,537
Other revenues(c)
Leasing services(d)
120
50
161
15
—
346
Derivatives adjustments on commodity sales
49
(2)
—
(52)
—
(5)
Other
17
6
—
6
—
29
Total other revenues
186
54
161
(31)
—
370
Total revenues
$
2,273
$
862
$
484
$
297
$
(9)
$
3,907
Nine Months Ended September 30, 2024
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
2,861
$
166
$
638
$
1
$
(3)
$
3,663
Fee-based services
798
789
335
31
(3)
1,950
Total services
3,659
955
973
32
(6)
5,613
Commodity sales
Natural gas sales
1,646
—
—
96
(6)
1,736
Product sales
655
1,086
37
787
(3)
2,562
Total commodity sales
2,301
1,086
37
883
(9)
4,298
Total revenues from contracts with customers
5,960
2,041
1,010
915
(15)
9,911
Other revenues(c)
Leasing services(d)
344
156
493
48
—
1,041
Derivatives adjustments on commodity sales
81
(1)
—
(73)
—
7
Other
120
19
—
15
—
154
Total other revenues
545
174
493
(10)
—
1,202
Total revenues
$
6,505
$
2,215
$
1,503
$
905
$
(15)
$
11,113
21
Nine Months Ended September 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)
$
2,615
$
138
$
626
$
1
$
(2)
$
3,378
Fee-based services
752
750
298
29
(1)
1,828
Total services
3,367
888
924
30
(3)
5,206
Commodity sales
Natural gas sales
1,972
—
—
61
(9)
2,024
Product sales
788
1,211
23
836
(6)
2,852
Total commodity sales
2,760
1,211
23
897
(15)
4,876
Total revenues from contracts with customers
6,127
2,099
947
927
(18)
10,082
Other revenues(c)
Leasing services(d)
357
149
476
40
—
1,022
Derivatives adjustments on commodity sales
196
(1)
—
(86)
—
109
Other
50
18
—
15
—
83
Total other revenues
603
166
476
(31)
—
1,214
Total revenues
$
6,730
$
2,265
$
1,423
$
896
$
(18)
$
11,296
(a)Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as “Fee-based services.”
(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 6 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, 2024 and December 31, 2023, our contract asset balances were $36 million and $34 million, respectively. Of the contract asset balance at December 31, 2023, $23 million was transferred to accounts receivable during the nine months ended September 30, 2024. As of September 30, 2024 and December 31, 2023, our contract liability balances were $395 million and $415 million, respectively. Of the contract liability balance at December 31, 2023, $81 million was recognized as revenue during the nine months ended September 30, 2024.
In addition to our contract balances above, we also had lease contract liabilities associated with prepaid fixed reservation charges under a long-term terminaling contract totaling $601 million and $643 million as of September 30, 2024 and December 31, 2023, respectively.
22
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, 2024 that we will invoice or transfer from contract liabilities and recognize in future periods:
Year
Estimated Revenue
(In millions)
Three months ended December 31, 2024
$
1,303
2025
4,706
2026
3,951
2027
3,258
2028
2,840
Thereafter
16,775
Total
$
32,833
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, based on the practical expedient that we elected to apply, generally exclude 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,
2024
2023
2024
2023
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers
$
2,173
$
2,268
$
6,496
$
6,718
Intersegment revenues
3
5
9
12
Products Pipelines
711
862
2,215
2,265
Terminals
Revenues from external customers
496
483
1,498
1,420
Intersegment revenues
2
1
5
3
CO2
Revenues from external customers
319
294
904
893
Intersegment revenues
—
3
1
3
Corporate and intersegment eliminations
(5)
(9)
(15)
(18)
Total consolidated revenues
$
3,699
$
3,907
$
11,113
$
11,296
23
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Segment EBDA(a)
Natural Gas Pipelines
$
1,294
$
1,179
$
4,035
$
3,929
Products Pipelines
278
311
871
780
Terminals
268
259
818
774
CO2
170
163
534
510
Total Segment EBDA
2,010
1,912
6,258
5,993
DD&A
(587)
(561)
(1,758)
(1,683)
Amortization of excess cost of equity investments
(12)
(18)
(37)
(54)
General and administrative and corporate charges
(181)
(176)
(545)
(534)
Interest, net
(466)
(457)
(1,402)
(1,345)
Income tax expense
(113)
(145)
(490)
(509)
Total consolidated net income
$
651
$
555
$
2,026
$
1,868
September 30, 2024
December 31, 2023
(In millions)
Assets
Natural Gas Pipelines
$
49,901
$
49,883
Products Pipelines
8,625
8,781
Terminals
8,108
8,235
CO2
3,603
3,497
Corporate assets(b)
642
624
Total consolidated assets
$
70,879
$
71,020
(a)Includes revenues; earnings from equity investments; operating expenses; (loss) gain on divestitures, 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.
9. Income Taxes
Income tax expense included on our accompanying consolidated statements of income is as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions, except percentages)
Income tax expense
$
113
$
145
$
490
$
509
Effective tax rate
14.8
%
20.7
%
19.5
%
21.4
%
The effective tax rates for the three and nine months ended September 30, 2024 are lower than the statutory federal rate of 21% primarily due to (i) the recognition of investment tax credits generated by biogas projects reported on the 2023 filed tax return; (ii) an adjustment to our deferred tax liability as a result of a reduction in state income tax rates; and (iii) dividend-received deductions from our investments in Florida Gas Pipeline (Citrus), NGPL Holdings and Products (SE) Pipe Line Company (PPL), partially offset by state income taxes.
The effective tax rate for the three months ended September 30, 2023 is lower than the statutory federal rate of 21% due to dividend-received deductions from our investments in Citrus, NGPL Holdings and PPL, partially offset by state income taxes.
24
The effective tax rate for the nine months ended September 30, 2023 is higher than the statutory federal rate of 21% primarily due to state income taxes, partially offset by dividend-received deductions from our investments in Citrus, NGPL Holdings and PPL.
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 numerous and substantial 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
Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) filed a lawsuit in 2018 against Eni S.p.A. in the Supreme Court of the State of New York to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. in 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). GLNG filed suit to enforce the Guarantee against Eni S.p.A. after an arbitration tribunal delivered an award 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, Eni S.p.A. filed counterclaims 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 based on the same substantive allegations that were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC, a consortium of international oil companies including Eni S.p.A. In early 2022, the trial court granted Eni S.p.A’s motion for summary judgment on GLNG’s claims to enforce the Guarantee. The Appellate Division denied GLNG’s appeal. GLNG elected not to pursue further recourse to the state Court of Appeals, which is the state’s highest appellate court, thereby concluding GLNG’s efforts to enforce the Guarantee. With respect to the counterclaims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment and entered judgment dismissing all of Eni S.p.A.’s claims with prejudice on September 15, 2023. On September 24, 2024, the state Appellate Division affirmed the entry of summary judgment in GLNG’s favor. Eni S.p.A. may petition the Court of Appeals for final appellate review which we will vigorously oppose.
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 our declaration of force majeure was proper and 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 complaint, which was transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590) and later amended to include the Kinder Morgan Retirement Plan B, alleges that the series of foregoing transactions resulted in changes to plaintiffs’ retirement benefits which are now contested on a 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 challenge plan
25
provisions which are alleged to constitute impermissible “backloading” or “cutback” of benefits, and seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. 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. On February 8, 2024, the Court certified a class defined as any and all persons who participated in the Kinder Morgan Retirement Plan A or B who are current or former employees of ANR or Coastal, and participated in the El Paso pension plan after El Paso acquired Coastal in 2001, and are members of at least one of three subclasses of individuals who are allegedly due benefits under one or more of the six claims asserted in the complaint. 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. On July 25, 2024, the Court decided the parties’ respective cross-motions for summary judgment. The Court granted our motion for summary judgment with respect to Claims I and II based on the Court’s determination that the formula used to calculate projected service was neither backloaded nor a violation of ERISA’s anti-cutback rule. The Court granted plaintiffs’ motion for partial summary judgment with respect to Claim III because the Court found that the summary plan description did not include any clarifying examples or illustrations of accrued benefits using the applicable formula. The Court granted plaintiffs’ motion for partial summary judgment as to Claim IV based upon the Court’s finding that an amendment to the plan in 2007 violated ERISA’s anti-cutback protection by terminating the accrual of early retirement benefits in connection with the sale of ANR. The Court granted plaintiffs’ motion for partial summary judgment as to Claim V because the Court found that the plan administrator used an inconsistent interpretation to calculate benefits for some retirees. The Court dismissed Claim VI without prejudice based upon its determination that the claim was moot given that the Court had allowed plaintiffs’ motion as to Counts IV and V. Neither the parties’ respective motions nor the Court’s decision addressed the extent of potential plan liabilities for past or future benefits or other potential equitable relief associated with the claims. The Court instructed the parties to propose a schedule to determine the scope of equitable relief associated with the remaining claims or obtain a referral to mediate the remaining issues before the presiding Magistrate Judge. On October 8, 2024, the case was referred to the presiding Magistrate Judge for mediation on a schedule that remains to be established. In the event a settlement cannot be achieved through the mediation process, we believe we have numerous and substantial defenses to support our vigorous defense at the trial or appellate levels if necessary. To the extent an adverse judgment or settlement results in an increase in plan liabilities, we may elect as the sponsor of the plans to address them in accordance with applicable ERISA provisions, including provisions that allow for contributions to the plans over several years. Accordingly, we do not anticipate that the resolution of this matter will have a material impact to our business.
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, 2024 and December 31, 2023, our total reserve for legal matters was $38 million and $23 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
26
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 June 2025. 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 August 2024, we reached an agreement to settle claims first made in January 2021 asserted by state and federal trustees following their natural resource assessment of the PHSS. We expect the cost to resolve this matter will not 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. On March 4, 2016, the EPA issued a 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 the 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. On January 17, 2024, the DOJ on behalf of the EPA voluntarily dismissed its Complaint against 3 PRPs, filed an Amended Complaint against 82 PRPs, including EPEC, and a modified Consent Decree in the U.S. District Court. On January 31, 2024, the DOJ on behalf of the EPA filed a motion to Enter Consent Decree in the U.S. District Court. We believe our share of the costs to resolve this matter, including our share of the settlement with the 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
27
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. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. The case has been effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal court and subsequently remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. On September 27, 2023, the U.S. District Court ordered the case be stayed and administratively closed pending the resolution of federal question jurisdictional issues. On June 11, 2024, the U.S. District Court lifted the stay and ordered the parties to file memoranda on or before June 28, 2024, addressing the pending jurisdictional issues. On July 8, 2024, the U.S. District Court ordered the case be stayed and administratively closed pending resolution of those same jurisdictional issues. 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 (Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party. On May 3, 2023, the U.S. District Court re-opened the case. On February 28, 2024, the U.S. District Court entered partial Final Judgment dismissing a co-defendant from the case and stayed the case pending appeal of that Judgment. On June 20, 2024, Orleans filed its Appellant’s Brief in the U.S. Court of Appeals for the Fifth Circuit seeking review of the U.S. District Court’s entry of partial Final Judgment. On August 21, 2024, the defendants, including SNG, filed their Appellees’ Briefs, and on September 11, 2024, Orleans filed its Reply to those briefs. The U.S. Court of Appeals scheduled oral arguments to take place December 2, 2024. 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.
Hurricane Harvey Emission Event
In August 2017, KMLT discovered that three tanks at its Pasadena, Texas Terminal failed during Hurricane Harvey. The tank failures resulted in emissions of products being stored in the tanks. The emissions were properly reported to the Texas Commission on Environmental Quality. On November 15, 2019, the State of Texas filed a petition against KMLT in a state district court in Travis County, Texas alleging that violations of maintenance standards contributed to cause both the tank failures in August 2017, and a subsequent tank failure in 2018. The State was seeking monetary penalties and corrective actions by KMLT. The State amended its petition in May 2023; the amended petition also sought penalties and corrective actions. On March 26, 2024, we reached an agreement with the State to settle this case. On July 1, 2024, the State filed a Motion for Entry of Judgment, and on July 2, 2024, the Court entered a Final Judgment. The cost to settle this case did not have a material impact to our business.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of September 30, 2024 and December 31, 2023, we have accrued a total reserve for environmental liabilities in the amount of $192 million and $199 million, respectively. In addition, as of September 30, 2024 and December 31, 2023, we had receivables of $10 million and $11 million, respectively, recorded for expected cost recoveries that have been deemed probable.
28
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 case was styled Kinder Morgan, Inc. v. EPA, et al. and has since been consolidated with other cases and is styled Utah, et al. v, EPA, et al. 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 (NAAQS). We believe that the Plan is deeply flawed and that numerous and substantial 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. On July 27, 2023, in combination with other parties, we filed a Motion to Stay the Plan Pending Review, and on September 25, 2023, the U.S. Court of Appeals denied the Motion. On October 13, 2023, in combination with other parties, we filed an Emergency Application for Stay of Final Agency Action in the United States Supreme Court. The case was styled Kinder Morgan, Inc, et al. v. EPA, et al. and has since been consolidated with other cases and is styled Ohio, et al. v. EPA, et al. The Supreme Court issued an order deferring consideration of the Emergency Application for Stay pending oral argument which took place February 21, 2024. On June 27, 2024, the Supreme Court granted the Emergency Application ruling that enforcement of the Plan shall be stayed pending the disposition of the case on the merits by the U.S. Court of Appeals, and any subsequent petition for writ of certiorari to the Supreme Court, if such writ is timely sought.
On July 31, 2023 and September 29, 2023, the EPA published interim final rules entitled, respectively, “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Judicial Stays of SIP Disapproval Action for Certain States” and “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Additional Judicial Stays of SIP Disapproval Action for Certain States.” We filed petitions for review against the EPA and others in the U.S. Court of Appeals for the District of Columbia seeking review of the interim final rule and the second interim final rule on September 29, 2023 and November 17, 2023, respectively. On February 1, 2024, the U.S. Court of Appeals ordered these cases be held in abeyance pending further order of the Court.
In reaching its decision to grant the Emergency Application, the Supreme Court found that the parties challenging the Plan are likely to prevail on their argument that the Plan was not reasonably explained, that the EPA failed to supply a satisfactory explanation for its action, and that the EPA ignored an important aspect of the problem it was attempting to solve by promulgating the Plan. The EPA has no legal basis to enforce the Plan while the Supreme Court stay remains in place. If the Plan ultimately were to take effect in its current form (including full compliance by a revised compliance deadline accounting for the stays, and assuming failure of all challenges to state implementation plan disapprovals and to the Plan), we anticipate that it would have a material impact on us. Due to the extensive pending litigation, impacts of the Plan are difficult to predict. Should the Plan take effect, we would seek to mitigate the impacts, and to recover expenditures through adjustments to our rates on our regulated assets where available.
11. Recent Accounting Pronouncements
Accounting Standards Updates (ASU)
ASU No. 2023-07
On November 27, 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” This ASU amends reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption of the ASU is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual and interim disclosures.
ASU No. 2023-09
On December 14, 2023, the FASB issued ASU No. 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” This ASU is intended to improve the transparency of income tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. This ASU will be effective for annual periods beginning after December 15, 2024, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual disclosures.
29
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
General and Basis of Presentation
The following discussion and analysis should be read in conjunction with our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes in our 2023 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2023 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2023 Form 10-K; and (iv) “Risk Factors” in Part I, Item 1 in our 2023 Form 10-K.
Acquisition and Divestitures
The following acquisition and divestitures were made during the 2024 period. See Note 2. “Acquisitions and Divestitures” to our consolidated financial statements for further information on these transactions.
Event
Description
Business Segment
North McElroy Unit acquisition
$60 million
(June 2024)
We acquired AVAD Energy Partners’ interest in the North McElroy Unit (NMU). NMU is an existing waterflood that currently produces approximately 1,250 Bbl/d of crude oil. Our analysis suggests that NMU could be a candidate for CO2 flooding.
CO2
(Oil and Gas Producing activities)
CO2 assets divestiture
$19 million
(June 2024)
We sold our interests in the Katz Unit, Goldsmith Landreth San Andres Unit, Tall Cotton Field and Reinecke Unit, along with certain shallow interests in the Diamond M Field, all located in the Permian Basin, and received a leasehold interest in an undeveloped leasehold directly adjacent to the SACROC unit.
CO2
(Oil and Gas Producing activities)
Oklahoma assets divestiture
$43 million
(February 2024)
We sold our Oklahoma midstream assets consisting of our Oklahoma system and Cedar Cove.
Natural Gas Pipelines
(Midstream)
2024 Dividends and Discretionary Capital
We expect to declare dividends of $1.15 per share for 2024, a 2% increase from the 2023 declared dividends of $1.13 per share. We now expect to invest $1.98 billion in expansion projects, acquisitions, and contributions to joint ventures during 2024.
The expectations for 2024 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.
Results of Operations
Overview
As described in further detail below, our management evaluates our performance primarily using Net income attributable to Kinder Morgan, Inc. and Segment earnings before DD&A expenses, including amortization of excess cost of equity investments, (EBDA) (as presented in Note 8 “Reportable Segments”). Management also considers the non-GAAP financial measures of Adjusted Net Income Attributable to Common Stock, and distributable cash flow (DCF), both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted Net Income Attributable to Kinder Morgan, Inc., Adjusted earnings before interest, income taxes, DD&A expenses, including amortization of excess cost of equity investments, (EBITDA) and Net Debt.
GAAP Financial Measures
Our Consolidated Earnings Results for the three and nine months ended September 30, 2024 and 2023 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with GAAP, and Segment EBDA, which is disclosed in Note 8 “Reportable Segments” pursuant to FASB ASC 280. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as
30
unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.
Non-GAAP Financial Measures
Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its decision-making processes.
Certain Items
Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA”below). We also include adjustments related to joint ventures (see “—Amounts from Joint Ventures” below). The following table summarizes our Certain Items for the three and nine months ended September 30, 2024 and 2023, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Certain Items
Change in fair value of derivative contracts(a)
$
(20)
$
37
$
32
$
(93)
(Gain) loss on divestitures and impairment, net
—
—
(70)
67
Income tax Certain Items(b)
(49)
(7)
(48)
6
Other
1
—
3
—
Total Certain Items(c)(d)
$
(68)
$
30
$
(83)
$
(20)
(a)Gains or losses are reflected when realized.
(b)Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the investees by the joint ventures which are also taxable entities.
(c)Amounts for the periods ending September 30, 2023 include the following amounts reported within “Earnings from equity investments” on the accompanying consolidated statements of income: (i) $1 million for the three-month period only of “Change in fair value of derivative contracts” and (ii) $67 million for the nine-month period only of “(Gain) loss on divestitures and impairment, net” for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 3 “Losses on Impairments—Impairments”).
(d)Amounts for the periods ending September 30, 2024 and 2023 include the following amounts reported within “Interest, net” on the accompanying consolidated statements of income: $4 million and $3 million for the three-month periods, respectively, and $5 million and $(10) million for the nine-month periods, respectively, of “Change in fair value of derivative contracts.”
Adjusted Net Income Attributable to Kinder Morgan, Inc.
Adjusted Net Income Attributable to Kinder Morgan, Inc. is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Net Income Attributable to Kinder Morgan, Inc. is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is Net income attributable to
31
Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.” below.
Adjusted Net Income Attributable to Common Stock and Adjusted EPS
Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income allocated to participating securities and adjusted net income in excess of distributions for participating securities. We believe Adjusted Net Income Attributable to Common Stock allows for calculation of adjusted earnings per share (Adjusted EPS) on the most comparable basis with earnings per share, the most comparable GAAP measure to Adjusted EPS. Adjusted EPS is calculated as Adjusted Net Income Attributable to Common Stock divided by our weighted average shares outstanding. Adjusted EPS applies the same two-class method used in arriving at basic earnings per share. Adjusted EPS is used by us, investors and other external users of our financial statements as a per-share supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock” below.
DCF
DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items, and further for DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “—Amounts from Joint Ventures” below). DCF is a significant performance measure used by us, investors and other external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate economic earnings after paying interest expense, paying cash taxes and expending sustaining capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF is also used by us, investors, and other external users to compare the performance of companies across our industry. DCF per share serves as the primary financial performance target for purposes of annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF”below.
Adjusted Segment EBDA
Adjusted Segment EBDA is calculated by adjusting segment earnings before DD&A and amortization of excess cost of equity investments, general and administrative expenses and corporate charges, interest expense, and income taxes (Segment EBDA) for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. See “—Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment EBDA”below.
Adjusted EBITDA
Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A and amortization of excess cost of equity investments, income tax expense and interest. We also include amounts from joint ventures for income taxes and DD&A (see “—Amounts from Joint Ventures” below). Adjusted EBITDA is used by management, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted
32
EBITDA is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA”below.
Amounts from Joint Ventures
Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to non-controlling interests. (See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA”below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.
Net Debt
Net Debt is calculated, based on amounts as of September 30, 2024, by subtracting the following amounts from our debt balance of $32,031 million: (i) cash and cash equivalents of $108 million; (ii) debt fair value adjustments of $222 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $14 million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors and other external users of our financial information to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is total debt.
33
Consolidated Earnings Results
The following tables summarize the key components of our consolidated earnings results.
Three Months Ended September 30,
2024
2023
Earnings increase/(decrease)
(In millions, except percentages)
Revenues
$
3,699
$
3,907
$
(208)
(5)
%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)
(1,024)
(1,405)
381
27
%
Operations and maintenance
(790)
(738)
(52)
(7)
%
DD&A
(587)
(561)
(26)
(5)
%
General and administrative
(176)
(162)
(14)
(9)
%
Taxes, other than income taxes
(107)
(106)
(1)
(1)
%
(Loss) gain on divestitures, net
(1)
3
(4)
(133)
%
Other income, net
1
—
1
—
%
Total Operating Costs, Expenses and Other
(2,684)
(2,969)
285
10
%
Operating Income
1,015
938
77
8
%
Other Income (Expense)
Earnings from equity investments
211
234
(23)
(10)
%
Amortization of excess cost of equity investments
(12)
(18)
6
33
%
Interest, net
(466)
(457)
(9)
(2)
%
Other, net
16
3
13
433
%
Total Other Expense
(251)
(238)
(13)
(5)
%
Income Before Income Taxes
764
700
64
9
%
Income Tax Expense
(113)
(145)
32
22
%
Net Income
651
555
96
17
%
Net Income Attributable to Noncontrolling Interests
(26)
(23)
(3)
(13)
%
Net Income Attributable to Kinder Morgan, Inc.
$
625
$
532
$
93
17
%
Basic and diluted earnings per share
$
0.28
$
0.24
$
0.04
17
%
Basic and diluted weighted average shares outstanding
2,221
2,230
(9)
—
%
Declared dividends per share
$
0.2875
$
0.2825
$
0.005
2
%
34
Nine Months Ended September 30,
2024
2023
Earnings increase/(decrease)
(In millions, except percentages)
Revenues
$
11,113
$
11,296
$
(183)
(2)
%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)
(3,098)
(3,591)
493
14
%
Operations and maintenance
(2,211)
(2,062)
(149)
(7)
%
DD&A
(1,758)
(1,683)
(75)
(4)
%
General and administrative
(530)
(497)
(33)
(7)
%
Taxes, other than income taxes
(327)
(319)
(8)
(3)
%
Gain on divestitures, net
76
16
60
375
%
Other income, net
11
2
9
450
%
Total Operating Costs, Expenses and Other
(7,837)
(8,134)
297
4
%
Operating Income
3,276
3,162
114
4
%
Other Income (Expense)
Earnings from equity investments
662
607
55
9
%
Amortization of excess cost of equity investments
(37)
(54)
17
31
%
Interest, net
(1,402)
(1,345)
(57)
(4)
%
Other, net
17
7
10
143
%
Total Other Expense
(760)
(785)
25
3
%
Income Before Income Taxes
2,516
2,377
139
6
%
Income Tax Expense
(490)
(509)
19
4
%
Net Income
2,026
1,868
158
8
%
Net Income Attributable to Noncontrolling Interests
(80)
(71)
(9)
(13)
%
Net Income Attributable to Kinder Morgan, Inc.
$
1,946
$
1,797
$
149
8
%
Basic and diluted earnings per share
$
0.87
$
0.80
$
0.07
9
%
Basic and diluted weighted average shares outstanding
2,220
2,238
(18)
(1)
%
Declared dividends per share
$
0.8625
$
0.8475
$
0.015
2
%
Our consolidated revenues primarily consist of services and sales revenue. Our services revenues include fees for transportation and other midstream services that we perform. Fluctuations in our consolidated services revenue largely reflect changes in volumes and/or in the rates we charge. Our consolidated sales revenues include sales of natural gas (includes natural gas, RNG and RINs) and products (includes NGL, crude oil, CO2 and transmix). Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the costs of sales associated with purchases will usually have a commensurate and offsetting impact, except for the CO2 segment, which produces, instead of purchases, the crude oil and CO2 it sells. Additionally, fluctuations in revenues and costs of sales may be further impacted by gains or losses from derivative contracts that we use to manage our commodity price risk.
Below is a discussion of significant changes in our Consolidated Earnings Results for the comparable three and nine-month periods ended September 30, 2024 and 2023:
Revenues
Revenues decreased $208 million and $183 million for the three and nine months ended September 30, 2024, respectively, as compared to the respective prior year periods due to a combination of factors. Product sales decreased $262 million and $290 million, respectively, driven by lower volumes and, for the three-month period, by lower commodity prices. Natural gas sales decreased $110 million and $288 million, respectively, due to lower commodity prices partially offset by higher volumes and higher RIN sales. Services revenues increased $123 million and $407 million, respectively, driven by (i) higher volumes, including expansion projects; (ii) our acquisition of the STX Midstream assets partially offset by a reduction in revenues related
35
to divested assets; and (iii) in the nine-month period, higher rate escalations. Revenues were further increased by $28 million and reduced by $102 million, respectively, for the impacts of derivative contracts used to hedge commodity sales which includes both realized and unrealized gains and losses from derivatives. The decreases in sales revenues, which include the impact of our divested assets, had corresponding decreases in our costs of sales as described below under “Operating Costs, Expenses and Other—Costs of sales.”
Operating Costs, Expenses and Other
Costs of sales
Costs of sales decreased $381 million and $493 million for the three and nine months ended September 30, 2024, respectively, as compared to the respective prior year periods. The decreases, which include the impact of our divested assets, were primarily due to (a) lower costs of sales for (i) natural gas of $225 million and $391 million, respectively, primarily due to lower commodity prices partially offset by higher volumes; and (ii) lower costs of sales for products of $135 million and $208 million, respectively, which were driven primarily by lower volumes and for the three-month period lower commodity prices, and (b) a decrease in costs of sales of $16 million and an increase of $118 million, respectively, related to derivative contracts used to hedge commodity purchases which includes both realized and unrealized gains and losses from derivatives.
Operations and Maintenance
Operations and maintenance increased $52 million and $149 million for the three and nine months ended September 30, 2024, respectively, as compared to the respective prior year periods. The increases were primarily driven by other expenses, including integrity and service costs, higher labor and fuel costs, related to greater activity levels and inflation.
Other Income (Expense)
Interest, net
In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our interest expense, net increased $9 million and $57 million for the three and nine months ended September 30, 2024, respectively, as compared to the respective prior year periods. The increases were primarily due to (i) higher interest rates associated with our fixed-to-variable interest rate swap agreements and our long-term debt; (ii) higher average short-term debt balances; and (iii) for the three-month period, higher average long-term debt balances; partially offset by a reduction in the notional balances associated with our fixed-to-variable interest rate swap agreements.
36
Non-GAAP Financial Measures
Reconciliations from Net Income Attributable to Kinder Morgan, Inc.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions, except per share amounts)
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.
Net income attributable to Kinder Morgan, Inc.
$
625
$
532
$
1,946
$
1,797
Certain Items(a)
Change in fair value of derivative contracts
(20)
37
32
(93)
(Gain) loss on divestitures and impairment, net
—
—
(70)
67
Income tax Certain Items
(49)
(7)
(48)
6
Other
1
—
3
—
Total Certain Items
(68)
30
(83)
(20)
Adjusted Net Income Attributable to Kinder Morgan, Inc.
$
557
$
562
$
1,863
$
1,777
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock
Net income attributable to Kinder Morgan, Inc.
$
625
$
532
$
1,946
$
1,797
Total Certain Items(b)
(68)
30
(83)
(20)
Net income allocated to participating securities(c)
(4)
(4)
(11)
(11)
Other(d)
—
(1)
1
—
Adjusted Net Income Attributable to Common Stock
$
553
$
557
$
1,853
$
1,766
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF
Net income attributable to Kinder Morgan, Inc.
$
625
$
532
$
1,946
$
1,797
Total Certain Items(b)
(68)
30
(83)
(20)
DD&A
587
561
1,758
1,683
Amortization of excess cost of equity investments
12
18
37
54
Income tax expense(e)
162
152
538
503
Cash taxes
(14)
(1)
(25)
(10)
Sustaining capital expenditures(f)
(270)
(242)
(680)
(593)
Amounts from joint ventures
Unconsolidated joint venture DD&A
99
80
271
241
Remove consolidated joint venture partners’ DD&A
(16)
(16)
(47)
(47)
Unconsolidated joint venture income tax expense(g)(h)
17
24
58
70
Unconsolidated joint venture cash taxes(g)
(6)
(21)
(59)
(73)
Unconsolidated joint venture sustaining capital expenditures
(43)
(43)
(132)
(118)
Remove consolidated joint venture partners’ sustaining capital expenditures
2
2
7
6
Other items(i)
9
18
29
51
DCF
$
1,096
$
1,094
$
3,618
$
3,544
Basic weighted average shares outstanding
2,221
2,230
2,220
2,238
Adjusted EPS
$
0.25
$
0.25
$
0.83
$
0.79
Weighted average shares outstanding for dividends(j)
2,235
2,244
2,233
2,251
DCF per share
$
0.49
$
0.49
$
1.62
$
1.57
Declared dividends per share
$
0.2875
$
0.2825
$
0.8625
$
0.8475
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
37
(b)See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.” for a detailed listing.
(c)Net income allocated to common stock and participating securities is 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, as applicable.
(d)Adjusted net income in excess of distributions for participating securities.
(e)To avoid duplication, adjustments for income tax expense for the periods ended September 30, 2024 and 2023 exclude $(49) million and $(7) million for the three-month periods, respectively, and $(48) million and $6 million for the nine-month periods, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(f)Net of a $14 million insurance reimbursement in both the three and nine-month periods ended September 30, 2024 for a sustaining capital expenditure project.
(g)Associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments.
(h)Includes the tax provision on Certain Items recognized by the investees that are taxable entities. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(i)Includes non-cash pension expense, non-cash compensation associated with our restricted stock program and pension contributions.
(j)Includes restricted stock awards that participate in dividends.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA
Net income attributable to Kinder Morgan, Inc.
$
625
$
532
$
1,946
$
1,797
Certain Items(a)
Change in fair value of derivative contracts
(20)
37
32
(93)
(Gain) loss on divestitures and impairment, net
—
—
(70)
67
Income tax Certain Items
(49)
(7)
(48)
6
Other
1
—
3
—
Total Certain Items
(68)
30
(83)
(20)
DD&A
587
561
1,758
1,683
Amortization of excess cost of equity investments
12
18
37
54
Income tax expense(b)
162
152
538
503
Interest, net(c)
462
454
1,397
1,355
Amounts from joint ventures
Unconsolidated joint venture DD&A
99
80
271
241
Remove consolidated joint venture partners’ DD&A
(16)
(16)
(47)
(47)
Unconsolidated joint venture income tax expense(d)
17
24
58
70
Adjusted EBITDA
$
1,880
$
1,835
$
5,875
$
5,636
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(b)To avoid duplication, adjustments for income tax expense for the periods ended September 30, 2024 and 2023 exclude $(49) million and $(7) million for the three-month periods, respectively, and $(48) million and $6 million for the nine-month periods, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(c)To avoid duplication, adjustments for interest, net for the periods ended September 30, 2024 and 2023 exclude $4 million and $3 million for the three-month periods, respectively, and $5 million and $(10) million for the nine-month periods, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.
(d)Includes that tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.
38
Below is a discussion of significant changes in our Adjusted Net Income Attributable to Kinder Morgan, Inc., DCF and Adjusted EBITDA:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Adjusted Net Income Attributable to Kinder Morgan, Inc.
$
557
$
562
$
1,863
$
1,777
DCF
1,096
1,094
3,618
3,544
Adjusted EBITDA
1,880
1,835
5,875
5,636
Change from prior period
Increase/(Decrease)
Adjusted Net Income Attributable to Kinder Morgan, Inc.
$
(5)
$
86
DCF
$
2
$
74
Adjusted EBITDA
$
45
$
239
Adjusted Net Income Attributable to Kinder Morgan, Inc. decreased $5 million and increased $86 million for the three and nine months ended September 30, 2024, respectively, as compared to the respective prior year periods. The changes resulted primarily from unfavorable earnings in our Products Pipelines business segment only in the three-month period, and our CO2 business segment offset, more significantly in the nine-month period, by favorable earnings in our Natural Gas Pipelines and Terminals business segments, and in the nine-month period, in our Products Pipelines business segment, all of which were also primary drivers of the increases in DCF of $2 million and $74 million, respectively, and the increases in Adjusted EBITDA of $45 million and $239 million, respectively. The three and nine-month period increases in DCF were also unfavorably impacted by an increase in sustaining capital expenditures.
General and administrative expenses increased $14 million and $33 million, and corporate charges decreased $9 million and $22 million for the three and nine months ended September 30, 2024, respectively, when compared with the respective prior year periods. The combined changes for the three and nine-month periods include $13 million and $29 million, respectively, consisting of higher labor and benefit-related costs, higher legal costs and higher corporate development costs, offset by lower pension costs of $9 million and $22 million, respectively. In addition, the combined changes described above includes $1 million and $3 million of costs for the three-month and nine-month 2024 periods, respectively, which we treated as Certain Items.
39
Reconciliation of Segment EBDA to Adjusted Segment EBDA
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA
$
1,294
$
1,179
$
4,035
$
3,929
Certain Items(b)
Change in fair value of derivative contracts
(14)
20
29
(99)
Gain on divestiture
—
—
(29)
—
Natural Gas Pipelines Adjusted Segment EBDA
$
1,280
$
1,199
$
4,035
$
3,830
Products Pipelines Segment EBDA
$
278
$
311
$
871
$
780
Certain Items(b)
Change in fair value of derivative contracts
(1)
2
—
3
Loss on impairment
—
—
—
67
Products Pipelines Adjusted Segment EBDA
$
277
$
313
$
871
$
850
Terminals Segment EBDA
$
268
$
259
$
818
$
774
Certain Items(b)
Change in fair value of derivative contracts
(1)
—
(1)
—
Terminals Adjusted Segment EBDA
$
267
$
259
$
817
$
774
CO2 Segment EBDA
$
170
$
163
$
534
$
510
Certain Items(b)
Change in fair value of derivative contracts
(8)
12
(1)
13
Gain on divestitures
—
—
(41)
—
CO2 Adjusted Segment EBDA
$
162
$
175
$
492
$
523
(a)Includes revenues; earnings from equity investments; operating expenses; (loss) gain on divestitures, net; other income; net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. See “—Overview—GAAP Financial Measures” above.
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending September 30, 2024 and 2023, Certain Items of (i) $(14) million and $19 million for the three-month periods, respectively, and $0 and $(99) million for the nine-month periods, respectively, are associated with our Midstream business and (ii) $1 million for the 2023 three-month period and none for the 2023 nine-month period are associated with our East business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Joint venture throughput is reported at our ownership share. Volumes for acquired assets are included for all periods presented. However, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.
41
Below are the changes in Natural Gas Pipelines Segment EBDA:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Midstream
$
440
$
327
$
1,336
$
1,261
East
631
624
1,998
1,965
West
223
228
701
703
Total Natural Gas Pipelines
$
1,294
$
1,179
$
4,035
$
3,929
Change from prior period
Increase/(Decrease)
Midstream
$
113
$
75
East
$
7
$
33
West
$
(5)
$
(2)
The changes in Natural Gas Pipelines Segment EBDA in the comparable three and nine-month periods ended September 30, 2024 and 2023 are explained by the following discussion:
•The $113 million (35%) and $75 million (6%) increases, respectively, in Midstream resulted from the impacts of (i) non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, which increased revenues and decreased costs of sales for the three-month period and increased costs of sales for the nine-month period; and (ii) a gain on sale of assets in the 2024 nine-month period, all of which we treated as Certain Items.
In addition, Midstream was favorably impacted by (i) our STX Midstream acquired assets partially offset by our divested assets; (ii) increased demand and rates for our services on our Texas intrastate systems and increased sales margin in the three-month period driven by lower prices on costs of sales, partially offset by higher operating expenses; (iii) higher equity earnings from Permian Highway Pipeline LLC driven by an expansion project that went into service in November 2023; and (iv) increased volumes partially offset by higher operating costs on our KinderHawk assets. The year-to-date increase was also partially offset by lower sales margin driven by lower commodity prices and volumes on our Altamont assets.
Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.
•The $7 million (1%) and $33 million (2%) increases, respectively, in East were impacted by expansion projects that went into service in July 2024 and November 2023 on TGP partly offset, to a greater extent in the nine-month period, by higher pipeline maintenance costs. The increases were also partially offset by (i) lower equity earnings from Midcontinent Express Pipeline LLC driven by lower contracted rates; and (ii) timing of revenue recognition associated with a prepaid customer contract on Southern LNG Company, L.L.C. The year-to-date increase was further impacted by increased demand for services on our Stagecoach assets partially offset by an increase in legal reserves on TGP.
•The $5 million (2%) and $2 million (—%) decreases, respectively, in West were primarily due to lower gas sales margin and a decrease in park and loan activity resulting from less favorable spreads on EPNG compared to 2023 and higher pipeline maintenance costs on EPNG and Colorado Interstate Gas Company, L.L.C. These decreases were partially offset by increased demand for services on Cheyenne Plains Gas Pipeline Company, L.L.C. and Wyoming Interstate Company, L.L.C. The year-to-date decrease was also offset by an insurance settlement received by EPNG in the 2024 period.
42
Products Pipelines
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions, except operating statistics)
Revenues
$
711
$
862
$
2,215
$
2,265
Costs of sales
(325)
(471)
(1,047)
(1,172)
Other operating expenses
(125)
(113)
(346)
(326)
Earnings from equity investments
17
32
49
12
Other, net
—
1
—
1
Segment EBDA
278
311
871
780
Certain Items:
Change in fair value of derivative contracts
(1)
2
—
3
Loss on impairment
—
—
—
67
Certain Items(a)
(1)
2
—
70
Adjusted Segment EBDA
$
277
$
313
$
871
$
850
Change from prior period
Increase/(Decrease)
Segment EBDA
$
(33)
$
91
Adjusted Segment EBDA
$
(36)
$
21
Volumetric data(b)
Gasoline(c)
1,003
1,002
978
985
Diesel fuel
376
362
357
349
Jet fuel
297
292
293
285
Total refined product volumes
1,676
1,656
1,628
1,619
Crude and condensate
472
490
474
481
Total delivery volumes (MBbl/d)
2,148
2,146
2,102
2,100
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending September 30, 2024 and 2023, Certain Items of (i) $(1) million and none for the three-month periods, respectively, and none and $1 million for the nine-month periods, respectively, are associated with our Southeast Refined Products business and (ii) $2 million for the 2023 three-month period, and $69 million for the 2023 nine-month period is associated with our Crude and Condensate business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.
43
Below are the changes in Products Pipelines Segment EBDA:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Crude and Condensate
$
64
$
91
$
213
$
183
Southeast Refined Products
61
82
215
216
West Coast Refined Products
153
138
443
381
Total Products Pipelines
$
278
$
311
$
871
$
780
Change from prior period
Increase (Decrease)
Crude and Condensate
$
(27)
$
30
Southeast Refined Products
$
(21)
$
(1)
West Coast Refined Products
$
15
$
62
The changes in Products Pipelines Segment EBDA in the comparable three and nine-month periods ended September 30, 2024 and 2023 are explained by the following discussion:
•The $27 million (30%) decrease and $30 million (16%) increase, respectively, in Crude and Condensate was impacted by:
A $67 million non-cash impairment in the 2023 nine-month period related to our investment in Double Eagle Pipeline LLC, which decreased equity earnings, and which we treated as a Certain Item; and
A decrease in equity earnings from Double Eagle Pipeline LLC, excluding the impairment discussed above, due to unfavorable recontracting and lower commodity prices in our marketing activities on our Bakken Crude assets. Our Crude and Condensate business also had lower revenues with a corresponding decrease in costs of sales, resulting primarily from decreased volumes.
•The $21 million (26%) and $1 million (—%) decreases, respectively, in Southeast Refined Products were driven by unfavorable commodity pricing and the associated impact on inventory at our Transmix processing operations and higher operating costs at our South East Terminals. The year-to-date decrease was favorably impacted by higher butane blending sales volumes at our South East Terminals.
•The $15 million (11%) and $62 million (16%) increases, respectively, in West Coast Refined Products resulted from higher transportation rates and volumes and higher renewable diesel volumes on our Pacific operations.
44
Terminals
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions, except operating statistics)
Revenues
$
498
$
484
$
1,503
$
1,423
Costs of sales
(8)
(11)
(30)
(25)
Other operating expenses
(230)
(219)
(677)
(639)
(Loss) gain on divestitures, net
(1)
—
6
3
Other income
1
—
1
—
Earnings from equity investments
2
2
6
6
Other, net
6
3
9
6
Segment EBDA
$
268
$
259
$
818
$
774
Certain Items:
Change in fair value of derivative contracts
(1)
—
(1)
—
Certain Items(a)
(1)
—
(1)
—
Adjusted Segment EBDA
$
267
$
259
$
817
$
774
Change from prior period
Increase/(Decrease)
Segment EBDA
$
9
$
44
Adjusted Segment EBDA
8
43
Volumetric data(b)
Liquids leasable capacity (MMBbl)
78.6
78.7
78.6
78.7
Liquids utilization %(c)
94.9
%
94.6
%
94.3
%
93.6
%
Bulk transload tonnage (MMtons)
13.4
12.6
41.1
39.7
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2024 Certain Items are associated with our Liquids business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Volumes for facilities divested, idled and/or held for sale are excluded for all periods presented.
(c)The ratio of our tankage capacity in service to liquids leasable capacity.
For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical business grouping and included within the Other group.
45
Below are the changes in Terminals Segment EBDA:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Liquids
$
151
$
148
$
474
$
442
Bulk
66
63
201
197
Jones Act tankers
49
47
139
131
Other
2
1
4
4
Total Terminals
$
268
$
259
$
818
$
774
Change from prior period
Increase/(Decrease)
Liquids
$
3
$
32
Bulk
$
3
$
4
Jones Act tankers
$
2
$
8
Other
$
1
$
—
The changes in Terminals Segment EBDA in the comparable three and nine-month periods ended September 30, 2024 and 2023 are explained by the following discussion:
•The $3 million (2%) and $32 million (7%) increases, respectively, in Liquids were primarily driven by (i) contributions from expansion projects; (ii) higher throughput and ancillary fees; and (iii) higher rates and utilization, primarily at our New York Harbor hub facilities, partially offset by higher labor and maintenance expenses.
•The $3 million (5%) and $4 million (2%) increases, respectively, in Bulk were primarily due to increased volume and related handling and ancillary charges for petroleum coke, fertilizer and steel and, in the nine-month period, coal and soda ash. These increases were partially offset by higher labor and maintenance expenses and demurrage costs incurred at our International Marine Terminal.
•The $2 million (4%) and $8 million (6%) increases, respectively, in Jones Act tankers were primarily due to higher average charter rates and lower operating costs.
46
CO2
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions, except operating statistics)
Revenues
$
319
$
297
$
905
$
896
Costs of sales
(21)
(18)
(61)
(57)
Other operating expenses
(137)
(124)
(377)
(352)
Gain on divestitures, net
—
—
41
1
Earnings from equity investments
9
8
26
22
Segment EBDA
170
163
534
510
Certain Items:
Change in fair value of derivative contracts
(8)
12
(1)
13
Gain on divestitures
—
—
(41)
—
Certain Items(a)
(8)
12
(42)
13
Adjusted Segment EBDA
$
162
$
175
$
492
$
523
Change from prior period
Increase/(Decrease)
Segment EBDA
$
7
$
24
Adjusted Segment EBDA
$
(13)
$
(31)
Volumetric data(b)
SACROC oil production
19.02
19.94
19.01
20.49
Yates oil production
5.90
6.66
6.08
6.65
Other
1.00
1.07
1.04
1.08
Total oil production, net (MBbl/d)(c)
25.92
27.67
26.13
28.22
NGL sales volumes, net (MBbl/d)(c)
8.69
8.98
8.51
8.93
CO2 sales volumes, net (Bcf/d)
0.319
0.311
0.323
0.338
RNG sales volumes (BBtu/d)
10
5
8
5
Realized weighted average oil price ($ per Bbl)
$
68.42
$
67.60
$
68.86
$
67.49
Realized weighted average NGL price ($ per Bbl)
$
32.38
$
30.74
$
29.36
$
31.87
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2024 and 2023 Certain Items are associated with our Oil and Gas Producing activities. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)Volumes for acquired assets are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.
(c)Net of royalties and outside working interests.
47
Below are the changes in CO2 Segment EBDA:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In millions)
Oil and Gas Producing activities
$
96
$
100
$
348
$
353
Source and Transportation activities
48
49
144
137
Subtotal
144
149
492
490
Energy Transition Ventures
26
14
42
20
Total CO2
$
170
$
163
$
534
$
510
Change from prior period
Increase/(Decrease)
Oil and Gas Producing activities
$
(4)
$
(5)
Source and Transportation activities
$
(1)
$
7
Energy Transition Ventures
$
12
$
22
The changes in CO2 Segment EBDA in the comparable three and nine-month periods ended September 30, 2024 and 2023 are explained by the following discussion:
•The $4 million (4%) and $5 million (1%) decreases, respectively, in Oil and Gas Producing activities resulted primarily from (i) lower crude oil volumes; (ii) higher power costs; and (iii) our divested assets. These decreases were partially offset by our acquired assets and higher realized crude oil prices. The year-to-date decrease was further impacted by lower realized NGL prices and volumes.
In addition, Oil and Gas Producing activities were favorably impacted by (i) non-cash mark-to-market derivative hedge contracts, which increased revenues in the three and nine-month periods; and (ii) in the nine-month 2024 period, a $41 million gain on sale of oil and gas producing fields, all of which we treated as Certain Items.
•The $1 million (2%) decrease and $7 million (5%) increase, respectively, in Source and Transportation activities were primarily due to lower realized CO2 sales prices and in the nine-month period, lower CO2 sales volumes, largely offset by reduced volumes due to a refinery outage in 2023 on our Wink pipeline. The year-to-date increase was also impacted by lower integrity maintenance costs in 2024.
•The $12 million (86%) and $22 million (110%) increases, respectively, in Energy Transition Ventures were primarily due to higher RIN sales margin resulting from increased volumes partially offset by higher operating expenses.
We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to a lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of September 30, 2024:
Remaining 2024
2025
2026
2027
2028
Crude Oil(a)
Price ($ per Bbl)
$
66.38
$
65.86
$
65.88
$
65.71
$
64.45
Volume (MBbl/d)
23.40
17.50
12.20
8.10
2.50
NGLs
Price ($ per Bbl)
$
48.60
$
48.99
Volume (MBbl/d)
5.08
1.87
(a)Includes WTI hedges.
48
Liquidity and Capital Resources
General
As of September 30, 2024, we had $108 million of “Cash and cash equivalents,” an increase of $25 million from December 31, 2023. Additionally, as of September 30, 2024, we had borrowing capacity of approximately $3.1 billion under our credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility is more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
We have consistently generated substantial cash flows from operations, providing a source of funds of $4,125 million and $4,169 million in the first nine months of 2024 and 2023, respectively. The period-to-period decrease is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash flow provided by operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our expansion capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any. From time to time, our short-term debt borrowings are used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations.
As of September 30, 2024 and December 31, 2023, approximately $5,097 million (16%) and $8,253 million (26%), respectively, of the principal amount of our debt balances were subject to variable interest rates. The amounts at September 30, 2024 and December 31, 2023 include $4,750 million and $6,200 million, respectively, of interest rate swap agreements and $307 million and $1,989 million, respectively, of commercial paper notes. We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. For more information on our interest rate swaps, see Note 6 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.
Our board of directors declared a quarterly dividend of $0.2875 per share for the third quarter of 2024, a 2% increase over the dividend declared for the third quarter of 2023.
On February 1, 2024, we issued, in a registered offering, two series of senior notes consisting of $1,250 million aggregate principal amount of 5.00% senior notes due 2029 and $1,000 million aggregate principal amount of 5.40% senior notes due 2034 for combined net proceeds of $2,230 million, which were used to repay short-term borrowings, fund maturing debt and for general corporate purposes.
On July 31, 2024, we issued, in a registered offering, two series of senior notes consisting of $500 million aggregate principal amount of 5.10% senior notes due 2029 and $750 million aggregate principal amount of 5.95% senior notes due 2054 and received combined net proceeds of $1,235 million, which were used to repay short-term borrowings, fund maturing debt and for general corporate purposes.
During the nine months ended September 30, 2024, upon maturity, we repaid our 4.15% senior notes, our 4.30% senior notes and our 4.25% senior notes.
Short-term Liquidity
As of September 30, 2024, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $3.5 billion credit facility with an available capacity of approximately $3.1 billion and an associated $3.5 billion commercial paper program. The loan commitments under our credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings and letters of credit reduce borrowings allowed under our $3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations.
As of September 30, 2024, our $1,984 million of short-term debt consisted primarily of senior notes that mature in the next twelve months and outstanding commercial paper borrowings. We intend to fund our debt as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations and/or issuing new long-term debt. Our short-term debt as of December 31, 2023 was $4,049 million.
We had working capital (defined as current assets less current liabilities) deficits of $2,554 million and $4,679 million as of September 30, 2024 and December 31, 2023, respectively. The overall $2,125 million favorable change from year-end 2023
49
was primarily due to (i) a $1,682 million decrease in commercial paper borrowings resulting from refinancing a portion of our short-term borrowings into long-term debt with the issuance of senior notes in 2024; (ii) a $400 million decrease in senior notes that mature in the next twelve months; (iii) a $152 million decrease in accrued interest; and (iv) an $89 million decrease in other current liabilities, primarily related to reductions in bonus accruals and cash margins, partially offset by a $213 million net unfavorable change in our accounts receivables and payables. Generally, our working capital varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts and changes in our cash and cash equivalents as a result of excess cash from operations after payments for investing and financing activities.
Capital Expenditures
We account for our capital expenditures in accordance with GAAP. Additionally, we distinguish between capital expenditures as follows:
Type of Expenditure
Physical Determination of Expenditure
Sustaining capital expenditures
•Investments to maintain the operational integrity and extend the useful life of our assets
Expansion capital expenditures (discretionary capital expenditures)
•Investments to expand throughput or capacity from that which existed immediately prior to the making or acquisition of additions or improvements
Budgeting of maintenance capital expenditures, which we refer to as sustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those sustaining capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional sustaining capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures generally occurs periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion and amortization over the remaining useful lives of the impacted or resulting assets.
Generally, the determination of whether a capital expenditure is classified as sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted in calculating DCF, while those classified as sustaining capital expenditures are.
50
Our capital expenditures for the nine months ended September 30, 2024, and the amount we expect to spend for the remainder of 2024 to sustain our assets and expand our business are as follows:
Nine Months Ended
September 30, 2024
2024 Remaining
Total 2024
(In millions)
Capital expenditures:
Sustaining capital expenditures
$
694
$
318
$
1,012
Expansion capital expenditures
1,183
565
1,748
Accrued capital expenditures, contractor retainage and other
(20)
—
—
Capital expenditures
$
1,857
$
883
$
2,760
Add:
Sustaining capital expenditures of unconsolidated joint ventures(a)
$
132
$
57
$
189
Investments in unconsolidated joint ventures(b)
151
43
194
Less: Consolidated joint venture partners’ sustaining capital expenditures
(7)
(5)
(12)
Less: Consolidated joint venture partners’ expansion capital expenditures
(19)
(5)
(24)
Less: Insurance reimbursement related to a sustaining capital expenditure
(14)
(9)
(23)
Acquisition
60
—
60
Accrued capital expenditures, contractor retainage and other
20
—
—
Total capital investments
$
2,180
$
964
$
3,144
(a)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
(b)Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.
Our capital investments consist of the following:
Nine Months Ended
September 30, 2024
2024 Remaining
Total 2024
(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment
$
694
$
318
$
1,012
Sustaining capital expenditures of unconsolidated joint ventures(a)
132
57
189
Less: Consolidated joint venture partners’ sustaining capital expenditures
(7)
(5)
(12)
Less: Insurance reimbursement related to a sustaining capital expenditure
(14)
(9)
(23)
Total sustaining capital investments
805
361
1,166
Expansion capital investments
Capital expenditures for property, plant and equipment
1,183
565
1,748
Investments in unconsolidated joint ventures(b)
151
43
194
Less: Consolidated joint venture partners’ expansion capital expenditures
(19)
(5)
(24)
Acquisition
60
—
60
Total expansion capital investments
1,375
603
1,978
Total capital investments
$
2,180
$
964
$
3,144
(a)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
51
(b)Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.
Impact of Regulation
The trend toward increasingly stringent regulations creates uncertainty regarding our capital and operating expenditure requirements over the longer term. For example, on June 5, 2023, the EPA’s final rule known as the “Good Neighbor Plan” (the Plan) was published in the Federal Register. As a precursor to the Plan, the EPA disapproved 21 State Implementation Plans (SIPs) and found that two other states had failed to submit SIPs under the interstate transport (Good Neighbor) provisions of the Clean Air Act for the 2015 Ozone NAAQS. The Plan imposes prescriptive emission standards for several sectors, including new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA subsequently proposed to disapprove five additional state SIPs and apply the Plan or portions of the Plan to sources in those states, including one state that would affect our operations.
Multiple legal challenges have already been filed, including by us. See Note 10, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements. While we are unable to predict whether any legal challenges will result in changes to the Plan or how those changes, if any, would impact us, we believe that the EPA’s disapprovals of the SIPs were improper, that the Plan is deeply flawed and that numerous and substantial bases for challenging the Plan exist as evidenced by the U.S. Supreme Court ruling on June 27, 2024 that enforcement of the Plan shall be stayed pending a decision on the merits of the case by the U.S. Court of Appeals for the District of Columbia Circuit and any subsequent timely appeal to the Supreme Court. In reaching its decision, the Supreme Court found that the parties challenging the Plan are likely to prevail on their argument that the Plan was not reasonably explained, that the EPA failed to supply a satisfactory explanation for its action, and that the EPA ignored an important aspect of the problem it was attempting to solve by promulgating the Plan. The Supreme Court did not analyze all of the parties’ legal challenges to the Plan. In addition to the Supreme Court stay, several states in which we have affected assets had previously appealed the EPA’s disapprovals of SIPs and obtained stays of those disapprovals pending appeal. The criteria for those stays pending appeal include a requirement that the applicant show likelihood of success on the merits. Stays pending appeal were granted with respect to the EPA’s disapprovals of SIPs submitted by Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah and West Virginia. The EPA has no legal basis to enforce the Plan in any state while the Supreme Court stay remains in place, and in many of those states there are also stays of the underlying SIP disapprovals, which also serve to prevent enforcement of the Plan. In response to the stays of the EPA’s SIP disapprovals, the EPA published interim final rules on July 31, 2023, and September 29, 2023, acknowledging that the Plan requirements in those states were suspended and indicating that the Plan compliance deadlines in those states may be extended. The guidance afforded by the EPA in the interim final rules is uncertain so we filed petitions seeking review of the interim final rules in the U.S. Court of Appeals for the District of Columbia Circuit. On February 1, 2024, the Court ordered these cases be held in abeyance pending further order of the Court.
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. The Plan, as initially published by EPA, would require that all impacted engines meet the stringent emission limits by May 1, 2026, unless compliance schedule extensions are granted by the EPA, which would need to be supported by us and approved by the EPA on an engine-by-engine basis. If the Plan ultimately were to take effect in its current form (including full compliance by a revised compliance deadline accounting for the stays, and assuming failure of all challenges to SIP disapprovals and the Plan), we currently estimate that it would have a material impact on us, including estimated costs necessary to comply with the Plan ranging from $1.5 billion to $1.8 billion (including costs for joint ventures that we operate, net to our interests in such joint ventures), potential shortages of equipment resulting in our inability to comply with the Plan, and operational disruptions. Given the extensive pending litigation, impacts of the Plan are difficult to predict. The outcomes of these numerous lawsuits may significantly decrease our exposure. In addition, we would seek to mitigate the impacts and to recover expenditures through adjustments to our rates on our regulated assets where available.
The cost estimates discussed above are preliminary, based on a number of assumptions and subject to significant variation, including outside of the ranges provided. Costs are assumed based on the average cost incurred historically for a typical retrofit of an average engine. These estimates reflect only the anticipated upgrades that would need to be performed (and in the case of joint ventures, only on assets that we operate) and do not take into account potential complications such as additional maintenance requirements that may be identified during the upgrade process.
52
Off Balance Sheet Arrangements
There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2023 in our 2023 Form 10-K.
Commitments for the purchase of property, plant and equipment as of September 30, 2024 and December 31, 2023 were $663 million and $469 million, respectively. The increase of $194 million was primarily driven by an overall increase of capital commitments related to our business segments.
Cash Flows
The following table summarizes our net cash flows provided by (used in) operating, investing and financing activities between 2024 and 2023.
Nine Months Ended September 30,
2024
2023
Changes
(In millions)
Net Cash Provided by (Used in)
Operating activities
$
4,125
$
4,169
$
(44)
Investing activities
(1,858)
(1,733)
(125)
Financing activities
(2,230)
(3,133)
903
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits
$
37
$
(697)
$
734
Operating Activities
Net cash provided by operating activities was relatively flat for the comparable nine-month periods ended September 30, 2024 and 2023.
Investing Activities
$125 million more cash used in investing activities in the comparable nine-month periods ended September 30, 2024 and 2023 is explained by the following discussion:
•a $168 million increase in capital expenditures primarily driven by expansion projects in our Natural Gas Pipelines business segment; partially offset by
•an $86 million decrease in cash used for contributions to equity investees driven primarily by lower contributions to Permian Highway Pipeline LLC and Greenholly Gathering Pipeline LLC, partially offset by higher contributions to SNG in the 2024 period compared to the 2023 period.
Financing Activities
$903 million less cash used in financing activities in the comparable nine-month periods ended September 30, 2024 and 2023 is explained by the following discussion:
•a $531 million decrease in cash used related to debt activity as a result of lower net payments; and
•a $383 million decrease in cash used for share repurchases under our share buy-back program.
53
Dividends
We expect to declare dividends of $1.15 per share on our stock for 2024. The table below reflects our 2024 dividends declared:
Three months ended
Total quarterly dividend per share for the period
Date of declaration
Date of record
Date of dividend
March 31, 2024
$
0.2875
April 17, 2024
April 30, 2024
May 15, 2024
June 30, 2024
0.2875
July 17, 2024
July 31, 2024
August 15, 2024
September 30, 2024
0.2875
October 16, 2024
October 31, 2024
November 15, 2024
The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—Risks Related to Ownership of Our Capital Stock—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2023 Form 10-K. All of these matters will be taken into consideration by our board of directors when declaring dividends.
Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.
54
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or a Subsidiary Issuer is in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. Also, see Exhibit 10.1 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of September 30, 2024.”
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors (referred to as “affiliates”), are presented separately in the accompanying supplemental summarized combined financial information.
Excluding fair value adjustments, as of September 30, 2024 and December 31, 2023, the Obligated Group had $31,067 million and $31,167 million, respectively, of Guaranteed Notes outstanding.
Summarized combined balance sheet and income statement information for the Obligated Group follows:
Summarized Combined Balance Sheet Information
September 30, 2024
December 31, 2023
(In millions)
Current assets
$
1,888
$
2,246
Current assets - affiliates
709
760
Noncurrent assets
63,082
62,877
Noncurrent assets - affiliates
825
903
Total Assets
$
66,504
$
66,786
Current liabilities
$
4,360
$
6,907
Current liabilities - affiliates
734
734
Noncurrent liabilities
34,021
31,681
Noncurrent liabilities - affiliates
1,535
1,306
Total Liabilities
40,650
40,628
Kinder Morgan, Inc.’s stockholders’ equity
25,854
26,158
Total Liabilities and Stockholders’ Equity
$
66,504
$
66,786
Summarized Combined Income Statement Information
Three Months Ended September 30, 2024
Nine Months Ended September 30, 2024
(In millions)
Revenues
$
3,328
$
10,040
Operating income
880
2,863
Net income
509
1,589
55
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2023, in Part II, Item 7A in our 2023 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 6 “Risk Management” to our consolidated financial statements.
Item 4. Controls and Procedures.
As of September 30, 2024, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2024 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.
Item 1A. Risk Factors.
There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2023 Form 10-K. For more information on our risk management activities, refer to Part I, Item 1, Note 6 “Risk Management” to our consolidated financial statements.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Except for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Act. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank Act for the quarter ended September 30, 2024.
Item 5. Other Information.
Rule 10b5-1 Plans
On August 2, 2024, Thomas A. Martin, President of KMI, adopted a trading plan that is intended to satisfy the affirmative defense of Rule 10b5-1(c) providing for the sale of up to 145,121 shares. The expiration date for Mr. Martin’s plan is June 30, 2025.
Interactive data files (formatted as Inline XBRL).
104
Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101).
57
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
KINDER MORGAN, INC.
Registrant
Date:
October 18, 2024
By:
/s/ David P. Michels
David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)
