(Tabular dollar and unit amounts, except per unit data, are in millions)
(unaudited)
1.ORGANIZATION AND BASIS OF PRESENTATION
Organization
The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”).
Basis of Presentation
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 16, 2024. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC. The Partnership owns the general partner interest, incentive distribution rights and 28.5 million common units of Sunoco LP, and the general partner interests and 46.1 million common units of USAC.
The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.
Certain prior period amounts have been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity.
Use of Estimates
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which requires the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and the accrual for and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
2.ACQUISITIONS, DIVESTITURES AND OTHER TRANSACTIONS
Energy Transfer’s Acquisition
WTG Midstream
On July 15, 2024, Energy Transfer completed the previously announced acquisition of 100% of the membership interest in WTG Midstream Holdings LLC (“WTG Midstream”). Consideration for the transaction was comprised of $2.28 billion in cash and approximately 50.8 million newly issued Energy Transfer common units, which had a fair value of approximately $833 million.
The acquired assets include approximately 6,000 miles of complementary gas gathering pipelines that extended Energy Transfer’s network in the Midland Basin. Also, as part of the transaction, the Partnership added eight gas processing plants with a total capacity of approximately 1.3 Bcf/d, and two additional processing plants that were under construction at closing. Since closing the transaction, one of these 200 MMcf/d processing plants was placed into service.
The WTG Midstream acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of a third-party valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.
The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed:
At July 15, 2024
Total current assets
$
334
Property, plant and equipment, net
3,109
Lease right-of-use assets, net
8
Intangible assets, net
20
Total assets
3,471
Total current liabilities
394
Non-current operating lease liabilities
5
Other non-current liabilities
20
Total liabilities
419
Total consideration
3,052
Cash received
45
Total consideration, net of cash received
$
3,007
Sunoco LP’s Acquisitions
NuStar
On May 3, 2024, Sunoco LP completed the previously announced acquisition of all of the common units of NuStar Energy L.P. (“NuStar”). Under the terms of the merger agreement, NuStar common unitholders received 0.400 Sunoco LP common units for each NuStar common unit. In connection with the acquisition, Sunoco LP issued approximately 51.5 million common units, which had a fair value of approximately $2.85 billion, assumed debt totaling approximately $3.5 billion including approximately $56 million of lease related financing obligations and assumed preferred units with a fair value of approximately $800 million. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids.
The NuStar acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of a third-party valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.
The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed:
At May 3, 2024
Total current assets
$
186
Property, plant and equipment, net
6,958
Lease right-of-use assets, net
136
Goodwill (1)
16
Intangible assets, net (2)
195
Other non-current assets
127
Total assets
7,618
Total current liabilities
245
Long-term debt, less current maturities (3)
3,500
Non-current operating lease liabilities
136
Deferred income taxes
4
Other non-current liabilities
82
Total liabilities
3,967
Preferred units (3)
801
Total consideration
2,850
Cash received
27
Total consideration, net of cash received
$
2,823
(1)Goodwill primarily represents expected commercial and operational synergies and is subject to change based on final purchase price allocations. None of the goodwill recorded as a result of this transaction is deductible for tax purposes.
(2)Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years.
(3)Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million.
Subsequent to the NuStar acquisition, Sunoco LP purchased a property previously leased by NuStar and cancelled the lease, resulting in an impairment of $50 million based on the value of comparable real property.
Zenith European Terminals
On March 13, 2024, Sunoco LP completed the previously announced acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for approximately €170 million ($185 million), which was allocated $6 million to other current assets, $204 million to property, plant and equipment, $36 million to other non-current assets and $7 million to goodwill. In connection with this transaction, Sunoco LP also assumed $14 million in current liabilities, $11 million in deferred income taxes and $43 million in other non-current liabilities.
Other Acquisition
On August 30, 2024, Sunoco LP acquired a terminal in Portland, Maine for approximately $24 million, including working capital. The purchase price was primarily allocated to property, plant and equipment.
Sunoco LP’s Divestiture
West Texas Sale
On April 16, 2024, Sunoco LP completed the previously announced sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.00 billion, including customary adjustments for fuel
and merchandise inventory. As part of the sale, Sunoco LP also amended its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. As a result of the sale, Sunoco LP recorded a $598 million gain ($451 million, net of current tax expense of $178 million and deferred tax benefit of $31 million).
Joint Venture Transaction
Permian Joint Venture
Effective July 1, 2024, Energy Transfer and Sunoco LP formed a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Pursuant to the contribution agreement by and among Sunoco LP, SUN Pipeline Holdings LLC, NuStar Permian Transportation and Storage LLC, NuStar Permian Crude Logistics LLC, NuStar Permian Holdings LLC, NuStar Logistics, L.P., ET-S Permian Holdings Company LP, ET-S Permian Pipeline Company LLC, ET-S Permian Marketing Company LLC, Energy Transfer and Energy Transfer Crude Marketing, LLC dated July 14, 2024, in a cashless transaction, Sunoco LP contributed all of its Permian crude oil gathering assets and operations to the joint venture. Additionally, Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to the joint venture. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from the joint venture.
The joint venture operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.
Energy Transfer holds a 67.5% interest with Sunoco LP holding the remaining 32.5% interest in the joint venture.
3.CASH AND CASH EQUIVALENTS
Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of September 30, 2024 or December 31, 2023.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities, net of effects of acquisitions and divestitures, included in cash flows from operating activities is comprised as follows:
Nine Months Ended September 30,
2024
2023
Accounts receivable
$
(415)
$
(1,125)
Accounts receivable from related companies
(44)
(8)
Inventories
(177)
(3)
Other current assets
82
208
Other non-current assets, net
(99)
(135)
Accounts payable
224
1,076
Accounts payable to related companies
1
(12)
Accrued and other current liabilities
711
562
Other non-current liabilities
(128)
669
Derivative assets and liabilities, net
35
(50)
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures
Non-cash investing and financing activities were as follows:
Nine Months Ended September 30,
2024
2023
Accrued capital expenditures
$
585
$
354
Lease assets obtained in exchange for new lease liabilities
36
26
Distribution reinvestment
66
70
USAC exercise and conversion of preferred units into common units
301
—
USAC government securities transferred in connection with the legal defeasance of USAC senior notes due 2026
749
—
Legal defeasance of USAC senior notes due 2026
725
—
Sunoco LP common units (noncontrolling interest) issued in connection with the NuStar acquisition
2,850
—
4.INVENTORIES
Inventories consisted of the following:
September 30, 2024
December 31, 2023
Natural gas, NGLs and refined products
$
1,779
$
1,642
Crude oil
65
258
Spare parts and other
658
578
Total inventories
$
2,502
$
2,478
Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As of September 30, 2024 and December 31, 2023, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $329 million and $230 million, respectively. For the three and nine months ended September 30, 2024 and 2023, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the three months ended September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory valuation adjustments of $197 million and favorable inventory adjustments of $141 million, respectively, related to Sunoco LP’s LIFO inventory. For the nine months ended September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $99 million and favorable inventory adjustments of $113 million, respectively, related to Sunoco LP’s LIFO inventory.
5.FAIR VALUE MEASURES
We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider options transacted through a clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. The valuation methodologies employed for our interest rate derivatives do not necessitate material judgment, and the inputs are observed from actively quoted public markets and therefore are categorized in Level 2. Level 3 inputs are unobservable. During the nine months ended September 30, 2024, no transfers were made between any levels within the fair value hierarchy.
The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2024 and December 31, 2023 based on inputs used to derive their fair values:
The aggregate estimated fair value and carrying amount of our consolidated debt obligations as of September 30, 2024 were $60.23 billion and $59.26 billion, respectively. As of December 31, 2023, the aggregate fair value and carrying amount of our consolidated debt obligations were $51.93 billion and $52.39 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs for similar liabilities.
A reconciliation of income or loss and weighted average units used in computing basic and diluted income per common unit is as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Net income
$
1,434
$
1,047
$
5,118
$
3,727
Less: Net income attributable to noncontrolling interests
238
451
1,337
1,080
Less: Net income attributable to redeemable noncontrolling interests
13
12
44
39
Net income, net of noncontrolling interests
1,183
584
3,737
2,608
Less: General Partner’s interest in net income
1
—
3
2
Less: Preferred Unitholders’ interest in net income
67
118
294
340
Less: Loss on redemption of preferred units
—
—
54
—
Common Unitholders’ interest in net income
$
1,115
$
466
$
3,386
$
2,266
Basic Income per Common Unit:
Weighted average common units
3,415.2
3,144.0
3,384.9
3,122.3
Basic income per common unit
$
0.33
$
0.15
$
1.00
$
0.73
Diluted Income per Common Unit:
Common Unitholders’ interest in net income
$
1,115
$
466
$
3,386
$
2,266
Dilutive effect of equity-based compensation of subsidiaries (1)
—
1
1
2
Diluted income attributable to Common Unitholders
$
1,115
$
465
$
3,385
$
2,264
Weighted average common units
3,415.2
3,144.0
3,384.9
3,122.3
Dilutive effect of unvested restricted unit awards (1)
26.0
23.7
25.8
23.6
Weighted average common units, assuming dilutive effect of unvested restricted unit awards
3,441.2
3,167.7
3,410.7
3,145.9
Diluted income per common unit
$
0.32
$
0.15
$
0.99
$
0.72
(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.
7.DEBT OBLIGATIONS
Recent Transactions
Energy Transfer Senior Notes Redemptions
During the first quarter of 2024, the Partnership redeemed its $1.15 billion aggregate principal amount of 5.875% senior notes due January 2024, $350 million aggregate principal amount of 4.90% senior notes due February 2024 and $82 million aggregate principal amount of 7.60% senior notes due February 2024 using proceeds from its January 2024 notes issuance described below.
During the second quarter of 2024, the Partnership redeemed its $500 million aggregate principal amount of 4.25% senior notes due April 2024, $750 million aggregate principal amount of 4.50% senior notes due April 2024, $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $600 million aggregate principal amount of 3.90% senior notes due May 2024 using cash on hand and proceeds from its Five-Year Credit Facility (defined below).
Bakken Project Debt Redemption
In April 2024, the Bakken Pipeline entities redeemed $1.00 billion aggregate principal amount of 3.90% senior notes due April 2024 using proceeds from member contributions, which included $637 million reflected as capital contributions from noncontrolling interests recorded in the Partnership’s consolidated financial statements.
In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% senior notes due 2034, $1.75 billion aggregate principal amount of 5.95% senior notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, redeem its outstanding Series C Preferred Units, Series D Preferred Units and Series E Preferred Units and for general partnership purposes.
Energy Transfer June 2024 Notes Issuance
In June 2024, the Partnership issued $1.00 billion aggregate principal amount of 5.25% senior notes due 2029, $1.25 billion aggregate principal amount of 5.60% senior notes due 2034, $1.25 billion aggregate principal amount of 6.05% senior notes due 2054 and $400 million aggregate principal amount of 7.125% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used part of the net proceeds to redeem its outstanding Series A Preferred Units. It also used the net proceeds to fund a portion of its previously announced acquisition of WTG Midstream, refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, and for general partnership purposes.
Sunoco LP April 2024 Notes Issuance
On April 30, 2024, Sunoco LP issued $750 million of 7.000% senior notes due 2029 and $750 million of 7.250% senior notes due 2032 in a private offering. Sunoco LP used the net proceeds from the offering to repay certain outstanding indebtedness of NuStar in connection with the merger between Sunoco LP and NuStar, to fund the redemption of NuStar's preferred units in connection with the merger and to pay offering fees and expenses.
NuStar Subordinated Note Redemption and Credit Facility Termination
During the second quarter of 2024, subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated NuStar's credit facility totaling $455 million.
USAC March 2024 Notes Issuance
In March 2024, USAC issued $1.00 billion aggregate principal amount of 7.125% senior notes due 2029. The net proceeds from this issuance were used to repay a portion of existing borrowings under USAC’s revolving credit facility, to redeem its $725 million aggregate principal amount of 6.875% senior notes due 2026, which constituted a legal defeasance under GAAP (the “Defeasance”), and for general partnership purposes.
The Defeasance required a cash outlay in the net amount of $749 million, which was used to purchase U.S. government securities. These securities generated sufficient cash upon maturity to fund interest payments on the senior notes due 2026 occurring between the effective date of the Defeasance through April 4, 2024, when the senior notes due 2026 were redeemed at par, as well as fund the redemption of the senior notes due 2026 in full. As a result of the Defeasance, USAC recognized a loss on early extinguishment of debt of $5 million for the three months ended March 31, 2024.
Current Maturities of Long-Term Debt
As of September 30, 2024, current maturities of long-term debt reflected on the Partnership’s consolidated balance sheet included $175 million aggregate principal amount of Transwestern’s 5.66% senior notes due December 2024 and Sunoco LP’s $75 million aggregate principal amount of Series 2011 GoZone Bonds with a mandatory purchase date of June 1, 2025.
Credit Facilities and Commercial Paper
Five-Year Credit Facility
The Partnership’s revolving credit facility (the “Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures in April 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.
As of September 30, 2024, the Five-Year Credit Facility had $1.63 billion of outstanding borrowings, $1.58 billion of which consisted of commercial paper. The amount available for future borrowings was $3.34 billion, after accounting for outstanding letters of credit in the amount of $31 million. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 5.04%.
As of September 30, 2024, Sunoco LP’s credit facility had $50 million of outstanding borrowings and $28 million in standby letters of credit and matures in May 2029 (as amended in May 2024). The amount available for future borrowings at September 30, 2024 was $1.42 billion. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 7.30%.
Upon the closing of the NuStar acquisition, the commitments under NuStar’s receivables financing agreement were reduced to zero during a suspension period, for which the period end has not been determined. As of September 30, 2024, this facility had no outstanding borrowings.
USAC Credit Facility
As of September 30, 2024, USAC’s credit facility, which matures in December 2026, had $803 million of outstanding borrowings and $1 million outstanding letters of credit. As of September 30, 2024, USAC’s credit facility had $796 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $642 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 7.50%.
Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our debt agreements as of September 30, 2024. For the quarter ended September 30, 2024, our leverage ratio, as calculated pursuant to the covenant related to our Five-Year Credit Facility, was 3.21x.
8.REDEEMABLE NONCONTROLLING INTERESTS
Certain redeemable noncontrolling interests in the Partnership’s subsidiaries were reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of September 30, 2024 and December 31, 2023 included a balance of $169 million and $476 million, respectively, related to the USAC Series A preferred units; $225 million and $280 million, respectively, related to Crestwood Niobrara LLC preferred units; and $24 million and $22 million, respectively, related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.
USAC Preferred Unit Conversions
On January 12, 2024, the holders of USAC preferred units elected to convert 40,000 preferred units into 1,998,850 common units. These preferred units were converted into common units and, for USAC’s fourth-quarter 2023 distribution, the holders received the common unit distribution of $0.525 on the 1,998,850 common units in lieu of the preferred unit distribution of $24.375 on the converted 40,000 preferred units.
On April 1, 2024, the holders of USAC preferred units elected to convert 280,000 preferred units into 13,991,954 common units. These preferred units were converted into common units and, for USAC’s first-quarter 2024 distribution, the holders received the common unit distribution of $0.525 on the 13,991,954 common units in lieu of the preferred unit distribution of $24.375 on the converted 280,000 preferred units.
Niobrara Preferred Unit Redemption
On February 23, 2024, the Partnership paid approximately $37 million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units.
Changes in Energy Transfer common units during the nine months ended September 30, 2024 were as follows:
Number of Units
Number of common units at December 31, 2023
3,367.5
Common units issued under the distribution reinvestment plan
4.3
Common units vested under equity incentive plans and other
1.1
Common units issued in connection with acquisition of WTG Midstream
50.8
Number of common units at September 30, 2024
3,423.7
Energy Transfer Repurchase Program
During the nine months ended September 30, 2024, Energy Transfer did not repurchase any of its common units under its current buyback program. As of September 30, 2024, $880 million remained available to repurchase under the current program.
Energy Transfer Distribution Reinvestment Program
During the nine months ended September 30, 2024, distributions of $66 million were reinvested under the distribution reinvestment program. As of September 30, 2024, a total of 40 million Energy Transfer common units remained available to be issued under currently effective registration statements in connection with the distribution reinvestment program.
Cash Distributions on Energy Transfer Common Units
Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2023 were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2023
February 7, 2024
February 20, 2024
$
0.3150
March 31, 2024
May 13, 2024
May 20, 2024
0.3175
June 30, 2024
August 9, 2024
August 19, 2024
0.3200
September 30, 2024
November 8, 2024
November 19, 2024
0.3225
Energy Transfer Preferred Units
As of September 30, 2024, Energy Transfer’s outstanding preferred units included 550,000Series B Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units, 900,000 Series H Preferred Units and 41,464,179 Series I Preferred Units. In addition, as of December 31, 2023, Energy Transfer’s outstanding preferred units also included the Series A Preferred Units, Series C Preferred Units, Series D Preferred Units and Series E Preferred Units, all of which were redeemed in 2024.
The following table summarizes changes in the Energy Transfer Preferred Units:
Preferred Unitholders
Series A
Series B
Series C
Series D
Series E
Series F
Series G
Series H
Series I
Total
Balance, December 31, 2023
$
948
$
556
$
438
$
435
$
786
$
496
$
1,488
$
893
$
419
$
6,459
Distributions to partners
(24)
(18)
(11)
(11)
(15)
—
—
—
(9)
(88)
Redemption of preferred units
—
—
(450)
(445)
—
—
—
—
—
(895)
Other, net
—
—
11
10
—
—
—
—
—
21
Net income
23
9
12
11
15
8
27
15
9
129
Balance, March 31, 2024
947
547
—
—
786
504
1,515
908
419
5,626
Distributions to partners
(32)
—
—
—
(15)
(17)
(53)
(29)
(9)
(155)
Redemption of preferred units
(950)
—
—
—
(800)
—
—
—
—
(1,750)
Other, net
13
—
—
—
20
—
—
—
—
33
Net income
22
9
—
—
9
9
26
14
9
98
Balance, June 30, 2024
—
556
—
—
—
496
1,488
893
419
3,852
Distributions to partners
—
(18)
—
—
—
—
—
—
(9)
(27)
Net income
—
9
—
—
—
8
26
15
9
67
Balance, September 30, 2024
$
—
$
547
$
—
$
—
$
—
$
504
$
1,514
$
908
$
419
$
3,892
Preferred Unitholders
Series A
Series B
Series C
Series D
Series E
Series F
Series G
Series H
Total
Balance, December 31, 2022
$
958
$
556
$
440
$
434
$
786
$
496
$
1,488
$
893
$
6,051
Distributions to partners
(30)
(18)
(8)
(9)
(15)
—
—
—
(80)
Net income
18
9
8
9
15
8
27
15
109
Balance, March 31, 2023
946
547
440
434
786
504
1,515
908
6,080
Distributions to partners
(21)
—
(8)
(9)
(15)
(16)
(53)
(29)
(151)
Net income
22
9
9
9
15
8
26
15
113
Balance, June 30, 2023
947
556
441
434
786
496
1,488
894
6,042
Distributions to partners
(22)
(20)
(12)
(8)
(15)
—
—
—
(77)
Net income
23
10
11
10
15
8
27
14
118
Balance, September 30, 2023
$
948
$
546
$
440
$
436
$
786
$
504
$
1,515
$
908
$
6,083
Cash Distributions on Energy Transfer Preferred Units
Distributions declared on the Energy Transfer Preferred Units were as follows:
Period Ended
Record Date
Payment Date
Series A
Series B (1)
Series C
Series D
Series E
Series F (1)
Series G (1)
Series H (1)
Series I (2)
December 31, 2023
February 1, 2024
February 15, 2024
$
24.710
$
33.125
$
0.6075
$
0.6199
$
0.475
$
—
$
—
$
—
$
0.2111
March 31, 2024
May 1, 2024
May 15, 2024
23.992
—
—
—
0.475
33.750
35.630
32.500
0.2111
June 30, 2024
August 1, 2024
August 15, 2024
9.879
33.125
—
—
—
—
—
—
0.2111
September 30, 2024
November 1, 2024
November 15, 2024
—
—
—
—
—
33.750
35.630
32.500
0.2111
(1)Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028.
(2)For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units will be paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.
The Partnership’s consolidated financial statements also include noncontrolling interests in Sunoco LP and USAC, both of which are master limited partnerships, as well as other non-wholly owned consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter.
Sunoco LP Cash Distributions
Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2023 were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2023
February 7, 2024
February 20, 2024
$
0.8420
March 31, 2024
May 13, 2024
May 20, 2024
0.8756
June 30, 2024
August 9, 2024
August 19, 2024
0.8756
September 30, 2024
November 8, 2024
November 19, 2024
0.8756
USAC Cash Distributions
Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2023 were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2023
January 22, 2024
February 2, 2024
$
0.525
March 31, 2024
April 22, 2024
May 3, 2024
0.525
June 30, 2024
July 22, 2024
August 2, 2024
0.525
September 30, 2024
October 21, 2024
November 1, 2024
0.525
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
September 30, 2024
December 31, 2023
Available-for-sale securities
$
20
$
13
Foreign currency translation adjustment
(11)
(5)
Actuarial gains related to pensions and other postretirement benefits
22
6
Investments in unconsolidated affiliates, net
11
14
Total AOCI included in partners’ capital, net of tax
$
42
$
28
10.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
FERC Proceedings
Rover – FERC – Stoneman House
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. The hearing was set to commence on March 6, 2023; as explained below, this FERC proceeding has been stayed.
On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of Texas (the “Federal District Court”) seeking an order declaring that FERC must bring its
enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the Federal District Court case. On May 24, 2022, the Federal District Court ordered a stay of the FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. On April 14, 2023, the United States Supreme Court held against the government in both cases, finding that the federal district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded to the federal district courts for further proceedings.
On September 13, 2023, the Federal District Court ordered that the Federal District Court case would be stayed pending the resolution of another case pending before the United States Supreme Court and that the FERC enforcement case would remain stayed. On November 13, 2023, the FERC appealed the Federal District Court order to the United States Court of Appeals for the Fifth Circuit. On December 11, 2023, FERC filed a motion to withdraw that appeal, which the Fifth Circuit granted on December 12, 2023. The FERC and the Federal District Court proceedings were stayed pending resolution of the case pending before the United States Supreme Court. The Supreme Court issued a decision in that case on June 27, 2024. The FERC and District Court proceedings remain stayed at this time. Energy Transfer and Rover intend to vigorously defend this claim.
Rover – FERC – Tuscarawas
In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the FERC regulations that Enforcement Staff intended to recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. FERC has taken no further action on the case since that time.
The primary contractor (and one of the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.
Other FERC Proceedings
By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which
it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified the discussion in the May 28, 2024 order and continued to reach the same result. On September 18, 2024, Panhandle petitioned the United States Court of Appeals for the District of Columbia for review of the September 9, 2024, July 29, 2024, and May 28, 2024 orders.
On December 1, 2022, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. By order dated June 29, 2023, a revised procedural schedule was adopted in this proceeding setting the commencement of the hearing for January 9, 2024, with an initial decision anticipated by May 21, 2024. Subsequently, by Order of the Acting Chief Administrative Law Judge, deadlines in the procedural schedule were extended, including revised hearing commencement and initial decisions deadlines to March 26, 2024 and August 8, 2024, respectively. On November 29, 2023, the parties reached a settlement in principle. The settlement was filed with the FERC on December 29, 2023 and approved by letter order on February 21, 2024. Among other things, the settlement required Sea Robin to submit a refund report detailing the amount of refunds due to Sea Robin’s shippers as a result of the proceeding. In compliance with the settlement, Sea Robin issued refunds and filed its refund report on June 7, 2024. The refund report was accepted by the FERC via a letter order issued on July 2, 2024. Moreover, the settlement established a rate case moratorium prohibiting Sea Robin or any party to the proceeding from seeking or soliciting a change or challenge to Sea Robin’s rates prior to December 1, 2026.
Commitments
In the normal course of business, Energy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon the unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable rights-of-way (“ROW”) commitments which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
ROW expense
$
23
$
20
$
50
$
46
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Due to the flammable and combustible nature of natural gas and crude oil, the potential exists for personal injury and/or property damage to occur in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
We or our subsidiaries are parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as
well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
As of September 30, 2024 and December 31, 2023, accruals of approximately $259 million and $285 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $125 million.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The following sections also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed in the following sections, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.
Dakota Access Pipeline
On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered the Dakota Access Pipeline to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the Court of Appeals which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals (1) granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, (2) denied a motion to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS and (3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary.
On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The Tribes subsequently filed a motion seeking an injunction to stop the operation of the pipeline and both USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.
On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General (December 17, 2021) and the Tribes
(December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.
The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. On May 21, 2021, the District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.
On September 8, 2023, the USACE published the Draft EIS. Comments on the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS will be issued in December 2025 and a Record of Decision will be issued in early 2026. The pipeline continues to operate pending completion of the EIS. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Bakken Pipeline; however, Energy Transfer expects that after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate.
In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.
Standing Rock Sioux Tribe in Federal Court in District of Columbia
Dakota Access is the subject of litigation in the U.S. District Court for the District of Columbia. The Standing Rock Sioux Tribe (“SRST”) sued the United States Army Corps of Engineers (“USACE”) arguing that the USACE’s alleged failure to stop Dakota Access from operating violates numerous laws, including the Mineral Leasing Act, the Government Acquisition and Streamlining Act, NEPA, the Clean Water Act, the National Historic Preservation Act, the Administrative Procedure Act as well as the 1868 Fort Laramie Treaty. The SRST requests a permanent injunction or writ of mandamus that would compel the USACE to shut Dakota Access down pending the completion of the USACE’s Environmental Impact Statement (“EIS”) and decision on whether to grant Dakota Access an easement under the Mineral Leasing Act.
On October 15, 2024, the SRST filed the above referenced complaint. A summons to the USACE was issued on October 17, 2024. As of this date, no further substantive activity has occurred in the new case. Dakota Access intends to intervene in that lawsuit at the appropriate time.
Louisiana Dispute with New Generation Gas Gathering LLC
On August 31, 2023, Energy Transfer and ETC Texas Pipeline, LTD amended the next day to be ETC Texas Pipeline, Ltd, Gulf Run Transmission, LLC, Enable Midstream Partners, LP and ETC Tiger Pipeline, LLC (collectively “Energy Transfer”), filed a petition for declaratory judgment against New Generation Gas Gathering LLC (“NG3”) in the 42nd Judicial District Court of DeSoto Parish, Louisiana. In relation to seven specific servitudes in DeSoto Parish, Louisiana underlying Energy Transfer natural gas pipelines, Energy Transfer requested declarations from the Court that, pursuant to Louisiana Civil Code Article 720, NG3 must obtain Energy Transfer’s permission to install NG3’s proposed pipelines across the Energy Transfer servitudes so that Energy Transfer may determine if NG3’s proposed installation of its proposed pipelines would interfere with Energy Transfer’s use of its existing servitudes.
On November 13, 2023, NG3 filed its answer and reconventional demand (a Louisiana term for counterclaim) asserting six claims against the entities asserting the claim, as well as against Energy Transfer. In Count I, NG3 seeks declaratory judgment that Energy Transfer lacks the right to object to its proposed crossings of Energy Transfer’s natural gas pipelines that adversely affect Energy Transfer. In Counts II–VI, NG3 asserts five causes of action alleging that Energy Transfer’s objection and lawsuit seeking court determination that it has the right to object to NG3’s request to cross Energy Transfer’s pipelines more than one hundred times constitutes tortious conduct, an abuse of Energy Transfer’s rights, an unfair trade practice, and a violation of Louisiana Monopolies Act sections prohibiting conspiracies, monopolies and attempted monopolies.
On December 7, 2023, the trial court set the deadline for Energy Transfer to respond to NG3’s reconventional demand as February 9, 2024, set a hearing on any exceptions for March 25, 2024, and set a trial date for September 9, 2024. The parties have begun written discovery.
On February 7, 2024, the Attorney General for the State of Louisiana, Public Protection Division (the “AG”) gave notice of a complaint filed by NG3. NG3 asserts that Energy Transfer violated Louisiana Revised Statutes 51:1401, et seq., the
Unfair Trade Practices and Consumer Protection Law. The AG has not investigated this matter and it makes no determination as to the merits of matter.
On March 25, 2024, the trial court denied Energy Transfer’s motion to strike NG3’s Counts II-VI, Energy Transfer’s exceptions, and NG3’s exceptions. Energy Transfer filed an appeal of the trial court’s orders denying its exceptions and motion to strike. The appeal was heard on an expedited basis and denied.
On June 4, 2024, a Joint Motion to Dismiss with Prejudice was filed ending the litigation.
Williams Antitrust Litigation
On June 28, 2024, Louisiana Energy Gateway LLC, The Williams Companies, Inc., and Williams Fields Services Group, LLC (“Williams”) filed a Petition for Damages against Energy Transfer and Gulf Run Transmission, LLC (“Gulf Run”) in the 42nd Judicial District Court, Parish of DeSoto, State of Louisiana, alleging that Energy Transfer and/or Gulf Run have monopolized, conspired to monopolize, and/or attempted to monopolize the relevant product and geographic market for the movement of natural gas from the Haynesville Shale in northwestern Louisiana south to natural gas facilities in the Louisiana Gulf Coast (the “Relevant Market”), engaged in acquisitions that have directly enabled and incentivized to substantially lessen competition, and engaged in unfair methods of competition and unfair trade practices.
On September 16, 2024, Energy Transfer and Gulf Run removed the case to the U.S. District Court for the Western District of Louisiana. On October 4, 2024, Williams filed a Motion to Remand, seeking to remand the case back to the 42nd Judicial District Court. On October 21, 2024, Energy Transfer and Gulf Run filed a consent to remand based on a subsequent change in circumstances. The federal court has not yet remanded the case to the 42nd Judicial District Court. Energy Transfer and Gulf Run’s responsive pleading will be due after the case is remanded. In addition, discovery has not commenced, and the case has not yet been set for trial.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu LP’s (“Lone Star,” now known as Energy Transfer Mont Belvieu NGLs LP) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and seek reimbursement for outstanding losses.
MTBE Litigation
ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging methyl tertiary butyl ether (“MTBE”) contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.
As of September 30, 2024, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco Corporation and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. ETP Holdco Corporation and Energy Transfer Marketing & Terminals L.P. are wholly owned subsidiaries of Energy Transfer.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Rover – State of Ohio
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme
Court. On April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.
On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. Briefing on those motions was completed on November 4, 2022. By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended Complaint.
On November 17, 2023, the State of Ohio appealed the trial judge’s decision to Ohio’s Fifth District Court of Appeals. The State filed its initial brief on January 8, 2024. Energy Transfer and Rover filed a responsive brief on February 20, 2024. The State filed a reply brief on February 26, 2024. Oral argument on the appeal was held on August 27, 2024. On October 1, 2024, Ohio’s Fifth District Court of Appeals affirmed the trial judge’s decision. The State of Ohio has the right to appeal this decision to the Ohio State Supreme Court. Energy Transfer and Rover intend to vigorously defend this claim.
Unitholder Litigation Regarding Pipeline Construction
Various purported unitholders of Energy Transfer have filed derivative actions against various past and current officers and members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s Partnership Agreement, tortious interference, abuse of control and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); Barry King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et al., Case No. 2022-0139-SG (Del. Ch.); Elliot v. LE GP LLC, Case No. 3:22-cv-01527-B (N.D. Tex.); Chapa v. Kelcy L. Warren, et al., Index No. 611307/2022 (N.Y. Sup. Ct.); Elliott v. LE GP et al, Cause No. DC-22-14194 (Dallas County, Tex.); and Charles King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The Barry King action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:20-cv-00719-X) has been consolidated with the Bettiol action. On August 9, 2022, the Elliot action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:22-cv-01527-B) was voluntarily dismissed.
Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors: Kelcy L. Warren, John W. McReynolds and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer directors Marshall S. McCrea and Matthew S. Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn and Hennigan. On August 23, 2022, the court granted in part and denied in part ACERS’ motion for class certification. The court certified a class consisting of those who purchased or otherwise acquired common units of Energy Transfer between February 25, 2017 and November 11, 2019. On January 19, 2024, the defendants filed a motion for summary judgment on all of the claims asserted in ACERS’ amended complaint, and ACERS filed a motion for partial summary judgment. The Court heard oral argument on the parties’ motions for summary judgment on July 15, 2024. On August 8, 2024, the Court ruled on the parties’ cross motions for summary judgment. The Court granted defendants’ motion in part, entering judgment for defendants on loss causation for two categories of challenged statements, thereby significantly reducing the class period and potential damages. The Court also granted plaintiffs’ motion for partial summary judgment in part, entering judgment for plaintiffs on the elements of falsity and the scienter of certain individuals as to four of the challenged statements.
On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and Messrs. Warren, Long, McCrea and Whitehurst. See Vega v. Energy Transfer LP et al., Case
No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims for violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of Rover. On August 10, 2022, the court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. On November 7, 2022, the court granted the defendants’ motion to transfer and transferred this action to the United States District Court for the Northern District of Texas. On January 27, 2023, the defendants filed their motion to dismiss the New Mexico Funds’ amended complaint.
The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing, nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.
Cline Class Action
On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M), LLC (now known as Energy Transfer R&M) and Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the District Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.
After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.
On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit Court of Appeals (“10th Circuit”) and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10, 2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the District Court to enter a final judgment in compliance with the Rules. ETMT also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction in part. The injunction has since been lifted.
Despite the fact that ETMT has taken the position that the judgment is not final and not subject to execution, the Class engaged in asset discovery and actively tried to collect on the judgment through garnishment proceedings from ETMT’s customers. ETMT unsuccessfully tried to deposit the funds into the District Court’s Registry. Accordingly, to stop the garnishment proceedings, on December 2, 2022, ETMT wired approximately $161 million to the Plaintiff’s approved Plan Administrator, which represented at the time the full amount of the judgment with attorney’s fees and post-judgment interest. ETMT did so without waiving its ability to pursue its pending appeal or its right to appeal the merits of the judgment. Plaintiff has since dismissed the garnishment actions.
ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the appeal. ETMT has been vigorous and diligent in its appeals relating to the finality issues underlying the Order and appealed the denial of the Motion to Modify to the 10th Circuit in an attempt to get a decision on finality. The appeal was fully briefed, and oral argument was held on March 21, 2023. On August 3, 2023, the 10th Circuit ruled in favor of ETMT and found that the district court’s plan of allocation (which was part of the final judgment) did not satisfy all finality requirements. The Court held that the district court abused its discretion in denying ETMT’s Rule 60(b)(6) Motion to Modify and reversed and remanded for further proceedings. The case was sent back to the trial court so that the district court could fix the finality requirements with the judgment. Further, ETMT sought and recovered a return of funds deposited with the Plan Administrator; Class Counsel did not oppose this motion.
At a status hearing on September 28, 2023, Class Counsel indicated that it would seek additional interest up until the date that the final judgment is entered. The District Court asked for briefing on the issue of additional interest and held a hearing on October 17, 2023 to address this issue further and enter a ruling as to whether additional interest should be added to the judgment total. During the hearing, the District Court ruled that additional interest should be awarded at the 12% statutory rate from the date of the prior improper judgment up until October 17, 2023. However, the Judge tolled the running of interest for the time period during which the Plan Administrator was in possession of ETMT’s funds (between November 2, 2022 and October 10, 2023). Based on this ruling, the Class calculated that approximately $23 million in additional interest should be added to the final judgment. On October 19, 2023, the District Court entered the new final judgment with a corrected Plan of Allocation. Both parties agree that this newly entered judgment fixes the finality concerns and will allow an appeal to the 10th Circuit on the merits. With the inclusion of additional interest, the total amount awarded to the Plaintiffs is approximately $104 million in actual damages and $75 million in punitive damages. ETMT has appealed the entirety of the judgment to the Tenth Circuit. Oral argument will take place at the Tenth Circuit on November 20, 2024.
Energy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.
On April 8, 2022, Energy Transfer and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower”). On October 1, 2018, ETC and Culberson entered into a Gas Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to require Energy Transfer to purchase their respective interests in Culberson for approximately $93 million. On April 8, 2022, Plaintiffs filed suit against Culberson, Culberson Equity and Moontower asserting claims for declaratory judgment and breach of contract, contending that they materially breached the Bypass GGPA by sending some committed gas to third parties and also by failing to send any gas to Plaintiffs since March 2020, and thus that Culberson Equity’s and Moontower’s put notice is void. Culberson, Culberson Equity, and Moontower have answered the lawsuit. Additionally, Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and attorneys’ fees. Culberson Equity and Moontower also filed a counterclaim against Energy Transfer for (1) breach of the Option Agreement, and (2) a declaratory judgment concerning Energy Transfer’s alleged obligation to purchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court (“the Court”) in Dallas County, Texas. On April 27, 2022, Culberson filed an application for a temporary restraining order, temporary injunction, and permanent injunction, and Culberson Equity and Moontower joined in that request. The Court held a hearing on the application on April 28 and denied the injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation, to which Plaintiffs objected. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an appraisal process regarding the put price. An independent appraiser was appointed and issued his decision on October 15, 2022, concluding that the put price totals $93 million. Plaintiffs have consistently reiterated their objection to the appraisal process and conclusion.
On October 6, 2022, Culberson, Culberson Equity and Moontower filed a motion for summary judgment, but the Court postponed considering it until after further document discovery and depositions. On December 7, 2022, Plaintiffs amended their petition to add Moontower Resources Operating, LLC and Moontower Resources WI, LLC as Defendants, and to assert a claim against all Defendants for fraudulent inducement.
Defendants refiled updated motions for summary judgment on May 5, 2023, seeking summary judgment on: (1) Plaintiffs’ breach of contract and declaratory judgment claims on a no-evidence basis; (2) Plaintiffs’ fraud and alter ego claims on a no-evidence basis; and (3) Plaintiffs’ fraud claim on a traditional basis. Plaintiffs responded on June 6, 2023. Defendants submitted their replies in support of summary judgment on June 12, 2023.
On June 5, 2023, counsel for Defendants informed the Court via a letter that Defendants were continuing the submission date of the no-evidence motion regarding Plaintiffs’ breach of contract and declaratory judgment claims, noting that such submission would be rescheduled along with a traditional summary judgment motion regarding the same subject matter. To that end, on July 17, 2023, Defendant Culberson Midstream, LLC filed a Traditional Motion for Summary Judgment on Plaintiffs’ Breach of Contract and Declaratory Judgment Claims, while Defendants Culberson Midstream Equity, LLC and Moontower Resources Gathering filed a Motion for Partial Summary Judgment Regarding the Breach of the Option Agreement. Further, on July 25, 2023, Defendants filed a Traditional and No-Evidence Motion for Summary Judgment Regarding Damages and Recission. On July 28, 2023, in turn, Plaintiff ETC Texas Pipeline, Ltd. filed a Traditional Motion for Partial Summary Judgment on Breach of Contract and Declaratory Judgment.
On September 20, 2023, the Court held oral argument on the various Motions for Summary Judgment. Following oral argument, on September 26, 2023, the Court ruled on each of the Motions. The Court denied Defendants’ Traditional Motion for Partial Summary Judgment Regarding Fraud, Defendants’ No Evidence Motion for Summary Judgment Regarding Plaintiffs’ Fraud and Alter Ego Claims, Defendants’ Traditional and No Evidence Motion for Partial Summary Judgment Regarding Damages and Rescission, and Plaintiff ETC Texas Pipeline, Ltd.’s Traditional Motion for Partial Summary Judgment on Breach of Contract and Declaratory Judgment. The Court granted Culberson Midstream, LLC’s Traditional Motion for Partial Summary Judgment Seeking Dismissal of Plaintiffs’ Breach of Contract and Declaratory Judgment Claims and Culberson Midstream Equity, LLC and Moontower Resources Gathering, LLC’s Motion for Partial Summary Judgment Regarding Breach of the Option Agreement. On June 26, 2024, the Fifth Court of Appeals (Dallas) denied Defendants’ motion seeking permission to allow an interlocutory appeal of the order denying their Traditional Motion for Partial Summary Judgment Regarding Fraud. Subsequently, Culberson Midstream Equity, LLC and Moontower Resources Gathering, LLC moved for reconsideration of their Motion for Summary Judgment on Fraud in the trial court, and a hearing on that motion was held on July 25, 2024. That motion remains pending. Culberson Midstream Equity, LLC and Moontower Resources Gathering, LLC additionally have appealed the Court of Appeals’ denial of their permissive interlocutory appeal to the Texas Supreme Court. At the Texas Supreme Court’s request, Energy Transfer filed briefing on this matter on October 14, 2024. That appeal remains pending.
Discovery has closed in this matter. On October 1, 2024, Plaintiff Energy Transfer filed a notice of removal of the lawsuit to the Dallas division of the Texas Business Court. After briefing from both parties regarding the propriety of such removal, the Business Court remanded the case to state court in Dallas County on October 31, 2024. Trial on Plaintiff Energy Transfer LP’s fraud claim remains set for trial in the 193rd District Court for January 21, 2025. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.
Massachusetts Attorney General v. New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU. Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50%) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA AG failed to take any further steps to prosecute its claims for nearly seven years. The case remained largely dormant until February 2022, when the Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a procedural schedule on March 16, 2022 (which was amended slightly on August 22, 2022). The parties engaged in discovery and the preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The MA AG served three sets of discovery requests on Respondents on September 9, September 12, and September 20, respectively, to which Respondents timely responded. On October 5, 2022, the MA AG requested that the DPU issue a ruling on whether the information that Respondents redacted in their attorneys’ fees invoices is protected by the attorney-client privilege. On the same day, the MA AG also filed a Motion to Stay the Procedural Schedule pending a ruling on the privilege issue. On October 6, 2022, without even affording Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the procedural schedule. Accordingly, all previous deadlines (including the MA AG’s October 7, 2022, deadline to submit direct pre-filed testimony) are presently stayed. On October 18, 2023, the DPU issued an Order on Attorney General’s Motion to Compel, ruling on issues originally raised in a motion to compel that the MA AG filed in 2013. The October 18, 2023 Order directed NEG to review its redactions again and, to the extent any invoices are completely redacted or heavily redacted, to provide more lightly redacted versions within 30 days. The October 18, 2023 Order also stated that the DPU will set a new procedural schedule in this matter sometime after NEG complies with the directives in the order, which the Company has completed as of January 17, 2024. The matter remains stayed until the DPU sets a new procedural schedule.
On December 23, 2019, Linde Engineering North America Inc. (“Linde”) filed a lawsuit in the District Court of Harris County, Texas alleging that Arrow Field Services, LLC, our consolidated subsidiary, and Crestwood Midstream Partners, LP (collectively, “Crestwood”) breached a contract entered into in March 2018 under which Linde was to provide engineering, procurement and construction services to Crestwood related to the completion of the construction of the Bear Den II cryogenic processing plant.
Trial was held in June 2022, and a final judgment was entered on October 24, 2022. The final judgment includes an award of damages of approximately $20.7 million, a pre-judgment interest award of approximately $17.7 million and attorney fees and other costs of approximately $4.7 million. Crestwood has insurance coverage related to certain pre-judgment interest awards but has not recorded a receivable related to any potential insurance recovery on June 30, 2023. On January 9, 2023, Crestwood paid approximately $21.2 million to the Court Registry under protest to mitigate the impact of post-judgment interest. Crestwood filed a Notice of Appeal on January 13, 2023, and filed its Appellate Brief on September 29, 2023. Linde’s response was filed on February 8, 2024. Oral argument was held on September 26, 2024 and an opinion is expected in early 2025. Crestwood is unable to predict the ultimate outcome on the appeal related to this matter.
State of Oklahoma Attorney General – Winter Storm Uri
On April 10, 2024, the State of Oklahoma, through Attorney General Gentner Drummond, filed a petition on behalf of Grand River Dam Authority against Defendants ET Gathering & Processing, LLC, successor by merger to Enable Midstream Partners, LP, Enable Oklahoma Intrastate Transmission, LLC, Enable Gas Transmission, LLC and Enable Energy Resources, LLC arising out of Winter Storm Uri in February 2021. Specifically, plaintiff alleges that defendants violated the Oklahoma Antitrust Reform Act (79 O.S. §201, et. seq.) by acting individually and in concert with each other to unreasonably restrain trade in the natural gas market in Oklahoma during the storm. Plaintiff also alleges causes of action for breach of contract, unjust enrichment, fraud, bad faith, conspiracy and negligence. Plaintiff’s petition seeks actual damages, punitive damages, treble damages and attorney’s fees and costs. However, the actual amount sought was not specified.
On June 3, 2024, defendants filed a Motion to Dismiss and, alternatively, a Motion to Transfer Venue, along with a Brief in Support. In its Motion to Dismiss, defendants argued that plaintiff’s petition fails to state a claim upon which relief can be granted and also that such claims should be dismissed because collateral estoppel bars plaintiff from bringing allegations inconsistent with earlier agency and judicial findings that the extreme cold weather—not defendants’ conduct—caused the natural gas shortage and resulting high prices during Winter Storm Uri. Defendants also argued that plaintiff’s suit should be dismissed for filing suit in the wrong forum or, alternatively, should be transferred to the correct county of venue (Oklahoma County). Plaintiff filed its response brief on July 12, 2024. A hearing on both motions was held on October 15, 2024, and the parties are currently awaiting the Judge’s ruling on the motions.
Defendants cannot predict the ultimate outcome of this litigation but will vigorously defend against these claims.
Tax Contingencies
Internal Revenue Service Audits
The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service (“IRS”). In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state tax authorities, for the 2019 and prior tax years.
USAC is currently under examination by the IRS for years 2019 and 2020. The IRS has issued preliminary partnership examination changes, along with imputed underpayment computations. Based on discussions with the IRS, USAC has estimated a potential range of loss up to $28 million, including interest. Once a final partnership imputed underpayment, if any, is determined, USAC’s general partner may either elect to pay the imputed underpayment (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each USAC unitholder, and former USAC unitholder, as applicable, with respect to an audited and adjusted return.
New York Motor Fuel Excise Tax Audits
ETMT, Sunoco LLC and Sunoco Retail LLC are currently under motor fuel excise tax audits in the state of New York for the periods of March 2017 through May 2020. These audits are currently ongoing and no assessments have been made. We cannot predict the outcome of these audits; however, to the extent material assessments may be issued, we would expect to use all appropriate administrative and legal measures to defend our positions.
USAC is currently protesting certain assessments made by the Oklahoma Tax Commission (“OTC”). In August 2024, the administrative law judge (“ALJ”) assigned by the OTC accepted USAC’s position that the transactions are not taxable. The OTC subsequently requested a motion for reconsideration, which was denied by the ALJ. The OTC has requested an “en banc” hearing from the OTC Commissioners, which request is pending. The OTC also has other legal options to challenge this decision; accordingly, a final resolution remains pending. If USAC ultimately loses the current and all subsequent legal challenges, USAC estimates that the range of losses it could incur is up to $30 million, including penalties and interest.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on our results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
•Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.
•Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
•Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.
•The Partnership is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2024, the Partnership had been named as a PRP at approximately 32 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon the Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The following table reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
September 30, 2024
December 31, 2023
Current
$
51
$
42
Non-current
221
235
Total environmental liabilities
$
272
$
277
We have established a wholly owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the nine months ended September 30, 2024 and 2023, the Partnership recorded $7 million and $23 million, respectively, of expenditures related to environmental cleanup programs.
Our pipeline operations are subject to regulation by the United States Department of Transportation under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of the Federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations; however, there is no assurance that such costs will not be material in the future.
11.REVENUE
Disaggregation of Revenue
The Partnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 13 depicts the disaggregation of revenue by segment.
Contract Balances with Customers
The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.
The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.
The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed
minimum fee, but allow customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
The following table summarizes the consolidated activity of our contract liabilities:
Contract Liabilities
Balance, December 31, 2023
$
749
Additions
902
Revenue recognized
(932)
Balance, September 30, 2024
$
719
Balance, December 31, 2022
$
615
Additions
794
Revenue recognized
(836)
Balance, September 30, 2023
$
573
The balances of Sunoco LP’s contract assets and contract liabilities were as follows:
September 30, 2024
December 31, 2023
Contract assets
$
284
$
256
Accounts receivable from contracts with customers
775
809
Contract liabilities
44
—
Performance Obligations
At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component, are considered a single performance obligation. For these types of contacts, only the fixed components of the contracts are included in the following table.
As of September 30, 2024, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $38.54 billion. The Partnership expects to recognize this amount as revenue within the time bands illustrated in the following table:
Years Ending December 31,
2024
(remainder)
2025
2026
Thereafter
Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2024
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales in our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
The following table details our outstanding commodity-related derivatives:
September 30, 2024
December 31, 2023
Notional Volume
Maturity
Notional Volume
Maturity
Mark-to-Market Derivatives
Natural Gas (BBtu):
Fixed Swaps/Futures
1,820
2024-2026
5,247
2024-2026
Basis Swaps IFERC/NYMEX
83,845
2024-2027
(46,975)
2024-2025
Swing Swaps
36,503
2024-2025
(97,728)
2024-2025
Options – Puts
—
2024
1,900
2024
Options – Calls
500
2024
250
2024
Forward Physical Contracts
2,138
2024-2026
(1,751)
2024-2026
Power (Megawatt):
Forwards
101,440
2024-2029
155,600
2024-2029
Futures
27,323
2024-2026
(464,897)
2024
Options – Puts
—
2024-2025
136,000
2024
Options – Calls
(33,600)
2024-2025
—
—
Crude (MBbls):
Forwards/Swaps
(856)
2024-2026
(2,674)
2024-2025
Options – Puts
—
—
(15)
2024
Options – Calls
—
—
(20)
2024
NGL/Refined Products (MBbls):
Forward/Swaps
(15,745)
2024-2027
(13,870)
2024-2027
Options – Puts
(12)
2024-2026
121
2024-2026
Options – Calls
(21)
2024-2026
(43)
2024-2026
Futures
(3,528)
2024-2026
(4,548)
2024-2025
Fair Value Hedging Derivatives
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX
(49,858)
2024-2025
(39,013)
2024
Fixed Swaps/Futures
(49,858)
2024-2025
(39,013)
2024
Hedged Item – Inventory
49,858
2024-2025
39,013
2024
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
The following table summarizes USAC’s interest rate swap which is no longer outstanding as of September 30, 2024, and which was not designated as a hedge for accounting purposes:
Term
Type
Notional Amount Outstanding
September 30, 2024
December 31, 2023
December 2025 (1)
Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR
$
—
$
700
(1)In August 2024, USAC elected to terminate the outstanding interest rate swap.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations, resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties
with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments is deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
Fair Value of Derivative Instruments
Asset Derivatives
Liability Derivatives
September 30, 2024
December 31, 2023
September 30, 2024
December 31, 2023
Derivatives designated as hedging instruments:
Commodity derivatives – margin deposits
$
6
$
51
$
(7)
$
(6)
6
51
(7)
(6)
Derivatives not designated as hedging instruments:
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
Asset Derivatives
Liability Derivatives
Balance Sheet Location
September 30, 2024
December 31, 2023
September 30, 2024
December 31, 2023
Derivatives without offsetting agreements
Derivative assets (liabilities)
$
—
$
6
$
—
$
(4)
Derivatives in offsetting agreements:
OTC contracts
Derivative assets (liabilities)
79
132
(60)
(80)
Broker cleared derivative contracts
Other current assets (liabilities)
287
478
(258)
(380)
Total gross derivatives
366
616
(318)
(464)
Offsetting agreements:
Counterparty netting
Derivative assets (liabilities)
(53)
(72)
53
72
Counterparty netting
Other current assets (liabilities)
(237)
(368)
237
368
Total net derivatives
$
76
$
176
$
(28)
$
(24)
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
The following table summarizes the location and amounts recognized in our consolidated statements of operations with respect to our derivative financial instruments:
Location
Amount of Gain (Loss) Recognized in Income on Derivatives
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Derivatives not designated as hedging instruments:
Commodity derivatives
Cost of products sold
$
163
$
(162)
$
148
$
(112)
Interest rate derivatives
Gain on interest rate derivatives
(6)
32
6
47
Total
$
157
$
(130)
$
154
$
(65)
13.REPORTABLE SEGMENTS
Our reportable segments, which conduct their business primarily in the United States, are as follows:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP;
•investment in USAC; and
•all other.
Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales and, subsequent to Sunoco LP’s acquisition of NuStar in May 2024, also in gathering, transportation and other fees. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales and gathering, transportation and other fees.
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory valuation adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 16, 2024. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I – Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 16, 2024 and in “Part II – Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024 filed with the SEC on May 9, 2024. Additional information on forward-looking statements is discussed in “Forward-Looking Statements.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “Energy Transfer” mean Energy Transfer LP and its consolidated subsidiaries.
RECENT DEVELOPMENTS
Energy Transfer’s Acquisition
WTG Midstream
On July 15, 2024, Energy Transfer completed the previously announced acquisition of 100% of the membership interest in WTG Midstream Holdings LLC (“WTG Midstream”). Consideration for the transaction was comprised of $2.28 billion in cash and approximately 50.8 million newly issued Energy Transfer common units, which had a fair value of approximately $833 million. Energy Transfer granted customary registration rights to the sellers and certain of their affiliates and designees in connection with the transaction.
The acquired assets include approximately 6,000 miles of complementary gas gathering pipelines that extended Energy Transfer’s network in the Midland Basin. Also, as part of the transaction, the Partnership added eight gas processing plants with a total capacity of approximately 1.3 Bcf/d, and two additional processing plants that were under construction at closing. Since closing the transaction, one of these 200 MMcf/d processing plants was placed into service.
Sunoco LP’s Acquisitions
NuStar
On May 3, 2024, Sunoco LP completed the previously announced acquisition of all of the common units of NuStar Energy L.P. (“NuStar”). Under the terms of the merger agreement, NuStar common unitholders received 0.400 Sunoco LP common units for each NuStar common unit. In connection with the acquisition, Sunoco LP issued approximately 51.5 million common units, which had a fair value of approximately $2.85 billion, assumed debt totaling approximately $3.5 billion including approximately $56 million of lease related financing obligations and assumed preferred units with a fair value of approximately $800 million. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids.
Zenith European Terminals
On March 13, 2024, Sunoco LP completed the previously announced acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for approximately €170 million ($185 million), including working capital.
Other Acquisition
On August 30, 2024, Sunoco LP acquired a terminal in Portland, Maine for approximately $24 million, including working capital.
On April 16, 2024, Sunoco LP completed the previously announced sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco LP also amended its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit.
Joint Venture Transaction
Permian Joint Venture
Effective July 1, 2024, Energy Transfer and Sunoco LP formed a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Pursuant to the contribution agreement by and among Sunoco LP, SUN Pipeline Holdings LLC, NuStar Permian Transportation and Storage LLC, NuStar Permian Crude Logistics LLC, NuStar Permian Holdings LLC, NuStar Logistics, L.P., ET-S Permian Holdings Company LP, ET-S Permian Pipeline Company LLC, ET-S Permian Marketing Company LLC, Energy Transfer and Energy Transfer Crude Marketing, LLC dated July 14, 2024, in a cashless transaction, Sunoco LP contributed all of its Permian crude oil gathering assets and operations to the joint venture. Additionally, Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to the joint venture. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from the joint venture.
The joint venture operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.
Energy Transfer holds a 67.5% interest with Sunoco LP holding the remaining 32.5% interest in the joint venture.
Quarterly Cash Distribution
In October 2024, Energy Transfer announced a quarterly distribution of $0.3225 per unit ($1.29 annualized) on Energy Transfer common units for the quarter ended September 30, 2024.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding an individual entity’s ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of the FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.
Even without application of the FERC’s rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost-of-service rates. Moreover, we receive revenues from our pipelines based on a variety
of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as Tiger Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as Florida Gas Transmission Pipeline, Transwestern and Panhandle, have a mix of tariff rate, discount rate and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified the discussion in the May 28, 2024 order and continued to reach the same result. On September 18, 2024, Panhandle petitioned the United States Court of Appeals for the District of Columbia for review of the September 9, 2024, July 29, 2024, and May 28, 2024 orders.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the Natural Gas Act. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC will not apply the now draft 2022 Policy Statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments were due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become
effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Interstate Common Carrier Regulation
Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the Interstate Commerce Act (“ICA”). Under the ICA, the FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years.
On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit.
On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases. Specifically, the policy statement adopted the proposal in the FERC’s earlier Notice of Inquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen applied to complaints against index rate increases and instead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.
Air Quality Standards
In 2023, the United States Environmental Protection Agency (“EPA”) finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be issuing prescriptive emission standards for several sectors, including certain new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA’s final rule was to become effective on August 4, 2023, and the prescribed emission standards were scheduled to be effective in 2026.
Operators and industry groups have challenged the Plan in the D.C. Circuit, as well as the legal predicates to the individual upwind states’ inclusion in the Plan in the regional circuits. The effectiveness of the rule is currently stayed in the nine states within the Partnership’s footprint, either by nature of judicial stays of the legal predicate to the Plan or by judicial stay of the Plan itself by the U.S. Supreme Court. Proceedings as to both on the merits are ongoing. In the challenge to the Plan in the D.C. Circuit, oral argument is expected in early 2025 and a decision could take several months, projected late 2025.
The Partnership currently estimates that the final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the DC Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.
RESULTS OF OPERATIONS
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on
disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory valuation adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Segment Adjusted EBITDA, as reported for each segment in the following table, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.
Consolidated Results
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Change
2024
2023
Change
Segment Adjusted EBITDA:
Intrastate transportation and storage
$
329
$
244
$
85
$
1,095
$
869
$
226
Interstate transportation and storage
460
491
(31)
1,335
1,468
(133)
Midstream
816
631
185
2,205
1,851
354
NGL and refined products transportation and services
Unrealized (gain) loss on commodity risk management activities
(53)
107
(160)
50
182
(132)
Inventory valuation adjustments (Sunoco LP)
197
(141)
338
99
(113)
212
Loss on extinguishment of debt
—
—
—
11
—
11
Adjusted EBITDA related to unconsolidated affiliates
181
182
(1)
522
514
8
Equity in earnings of unconsolidated affiliates
(102)
(103)
1
(285)
(286)
1
Non-operating litigation-related loss
—
625
(625)
—
625
(625)
Gain on sale of West Texas assets (Sunoco LP)
—
—
—
(598)
—
(598)
Other, net
18
4
14
11
8
3
Adjusted EBITDA (consolidated)
$
3,959
$
3,541
$
418
$
11,599
$
10,096
$
1,503
Net Income. For the three months ended September 30, 2024 compared to the same period last year, net income increased $387 million, or approximately 37%, primarily due to the recognition of a $625 million non-operating litigation-related loss in the prior period. This impact was partially offset by an increase in interest expense, as well as changes in Segment Adjusted EBITDA, as discussed below.
For the nine months ended September 30, 2024 compared to the same period last year, net income increased $1.39 billion, or approximately 37%, primarily due to the recognition of a $598 million gain on Sunoco LP’s sale of its West Texas assets in the current period, as well as the recognition of a $625 million non-operating litigation-related loss in the prior period. The change in net income also reflected higher segment margin from multiple segments, partially offset by increases in operating expenses, selling, general and administrative expenses, depreciation, depletion and amortization, impairment losses, interest expense and income tax expense; these changes are discussed in more detail below and in “Segment Operating Results.”
Adjusted EBITDA (consolidated). For the three months ended September 30, 2024 compared to the same period last year, Adjusted EBITDA increased primarily due to the impacts of recently acquired assets, as well as higher volumes in our midstream segment and higher pipeline optimization in our intrastate transportation and storage segment.
For the nine months ended September 30, 2024 compared to the same period last year, the increase in Adjusted EBITDA reflected higher earnings from multiple segments, primarily due to the impacts of recently acquired assets.
Additional discussion on the changes impacting net income and Adjusted EBITDA for the three and nine months ended September 30, 2024 compared to the same periods last year is available below and in “Segment Operating Results.”
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and nine months ended September 30, 2024 compared to the same periods last year primarily due to additional depreciation and amortization from assets recently placed in service and recent acquisitions.
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased for the three and nine months ended September 30, 2024 compared to the same periods last year primarily due to higher aggregate debt balances as a result of recent acquisitions and an increase in Sunoco LP’s debt, including the impact of the NuStar acquisition, as well as higher interest rates on floating rate and recently refinanced debt.
Income Tax Expense. For the three and nine months ended September 30, 2024 compared to the same periods last year, income tax expense increased due to the taxable gain recognized by a corporate subsidiary of Sunoco LP on its sale of West Texas assets.
Impairment Losses. For the nine months ended September 30, 2024, impairment losses were related to Sunoco LP’s termination of a lease in June 2024. For the three months ended September 30, 2023, impairment losses included a total of $1 million recognized by USAC related to its compression equipment. For the nine months ended September 30, 2023, impairment losses included a total of $12 million recognized by USAC related to its compression equipment.
(Gain) loss on Interest Rate Derivatives. Gains and losses on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value.
Unrealized (Gain) Loss on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results,” and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and in Note 12 to our consolidated financial statements included in “Item 1. Financial Statements.”
Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market reserves using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the three months ended September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory valuation adjustments of $197 million and favorable inventory adjustments of $141 million, respectively, related to Sunoco LP’s LIFO inventory. For the nine months ended September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $99 million and favorable inventory adjustments of $113 million, respectively, related to Sunoco LP’s LIFO inventory.
Loss on Extinguishment of Debt. For the nine months ended September 30, 2024, the loss on extinguishment of debt included a $4 million loss on Energy Transfer’s redemption of its $450 million aggregate principal amount of 8.00% senior notes due April 2029, a $2 million loss recognized by Sunoco LP and a $5 million loss related to USAC’s redemption of its $725 million aggregate principal amount of 6.875% senior notes due 2026.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operating Results.”
Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized in the three and nine months ended September 30, 2023 represents the loss associated with The Williams Companies, Inc. litigation.
Gain on sale of West Texas Assets. The gain on sale of West Texas assets was related to the gain recognized by Sunoco LP on its sale of convenience stores to 7-Eleven Inc.
Other, net. Other, net primarily includes the amortization of regulatory assets and other income and expense amounts.
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Change
2024
2023
Change
Equity in earnings of unconsolidated affiliates:
Citrus
$
41
$
39
$
2
$
105
$
110
$
(5)
MEP
16
21
(5)
47
68
(21)
White Cliffs
4
2
2
14
5
9
Explorer
11
10
1
26
27
(1)
SESH
12
8
4
32
22
10
Other
18
23
(5)
61
54
7
Total equity in earnings of unconsolidated affiliates
$
102
$
103
$
(1)
$
285
$
286
$
(1)
Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus
$
89
$
86
$
3
$
252
$
250
$
2
MEP
25
30
(5)
73
94
(21)
White Cliffs
9
7
2
28
19
9
Explorer
17
16
1
41
42
(1)
SESH
13
12
1
39
32
7
Other
28
31
(3)
89
77
12
Total Adjusted EBITDA related to unconsolidated affiliates
$
181
$
182
$
(1)
$
522
$
514
$
8
Distributions received from unconsolidated affiliates:
Citrus
$
—
$
53
$
(53)
$
94
$
123
$
(29)
MEP
16
25
(9)
63
89
(26)
White Cliffs
9
7
2
30
18
12
Explorer
11
10
1
29
29
—
SESH
15
8
7
47
25
22
Other
20
19
1
60
47
13
Total distributions received from unconsolidated affiliates
$
71
$
122
$
(51)
$
323
$
331
$
(8)
(1)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The following tables identify the components of Segment Adjusted EBITDA, which is calculated as follows:
•Segment margin, operating expenses and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
•Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.
The following analysis of segment operating results includes a measure of segment margin. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the following sections include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
Intrastate Transportation and Storage
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Change
2024
2023
Change
Natural gas transported (BBtu/d)
13,214
15,123
(1,909)
13,510
15,011
(1,501)
Withdrawals from storage natural gas inventory (BBtu)
2,325
—
2,325
10,555
8,400
2,155
Revenues
$
678
$
973
$
(295)
$
2,233
$
3,070
$
(837)
Cost of products sold
272
664
(392)
964
2,119
(1,155)
Segment margin
406
309
97
1,269
951
318
Unrealized (gains) losses on commodity risk management activities
Selling, general and administrative expenses, excluding non-cash compensation expense
(11)
(13)
2
(37)
(38)
1
Adjusted EBITDA related to unconsolidated affiliates
6
6
—
18
19
(1)
Other
—
(1)
1
1
—
1
Segment Adjusted EBITDA
$
329
$
244
$
85
$
1,095
$
869
$
226
Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, transported volumes of gas on our Texas intrastate pipelines decreased primarily due to less third-party transportation and decreased gas production from the Haynesville area. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity.
Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Change
2024
2023
Change
Transportation fees
$
207
$
211
$
(4)
$
651
$
636
$
15
Natural gas sales and other (excluding unrealized gains and losses)
165
65
100
563
311
252
Retained fuel (excluding unrealized gains and losses)
8
19
(11)
25
49
(24)
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)
15
28
(13)
54
99
(45)
Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustments
11
(14)
25
(24)
(144)
120
Total segment margin
$
406
$
309
$
97
$
1,269
$
951
$
318
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:
•an increase of $100 million in realized natural gas sales and other primarily due to higher pipeline optimization from physical sales; and
•a decrease of $10 million in operating expenses primarily due to a change related to fuel consumption that is offset in cost of products sold in 2024; partially offset by
•a decrease of $13 million in storage margin primarily due to the timing of financial gains;
•a decrease of $11 million in retained fuel margin primarily due to a change related to fuel consumption that is offset in operating expenses in 2024; and
•a decrease of $4 million in transportation fees primarily due to a contract expiration on our Louisiana system.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:
•an increase of $252 million in realized natural gas sales and other primarily due to higher pipeline optimization from physical sales and settled derivatives;
•a decrease of $27 million in operating expenses primarily due to a change related to fuel consumption that is offset in cost of products sold in 2024 and lower compressor rental expense; and
•an increase of $15 million in transportation fees primarily due to the recovery of certain fees earned in a prior period on our Texas system; partially offset by
•a decrease of $45 million in storage margin primarily due to lower storage optimization from settled derivatives; and
•a decrease of $24 million in retained fuel margin primarily due to a change related to fuel consumption that is offset in operating expenses in 2024.
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(203)
(178)
(25)
(616)
(567)
(49)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(34)
(30)
(4)
(99)
(89)
(10)
Adjusted EBITDA related to unconsolidated affiliates
125
129
(4)
361
374
(13)
Other
—
1
(1)
(1)
—
(1)
Segment Adjusted EBITDA
$
460
$
491
$
(31)
$
1,335
$
1,468
$
(133)
Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, transported volumes increased primarily due to more capacity sold and higher utilization on our Panhandle, Trunkline and Gulf Run systems due to increased demand.
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following:
•an increase of $25 million in operating expenses primarily due to a $10 million one-time benefit recorded in the third quarter of 2023 which reduced operating expense, a $6 million increase in maintenance project costs, a $3 million increase from the revaluation of system gas and an aggregate increase of $5 million in employee costs and office expense;
•an increase of $4 million in selling, general and administrative expenses primarily due to higher professional fees and higher overhead costs; and
•a decrease of $4 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower revenue on our Midcontinent Express Pipeline joint venture; partially offset by
•an increase of $3 million in segment margin primarily due to a $23 million increase resulting from a rate adjustment in 2023 related to the conclusion of a rate case on our Panhandle system, partially offset by an $11 million decrease due to lower interruptible utilization, a $7 million decrease in transportation revenue from several of our interstate pipeline systems due to lower contracted volumes at lower rates and a $5 million decrease due to lower market prices on the sale of operational gas.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following:
•a decrease of $60 million in segment margin primarily due to a $36 million decrease due to lower market prices on the sale of operational gas, a $16 million decrease in interruptible utilization and a $9 million decrease in parking revenue;
•an increase of $49 million in operating expenses primarily due to a $32 million increase in maintenance project costs, a $12 million increase in employee related costs, a $6 million increase from the revaluation of system gas and an aggregate $8 million increase in transportation expense, outside services and office expense. These increases were partially offset by an aggregate $9 million decrease in ad valorem taxes, electricity and storage expenses;
•an increase of $10 million in selling, general and administrative expenses primarily due to higher professional fees, overhead and employee related costs; and
•a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower revenue on our Midcontinent Express Pipeline joint venture.
Selling, general and administrative expenses, excluding non-cash compensation expense
(57)
(50)
(7)
(144)
(152)
8
Adjusted EBITDA related to unconsolidated affiliates
6
5
1
18
14
4
Other
71
1
70
74
4
70
Segment Adjusted EBITDA
$
816
$
631
$
185
$
2,205
$
1,851
$
354
Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, gathered volumes increased primarily due to recently acquired assets and higher volumes in the Permian region. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization.
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following:
•an increase of $254 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region; and
•an increase of $70 million in other income due to the recognition of proceeds from a business interruption claim; partially offset by
•an increase of $117 million in operating expenses primarily due to a $108 million increase related to recent acquisitions and assets placed in service and a $9 million increase in employee costs;
•a decrease of $16 million in segment margin due to lower natural gas prices; and
•an increase of $7 million in selling, general and administrative expenses primarily due to higher insurance expenses.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following:
•an increase of $458 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region;
•an increase of $70 million in other income due to the recognition of proceeds from a business interruption claim;
•a decrease of $8 million in selling, general and administrative expenses primarily due to one-time expenses in the prior period; and
•an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets; partially offset by
•an increase of $165 million in operating expenses primarily due to a $159 million increase related to recent acquisitions and assets placed in service and a $22 million increase in employee costs, partially offset by an $8 million decrease in environmental reserves and a $6 million decrease in compressor rental expense; and
•a decrease of $21 million in segment margin due to lower natural gas prices of $52 million, partially offset by higher NGL prices of $31 million.
Selling, general and administrative expenses, excluding non-cash compensation expense
(42)
(33)
(9)
(118)
(106)
(12)
Adjusted EBITDA related to unconsolidated affiliates
35
34
1
98
92
6
Segment Adjusted EBITDA
$
1,012
$
1,076
$
(64)
$
3,071
$
2,852
$
219
Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, NGL transportation volumes increased primarily due to higher volumes from the Permian region, on our Mariner East pipeline system and on our Gulf Coast export pipelines.
The increase in transportation volumes and the commissioning of our eighth fractionator in August 2023 also led to higher fractionated volumes at our Mont Belvieu NGL Complex.
Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Change
2024
2023
Change
Transportation margin
$
647
$
639
$
8
$
1,916
$
1,778
$
138
Fractionators and refinery services margin
239
251
(12)
704
647
57
Terminal services margin
260
235
25
718
664
54
Storage margin
79
78
1
233
232
1
Marketing margin
37
107
(70)
223
212
11
Unrealized gains (losses) on commodity risk management activities
64
(84)
148
22
(34)
56
Total segment margin
$
1,326
$
1,226
$
100
$
3,816
$
3,499
$
317
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impact of the following:
•a decrease of $70 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to $100 million in gains recorded in the third quarter of 2023 from the optimization of hedged NGL and refined product inventories compared to $30 million in gains recorded for the third quarter of 2024. This decrease also included a $2 million decrease in intrasegment margin which is fully offset within our transportation margin;
•a decrease of $12 million in fractionators and refinery services margin resulting from a $27 million increase due to higher volumes and a $2 million increase from our refinery services business, offset by a $41 million decrease in rates, primarily from our midstream segment due to lower gas prices and the restructuring of certain affiliate fractionation agreements;
•an increase of $8 million in operating expenses primarily due to a $6 million increase in employee costs, a $4 million increase in ad valorem taxes, a $4 million increase in outside services expenses and increases totaling $6 million from various other operating expenses. These increases were partially offset by an $11 million decrease in gas and power utility costs; and
•an increase of $9 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets; partially offset by
•an increase of $25 million in terminal services margin primarily due to a $15 million increase from higher export volumes loaded at our Nederland Terminal, an $8 million increase from our Marcus Hook Terminal due to higher throughput and contractual rate escalations and a $3 million increase due to higher throughput and storage at our refined product terminals; and
•an increase of $8 million in transportation margin primarily due to higher throughput and contractual rate escalations of $19 million on our Mariner East pipeline system and intrasegment charges of $7 million and $2 million which were fully offset within our fractionators and marketing margins, respectively. These increases were partially offset by decreased revenue on our Texas y-grade pipeline system, despite higher volumes, primarily due to the restructuring of certain affiliate transportation agreements.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impact of the following:
•an increase of $138 million in transportation margin primarily due to higher throughput and contractual rate escalations of $61 million on our Mariner East pipeline system, $30 million on our Texas y-grade pipeline system, $22 million on our refined product pipelines and $21 million on our Mariner West pipeline, as well as an $8 million increase from higher exported volumes feeding into our Nederland Terminal and intrasegment charges of $4 million and $10 million which are fully offset within our fractionation and marketing margins, respectively;
•an increase of $57 million in fractionators and refinery services margin primarily due to a $52 million increase resulting from higher throughput as our eighth fractionator was placed in service in August 2023 and an $8 million increase from our refinery services business. These increases were partially offset by a $4 million decrease in intrasegment margin which was fully offset within our transportation margin;
•an increase of $54 million in terminal services margin primarily due to a $24 million increase from higher export volumes loaded at our Nederland Terminal, a $21 million increase from our Marcus Hook Terminal due to higher throughput and contractual rate escalations and a $9 million increase from higher throughput and storage at our refined product terminals;
•an increase of $11 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to an increase to intrasegment margin of $10 million which is fully offset within our transportation margin; and
•an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by
•an increase of $36 million in operating expenses primarily due to an $18 million increase in employee costs, a $12 million increase resulting from the timing of project related expenses, a $7 million increase in outside services expenses, a $6 million increase in ad valorem taxes and increases totaling $4 million from various other operating expenses. These increases were partially offset by an $11 million decrease in gas and power utility costs; and
•an increase of $12 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets.
Selling, general and administrative expenses, excluding non-cash compensation expense
(39)
(29)
(10)
(111)
(90)
(21)
Adjusted EBITDA related to unconsolidated affiliates
6
6
—
22
12
10
Other
—
1
(1)
2
2
—
Segment Adjusted EBITDA
$
768
$
706
$
62
$
2,417
$
1,906
$
511
Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, crude oil transportation volumes were higher due to continued growth on our gathering systems and contributions from recently acquired assets.
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following:
•an increase of $121 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $150 million increase from recently acquired assets and contributions from the recently formed Permian joint venture with Sunoco LP; this increase was partially offset by a $21 million decrease from our crude oil acquisition and marketing business primarily due to lower refined product prices and an $11 million decrease from existing pipeline assets; partially offset by
•an increase of $48 million in operating expenses from recently acquired and contributed assets, as well as increases in ad valorem taxes, employee costs, outside services and various volume-driven expenses; and
•an increase of $10 million in selling, general and administrative expenses primarily due to an increase of $7 million from recently acquired assets and related corporate allocations, and higher employee expenses.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following:
•an increase of $649 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $442 million increase from recently acquired assets and contributions from the recently formed Permian joint venture with Sunoco LP, a $169 million increase in transportation revenues from existing pipeline assets and a $32 million increase in our crude oil acquisition and marketing business from more favorable market conditions; and
•an increase of $10 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets and higher volumes on our White Cliffs crude pipeline; partially offset by
•an increase of $127 million in operating expenses primarily due to a $77 million increase from recently acquired and contributed assets, a $14 million increase in outside services, a $12 million increase in employee expenses and a $9 million increase in ad valorem taxes, as well as various increases in volume-driven expenses; and
•an increase of $21 million in selling, general and administrative expenses primarily due to a $16 million increase from recently acquired assets and related corporate allocations, and higher employee expenses.
Selling, general and administrative expenses, excluding non-cash compensation expense
(52)
(28)
(24)
(216)
(83)
(133)
Adjusted EBITDA related to unconsolidated affiliates
47
2
45
53
8
45
Inventory valuation adjustments
197
(141)
338
99
(113)
212
Other
7
8
(1)
24
21
3
Segment Adjusted EBITDA
$
456
$
257
$
199
$
1,018
$
728
$
290
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impact of the following:
•an increase in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) of $237 million primarily related to the acquisitions of NuStar and Zenith European terminals; and
•a $45 million increase in Adjusted EBITDA related to unconsolidated affiliates due to the formation of the Permian joint venture; partially offset by
•a $58 million increase in operating expenses and a $24 million increase in selling, general and administrative expenses primarily related to the acquisitions of NuStar and Zenith European terminals.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impact of the following:
•an increase in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) of $488 million primarily related to the acquisitions of NuStar and Zenith European terminals; and
•a $45 million increase in Adjusted EBITDA related to unconsolidated affiliates due to the formation of the Permian joint venture; partially offset by
•a $113 million increase in operating expenses and a $133 million increase in selling, general and administrative expenses primarily related to the acquisitions of NuStar and Zenith European terminals.
Selling, general and administrative expenses, excluding non-cash compensation expense
(13)
(13)
—
(42)
(37)
(5)
Other
—
—
—
1
—
1
Segment Adjusted EBITDA
$
146
$
130
$
16
$
429
$
373
$
56
The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following:
•an increase of $20 million in segment margin primarily due to higher revenue-generating horsepower as a result of increased demand for compression services, higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts; partially offset by
•an increase of $4 million in operating expenses primarily due to an increase in employee costs associated with increased revenue-generating horsepower.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following:
•an increase of $78 million in segment margin primarily due to higher revenue-generating horsepower as a result of increased demand for compression services, higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts; partially offset by
•an increase of $18 million in operating expenses primarily due to an increase in employee costs associated with increased revenue-generating horsepower; and
•an increase of $5 million in selling, general and administrative expenses primarily due to an increase in professional fees.
Selling, general and administrative expenses, excluding non-cash compensation expense
(23)
(13)
(10)
(43)
(33)
(10)
Adjusted EBITDA related to unconsolidated affiliates
2
2
—
4
3
1
Other and eliminations
2
42
(40)
43
75
(32)
Segment Adjusted EBITDA
$
(28)
$
6
$
(34)
$
29
$
49
$
(20)
Amounts reflected in our all other segment primarily include:
•our natural gas marketing operations;
•our wholly owned natural gas compression operations; and
•our natural resources business.
Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impact of the following:
•a decrease of $49 million related to intersegment eliminations primarily driven by the formation of the Permian joint venture, which is consolidated in our crude oil transportation and services segment and also reflected as an unconsolidated affiliate in our investment in Sunoco LP segment; partially offset by
•an increase of $11 million in our natural gas marketing business due to higher gains from gas trading and storage positions; and
•an increase of $7 million from our compressor packaging business.
Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impact of the following:
•a decrease of $45 million related to intersegment eliminations primarily driven by the formation of the Permian joint venture, which is consolidated in our crude oil transportation and services segment and also reflected as an unconsolidated affiliate in our investment in Sunoco LP segment; partially offset by
•an increase of $29 million in our natural gas marketing business due to higher gains from gas trading and storage positions.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Our ability to satisfy obligations and pay distributions to unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.
We currently expect capital expenditures in 2024 to be within the following ranges (including capitalized interest and overhead and only our proportionate share for joint ventures, but excluding capital expenditures related to our investments in Sunoco LP and USAC):
Growth
Maintenance
Low
High
Low
High
Intrastate transportation and storage
$
45
$
50
$
55
$
60
Interstate transportation and storage
160
170
190
195
Midstream
870
940
390
395
NGL and refined products transportation and services
1,215
1,290
130
135
Crude oil transportation and services
290
310
140
145
All other (including eliminations)
220
240
65
70
Total capital expenditures
$
2,800
$
3,000
$
970
$
1,000
The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we have included these factors in our anticipated growth capital expenditures for each year.
We generally fund capital expenditures and distributions with cash flows from operating activities.
Sunoco LP currently expects to spend approximately $120 million in maintenance capital expenditures and at least $300 million in growth capital for the full year 2024.
USAC currently plans to spend between $27 million and $30 million in maintenance capital expenditures and between $240 million and $250 million in expansion capital expenditures for the full year 2024.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations”), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers.
Nine months ended September 30, 2024 compared to nine months ended September 30, 2023. Cash provided by operating activities during 2024 was $8.92 billion compared to $8.26 billion for 2023, and net income was $5.12 billion for 2024 and $3.73 billion for 2023. The difference between net income and net cash provided by operating activities for the nine months ended September 30, 2024 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and divestitures) of $190 million and other items totaling $3.39 billion, which includes non-cash items and items related to investing and financing activities that are included in net income.
The non-cash activity in 2024 and 2023 consisted primarily of depreciation, depletion and amortization of $3.79 billion and $3.23 billion, respectively, non-cash compensation expense of $113 million and $99 million, respectively, unfavorable
inventory valuation adjustments of $99 million and favorable inventory adjustments of $113 million, respectively, and deferred income taxes of $165 million and $187 million, respectively. Net income also included equity in earnings of unconsolidated affiliates of $285 million and $286 million for 2024 and 2023, respectively, as well as a $598 million gain on Sunoco LP’s sale of its West Texas assets in 2024.
Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $263 million in 2024 and $286 million in 2023.
Cash paid for interest, net of interest capitalized, was $1.84 billion and $1.54 billion for the nine months ended September 30, 2024 and 2023, respectively. Interest capitalized was $77 million and $53 million for the nine months ended September 30, 2024 and 2023, respectively.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash contributions to our joint ventures and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.
Nine months ended September 30, 2024 compared to nine months ended September 30, 2023. Cash used in investing activities during 2024 was $4.44 billion compared to $3.36 billion for 2023. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2024 were $2.64 billion compared to $2.39 billion for 2023. Additional detail related to our capital expenditures is provided in the table below.
In 2024, we paid $2.17 billion, net of cash received, for the WTG Midstream acquisition, we paid $84 million to acquire the outstanding noncontrolling interest in Edwards Lime Gathering, LLC, which is now a wholly owned subsidiary, and we also paid $219 million for other acquisitions. In 2024, Sunoco LP paid $209 million in cash for acquisitions of terminals and received $27 million in cash from the NuStar acquisition. Additionally, in 2024, Sunoco LP received cash proceeds of $990 million from its sale of West Texas assets. In 2023, we paid $930 million in cash for the Lotus Midstream acquisition and Sunoco LP paid $111 million in cash for the acquisition of terminals.
In 2024 and 2023, we received cash distributions from unconsolidated affiliates in excess of cumulative earnings of $60 million and $45 million, respectively, and we paid contributions to unconsolidated affiliates of $205 million and $5 million in cash, respectively.
The following is a summary of capital expenditures (including only our proportionate share for joint ventures, net of contributions in aid of construction costs) on an accrual basis for the nine months ended September 30, 2024:
Capital Expenditures Recorded During Period
Growth
Maintenance
Total
Intrastate transportation and storage
$
9
$
41
$
50
Interstate transportation and storage
103
129
232
Midstream
529
296
825
NGL and refined products transportation and services
846
83
929
Crude oil transportation and services
183
100
283
Investment in Sunoco LP
146
66
212
Investment in USAC
206
24
230
All other (including eliminations)
64
48
112
Total capital expenditures
$
2,086
$
787
$
2,873
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.
Nine months ended September 30, 2024 compared to nine months ended September 30, 2023. Cash used in financing activities during 2024 was $4.34 billion compared to $4.64 billion for 2023. During 2024, we had a net increase in our debt
level of $4.24 billion compared to a net decrease of $183 million for 2023. In 2024, we paid debt issuance costs of $142 million, paid $2.65 billion in cash for the redemption of our Series A, Series C, Series D and Series E Preferred Units and paid $37 million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units. In 2024, USAC paid $749 million in cash for investments in government securities in connection with the legal defeasance of senior notes and Sunoco LP paid $784 million in cash for the redemption of NuStar preferred units.
In 2024 and 2023, we paid distributions of $3.43 billion and $3.12 billion, respectively, to our partners. In 2024 and 2023, we paid distributions of $1.38 billion and $1.29 billion, respectively, to noncontrolling interests. In 2024 and 2023, we paid distributions of $51 million and $37 million, respectively, to our redeemable noncontrolling interests.
In 2024 and 2023, we received capital contributions of $637 million and $3 million, respectively, in cash from noncontrolling interests. In 2024, we received capital contributions of $2 million in cash from redeemable noncontrolling interests.
Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
September 30, 2024
December 31, 2023
Energy Transfer indebtedness:
Notes and debentures(1) (2)
$
46,834
$
43,016
Five-Year Credit Facility(2)
1,633
1,412
Subsidiary indebtedness:
Transwestern senior notes
250
250
Bakken Project senior notes(2)
850
1,850
Sunoco LP senior notes, bonds and lease-related obligations(2) (3)
7,311
3,194
USAC senior notes(2)
1,750
1,475
Sunoco LP credit facility
50
411
USAC credit facility
803
872
Other long-term debt
17
18
Net unamortized premiums, discounts and fair value adjustments
81
127
Deferred debt issuance costs
(321)
(237)
Total debt
59,258
52,388
Less: current maturities of long-term debt(4)
263
1,008
Long-term debt, less current maturities
$
58,995
$
51,380
(1)As of September 30, 2024, this balance included a total of $2.57 billion aggregate principal amount of senior notes due on or before September 30, 2025, which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
(2)See additional information below under “Recent Transactions.”
(3)Sunoco LP assumed $2.57 billion aggregate principal amount of NuStar senior notes and bonds in connection with the closing of the NuStar acquisition in May 2024.
(4)As of December 31, 2023, current maturities of long-term debt reflected on the Partnership’s consolidated balance sheet included $1.00 billion of senior notes issued by the Bakken Pipeline entities which were repaid in April 2024, as described below under “Recent Transactions.”
Recent Transactions
Energy Transfer Senior Notes Redemptions
During the first quarter of 2024, the Partnership redeemed its $1.15 billion aggregate principal amount of 5.875% senior notes due January 2024, $350 million aggregate principal amount of 4.90% senior notes due February 2024 and $82 million aggregate principal amount of 7.60% senior notes due February 2024 using proceeds from its January 2024 notes issuance described below.
During the second quarter of 2024, the Partnership redeemed its $500 million aggregate principal amount of 4.25% senior notes due April 2024, $750 million aggregate principal amount of 4.50% senior notes due April 2024, $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $600 million aggregate principal amount of 3.90% senior notes due May 2024 using cash on hand and proceeds from its Five-Year Credit Facility (defined below).
Bakken Project Debt Redemption
In April 2024, the Bakken Pipeline entities redeemed $1.00 billion aggregate principal amount of 3.90% senior notes due April 2024 using proceeds from member contributions, which included $637 million reflected as capital contributions from noncontrolling interests recorded in the Partnership’s consolidated financial statements.
Energy Transfer January 2024 Notes Issuance
In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% senior notes due 2034, $1.75 billion aggregate principal amount of 5.95% senior notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, redeem its outstanding Series C Preferred Units, Series D Preferred Units and Series E Preferred Units and for general partnership purposes.
Energy Transfer June 2024 Notes Issuance
In June 2024, the Partnership issued $1.00 billion aggregate principal amount of 5.25% senior notes due 2029, $1.25 billion aggregate principal amount of 5.60% senior notes due 2034, $1.25 billion aggregate principal amount of 6.05% senior notes due 2054 and $400 million aggregate principal amount of 7.125% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used part of the net proceeds to redeem its outstanding Series A Preferred Units. It also used the net proceeds to fund a portion of its previously announced acquisition of WTG Midstream, refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, and for general partnership purposes.
Sunoco LP April 2024 Notes Issuance
On April 30, 2024, Sunoco LP issued $750 million of 7.000% senior notes due 2029 and $750 million of 7.250% senior notes due 2032 in a private offering. Sunoco LP used the net proceeds from the offering to repay certain outstanding indebtedness of NuStar in connection with the merger between Sunoco LP and NuStar, to fund the redemption of NuStar's preferred units in connection with the merger and to pay offering fees and expenses.
NuStar Subordinated Note Redemption and Credit Facility Termination
During the second quarter of 2024, subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated NuStar's credit facility totaling $455 million.
USAC March 2024 Notes Issuance
In March 2024, USAC issued $1.00 billion aggregate principal amount of 7.125% senior notes due 2029. The net proceeds from this issuance were used to repay a portion of existing borrowings under USAC’s revolving credit facility, to redeem its $725 million aggregate principal amount of 6.875% senior notes due 2026, which constituted a legal defeasance under GAAP (the “Defeasance”), and for general partnership purposes.
The Defeasance required a cash outlay in the net amount of $749 million, which was used to purchase U.S. government securities. These securities generated sufficient cash upon maturity to fund interest payments on the senior notes due 2026 occurring between the effective date of the Defeasance through April 4, 2024, when the senior notes due 2026 were redeemed at par, as well as fund the redemption of the senior notes due 2026 in full. As a result of the Defeasance, USAC recognized a loss on early extinguishment of debt of $5 million for the three months ended March 31, 2024.
Credit Facilities and Commercial Paper
Five-Year Credit Facility
The Partnership’s revolving credit facility (the “Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures in April 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.
As of September 30, 2024, the Five-Year Credit Facility had $1.63 billion of outstanding borrowings, $1.58 billion of which consisted of commercial paper. The amount available for future borrowings was $3.34 billion, after accounting for outstanding
letters of credit in the amount of $31 million. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 5.04%.
Sunoco LP Facilities
As of September 30, 2024, Sunoco LP’s credit facility had $50 million of outstanding borrowings and $28 million in standby letters of credit and matures in May 2029 (as amended in May 2024). The amount available for future borrowings at September 30, 2024 was $1.42 billion. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 7.30%.
Upon the closing of the NuStar acquisition, the commitments under NuStar’s receivables financing agreement were reduced to zero during a suspension period, for which the period end has not been determined. As of September 30, 2024, this facility had no outstanding borrowings.
USAC Credit Facility
As of September 30, 2024, USAC’s credit facility, which matures in December 2026, had $803 million of outstanding borrowings and $1 million outstanding letters of credit. As of September 30, 2024, USAC’s credit facility had $796 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $642 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 7.50%.
Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our debt agreements as of September 30, 2024.
CASH DISTRIBUTIONS
Cash Distributions Paid by Energy Transfer
Under its Partnership Agreement, Energy Transfer will distribute all of its Available Cash, as defined in the Partnership Agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our General Partner to provide for future cash requirements.
Cash Distributions on Energy Transfer Common Units
Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2023 were as follows:
Cash Distributions on Energy Transfer Preferred Units
Distributions declared on the Energy Transfer Preferred Units were as follows:
Period Ended
Record Date
Payment Date
Series A
Series B (1)
Series C
Series D
Series E
Series F (1)
Series G (1)
Series H (1)
Series I (2)
December 31, 2023
February 1, 2024
February 15, 2024
$
24.710
$
33.125
$
0.6075
$
0.6199
$
0.475
$
—
$
—
$
—
$
0.2111
March 31, 2024
May 1, 2024
May 15, 2024
23.992
—
—
—
0.475
33.750
35.630
32.500
0.2111
June 30, 2024
August 1, 2024
August 15, 2024
9.879
33.125
—
—
—
—
—
—
0.2111
September 30, 2024
November 1, 2024
November 15, 2024
—
—
—
—
—
33.750
35.630
32.500
0.2111
(1)Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028.
(2)For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units will be paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.
Description of Energy Transfer Preferred Units
A summary of the distribution and redemption rights associated with the Energy Transfer Preferred Units is included in Note 9 in “Item 1. Financial Statements.”
Cash Distributions Paid by Subsidiaries
The Partnership’s consolidated financial statements include Sunoco LP and USAC, both of which are master limited partnerships, as well as other non-wholly owned consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter.
Cash Distributions Paid by Sunoco LP
Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2023 were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2023
February 7, 2024
February 20, 2024
$
0.8420
March 31, 2024
May 13, 2024
May 20, 2024
0.8756
June 30, 2024
August 9, 2024
August 19, 2024
0.8756
September 30, 2024
November 8, 2024
November 19, 2024
0.8756
Cash Distributions Paid by USAC
Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2023 were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2023
January 22, 2024
February 2, 2024
$
0.525
March 31, 2024
April 22, 2024
May 3, 2024
0.525
June 30, 2024
July 22, 2024
August 2, 2024
0.525
September 30, 2024
October 21, 2024
November 1, 2024
0.525
CRITICAL ACCOUNTING ESTIMATES
The Partnership’s critical accounting estimates are described in its Annual Report on Form 10-K filed with the SEC on February 16, 2024. We have not made any changes to the accounting policies involving critical accounting estimates
subsequent to the Form 10-K filing. Changes to any of the related estimate amounts are discussed in the notes to consolidated financial statements included in “Item 1. Financial Statements” in this quarterly report on Form 10-Q.
FORWARD-LOOKING STATEMENTS
This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
•the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;
•the actual amount of cash distributions by our subsidiaries to us;
•the volumes transported on our subsidiaries’ pipelines and gathering systems;
•the level of throughput in our subsidiaries’ processing and treating facilities;
•the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
•the prices and market demand for, and the relationship between, natural gas and NGLs;
•energy prices generally;
•impacts of world health events;
•the possibility of cyber and malware attacks;
•the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
•the general level of petroleum product demand and the availability and price of NGL supplies;
•the level of domestic oil, natural gas and NGL production;
•the availability of imported oil, natural gas and NGLs;
•actions taken by foreign oil and gas producing nations;
•the political and economic stability of petroleum producing nations;
•the effect of weather conditions on demand for oil, natural gas and NGLs;
•availability of local, intrastate and interstate transportation systems;
•the continued ability to find and contract for new sources of natural gas supply;
•availability and marketing of competitive fuels;
•the impact of energy conservation efforts;
•energy efficiencies and technological trends;
•governmental regulation and taxation;
•changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•competition from other midstream companies and interstate pipeline companies;
•loss of key personnel;
•loss of key natural gas producers or the providers of fractionation services;
•reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries’ pipelines and facilities;
•the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;
•the nonpayment or nonperformance by our subsidiaries’ customers;
•risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify continued development, delays in obtaining customers, increased costs of financing and regulatory, environmental, political and legal uncertainties that may affect the timing and cost of these projects;
•risks associated with the construction of new pipelines, treating and processing facilities or other facilities, or additions to our subsidiaries’ existing pipelines and their facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
•the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;
•a deterioration of the credit and capital markets;
•risks associated with the assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;
•the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
•changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations;
•the costs and effects of legal and administrative proceedings; and
•risks associated with a potential failure to successfully combine Sunoco LP’s business with that of NuStar, as well as the risks associated with a potential failure to successfully integrate our business with that of WTG Midstream.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 16, 2024. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II - Item 7A included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 16, 2024, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2023. Since December 31, 2023, there have been no material changes to our primary market risk exposures or how those exposures are managed.
Commodity Price Risk
The following table summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Dollar amounts are presented in millions.
September 30, 2024
December 31, 2023
Notional Volume
Fair Value Asset (Liability)
Effect of Hypothetical 10% Change
Notional Volume
Fair Value Asset (Liability)
Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
Natural Gas (BBtu):
Fixed Swaps/Futures
1,820
$
3
$
—
5,247
$
16
$
2
Basis Swaps IFERC/NYMEX
83,845
(3)
1
(46,975)
20
5
Swing Swaps IFERC
36,503
2
1
(97,728)
18
1
Options – Puts
—
—
—
1,900
(2)
—
Options – Calls
500
—
—
250
—
—
Forward Physical Contracts
2,138
3
2
(1,751)
8
1
Power (Megawatt):
Forwards
101,440
1
—
155,600
1
—
Futures
27,323
2
2
(464,897)
—
1
Options – Puts
—
—
—
136,000
—
—
Options – Calls
(33,600)
—
—
—
—
—
Crude (MBbls):
Forward Physical Contracts
(856)
(12)
2
(2,674)
8
5
Options – Puts
—
—
—
(15)
—
—
Options – Calls
—
—
—
(20)
—
—
NGL/Refined Products (MBbls):
Forwards/Swaps
(15,745)
53
47
(13,870)
20
43
Options – Puts
(12)
—
—
121
(1)
—
Options – Calls
(21)
—
—
(43)
(1)
—
Futures
(3,528)
(1)
26
(4,548)
17
38
Fair Value Hedging Derivatives
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX
(49,858)
(2)
2
(39,013)
1
1
Fixed Swaps/Futures
(49,858)
2
16
(39,013)
45
9
The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the
financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
Interest Rate Risk
As of September 30, 2024, we and our subsidiaries had $3.09 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $31 million annually. However, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.
The following table summarizes USAC’s interest rate swap which is no longer outstanding as of September 30, 2024, and which was not designated as a hedge for accounting purposes:
Term
Type
Notional Amount Outstanding
September 30, 2024
December 31, 2023
December 2025 (1)
Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR
$
—
$
700
(1)In August 2024, USAC elected to terminate the outstanding interest rate swap.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Under the supervision and with the participation of senior management, including the Co-Chief Executive Officers (Co-Principal Executive Officers) and the Chief Financial Officer (Principal Financial Officer) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Co-Principal Executive Officers and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2024 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Co-Principal Executive Officers and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
For information regarding legal proceedings, see our Annual Report on Form 10-K filed with the SEC on February 16, 2024 and Note 10 in “Item 1. Financial Statements” in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2024.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the following environmental proceedings were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings could result in monetary sanctions in excess of $0.3 million.
In January 2019, we received notice from the United States Department of Justice (“DOJ”) on behalf of the United States Environmental Protection Agency (“EPA”) that a civil penalty enforcement action was being pursued under the Clean Water Act for an estimated 450 barrel crude oil release from the Mid Valley Pipeline operated by SPLP and owned by Mid Valley Pipeline Company LLC (“MVPL”). The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete. In December of 2019, SPLP reached an agreement in principal with the USEPA regarding payment of a civil penalty. In September of 2024, after a public comment period, the United States District Court for the Southern District of Ohio (Western Division) entered a Consent Decree whereby SPLP and MVPL fully resolved both the civil penalty and alleged natural resource damages (NRD) which had been brought jointly by the DOJ, on behalf of trustees of the United States, and the Ohio Attorney General, on behalf of the trustees of the State of Ohio. Payments of approximately $565,000 for the civil penalty plus interest and approximately $1.9 million for natural resource damages, reimbursement and interest will be made within 30 days. Operation and maintenance activities associated with the restoration are expected to continue for several years.
On June 26, 2023, Plaintiffs Michael and Cecilia Weinman ("Plaintiffs") filed suit in Chester County, Tennessee, against MVPL and other Energy Transfer defendants asserting claims for negligence, trespass, and other tort claims and alleging damage to their property stemming from the crude oil release. Plaintiffs alleged actual monetary damages and punitive damages totaling $380 million. The Energy Transfer defendants were served on or around July 5, 2023, and timely filed a notice of removal of the lawsuit to federal court in the Western District of Tennessee Eastern Division on August 2, 2023. On August 8, 2023, plaintiffs filed a notice of voluntary dismissal of their lawsuit without prejudice. On or about August 7, 2024, plaintiffs refiled their suit with slight modifications and removing their negligence per se claim in Chester County, Tennessee. On or about August 27, 2024, the first two Energy Transfer defendants were served. On or about September 13, 2024, plaintiffs filed a notice of voluntary dismissal of their latest lawsuit without prejudice.
On June 15, 2023, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (collectively “NOPV”), CPF 4-2023-011-NOPV, identifying three probable violations with compliance order actions associated with two of them and civil penalties proposed in an amount totaling $2,473,912. The NOPV related to a PHMSA Accident Investigation Division investigation of a pigging incident which occurred on March 26, 2020 at the Partnership’s Borcher Station in Kansas and resulted in a fatality. The Partnership challenged PHMSA’s alleged violations and related civil penalties and compliance order actions contained in the NOPV. After an administrative hearing, which was held on April 24, 2024 before a PHMSA Presiding Official, the PHMSA Southwest Region recommended to remain relatively firm on the NOPV, with only a slightly reduced civil penalty of approximately $2.5 million. The Partnership is challenging this recommendation and filed its response on July 31, 2024.
Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II - Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.
For additional information required in this Item, see disclosure under the headings “Litigation and Contingencies” and “Environmental Matters” in Note 10 to our consolidated financial statements in “Item 1. Financial Statements,” which information is incorporated by reference into this Item.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors described in “Part I — Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 16, 2024 and in “Part II — Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024 filed with the SEC on May 9, 2024.
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements of Comprehensive Income; (iv) our Consolidated Statements of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements
104
Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
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.
ENERGY TRANSFER LP
By:
LE GP, LLC, its general partner
Date:
November 7, 2024
By:
/s/ A. Troy Sturrock
A. Troy Sturrock
Group Senior Vice President, Controller and Principal Accounting Officer
