(Exact name of registrant as specified in its charter)
Delaware
80-0682103
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
1001 Louisiana Street, Suite 1000, Houston, Texas77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713-369-9000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Class P Common Stock
KMI
New York Stock Exchange
2.250% Senior Notes due 2027
KMI 27 A
New York Stock Exchange
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yesþ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerþ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ
As of October 19, 2023, the registrant had 2,222,773,933 shares of Class P common stock outstanding.
Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries
SNG
=
Southern Natural Gas Company, L.L.C.
TGP
=
Tennessee Gas Pipeline Company, L.L.C.
KMLT
=
Kinder Morgan Liquid Terminals, LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d
=
per day
GAAP
=
U.S. Generally Accepted Accounting Principles
Bbl
=
barrels
LLC
=
limited liability company
BBtu
=
billion British Thermal Units
LIBOR
=
London Interbank Offered Rate
Bcf
=
billion cubic feet
MBbl
=
thousand barrels
CERCLA
=
Comprehensive Environmental Response, Compensation and Liability Act
MMBbl
=
million barrels
MMtons
=
million tons
CO2
=
carbon dioxide or our CO2 business segment
NGL
=
natural gas liquids
DCF
=
distributable cash flow
NYMEX
=
New York Mercantile Exchange
DD&A
=
depreciation, depletion and amortization
OTC
=
over-the-counter
EBDA
=
earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments
PHMSA
=
Pipeline and Hazardous Materials Safety Administration
RNG
=
Renewable natural gas
EBITDA
=
earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investments
ROU
=
Right-of-Use
U.S.
=
United States of America
EPA
=
U.S. Environmental Protection Agency
WTI
=
West Texas Intermediate
FASB
=
Financial Accounting Standards Board
2
Information Regarding Forward-Looking Statements
This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, our anticipated dividends and capital projects, including expected completion timing and benefits of those projects.
Important factors that could cause actual results to differ materially from those expressed in or implied by the forward-looking statements in this report include: the timing and extent of changes in the supply of and demand for the products we transport and handle; commodity prices; the outcomes of challenges to new regulations; our ability to mitigate the impacts of and recover expenditures made in respect of new regulations; and the other risks and uncertainties described in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Part II, Item 1A. “Risk Factors” in this report, as well as “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2022 (except to the extent such information is modified or superseded by information in subsequent reports).
You should keep these risk factors in mind when considering forward-looking statements. These risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts, unaudited)
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Revenues
Services
$
2,087
$
2,028
$
6,201
$
6,089
Commodity sales
1,785
3,108
4,991
8,416
Other
35
41
104
116
Total Revenues
3,907
5,177
11,296
14,621
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)
1,405
2,717
3,591
7,294
Operations and maintenance
738
712
2,062
1,960
Depreciation, depletion and amortization
561
551
1,683
1,632
General and administrative
162
162
497
470
Taxes, other than income taxes
106
113
319
340
Gain on divestitures and impairments, net
(3)
(9)
(16)
(30)
Other income, net
—
—
(2)
(6)
Total Operating Costs, Expenses and Other
2,969
4,246
8,134
11,660
Operating Income
938
931
3,162
2,961
Other Income (Expense)
Earnings from equity investments
234
195
607
564
Amortization of excess cost of equity investments
(18)
(19)
(54)
(57)
Interest, net
(457)
(399)
(1,345)
(1,087)
Other, net
3
21
7
63
Total Other Expense
(238)
(202)
(785)
(517)
Income Before Income Taxes
700
729
2,377
2,444
Income Tax Expense
(145)
(134)
(509)
(512)
Net Income
555
595
1,868
1,932
Net Income Attributable to Noncontrolling Interests
(23)
(19)
(71)
(54)
Net Income Attributable to Kinder Morgan, Inc.
$
532
$
576
$
1,797
$
1,878
Class P Common Stock
Basic and Diluted Earnings Per Share
$
0.24
$
0.25
$
0.80
$
0.83
Basic and Diluted Weighted Average Shares Outstanding
2,230
2,253
2,238
2,262
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,
2023
2022
2023
2022
Net income
$
555
$
595
$
1,868
$
1,932
Other comprehensive (loss) income, net of tax
Net unrealized (loss) gain from derivative instruments (net of taxes of $45, $(40), $(1) and $109, respectively)
(153)
123
2
(366)
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $(6), $(29), $9 and $(118), respectively)
22
104
(29)
396
Benefit plan adjustments (net of taxes of $(2), $(1), $(4) and $(6), respectively)
3
2
11
18
Total other comprehensive (loss) income
(128)
229
(16)
48
Comprehensive income
427
824
1,852
1,980
Comprehensive income attributable to noncontrolling interests
(23)
(19)
(71)
(54)
Comprehensive income attributable to KMI
$
404
$
805
$
1,781
$
1,926
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, 2023
December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents
$
80
$
745
Restricted deposits
17
49
Accounts receivable
1,502
1,840
Fair value of derivative contracts
79
231
Inventories
565
634
Other current assets
190
304
Total current assets
2,433
3,803
Property, plant and equipment, net
35,944
35,599
Investments
7,674
7,653
Goodwill
19,965
19,965
Other intangibles, net
1,652
1,809
Deferred charges and other assets
1,194
1,249
Total Assets
$
68,862
$
70,078
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt
$
3,130
$
3,385
Accounts payable
1,430
1,444
Accrued interest
387
515
Fair value of derivative contracts
346
465
Other current liabilities
958
1,121
Total current liabilities
6,251
6,930
Long-term liabilities and deferred credits
Long-term debt
Outstanding
27,863
28,288
Debt fair value adjustments
8
115
Total long-term debt
27,871
28,403
Deferred income taxes
1,112
623
Other long-term liabilities and deferred credits
2,047
2,008
Total long-term liabilities and deferred credits
31,030
31,034
Total Liabilities
37,281
37,964
Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,227,817,827and 2,247,681,626 shares, respectively, issued and outstanding
22
22
Additional paid-in capital
41,306
41,673
Accumulated deficit
(10,652)
(10,551)
Accumulated other comprehensive loss
(418)
(402)
Total Kinder Morgan, Inc.’s stockholders’ equity
30,258
30,742
Noncontrolling interests
1,323
1,372
Total Stockholders’ Equity
31,581
32,114
Total Liabilities and Stockholders’ Equity
$
68,862
$
70,078
The accompanying notes are an integral part of these consolidated financial statements.
6
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
2023
2022
Cash Flows From Operating Activities
Net income
$
1,868
$
1,932
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization
1,683
1,632
Deferred income taxes
495
499
Amortization of excess cost of equity investments
54
57
Change in fair value of derivative contracts
(93)
45
Gain on divestitures and impairments, net
(16)
(30)
Earnings from equity investments
(607)
(564)
Distributions from equity investment earnings
572
548
Changes in components of working capital
Accounts receivable
351
(260)
Inventories
130
(165)
Other current assets
89
(60)
Accounts payable
(115)
347
Accrued interest, net of interest rate swaps
(131)
(160)
Other current liabilities
(84)
29
Rate reparations, refunds and other litigation reserve adjustments
(21)
(189)
Other, net
(6)
(98)
Net Cash Provided by Operating Activities
4,169
3,563
Cash Flows From Investing Activities
Acquisition of assets, net of cash acquired
(13)
(488)
Capital expenditures
(1,689)
(1,144)
Contributions to investments
(179)
(60)
Distributions from equity investments in excess of cumulative earnings
166
126
Other, net
(18)
21
Net Cash Used in Investing Activities
(1,733)
(1,545)
Cash Flows From Financing Activities
Issuances of debt
4,373
8,898
Payments of debt
(5,051)
(9,569)
Debt issue costs
(18)
(21)
Dividends
(1,898)
(1,876)
Repurchases of shares
(390)
(333)
Proceeds from sale of noncontrolling interests
—
557
Contributions from noncontrolling interests
1
1
Distributions to noncontrolling interests
(121)
(85)
Other, net
(29)
(14)
Net Cash Used in Financing Activities
(3,133)
(2,442)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits
(697)
(424)
Cash, Cash Equivalents and Restricted Deposits, beginning of period
794
1,147
Cash, Cash Equivalents and Restricted Deposits, end of period
$
97
$
723
7
KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
2023
2022
Cash and Cash Equivalents, beginning of period
$
745
$
1,140
Restricted Deposits, beginning of period
49
7
Cash, Cash Equivalents and Restricted Deposits, beginning of period
794
1,147
Cash and Cash Equivalents, end of period
80
483
Restricted Deposits, end of period
17
240
Cash, Cash Equivalents and Restricted Deposits, end of period
97
723
Net Decrease in Cash, Cash Equivalents and Restricted Deposits
$
(697)
$
(424)
Non-cash Investing and Financing Activities
Assets contributed to equity investment
$
16
$
—
ROU assets and operating lease obligations recognized including adjustments
38
19
Increase in property, plant and equipment from both accruals and contractor retainage
104
23
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)
1,505
1,278
Cash paid during the period for income taxes, net
10
12
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, 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 June 30, 2022
2,257
$
23
$
41,654
$
(10,540)
$
(592)
$
30,545
$
1,080
$
31,625
Repurchases of shares
(9)
(160)
(160)
(160)
Restricted shares
2
5
5
5
Net income
576
576
19
595
Dividends
(629)
(629)
(629)
Distributions
—
(32)
(32)
Contributions
—
1
1
Impact of change in ownership interest in subsidiary
190
190
311
501
Other comprehensive income
229
229
229
Balance at September 30, 2022
2,250
$
23
$
41,689
$
(10,593)
$
(363)
$
30,756
$
1,379
$
32,135
The accompanying notes are an integral part of these consolidated financial statements.
9
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)
(In millions, unaudited)
Common stock
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Stockholders’ equity attributable to KMI
Non- controlling interests
Total
Issued shares
Par value
Balance at December 31, 2022
2,248
$
22
$
41,673
$
(10,551)
$
(402)
$
30,742
$
1,372
$
32,114
Repurchases of shares
(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
Common stock
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Stockholders’ equity attributable to KMI
Non- controlling interests
Total
Issued shares
Par value
Balance at December 31, 2021
2,267
$
23
$
41,806
$
(10,595)
$
(411)
$
30,823
$
1,098
$
31,921
Impact of adoption of ASU 2020-06 (Note 4)
(11)
(11)
(11)
Balance at January 1, 2022
2,267
23
41,795
(10,595)
(411)
30,812
1,098
31,910
Repurchases of shares
(19)
(333)
(333)
(333)
EP Trust I Preferred security conversions
1
1
1
Restricted shares
2
36
36
36
Net income
1,878
1,878
54
1,932
Dividends
(1,876)
(1,876)
(1,876)
Distributions
—
(85)
(85)
Contributions
—
1
1
Impact of change in ownership interest in subsidiary
190
190
311
501
Other comprehensive income
48
48
48
Balance at September 30, 2022
2,250
$
23
$
41,689
$
(10,593)
$
(363)
$
30,756
$
1,379
$
32,135
The accompanying notes are an integral part of these consolidated financial statements.
10
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 82,000 miles of pipelines, 140 terminals, 700 Bcf of working natural gas storage capacity and 5.4 Bcf per year of RNG generation capacity. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.
Basis of Presentation
General
Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation.
In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2022 Form 10-K.
The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.
Goodwill
In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals and (vii) Energy Transition Ventures.
The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding future cash flows based on production growth assumptions, terminal values and discount rates. Changes to any one or a combination of these factors would result in a change to the reporting unit fair values, which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.
The results of our May 31, 2023 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value, with our Terminals reporting unit’s fair value in excess of its carrying value by less than 10% which was impacted by a decline in market multiples.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions
11
over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.
The following table sets forth the allocation of net income available to shareholders of Class P common stock and participating securities:
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions, except per share amounts)
Net Income Available to Stockholders
$
532
$
576
$
1,797
$
1,878
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)
(4)
(4)
(11)
(9)
Net Income Allocated to Class P Stockholders
$
528
$
572
$
1,786
$
1,869
Basic Weighted Average Shares Outstanding
2,230
2,253
2,238
2,262
Basic Earnings Per Share
$
0.24
$
0.25
$
0.80
$
0.83
(a)As of September 30, 2023, there were 13 million restricted stock awards outstanding.
The following table presents the maximum number of potential common stock equivalents which are antidilutive and accordingly are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions on a weighted average basis)
Unvested restricted stock awards
13
13
13
13
Convertible trust preferred securities
3
3
3
3
2. Losses on Impairments
Impairments
During the first quarter of 2023, we recognized an impairment of $67 million related to our investment in Double Eagle Pipeline LLC (Double Eagle). The impairment was driven by lower expected renewal rates on contracts that expire in the second half of 2023. The impairment is recognized on our accompanying consolidated statement of income for the nine months ended September 30, 2023 within “Earnings from equity investments.” Our investment in Double Eagle and associated earnings is included within our Products Pipelines business segment.
Ruby Chapter 11 Bankruptcy
On January 13, 2023, the bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby, which involved payment of Ruby’s outstanding senior notes with the proceeds from the sale of Ruby to Tallgrass, a settlement by KMI and Pembina of certain potential causes of action relating to the bankruptcy, and cash on hand. Our payment to the bankruptcy estate, net of payments received in respect of a long-term subordinated note receivable from Ruby, was approximately $28.5 million which was accrued for as of December 31, 2022. Consummation of the settlement and the sale of Ruby to Tallgrass occurred on January 13, 2023. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021.
12
3. Debt
The following table provides information on the principal amount of our outstanding debt balances:
September 30, 2023
December 31, 2022
(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2027
$
—
$
—
$500 million credit facility due November 16, 2023
—
—
Commercial paper notes(a)
320
—
Current portion of senior notes
3.15% due January 2023
—
1,000
Floating rate, due January 2023
—
250
3.45% due February 2023
—
625
3.50% due September 2023
—
600
5.625% due November 2023
750
750
4.15% due February 2024
650
—
4.30% due May 2024
600
—
4.25% due September 2024
650
—
Trust I preferred securities, 4.75%, due March 2028(b)
111
111
Current portion of other debt
49
49
Total current portion of debt
3,130
3,385
Long-term debt (excluding current portion)
Senior notes
27,232
27,638
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035
316
330
Trust I preferred securities, 4.75%, due March 2028
109
109
Other
206
211
Total long-term debt
27,863
28,288
Total debt(c)
$
30,993
$
31,673
(a)Weighted average interest rate on borrowings at September 30, 2023 was 5.50%.
(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, 2023 and December 31, 2022, increased our total debt balances by $8 million and $115 million, respectively.
We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.
On January 31, 2023, we issued in a registered offering $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.
Credit Facilities and Restrictive Covenants
As of September 30, 2023, we had no borrowings outstanding under our credit facilities, $320 million borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of September 30, 2023 was $3.6 billion. For the period ended September 30, 2023, we were in compliance with all required covenants.
13
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances are disclosed below:
September 30, 2023
December 31, 2022
Carrying value
Estimated fair value(a)
Carrying value
Estimated fair value(a)
(In millions)
Total debt
$
31,001
$
28,451
$
31,788
$
30,070
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $199 million and $195 million as of September 30, 2023 and December 31, 2022, respectively.
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2023 and December 31, 2022.
4. Stockholders’ Equity
Class P Common Stock
On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion. During the nine months ended September 30, 2023, we repurchased 23 million of our shares for $390 million at an average price of $16.62 per share. Subsequent to September 30, 2023 and through October 19, 2023, we repurchased 5 million shares for $83 million at an average price of $16.38 per share. All shares we have repurchased are canceled and are no longer outstanding.
Dividends
The following table provides information about our per share dividends:
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
Per share cash dividend declared for the period
$
0.2825
$
0.2775
$
0.8475
$
0.8325
Per share cash dividend paid in the period
0.2825
0.2775
0.8425
0.825
On October 18, 2023, our board of directors declared a cash dividend of $0.2825 per share for the quarterly period ended September 30, 2023, which is payable on November 15, 2023 to shareholders of record as of the close of business on October 31, 2023.
Adoption of Accounting Pronouncement
On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in Subtopic 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the nine months ended September 30, 2022.
14
Accumulated Other Comprehensive Loss
Changes in the components of our “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as follows:
Net unrealized gains/(losses) on cash flow hedge derivatives
Pension and other postretirement liability adjustments
Total accumulated other comprehensive loss
(In millions)
Balance as of December 31, 2022
$
(164)
$
(238)
$
(402)
Other comprehensive gain before reclassifications
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)
Net unrealized gains/(losses) on cash flow hedge derivatives
Pension and other postretirement liability adjustments
Total accumulated other comprehensive loss
(In millions)
Balance as of December 31, 2021
$
(172)
$
(239)
$
(411)
Other comprehensive (loss) gain before reclassifications
(366)
18
(348)
Loss reclassified from accumulated other comprehensive loss
396
—
396
Net current-period change in accumulated other comprehensive loss
30
18
48
Balance as of September 30, 2022
$
(142)
$
(221)
$
(363)
5. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.
Energy Commodity Price Risk Management
As of September 30, 2023, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price
(18.2)
MMBbl
Crude oil basis
(1.1)
MMBbl
Natural gas fixed price
(56.2)
Bcf
Natural gas basis
(48.0)
Bcf
NGL fixed price
(0.8)
MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price
(1.6)
MMBbl
Crude oil basis
(6.7)
MMBbl
Natural gas fixed price
(6.9)
Bcf
Natural gas basis
(98.3)
Bcf
NGL fixed price
(1.0)
MMBbl
15
As of September 30, 2023, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2027.
Interest Rate Risk Management
We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2023:
Notional amount
Accounting treatment
Maximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)
$
6,800
Fair value hedge
March 2035
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts
3,445
Mark-to-Market
December 2023
(a)The principal amount of hedged senior notes consisted of $2,050 million included in “Current portion of debt” and $4,750 million included in “Long-term debt” on our accompanying consolidated balance sheet.
(b)During the nine months ended September 30, 2023, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 10 for further information on Topic 848.
Foreign Currency Risk Management
We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, 2023:
Notional amount
Accounting treatment
Maximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)
$
543
Cash flow hedge
March 2027
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.
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, 2023
December 31, 2022
September 30, 2023
December 31, 2022
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
$
38
$
150
$
(153)
$
(156)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
1
6
(87)
(91)
Subtotal
39
156
(240)
(247)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
—
—
(153)
(144)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
19
39
(288)
(261)
Subtotal
19
39
(441)
(405)
Foreign currency contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
—
—
(6)
(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
—
—
(23)
(32)
Subtotal
—
—
(29)
(35)
Total
58
195
(710)
(687)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
33
80
(34)
(162)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
7
23
(1)
(19)
Subtotal
40
103
(35)
(181)
Interest rate contracts
Fair value of derivative contracts/(Fair value of derivative contracts)
8
1
—
—
Total
48
104
(35)
(181)
Total derivatives
$
106
$
299
$
(745)
$
(868)
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, 2023
Energy commodity derivative contracts(b)
$
40
$
39
$
—
$
79
$
(25)
$
—
$
54
Interest rate contracts
—
27
—
27
—
—
27
As of December 31, 2022
Energy commodity derivative contracts(b)
$
115
$
144
$
—
$
259
$
(186)
$
—
$
73
Interest rate contracts
—
40
—
40
—
—
40
Balance sheet liability fair value measurements by level
Contracts available for netting
Cash collateral posted(a)
Level 1
Level 2
Level 3
Gross amount
Net amount
(In millions)
As of September 30, 2023
Energy commodity derivative contracts(b)
$
(3)
$
(272)
$
—
$
(275)
$
25
$
(52)
$
(302)
Interest rate contracts
—
(442)
—
(442)
—
—
(442)
Foreign currency contracts
—
(28)
—
(28)
—
—
(28)
As of December 31, 2022
Energy commodity derivative contracts(b)
$
(23)
$
(405)
$
—
$
(428)
$
186
$
(30)
$
(272)
Interest rate contracts
—
(405)
—
(405)
—
—
(405)
Foreign currency contracts
—
(35)
—
(35)
—
—
(35)
(a)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.
(b)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
The following tables summarize the pre-tax impact of our derivative contracts on our accompanying consolidated statements of income and comprehensive income:
Derivatives in fair value hedging relationships
Location
Gain/(loss) recognized in income on derivative and related hedged item
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
Interest rate contracts
Interest, net
$
(74)
$
(278)
$
(55)
$
(754)
Hedged fixed rate debt(a)
Interest, net
$
77
$
279
$
59
$
761
(a)As of September 30, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $426 million 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(b)
Three Months Ended September 30,
Three Months Ended September 30,
2023
2022
2023
2022
(In millions)
(In millions)
Energy commodity derivative contracts
$
(188)
$
195
Revenues—Commodity sales
$
16
$
(116)
Costs of sales
(27)
17
Foreign currency contracts
(10)
(32)
Other, net
(17)
(34)
Total
$
(198)
$
163
Total
$
(28)
$
(133)
Derivatives in cash flow hedging relationships
Gain/(loss) recognized in OCI on derivative(a)
Location
Gain/(loss) reclassified from Accumulated OCI into income(b)
Nine Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
(In millions)
Energy commodity derivative contracts
$
(3)
$
(375)
Revenues—Commodity sales
$
98
$
(433)
Costs of sales
(54)
34
Interest rate contracts
—
7
Interest, net
—
—
Foreign currency contracts
6
(107)
Other, net
(6)
(115)
Total
$
3
$
(475)
Total
$
38
$
(514)
(a)We expect to reclassify approximately $145 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2023 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the three and nine months ended September 30, 2022, we recognized approximate gains of $29 million and $34 million associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
Derivatives not designated as accounting hedges
Location
Gain/(loss) recognized in income on derivatives
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$
(21)
$
44
$
11
$
18
Costs of sales
(4)
(30)
116
(129)
Earnings from equity investments
—
(7)
1
(11)
Interest rate contracts
Interest, net
(6)
(20)
6
28
Total(a)
$
(31)
$
(13)
$
134
$
(94)
(a)The three and nine months ended September 30, 2023 amounts include approximate gains of $9 million and $45 million, respectively, and the three and nine months ended September 30, 2022 amounts include approximate losses of $19 million and $39 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, 2023 and December 31, 2022, we had
19
no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2023 and December 31, 2022, we had cash margins of $28 million and $1 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The cash margin balance at September 30, 2023 represents our initial margin requirements of $24 million and variation margin requirements of $52 million posted by our counterparties. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of September 30, 2023, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $187 million of additional collateral.
6. 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, 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
20
Three Months Ended September 30, 2022
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
845
$
57
$
199
$
—
$
—
$
1,101
Fee-based services
243
247
106
11
—
607
Total services
1,088
304
305
11
—
1,708
Commodity sales
Natural gas sales
1,902
—
—
24
(7)
1,919
Product sales
389
511
11
353
(1)
1,263
Total commodity sales
2,291
511
11
377
(8)
3,182
Total revenues from contracts with customers
3,379
815
316
388
(8)
4,890
Other revenues(c)
Leasing services(d)
120
51
141
16
—
328
Derivatives adjustments on commodity sales
(12)
—
—
(60)
—
(72)
Other
18
6
—
7
—
31
Total other revenues
126
57
141
(37)
—
287
Total revenues
$
3,505
$
872
$
457
$
351
$
(8)
$
5,177
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
21
Nine Months Ended September 30, 2022
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
2,633
$
176
$
585
$
1
$
(2)
$
3,393
Fee-based services
690
723
300
35
—
1,748
Total services
3,323
899
885
36
(2)
5,141
Commodity sales
Natural gas sales
4,938
—
—
68
(17)
4,989
Product sales
1,141
1,577
22
1,105
(4)
3,841
Total commodity sales
6,079
1,577
22
1,173
(21)
8,830
Total revenues from contracts with customers
9,402
2,476
907
1,209
(23)
13,971
Other revenues(c)
Leasing services(d)
355
144
430
44
—
973
Derivatives adjustments on commodity sales
(132)
(3)
—
(280)
—
(415)
Other
49
17
—
26
—
92
Total other revenues
272
158
430
(210)
—
650
Total revenues
$
9,674
$
2,634
$
1,337
$
999
$
(23)
$
14,621
(a)Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as “Fee-based services.”
(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.
Contract Balances
As of September 30, 2023 and December 31, 2022, our contract asset balances were $43 million and $33 million, respectively. Of the contract asset balance at December 31, 2022, $21 million was transferred to accounts receivable during the nine months ended September 30, 2023. As of September 30, 2023 and December 31, 2022, our contract liability balances were $221 million and $204 million, respectively. Of the contract liability balance at December 31, 2022, $61 million was recognized as revenue during the nine months ended September 30, 2023.
Subsequent to September 30, 2023, we entered into an agreement with a customer to prepay certain fixed reservation charges under long-term transportation and terminalling contracts. We anticipate receiving $843 million in the fourth quarter of 2023 as part of this agreement. The prepayment, which relates to contracts expiring from 2035 to 2040, was discounted to present value at a rate that is attractive relative to our cost of issuing long-term debt.
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, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods:
Year
Estimated Revenue
(In millions)
Three months ended December 31, 2023
$
1,167
2024
4,153
2025
3,423
2026
2,933
2027
2,462
Thereafter
14,057
Total
$
28,195
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.
7. Reportable Segments
Financial information by segment follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers
$
2,268
$
3,497
$
6,718
$
9,653
Intersegment revenues
5
8
12
21
Products Pipelines
862
872
2,265
2,634
Terminals
Revenues from external customers
483
457
1,420
1,335
Intersegment revenues
1
—
3
2
CO2
Revenues from external customers
294
351
893
999
Intersegment revenues
3
—
3
—
Corporate and intersegment eliminations
(9)
(8)
(18)
(23)
Total consolidated revenues
$
3,907
$
5,177
$
11,296
$
14,621
23
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
Segment EBDA(a)
Natural Gas Pipelines
$
1,179
$
1,135
$
3,929
$
3,453
Products Pipelines
311
257
780
855
Terminals
259
240
774
731
CO2
163
215
510
619
Total Segment EBDA
1,912
1,847
5,993
5,658
DD&A
(561)
(551)
(1,683)
(1,632)
Amortization of excess cost of equity investments
(18)
(19)
(54)
(57)
General and administrative and corporate charges
(176)
(149)
(534)
(438)
Interest, net
(457)
(399)
(1,345)
(1,087)
Income tax expense
(145)
(134)
(509)
(512)
Total consolidated net income
$
555
$
595
$
1,868
$
1,932
September 30, 2023
December 31, 2022
(In millions)
Assets
Natural Gas Pipelines
$
47,642
$
47,978
Products Pipelines
8,923
8,985
Terminals
8,250
8,357
CO2
3,459
3,449
Corporate assets(b)
588
1,309
Total consolidated assets
$
68,862
$
70,078
(a)Includes revenues, earnings from equity investments, operating expenses, gain on divestitures and impairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.
8. Income Taxes
Income tax expense included on our accompanying consolidated statements of income is as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions, except percentages)
Income tax expense
$
145
$
134
$
509
$
512
Effective tax rate
20.7
%
18.4
%
21.4
%
20.9
%
The effective tax rate for the three months ended September 30, 2023 is lower than the statutory federal rate of 21% primarily due to 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 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.
The effective tax rates for the three and nine months ended September 30, 2022 are lower than the statutory federal rate of 21% primarily due to the recognition of additional 2021 enhanced oil recovery credits from our initial estimate, the adjustment
24
to the deferred tax liability as a result of the reduction in the state tax rate and dividend-received deductions from our investments in Citrus, NGPL Holdings and PPL, partially offset by state income taxes.
9. Litigation and Environmental
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have 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
On September 28, 2018, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. on December 10, 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). The suit to enforce the Guarantee against Eni S.p.A. was filed after an arbitration tribunal delivered an award on June 29, 2018 which called for the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response to GLNG’s lawsuit to enforce the Guarantee, Eni S.p.A. filed counterclaims and other claims based on the terminal use agreement and a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing counterclaims and other claims asserted by Eni S.p.A sought unspecified damages and involved the same substantive allegations which were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A. On January 4, 2022, the trial court granted Eni S.p.A’s motion for summary judgment on GLNG’s claims to enforce the Guarantee. The Appellate Division denied GLNG’s appeal on February 9, 2023 and denied GLNG’s motion for rehearing on July 6, 2023. 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 and other claims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment on June 13, 2023 and entered judgment dismissing all of Eni S.p.A.’s claims with prejudice on September 15, 2023. Eni S.p.A. filed a notice of appeal to the state Appellate Division. We intend to vigorously oppose Eni S.p.A’s appeal.
Freeport LNG Winter Storm Litigation
On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On November 21, 2022, Freeport filed a notice of appeal to the 14th Court of Appeals, where the matter remains pending. We believe 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 filed initially in federal court in Michigan, then 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 purported class-wide basis in the lawsuit. The complaint asserts six claims that fall within three primary theories of
25
liability. Claims I, II, and III all seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. These claims challenge plan provisions which are alleged to constitute impermissible “backloading” or “cutback” of benefits. Claims IV and V allege that former participants in the ANR plans should be eligible for unreduced benefits at younger ages than the plans currently provide. Claim VI asserts that actuarial assumptions used to calculate reduced early retirement benefits for current or former ANR employees are outdated and therefore unreasonable. The complaint alleges that the purported class includes over 10,000 individuals. The lawsuit is in the discovery stage and plaintiffs have moved for class certification. Plaintiffs seek to recover early retirement benefits as well as declaratory and injunctive relief, but have not pleaded, disclosed or otherwise specified a calculation of alleged damages. Accordingly, the extent of potential plan liabilities for past or future benefits, if any, remains to be determined. We believe we have numerous and substantial defenses and intend to vigorously defend this case.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
Arizona Line 2000 Rupture
On August 15, 2021, the 30” EPNG Line 2000 natural gas transmission pipeline ruptured in a rural area in Coolidge, Arizona. The failure resulted in a fire which destroyed a home, resulting in two fatalities and one injury. The National Transportation Safety Board investigated the incident and issued its report on April 27, 2023. EPNG completed the physical work on Line 2000 in accordance with PHMSA’s requirements and returned the pipeline to commercial service in February 2023. We notified our insurers and resolved the claims presented by or on behalf of the residents of the home without litigation or a material adverse impact to our business.
General
As of September 30, 2023 and December 31, 2022, our total reserve for legal matters was $21 million and $70 million, respectively.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal, CO2 field and oil field, and our other operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.
We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but except as disclosed herein we do not believe any such fines and penalties will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts.
In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, crude oil, NGL, natural gas or CO2, including natural resource damage (NRD) claims.
26
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated to be more than $2.8 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around December 2024. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.
In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, NRD claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey
EPEC Polymers, Inc. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River in New Jersey. On March 4, 2016, the EPA issued a Record of Decision (ROD) for the lower eight miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020 and certain PRPs, including EPEC, engaged in discussions with the EPA as a result thereof. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. At that time, the cleanup plan in the ROD was estimated to cost $440 million. No timeline for the cleanup has been established. On December 16, 2022, the United States Department of Justice (DOJ) and EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, to resolve their collective liability at the Site. The total amount of the settlement is $150 million. Also on December 16, 2022, the DOJ on behalf of the EPA filed a Complaint against the 85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and a Consent Decree in the U.S. District Court for the District of New Jersey. We believe our share of the costs to resolve this matter, including our share of the settlement with EPA and the costs to remediate the Site, if any, will not have a material adverse impact to our business.
Louisiana Governmental Coastal Zone Erosion Litigation
Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.
On November 8, 2013, the Parish of Plaquemines, Louisiana and others filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. 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
27
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 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 and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party. On May 3, 2023, the U.S. District Court re-opened the case. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.
Products Pipeline Incident, Walnut Creek, California
On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in California from Concord to San Jose. We shut down the pipeline and notified the appropriate regulatory agencies of a “threatened release” of gasoline. We investigated the issue and on November 24, 2020, identified a crack in the pipeline and notified the regulatory agencies of a “confirmed release.” The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on November 26, 2020. We reported the estimated volume of gasoline released to be 8.1 Bbl. On December 2, 2020, complaints of gasoline odors were reported along the LS-16 pipeline corridor in Walnut Creek. A unified response was implemented by us along with the EPA, the California Office of Spill Prevention and Response, the California Fire Marshall, and the San Francisco Regional Water Quality Control Board. On December 8, 2020, we reported an updated estimated spill volume of up to 1,000 Bbl.
On October 28, 2021, we were informed by the California Attorney General it was contemplating criminal charges against us asserting the November 2020 discharge of gasoline affected waters of the State of California, and there was a failure to make timely notices of this discharge to appropriate state agencies. On December 16, 2021, we entered into a plea agreement with the State of California to resolve misdemeanor charges of the unintentional, non-negligent discharge of gasoline resulting from the release and the claimed failure to provide timely notices of the discharge to appropriate state agencies. Under the plea agreement, SFPP plead no-contest to two misdemeanors and paid approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and was placed on informal, unsupervised probation for a term of 18 months. On May 8, 2023, the California Attorney General confirmed SFPP had complied with the terms of the plea agreement.
Since the November 2020 release, we have cooperated fully with federal and state agencies and worked diligently to remediate the affected areas. There may be civil enforcement actions by federal and state agencies arising from the November 2020 release. Further, we anticipate ongoing monitoring and, where necessary, remediation under the oversight of the San Francisco Regional Water Quality Control Board until site conditions demonstrate no further actions are required. We do not anticipate the costs to resolve those enforcement matters, if any, or the costs to monitor and further remediate the site, will have a material adverse impact to our business.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of September 30, 2023 and December 31, 2022, we have accrued a total reserve for environmental liabilities in the amount of $208 million and $221 million, respectively. In addition, as of September 30, 2023 and December 31, 2022, we had receivables of $11 million and $12 million, respectively, recorded for expected cost recoveries that have been deemed probable.
Challenge to Federal “Good Neighbor Plan”
On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the EPA’s final action promulgating the EPA’s final rule known as the “Good Neighbor Plan” (the Plan). The Plan was published in the Federal Register as a final rule on June 5, 2023. The Plan is a federal
28
implementation plan to address certain interstate transport requirements of the Clean Air Act for the 2015 8-hour Ozone National Ambient Air Quality Standards. We believe that the Plan is deeply flawed and that numerous 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. If the Plan were to remain in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to state implementation plan disapprovals and no successful challenge to the Plan), we anticipate that it would have a material impact on us. On July 27, 2023, 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, we filed an Emergency Application for Stay of Final Agency Action in the United States Supreme Court.
On July 31, 2023, the EPA published an Interim Final Rule entitled “Federal ‘Good Neighbor Plan’ for the 2015 Ozone National Ambient Air Quality Standards; Response to Judicial Stays of SIP Disapproval Action for Certain States.” On September 29, 2023, we filed a Petition 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.
Impacts of the Plan are difficult to predict, particularly given the extensive pending litigation. We would seek to mitigate the impacts, and to recover expenditures through adjustments to our rates on our regulated assets where available.
10. Recent Accounting Pronouncements
Accounting Standards Updates
Reference Rate Reform (Topic 848)
On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform – Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate (SOFR). Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.
On January 7, 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of Topic 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.
On December 21, 2022, the FASB issued ASU No. 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848.” This ASU defers the sunset date of Topic 848 from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the optional expedients and exceptions in Topic 848.
The guidance was effective upon issuance.
During the nine months ended September 30, 2023 we amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. These agreements contain a combined notional principal amount of $1,225 million and convert a portion of our fixed rate debt to variable rates. Concurrent with these amendments, we elected certain of the optional expedients provided in Topic 848 which allow us to maintain our prior designation of fair value hedge accounting to these agreements. See Note 5 “Risk Management—Interest Rate Risk Management” for more information on our interest rate risk management activities.
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 2022 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2022 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2022 Form 10-K; and (iv) “Risk Factors” in Part II, Item 1A of this report and Part I, Item 1 in our 2022 Form 10-K.
Acquisition
Following is an acquisition we made during the nine months ended September 30, 2023.
Event
Description
Business Segment
Diamond M Field acquisition
(June 2023)
We closed on our acquisition of Parallel Petroleum’s interest in the Diamond M Field for $15 million, before working capital adjustments. The acquired field is located directly adjacent to our existing SACROC field. It is currently under waterflood, but it is expected to be very receptive to CO2 flooding given its proximity to SACROC. Implementation of enhanced oil recovery is projected to begin in 2024.
CO2 business segment
(Oil and Gas Producing activities)
2023 Dividends and Discretionary Capital
We expect to declare dividends of $1.13 per share for 2023, a 2% increase from the 2022 declared dividends of $1.11 per share. We now expect to invest $1.9 billion in expansion projects, acquisitions, and contributions to joint ventures during 2023.
The expectations for 2023 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.
Results of Operations
Overview
As described in further detail below, our management evaluates our performance primarily using Net income attributable to Kinder Morgan, Inc. and Segment EBDA (as presented in Note 7 “Reportable Segments”) along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA and Net Debt.
GAAP Financial Measures
The Consolidated Earnings Results for the three and nine months ended September 30, 2023 and 2022 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with GAAP, and Segment EBDA, which is disclosed in Note 7 “Reportable Segments” pursuant to FASB ASC 280. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.
Non-GAAP Financial Measures
Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our
30
computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its decision-making processes.
Certain Items
Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings,” “—Non-GAAP Financial Measures—Reconciliation of Net Income 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, 2023 and 2022, 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,
2023
2022
2023
2022
(In millions)
Certain Items
Fair value amortization
$
—
$
(4)
$
—
$
(11)
Legal, environmental and other reserves
—
23
—
23
Change in fair value of derivative contracts(a)
37
(6)
(93)
49
Loss on impairment
—
—
67
—
Income tax Certain Items(b)
(7)
(20)
6
(35)
Other
—
6
—
24
Total Certain Items(c)(d)
$
30
$
(1)
$
(20)
$
50
(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 and 2022 include the following amounts reported within “Earnings from equity investments” on the accompanying consolidated statements of income: (i) $1 million and $(1) million for the three-month periods, respectively, and none and $4 million for the nine-month periods, respectively, included within “Change in fair value of derivative contracts” and (ii) $67 million, for the 2023 nine-month period only, included within “Loss on impairment” for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 2 “Losses on Impairments—Impairments”).
(d)Amounts for the periods ending September 30, 2023 and 2022 include, in the aggregate, $3 million and $15 million for the three-month periods, respectively, and $(10) million and $(46) million for the nine-month periods, respectively, included within “Interest, net” on the accompanying consolidated statements of income which consist of (i) none and $(4) million for the three-month periods, respectively, and none and $(11) million for the nine-month periods, respectively, of “Fair value amortization” and (ii) $3 million and $19 million for the three-month periods, respectively, and $(10) million and $(35) million for the nine-month periods, respectively, of “Change in fair value of derivative contracts.”
Adjusted Earnings
Adjusted Earnings is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in
31
arriving at basic earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings”below.
DCF
DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items, and further for DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure used by us, investors and other external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate economic earnings after paying interest expense, paying cash taxes and expending sustaining capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF is also used by us, investors, and other external users to compare the performance of companies across our industry. DCF per share serves as the primary financial performance target for purposes of annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF”below.
Adjusted Segment EBDA
Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. See “—Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment EBDA”below.
Adjusted EBITDA
Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A and amortization of excess cost of equity investments, income tax expense and interest. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA”below.
Amounts from Joint Ventures
Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to non-controlling interests. (See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA”below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.
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Net Debt
Net Debt is calculated, based on amounts as of September 30, 2023, by subtracting the following amounts from our debt balance of $31,001 million: (i) cash and cash equivalents of $80 million; (ii) debt fair value adjustments of $8 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.
Consolidated Earnings Results
The following tables summarize the key components of our consolidated earnings results.
Three Months Ended September 30,
2023
2022
Earnings increase/(decrease)
(In millions, except percentages)
Revenues
$
3,907
$
5,177
$
(1,270)
(25)
%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)
(1,405)
(2,717)
1,312
48
%
Operations and maintenance
(738)
(712)
(26)
(4)
%
DD&A
(561)
(551)
(10)
(2)
%
General and administrative
(162)
(162)
—
—
%
Taxes, other than income taxes
(106)
(113)
7
6
%
Gain on divestitures and impairments, net
3
9
(6)
(67)
%
Total Operating Costs, Expenses and Other
(2,969)
(4,246)
1,277
30
%
Operating Income
938
931
7
1
%
Other Income (Expense)
Earnings from equity investments
234
195
39
20
%
Amortization of excess cost of equity investments
(18)
(19)
1
5
%
Interest, net
(457)
(399)
(58)
(15)
%
Other, net
3
21
(18)
(86)
%
Total Other Expense
(238)
(202)
(36)
(18)
%
Income Before Income Taxes
700
729
(29)
(4)
%
Income Tax Expense
(145)
(134)
(11)
(8)
%
Net Income
555
595
(40)
(7)
%
Net Income Attributable to Noncontrolling Interests
(23)
(19)
(4)
(21)
%
Net Income Attributable to Kinder Morgan, Inc.
$
532
$
576
$
(44)
(8)
%
Basic and diluted earnings per share
$
0.24
$
0.25
$
(0.01)
(4)
%
Basic and diluted weighted average shares outstanding
2,230
2,253
(23)
(1)
%
Declared dividends per share
$
0.2825
$
0.2775
$
0.005
2
%
33
Nine Months Ended September 30,
2023
2022
Earnings increase/(decrease)
(In millions, except percentages)
Revenues
$
11,296
$
14,621
$
(3,325)
(23)
%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)
(3,591)
(7,294)
3,703
51
%
Operations and maintenance
(2,062)
(1,960)
(102)
(5)
%
DD&A
(1,683)
(1,632)
(51)
(3)
%
General and administrative
(497)
(470)
(27)
(6)
%
Taxes, other than income taxes
(319)
(340)
21
6
%
Gain on divestitures and impairments, net
16
30
(14)
(47)
%
Other income, net
2
6
(4)
(67)
%
Total Operating Costs, Expenses and Other
(8,134)
(11,660)
3,526
30
%
Operating Income
3,162
2,961
201
7
%
Other Income (Expense)
Earnings from equity investments
607
564
43
8
%
Amortization of excess cost of equity investments
(54)
(57)
3
5
%
Interest, net
(1,345)
(1,087)
(258)
(24)
%
Other, net
7
63
(56)
(89)
%
Total Other Expense
(785)
(517)
(268)
(52)
%
Income Before Income Taxes
2,377
2,444
(67)
(3)
%
Income Tax Expense
(509)
(512)
3
1
%
Net Income
1,868
1,932
(64)
(3)
%
Net Income Attributable to Noncontrolling Interests
(71)
(54)
(17)
(31)
%
Net Income Attributable to Kinder Morgan, Inc.
$
1,797
$
1,878
$
(81)
(4)
%
Basic and diluted earnings per share
$
0.80
$
0.83
$
(0.03)
(4)
%
Basic and diluted weighted average shares outstanding
2,238
2,262
(24)
(1)
%
Declared dividends per share
$
0.8475
$
0.8325
$
0.015
2
%
Our consolidated 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 costs of sales and sales revenues also include purchases and sales of natural gas and products (which means, collectively, NGL, crude oil, CO2 and transmix) and related derivative activity. Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the associated costs of sales 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, 2023 and 2022:
Revenues
Revenues decreased $1,270 million and $3,325 million for the three and nine months ended September 30, 2023, respectively, as compared to the respective prior year periods. The decreases were primarily due to lower natural gas sales of $1,207 million and $2,965 million, respectively, and lower product sales of $188 million and $989 million, respectively, driven primarily by lower commodity prices partially offset by the impact of derivative contracts used to hedge commodity sales of $67 million and $524 million, respectively, which includes both realized and unrealized gains and losses from derivatives. These decreases in revenues were offset by corresponding decreases in our costs of sales as described below under “Operating Costs, Expenses and Other—Costs of sales.”
34
Operating Costs, Expenses and Other
Costs of sales
Costs of sales decreased $1,312 million and $3,703 million for the three and nine months ended September 30, 2023, respectively, as compared to the respective prior year periods. The decreases were primarily due to lower costs of sales for natural gas of $1,129 million and $2,860 million, respectively, and for products of $197 million and $646 million, respectively, driven primarily by lower commodity prices. Costs of sales was partially offset by increases of $18 million and further reduced by $157 million, respectively, for the impacts of 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 $26 million and $102 million for the three and nine months ended September 30, 2023, respectively, as compared to the respective prior year periods. The increases were primarily driven by higher labor, fuel costs, materials and supplies and services related to greater activity levels and inflation partially offset by a legal reserve associated with the EPNG pipeline rupture established in the 2022 period.
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 $58 million and $258 million for the three and nine months ended September 30, 2023, respectively, as compared to the respective prior year periods. The increases were primarily due to higher realized Secured Overnight Financing Rates associated with interest rate swaps.
35
Non-GAAP Financial Measures
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions, except per share amounts)
Net income attributable to Kinder Morgan, Inc.
$
532
$
576
$
1,797
$
1,878
Certain Items(a)
Fair value amortization
—
(4)
—
(11)
Legal, environmental and other reserves
—
23
—
23
Change in fair value of derivative contracts
37
(6)
(93)
49
Loss on impairment
—
—
67
—
Income tax Certain Items
(7)
(20)
6
(35)
Other
—
6
—
24
Total Certain Items
30
(1)
(20)
50
Adjusted Earnings
$
562
$
575
$
1,777
$
1,928
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF
Net income attributable to Kinder Morgan, Inc.
$
532
$
576
$
1,797
$
1,878
Total Certain Items(b)
30
(1)
(20)
50
DD&A
561
551
1,683
1,632
Amortization of excess cost of equity investments
18
19
54
57
Income tax expense(c)
152
154
503
547
Cash taxes
(1)
(3)
(10)
(12)
Sustaining capital expenditures
(242)
(207)
(593)
(498)
Amounts from joint ventures
Unconsolidated joint venture DD&A
80
89
241
242
Remove consolidated joint venture partners’ DD&A
(16)
(12)
(47)
(34)
Unconsolidated joint venture income tax expense(d)(e)
24
13
70
54
Unconsolidated joint venture cash taxes(d)
(21)
(12)
(73)
(51)
Unconsolidated joint venture sustaining capital expenditures
(43)
(38)
(118)
(89)
Remove consolidated joint venture partners’ sustaining capital expenditures
2
2
6
6
Other items(f)
18
(9)
51
(29)
DCF
$
1,094
$
1,122
$
3,544
$
3,753
Adjusted Earnings per share
$
0.25
$
0.25
$
0.79
$
0.85
Weighted average shares outstanding for dividends(g)
2,244
2,267
2,251
2,275
DCF per share
$
0.49
$
0.49
$
1.57
$
1.65
Declared dividends per share
$
0.2825
$
0.2775
$
0.8475
$
0.8325
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(b)See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings” for a detailed listing.
(c)To avoid duplication, adjustments for income tax expense for the periods ended September 30, 2023 and 2022 exclude $(7) million and $(20) million for the three-month periods, respectively, and $6 million and $(35) 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.
36
(d)Associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments.
(e)Includes the tax provision on Certain Items recognized by the investees that are taxable entities. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.
(f)Includes non-cash pension expense, non-cash compensation associated with our restricted stock program and pension contributions.
(g)Includes restricted stock awards that participate in dividends.
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
Net income attributable to Kinder Morgan, Inc.
$
532
$
576
$
1,797
$
1,878
Certain Items(a)
Fair value amortization
—
(4)
—
(11)
Legal, environmental and other reserves
—
23
—
23
Change in fair value of derivative contracts
37
(6)
(93)
49
Loss on impairment
—
—
67
—
Income tax Certain Items
(7)
(20)
6
(35)
Other
—
6
—
24
Total Certain Items
30
(1)
(20)
50
DD&A
561
551
1,683
1,632
Amortization of excess cost of equity investments
18
19
54
57
Income tax expense(b)
152
154
503
547
Interest, net(c)
454
384
1,355
1,133
Amounts from joint ventures
Unconsolidated joint venture DD&A
80
89
241
242
Remove consolidated joint venture partners’ DD&A
(16)
(12)
(47)
(34)
Unconsolidated joint venture income tax expense(d)
24
13
70
54
Adjusted EBITDA
$
1,835
$
1,773
$
5,636
$
5,559
(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, 2023 and 2022 exclude $(7) million and $(20) million for the three-month periods, respectively, and $6 million and $(35) 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, 2023 and 2022 exclude $3 million and $15 million for the three-month periods, respectively, and $(10) million and $(46) 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.
37
Below is a discussion of significant changes in our Adjusted Earnings, DCF and Adjusted EBITDA:
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
Adjusted Earnings
$
562
$
575
$
1,777
$
1,928
DCF
1,094
1,122
3,544
3,753
Adjusted EBITDA
1,835
1,773
5,636
5,559
Change from prior period
Increase/(Decrease)
Adjusted Earnings
$
(13)
$
(151)
DCF
$
(28)
$
(209)
Adjusted EBITDA
$
62
$
77
Adjusted Earnings decreased $13 million and $151 million for the three and nine months ended September 30, 2023, respectively, as compared to the respective prior year periods and were primarily driven by higher interest expense. Higher interest expense also affected DCF. The $28 million and $209 million decreases in DCF for the three and nine months ended September 30, 2023, respectively, as compared to the respective prior year periods were further impacted by increases in sustaining capital expenditures. Adjusted EBITDA increased $62 million and $77 million for the three and nine months ended September 30, 2023, respectively, as compared to the respective prior year periods due to favorable margins from our Natural Gas Pipeline business segment, and for the three-month period, favorable product pricing from our Products Pipelines business segment partially offset by lower commodity prices.
General and Administrative and Corporate Charges
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
General and administrative
$
(162)
$
(162)
$
(497)
$
(470)
Corporate (charges) benefit
(14)
13
(37)
32
General and administrative and corporate charges
$
(176)
$
(149)
$
(534)
$
(438)
Change from prior period
Earnings increase/(decrease)
General and administrative
$
—
$
(27)
Corporate (charges) benefit
(27)
(69)
Total
$
(27)
$
(96)
General and administrative expenses were flat and increased $27 million and corporate (charges) benefit increased $27 million and $69 million for the three and nine months ended September 30, 2023, respectively, when compared with the respective prior year periods. The combined changes were primarily due to higher pension costs of $24 million and $72 million, and higher labor and benefit-related costs of $6 million and $30 million, for the three and nine months ended September 30, 2023, respectively.
38
Reconciliation of Segment EBDA to Adjusted Segment EBDA
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA
$
1,179
$
1,135
$
3,929
$
3,453
Certain Items(b)
Legal, environmental reserves
—
23
—
23
Change in fair value of derivative contracts
20
(5)
(99)
89
Other
—
6
—
24
Natural Gas Pipelines Adjusted Segment EBDA
$
1,199
$
1,159
$
3,830
$
3,589
Products Pipelines Segment EBDA
$
311
$
257
$
780
$
855
Certain Items(b)
Change in fair value of derivative contracts
2
—
3
—
Loss on impairment
—
—
67
—
Products Pipelines Adjusted Segment EBDA
$
313
$
257
$
850
$
855
Terminals Segment EBDA
$
259
$
240
$
774
$
731
CO2 Segment EBDA
$
163
$
215
$
510
$
619
Certain Items(b)
Change in fair value of derivative contracts
12
(20)
13
(5)
CO2 Adjusted Segment EBDA
$
175
$
195
$
523
$
614
(a)Includes revenues, earnings from equity investments, operating expenses, gain on divestitures and impairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. See “—Overview—GAAP Financial Measures” above.
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending September 30, 2023 and 2022 Certain Items of (i) $19 million and $(4) million for the three-month periods, respectively, and $(99) million and $85 million for the nine-month periods, respectively, are associated with our Midstream business; (ii) $1 million and $(1) million for the three-month periods, respectively, and none and $4 million for the nine-month periods, respectively, are associated with our East business; and (iii) none and $29 million for the three-month periods, respectively, and none and $47 million for the nine-month periods, respectively, are associated with our West 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 assets sold are excluded for all periods presented.
40
Below are the changes in Segment EBDA:
Three Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
West
$
228
$
184
$
44
East
624
596
28
Midstream
327
355
(28)
Total Natural Gas Pipelines Segment EBDA
$
1,179
$
1,135
$
44
Nine Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
West
$
703
$
633
$
70
East
1,965
1,842
123
Midstream
1,261
978
283
Total Natural Gas Pipelines Segment EBDA
$
3,929
$
3,453
$
476
The changes in Segment EBDA for our Natural Gas Pipelines business segment in the comparable three and nine-month periods ended September 30, 2023 and 2022 are explained by the following discussion:
•The $44 million (24%) and $70 million (11%) increases, respectively, in West were primarily due to higher earnings from EPNG due to (i) increased revenues from favorable pricing on its services and the return of a pipeline segment to service in February 2023 and (ii) an increase in gas sales margin, partially offset by (i) increased pipeline maintenance costs on EPNG and (ii) lower revenues from Cheyenne Plains Gas Pipeline Company, L.L.C. and Wyoming Interstate Company, L.L.C., principally resulting from contract expirations in December 2022.
In addition, the West was affected by costs associated with the EPNG pipeline rupture and related litigation reserve for the 2022 periods only, which we treated as Certain Items.
•The $28 million (5%) and $123 million (7%) increases, respectively, in East were primarily due to higher equity earnings from Midcontinent Express Pipeline LLC, driven by favorable pricing on new customer contracts entered into in the later part of 2022, higher revenues on our Stagecoach assets as a result of increased demand in its services and favorable pricing, higher revenues on TGP due to increased rates on capacity sales, increased demand for its services and favorable pricing partially offset by higher pipeline maintenance costs.
•The $28 million (8%) decrease and $283 million (29%) increase, respectively, in Midstream were affected by decreases in revenues and, largely in the nine-month period, costs of sales related to the impacts of non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, which we treated as Certain Items.
In addition, Midstream was impacted by (i) higher sales margins on our Texas intrastate natural gas pipeline operations largely driven by realized gains on sales hedges partially offset by lower commodity prices and (ii) higher earnings from our Hiland Midstream systems primarily due to higher services fees resulting from higher volumes and increased rates partially offset by (i) lower service fee revenues as a result of renegotiated contracts at lower rates on our South Texas assets; and (ii) lower commodity sales margin driven primarily by lower prices on our Altamont asset to a greater extent in the three-month period. The year-to-date increase was further impacted by higher commodity sales margin due to increased volumes on our Altamont asset partially offset by lower sales volumes on our Texas intrastate natural gas pipeline operations.
Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.
41
Products Pipelines
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions, except operating statistics)
Revenues
$
862
$
872
$
2,265
$
2,634
Operating expenses
(584)
(632)
(1,498)
(1,846)
Gain on divestitures and impairments, net
—
—
—
12
Earnings from equity investments
32
17
12
55
Other, net
1
—
1
—
Segment EBDA
311
257
780
855
Certain Items:
Change in fair value of derivative contracts
2
—
3
—
Loss on impairment
—
—
67
—
Certain Items(a)
2
—
70
—
Adjusted Segment EBDA
$
313
$
257
$
850
$
855
Change from prior period
Increase/(Decrease)
Segment EBDA
$
54
$
(75)
Adjusted Segment EBDA
$
56
$
(5)
Volumetric data(b)
Gasoline(c)
1,002
989
985
982
Diesel fuel
362
368
349
370
Jet fuel
292
278
285
262
Total refined product volumes
1,656
1,635
1,619
1,614
Crude and condensate
490
467
481
477
Total delivery volumes (MBbl/d)
2,146
2,102
2,100
2,091
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending September 30, 2023 and 2022 Certain Items of (i) none and $1 million for the three-month periods, respectively, and $1 million and none for the nine-month periods, respectively, are associated with our Southeast Refined Products business and (ii) $2 million and $(1) million for the three-month periods, respectively, and $69 million and none for the nine-month periods, respectively, are 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.
42
Below are the changes in Segment EBDA:
Three Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
Southeast Refined Products
$
82
$
56
$
26
Crude and Condensate
91
73
18
West Coast Refined Products
138
128
10
Total Products Pipelines Segment EBDA
$
311
$
257
$
54
Nine Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
Southeast Refined Products
$
216
$
209
$
7
Crude and Condensate
183
250
(67)
West Coast Refined Products
381
396
(15)
Total Products Pipelines Segment EBDA
$
780
$
855
$
(75)
The changes in Segment EBDA for our Products Pipelines business segment in the comparable three and nine-month periods ended September 30, 2023 and 2022 are explained by the following discussion:
•The $26 million (46%) and $7 million (3%) increases, respectively, in Southeast Refined Products were driven by higher earnings at our Transmix processing operations primarily due to favorable product pricing to a greater extent in the three-month period, an increase in equity earnings from Products (SE) Pipe Line primarily due to increased revenues driven by higher rates, volumes and blending activities and higher volumes on Central Florida Pipeline LLC.
•The $18 million (25%) increase and $67 million (27%) decrease, respectively, in Crude and Condensate was affected by a year-to-date decrease of $67 million to equity earnings for a non-cash impairment related to our investment in Double Eagle Pipeline LLC, which we treated as a Certain Item.
In addition, Crude and Condensate was impacted by (i) higher earnings from our Bakken assets due primarily to higher gathering fees as a result of higher volumes and rates and, to a greater extent in the three-month period, favorable product pricing and (ii) an increase in equity earnings, excluding the impairment discussed above, from Double Eagle Pipeline LLC due to an increase in deficiency revenues and volumes, partially offset by lower earnings from Kinder Morgan Crude & Condensate pipeline driven primarily by a decrease in revenues as a result of re-contracting at lower rates and lower deficiency revenues. The year-to-date decrease was further impacted by lower transportation volumes on our Bakken assets. Our Crude and Condensate business also had lower revenues with a corresponding decrease in costs of sales, resulting primarily from decreased commodity pricing.
•The $10 million (8%) increase and $15 million (4%) decrease, respectively, in West Coast Refined Products were impacted by increased revenues from our Pacific operations as a result of new contracts and higher rates reduced by higher operating costs to a greater extent in the nine-month period and increased revenues from Calnev Pipe Line LLC driven by higher rates. The year-to-date decrease was further impacted by a gain on sale of land in the 2022 period at Calnev Pipe Line LLC.
43
Terminals
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions, except operating statistics)
Revenues
$
484
$
457
$
1,423
$
1,337
Operating expenses
(230)
(222)
(664)
(637)
Gain on divestitures and impairments, net
—
—
3
9
Other income
—
1
—
5
Earnings from equity investments
2
3
6
11
Other, net
3
1
6
6
Segment EBDA
$
259
$
240
$
774
$
731
Change from prior period
Increase/(Decrease)
Segment EBDA
$
19
$
43
Volumetric data(a)
Liquids leasable capacity (MMBbl)
78.7
78.2
78.7
78.2
Liquids leased capacity %(b)
94.6
%
90.8
%
93.6
%
90.9
%
Bulk transload tonnage (MMtons)
12.6
13.4
39.7
40.0
(a)Volumes for assets divested, idled and/or held for sale are excluded for all periods presented.
(b)The ratio of our tankage capacity in service to liquids leasable capacity.
For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical business grouping below and included within the All others group.
44
Below are the changes in Segment EBDA:
Three Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
Marine operations
$
46
$
33
$
13
Gulf Liquids
76
66
10
Gulf Central
36
35
1
Mid Atlantic
20
30
(10)
All others (including intrasegment eliminations)
81
76
5
Total Terminals Segment EBDA
$
259
$
240
$
19
Nine Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
Marine operations
$
131
$
105
$
26
Gulf Liquids
225
217
8
Gulf Central
112
102
10
Mid Atlantic
70
76
(6)
All others (including intrasegment eliminations)
236
231
5
Total Terminals Segment EBDA
$
774
$
731
$
43
The changes in Segment EBDA for our Terminals business segment in the comparable three and nine-month periods ended September 30, 2023 and 2022 are explained by the following discussion:
•The $13 million (39%) and $26 million (25%) increases, respectively, in Marine operations were primarily due to higher average charter rates.
•The $10 million (15%) and $8 million (4%) increases, respectively, in the Gulf Liquids terminals were primarily due to increased revenues from contractual rate escalations and higher volumes.
•The $1 million (3%) and $10 million (10%) increases, respectively, in the Gulf Central terminals were primarily due to higher revenues resulting from contractual rate escalations and higher volumes for petroleum coke handling activities partially offset by higher property tax expense at our Battleground Oil Specialty Terminal Company LLC.
•The $10 million (33%) and $6 million (8%) decreases, respectively, in the Mid Atlantic terminals were primarily due to lower earnings from coal handling activities at our Pier IX facility.
45
CO2
Three Months Ended September 30,
Nine Months Ended September 30,
2023
2022
2023
2022
(In millions, except operating statistics)
Revenues
$
297
$
351
$
896
$
999
Operating expenses
(142)
(143)
(409)
(408)
Gain on divestitures and impairments, net
—
—
1
1
Earnings from equity investments
8
7
22
27
Segment EBDA
163
215
510
619
Certain Items:
Change in fair value of derivative contracts
12
(20)
13
(5)
Certain Items(a)
12
(20)
13
(5)
Adjusted Segment EBDA
$
175
$
195
$
523
$
614
Change from prior period
Increase/(Decrease)
Segment EBDA
$
(52)
$
(109)
Adjusted Segment EBDA
$
(20)
$
(91)
Volumetric data(b)
SACROC oil production
19.59
19.91
20.10
19.62
Yates oil production
6.66
6.43
6.65
6.52
Other
2.52
3.10
2.80
3.21
Total oil production, net (MBbl/d)(c)
28.77
29.44
29.55
29.35
NGL sales volumes, net (MBbl/d)(c)
8.98
9.74
8.79
9.47
CO2 sales volumes, net (Bcf/d)
0.311
0.335
0.338
0.352
Realized weighted average oil price ($ per Bbl)
$
67.60
$
66.34
$
67.49
$
67.91
Realized weighted average NGL price ($ per Bbl)
$
30.74
$
37.68
$
31.87
$
41.01
(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. Three and nine months ended September 2023 and 2022 Certain Items are associated with our Oil and Gas Producing activities. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.
(b)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.
(c)Net of royalties and outside working interests.
Below are the changes in Segment EBDA:
Three Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
Oil and Gas Producing activities
$
100
$
152
$
(52)
Source and Transportation activities
49
59
(10)
Subtotal
149
211
(62)
Energy Transition Ventures
14
4
10
Total CO2 Segment EBDA
$
163
$
215
$
(52)
46
Nine Months Ended September 30,
2023
2022
increase/ (decrease)
(In millions)
Oil and Gas Producing activities
$
353
$
415
$
(62)
Source and Transportation activities
137
190
(53)
Subtotal
490
605
(115)
Energy Transition Ventures
20
14
6
Total CO2 Segment EBDA
$
510
$
619
$
(109)
The changes in Segment EBDA for our CO2 business segment in the comparable three and nine-month periods ended September 30, 2023 and 2022 are explained by the following discussion:
•The $52 million (34%) and $62 million (15%) decreases, respectively, in Oil and Gas Producing activities were affected by unfavorable changes in revenues related to non-cash mark-to-market derivative hedge contracts, which we treated as Certain Items.
In addition, Oil and Gas Producing activities were impacted by decreases in revenues related to lower realized NGL prices and volumes and higher operating expenses.
•The $10 million (17%) and $53 million (28%) decreases, respectively, in Source and Transportation activities were primarily due to lower revenues related to lower CO2 sales prices and volumes.
•The $10 million (250%) and $6 million (43%) increases, respectively, in Energy Transition Ventures were primarily due to higher RNG margins as a result of higher volumes, partially offset by higher operating expenses.
We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to a lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of September 30, 2023:
Remaining 2023
2024
2025
2026
2027
Crude Oil(a)
Price ($ per Bbl)
$
65.66
$
65.04
$
63.19
$
65.16
$
64.14
Volume (MBbl/d)
26.90
20.40
11.45
8.60
2.60
NGLs
Price ($ per Bbl)
$
49.95
$
53.72
Volume (MBbl/d)
5.11
2.68
(a)Includes West Texas Intermediate hedges.
Liquidity and Capital Resources
General
As of September 30, 2023, we had $80 million of “Cash and cash equivalents,” a decrease of $665 million from December 31, 2022. Additionally, as of September 30, 2023, we had borrowing capacity of approximately $3.6 billion under our credit facilities (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
We have consistently generated substantial cash flows from operations, providing a source of funds of $4,169 million and $3,563 million in the first nine months of 2023 and 2022, respectively. The period-to-period increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash flows from operations to fund our sustaining capital
47
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. Additionally, from time to time, our short-term debt balances may include borrowings used to initially finance our long-term debt maturities and/or expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations.
We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of September 30, 2023 and December 31, 2022, approximately $3,739 million (12%) and $6,314 million (20%), respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable-rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The percentage at September 30, 2023 and December 31, 2022 includes $3,445 million and $1,250 million, respectively, of variable-to-fixed interest rate derivative contracts which expire in December 2023. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.
Our board of directors declared a quarterly dividend of $0.2825 per share for the third quarter of 2023, a 2% increase over the dividend declared for the third quarter of 2022.
On January 31, 2023, we issued in a registered offering $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.
During the nine months ended September 30, 2023, upon maturity, we repaid our 3.15% senior notes, our floating rate senior notes, our 3.45% senior notes and our 3.50% senior notes.
Short-term Liquidity
As of September 30, 2023, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion of credit facilities with an available capacity of approximately $3.6 billion and an associated $3.5 billion commercial paper program. The loan commitments under our credit facilities can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our credit facilities and letters of credit reduce borrowings allowed under our $3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facilities and, as previously discussed, have consistently generated strong cash flows from operations.
As of September 30, 2023, our $3,130 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, 2022 was $3,385 million.
We had working capital (defined as current assets less current liabilities) deficits of $3,818 million and $3,127 million as of September 30, 2023 and December 31, 2022, respectively. The overall $691 million increase in deficit from year-end 2022 was primarily due to (i) a $665 million decrease in cash and cash equivalents primarily resulting from using cash on hand as of December 31, 2022 to repay a portion of our senior notes that matured in the first quarter of 2023; (ii) a $324 million net unfavorable change in our accounts receivables and payables; (iii) a $320 million increase in commercial paper borrowings to partially fund the repayment of our senior notes that matured in the third quarter; (iv) a $114 million decrease in other current assets, primarily in exchange gas receivables and regulatory assets; (v) a $69 million decrease in inventories, primarily associated with gas in underground storage, partially offset by (i) a $575 million decrease in senior notes that mature in the next twelve months; (ii) a $163 million decrease in other current liabilities, primarily related to reductions in exchange gas payables and accrued contingencies; and (iii) a $128 million decrease in accrued interest. 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.
48
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 is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted in calculating DCF, while those classified as sustaining capital expenditures are.
Our capital expenditures for the nine months ended September 30, 2023, and the amount we expect to spend for the remainder of 2023 to sustain our assets and expand our business are as follows:
Nine Months Ended
September 30, 2023
2023 Remaining
Total 2023
(In millions)
Capital expenditures:
Sustaining capital expenditures
$
593
$
271
$
864
Expansion capital expenditures
1,227
431
1,658
Accrued capital expenditures, contractor retainage and other
(131)
—
—
Capital expenditures
$
1,689
$
702
$
2,522
Add:
Sustaining capital expenditures of unconsolidated joint ventures(a)
$
118
$
44
$
162
Investments in unconsolidated joint ventures(b)
178
73
251
Less: Consolidated joint venture partners’ sustaining capital expenditures
(6)
(5)
(11)
Less: Consolidated joint venture partners’ expansion capital expenditures
(14)
(6)
(20)
Acquisition
13
—
13
Accrued capital expenditures, contractor retainage and other
131
—
—
Total capital investments
$
2,109
$
808
$
2,917
(a)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.
49
(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, 2023
2023 Remaining
Total 2023
(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment
$
593
$
271
$
864
Sustaining capital expenditures of unconsolidated joint ventures(a)
118
44
162
Less: Consolidated joint venture partners’ sustaining capital expenditures
(6)
(5)
(11)
Total sustaining capital investments
705
310
1,015
Expansion capital investments
Capital expenditures for property, plant and equipment
1,227
431
1,658
Investments in unconsolidated joint ventures(b)
178
73
251
Less: Consolidated joint venture partners’ expansion capital expenditures
(14)
(6)
(20)
Acquisition
13
—
13
Total expansion capital investments
1,404
498
1,902
Total capital investments
$
2,109
$
808
$
2,917
(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.
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 final rule. As part of the Plan, the EPA disapproved 19 state implementation plans (SIPs) under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone National Ambient Air Quality Standards and issued prescriptive emission standards for several sectors, including new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas.
Multiple legal challenges have already been filed, including by us. See Note 9, “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. Several states in which we have affected assets, including Arkansas, Kentucky, Louisiana, Mississippi, Missouri, Oklahoma and Texas, have appealed the EPA’s disapprovals of SIPs and requested stays pending appeal. The criteria for a stay pending appeal include a requirement that the applicant show likelihood of success on the merits. Stays pending appeal have been 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 (pending oral argument on October 27, 2023) meaning that (for as long as the stays remain in place) the EPA no longer has a legal basis to enforce the Plan in these states. In response to those stays, on July 31, 2023, the EPA published an interim final rule 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 rule is uncertain so we filed a petition seeking review of the interim final rule. 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 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 were to remain in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to SIP disapprovals and no successful challenge to the Plan), we currently estimate that it would have a material impact on us, including estimated costs necessary to comply with the
50
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. However, impacts are difficult to predict, particularly given the extensive pending litigation. The outcomes of these numerous lawsuits may significantly decrease our exposure. For example, our currently estimated costs necessary to comply with the Plan associated with states that have not been granted stays with respect to the EPA’s disapproval of their SIPs range from $200 million to $300 million. However, successful challenges to the Plan would impact all states. 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.
Off Balance Sheet Arrangements
There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2022 in our 2022 Form 10-K.
Commitments for the purchase of property, plant and equipment as of September 30, 2023 and December 31, 2022 were $447 million and $527 million, respectively. The decrease of $80 million was driven by an overall decrease of capital commitments.
Cash Flows
The following table summarizes our net cash flows provided by (used in) operating, investing and financing activities between 2023 and 2022.
Nine Months Ended September 30,
2023
2022
Changes
(In millions)
Net Cash Provided by (Used in)
Operating activities
$
4,169
$
3,563
$
606
Investing activities
(1,733)
(1,545)
(188)
Financing activities
(3,133)
(2,442)
(691)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits
$
(697)
$
(424)
$
(273)
Operating Activities
$606 million more cash provided by operating activities in the comparable nine-month periods ended September 30, 2023 and 2022 is explained by the following discussion:
•a $793 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities. The increase was primarily driven by (i) the sale of natural gas inventories and higher settlements associated with commodity hedges in 2023, both related to gas in underground storage; (ii) lower litigation payments in the 2023 period compared with 2022; and (iii) net favorable changes related to the timing of accounts receivable collections and trade payable payments, largely in our Natural Gas Pipelines business segment, partially offset by,
•a $187 million decrease in cash after adjusting the $64 million decrease in net income by $123 million for the combined effects of the period-to-period net changes in non-cash items.
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Investing Activities
$188 million more cash used in investing activities in the comparable nine-month periods ended September 30, 2023 and 2022 is explained by the following discussion:
•a $545 million increase in capital expenditures primarily driven by the expansion projects in our Natural Gas Pipelines and Products Pipelines business segments, partially offset by a decrease in expansion projects in our Terminals business segment; and
•a $119 million increase in cash used for contributions to equity investees driven primarily by higher contributions to Permian Highway Pipeline LLC in the 2023 period compared with the 2022 period, and contributions in 2023 to our newly formed equity investment, Greenholly Gathering Pipeline LLC, partially offset by
•a $475 million decrease in cash used for acquisitions of assets, net of cash acquired, primarily driven by a combined $488 million of net cash used for our acquisitions of Mas Ranger, LLC and North American Natural Resources, Inc. in 2022.
Financing Activities
$691 million more cash used in financing activities in the comparable nine-month periods ended September 30, 2023 and 2022 is explained by the following discussion:
•a decrease of $557 million in cash due to net proceeds received from the sale of a 25.5% ownership interest in Elba Liquefaction Company, L.L.C. in 2022; and
•a $57 million increase in cash used for share repurchases under our share buy-back program.
Dividends
We expect to declare dividends of $1.13 per share on our stock for 2023. The table below reflects our 2023 dividends declared:
Three months ended
Total quarterly dividend per share for the period
Date of declaration
Date of record
Date of dividend
March 31, 2023
$
0.2825
April 19, 2023
May 1, 2023
May 15, 2023
June 30, 2023
0.2825
July 19, 2023
July 31, 2023
August 15, 2023
September 30, 2023
0.2825
October 18, 2023
October 31, 2023
November 15, 2023
The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2022 Form 10-K. All of these matters will be taken into consideration by our board of directors when declaring dividends.
Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.
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Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or a Subsidiary Issuer is in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. Also, see Exhibit 10.1 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of September 30, 2023.”
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors, (referred to as “affiliates”) are presented separately in the accompanying supplemental summarized combined financial information.
Excluding fair value adjustments, as of September 30, 2023 and December 31, 2022, the Obligated Group had $30,225 million and $30,886 million, respectively, of Guaranteed Notes outstanding.
Summarized combined balance sheet and income statement information for the Obligated Group follows:
Summarized Combined Balance Sheet Information
September 30, 2023
December 31, 2022
(In millions)
Current assets
$
2,184
$
3,514
Current assets - affiliates
649
618
Noncurrent assets
61,703
61,523
Noncurrent assets - affiliates
530
516
Total Assets
$
65,066
$
66,171
Current liabilities
$
5,922
$
6,612
Current liabilities - affiliates
711
707
Noncurrent liabilities
30,651
30,668
Noncurrent liabilities - affiliates
1,260
1,096
Total Liabilities
38,544
39,083
Kinder Morgan, Inc.’s stockholders’ equity
26,522
27,088
Total Liabilities and Stockholders’ Equity
$
65,066
$
66,171
Summarized Combined Income Statement Information
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2023
(In millions)
Revenues
$
3,580
$
10,403
Operating income
823
2,843
Net income
430
1,530
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Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2022, in Part II, Item 7A in our 2022 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.
Item 4. Controls and Procedures.
As of September 30, 2023, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2023 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.
Item 1A. Risk Factors.
Except as follows, there have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2022 Form 10-K.
For more information on our risk management activities, refer to Part I, Item 1, Note 5 “Risk Management” to our consolidated financial statements.
For updates regarding the EPA’s final rule known as the “Good Neighbor Plan,” which was discussed under Item 1A in our Form 10-Q for the three months ended March 31, 2023, please refer to Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation” and Note 9, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Our Purchases of Our Class P Stock
(During the quarter ended September 30, 2023)
Settlement Period
Total number of securities purchased(a)(b)
Average price paid per security(b)(c)
Total number of securities purchased as part of publicly announced plans(a)
Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs(a)
July 1 to July 31, 2023
797,258
$
16.94
785,770
$
1,727,381,691
August 1 to August 31, 2023
12,300
17.00
12,300
1,727,172,533
September 1 to September 30, 2023
3,543,367
16.73
3,543,367
1,667,886,238
Total
4,352,925
$
16.77
4,341,437
$
1,667,886,238
(a)On July 19, 2017, our board of directors approved a $2 billion common share buy-back program. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion from $2 billion. After repurchase, the shares are canceled and no longer outstanding.
(b)Includes 11,488 shares of restricted stock that were withheld to pay taxes due upon vesting at a price of $17.21 per share on the vesting date.
(c)Amount includes any commission or other costs to repurchase shares.
Subsequent to September 30, 2023 and through October 19, 2023, we repurchased 5 million shares for $83 million at an average price of $16.38 per share.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Except for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank). We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended September 30, 2023.
Item 5. Other Information.
During the quarter ended September 30, 2023, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the three and nine months ended September 30, 2023 and 2022; (ii) our Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2023 and 2022; (iii) our Consolidated Balance Sheets as of September 30, 2023 and December 31, 2022; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2023 and 2022; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2023 and 2022; and (vi) the notes to our Consolidated Financial Statements.
104
Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
KINDER MORGAN, INC.
Registrant
Date:
October 20, 2023
By:
/s/ David P. Michels
David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)
