NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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, 2021, filed with the SEC on February 18, 2022. 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.
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 AND DIVESTITURE TRANSACTIONS
Energy Transfer Canada Sale
In March 2022, the Partnership announced a definitive agreement to sell its 51% interest in Energy Transfer Canada. The sale is expected to result in cash proceeds to Energy Transfer of approximately C$340 million (US$272 million at the March 31, 2022 exchange rate), subject to certain purchase price adjustments. The transaction is expected to close by the third quarter of 2022.
Energy Transfer Canada’s assets and liabilities were reflected as held for sale in the Partnership’s consolidated balance sheet as of March 31, 2022. Energy Transfer Canada’s assets and operations are included in the all other segment. Energy Transfer Canada does not meet the criteria to be reflected as discontinued operations in the Partnership’s consolidated statement of operations. Based on the anticipated proceeds of the sale, during the three months ended March 31, 2022, the Partnership recorded a write-down on Energy Transfer Canada’s assets of $300 million, of which $164 million was allocated to noncontrolling interests and $136 million was reflected in net income attributable to partners.
The following table presents the assets and liabilities classified as held for sale in the Partnership’s consolidated balance sheet as of March 31, 2022:
| | | | | |
| March 31, 2022 |
Carrying amounts of assets held for sale | |
Cash and cash equivalents | $ | 4 | |
Accounts receivable, net | 101 | |
Other current assets | 3 | |
Property, plant and equipment, net | 1,451 | |
Other non-current assets, net | 20 | |
Intangible assets, net | 101 | |
Total assets held for sale | $ | 1,680 | |
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Carrying amounts of liabilities held for sale | |
Accounts payable | $ | 12 | |
Accrued and other current liabilities | 94 | |
Long-term debt, including current maturities | 441 | |
Other non-current liabilities, net | 193 | |
Redeemable noncontrolling interests | 291 | |
Total liabilities held for sale | $ | 1,031 | |
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Spindletop Assets Purchase
In March 2022, the Partnership purchased the membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for approximately $325 million.
Enable Acquisition
On December 2, 2021, the Partnership completed the acquisition of Enable. As of May 5, 2022, there has been no material change to the preliminary purchase price allocation disclosed in our Annual Report on Form 10-K for the year ended December 31, 2021.
Sunoco LP Acquisition
On April 1, 2022, Sunoco LP completed the acquisition of a transmix processing and terminal facility in Huntington, Indiana. As of March 31, 2022, the Partnership's consolidated balance sheet included a cash deposit of $264 million in other current assets related to this acquisition.
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 March 31, 2022 or December 31, 2021.
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, included in cash flows from operating activities is comprised as follows:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
Accounts receivable | $ | (2,412) | | | $ | (1,413) | |
Accounts receivable from related companies | (17) | | | (11) | |
Inventories | 153 | | | 30 | |
Other current assets | (119) | | | (12) | |
Other non-current assets, net | 45 | | | (31) | |
Accounts payable | 1,885 | | | 1,958 | |
Accounts payable to related companies | 7 | | | (7) | |
Accrued and other current liabilities | 230 | | | 194 | |
Other non-current liabilities | 61 | | | 51 | |
Derivative assets and liabilities, net | (153) | | | (226) | |
Net change in operating assets and liabilities, net of effects of acquisitions | $ | (320) | | | $ | 533 | |
Non-cash activities were as follows:
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| Three Months Ended March 31, |
| 2022 | | 2021 |
NON-CASH INVESTING AND FINANCING ACTIVITIES: | | | |
Accrued capital expenditures | $ | 475 | | | $ | 559 | |
| | | |
Lease assets obtained in exchange for new lease liabilities | 56 | | | 14 | |
Distribution reinvestment | 12 | | | 6 | |
4.INVENTORIES
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.
Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As of March 31, 2022 and December 31, 2021, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of zero and $121 million, respectively. The fuel inventory replacement cost was $112 million higher than the fuel inventory balance as of March 31, 2022. For the three months ended March 31, 2022 and 2021, 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 March 31, 2022 and 2021, the Partnership’s cost of products sold included favorable inventory adjustments of $120 million and $100 million, respectively, related to Sunoco LP’s LIFO inventory.
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| March 31, 2022 | | December 31, 2021 |
Natural gas, NGLs and refined products | $ | 1,379 | | | $ | 1,259 | |
Crude oil | 171 | | | 328 | |
Spare parts and other | 431 | | | 427 | |
Total inventories | $ | 1,981 | | | $ | 2,014 | |
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
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. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the three months ended March 31, 2022, 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 March 31, 2022 and December 31, 2021 based on inputs used to derive their fair values:
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| | | Fair Value Measurements at March 31, 2022 |
| Fair Value Total | | Level 1 | | Level 2 | | |
Assets: | | | | | | | |
| | | | | | | |
Commodity derivatives: | | | | | | | |
| | | | | | | |
Natural Gas: | | | | | | | |
Basis Swaps IFERC/NYMEX | $ | 4 | | | $ | 4 | | | $ | — | | | |
Swing Swaps IFERC | 2 | | | 2 | | | — | | | |
Fixed Swaps/Futures | 2 | | | 2 | | | — | | | |
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Forward Physical Contracts | 7 | | | — | | | 7 | | | |
Power: | | | | | | | |
Forwards | 52 | | | — | | | 52 | | | |
Futures | 9 | | | 9 | | | — | | | |
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NGLs – Forwards/Swaps | 383 | | | 383 | | | — | | | |
Refined Products – Futures | 23 | | | 23 | | | — | | | |
Crude – Forwards/Swaps | 20 | | | 20 | | | — | | | |
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Total commodity derivatives | 502 | | | 443 | | | 59 | | | |
Other non-current assets | 37 | | | 24 | | | 13 | | | |
Total assets | $ | 539 | | | $ | 467 | | | $ | 72 | | | |
Liabilities: | | | | | | | |
Interest rate derivatives | $ | (273) | | | $ | — | | | $ | (273) | | | |
Commodity derivatives: | | | | | | | |
Natural Gas: | | | | | | | |
Basis Swaps IFERC/NYMEX | (3) | | | (3) | | | — | | | |
Swing Swaps IFERC | (8) | | | (8) | | | — | | | |
Fixed Swaps/Futures | (64) | | | (64) | | | — | | | |
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Power: | | | | | | | |
Forwards | (37) | | | — | | | (37) | | | |
Futures | (19) | | | (19) | | | — | | | |
Options – Calls | (1) | | | (1) | | | — | | | |
| | | | | | | |
NGLs – Forwards/Swaps | (359) | | | (359) | | | — | | | |
Refined Products – Futures | (1) | | | (1) | | | — | | | |
Crude – Forwards/Swaps | (19) | | | (19) | | | — | | | |
Total commodity derivatives | (511) | | | (474) | | | (37) | | | |
Total liabilities | $ | (784) | | | $ | (474) | | | $ | (310) | | | |
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| | | Fair Value Measurements at December 31, 2021 |
| Fair Value Total | | Level 1 | | Level 2 | | |
Assets: | | | | | | | |
| | | | | | | |
Commodity derivatives: | | | | | | | |
| | | | | | | |
Natural Gas: | | | | | | | |
Basis Swaps IFERC/NYMEX | $ | 7 | | | $ | 7 | | | $ | — | | | |
Swing Swaps IFERC | 38 | | | 38 | | | — | | | |
Fixed Swaps/Futures | 26 | | | 26 | | | — | | | |
| | | | | | | |
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Forward Physical Contracts | 7 | | | — | | | 7 | | | |
Power: | | | | | | | |
Forwards | 17 | | | — | | | 17 | | | |
Futures | 6 | | | 6 | | | — | | | |
| | | | | | | |
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NGLs – Forwards/Swaps | 152 | | | 152 | | | — | | | |
Refined Products – Futures | 3 | | | 3 | | | — | | | |
| | | | | | | |
Crude – Forwards/Swaps | 16 | | | 16 | | | — | | | |
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Total commodity derivatives | 272 | | | 248 | | | 24 | | | |
Other non-current assets | 39 | | | 26 | | | 13 | | | |
Total assets | $ | 311 | | | $ | 274 | | | $ | 37 | | | |
Liabilities: | | | | | | | |
Interest rate derivatives | $ | (387) | | | $ | — | | | $ | (387) | | | |
Commodity derivatives: | | | | | | | |
Natural Gas: | | | | | | | |
Basis Swaps IFERC/NYMEX | (10) | | | (10) | | | — | | | |
Swing Swaps IFERC | (6) | | | (6) | | | — | | | |
Fixed Swaps/Futures | (9) | | | (9) | | | — | | | |
| | | | | | | |
| | | | | | | |
Forward Physical Contracts | (6) | | | — | | | (6) | | | |
Power: | | | | | | | |
Forwards | (15) | | | — | | | (15) | | | |
Futures | (4) | | | (4) | | | — | | | |
| | | | | | | |
NGLs – Forwards/Swaps | (140) | | | (140) | | | — | | | |
Refined Products – Futures | (18) | | | (18) | | | — | | | |
| | | | | | | |
Crude – Forwards/Swaps | (3) | | | (3) | | | — | | | |
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Total commodity derivatives | (211) | | | (190) | | | (21) | | | |
Total liabilities | $ | (598) | | | $ | (190) | | | $ | (408) | | | |
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of March 31, 2022 were $51.53 billion and $49.92 billion, respectively, including a fair value of $441 million and a carrying amount of $441 million related to Energy Transfer Canada debt reflected in liabilities held for sale on the Partnership’s consolidated balance sheet. As of December 31, 2021, the aggregate fair value and carrying amount of our consolidated debt obligations were $54.97 billion and $49.70 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.
6.NET INCOME PER COMMON UNIT
A reconciliation of income or loss and weighted average units used in computing basic and diluted income per common unit is as follows:
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| | | Three Months Ended March 31, |
| | | | | 2022 | | 2021 |
Net income | | | | | $ | 1,487 | | | $ | 3,641 | |
Less: Net income attributable to noncontrolling interests | | | | | 205 | | | 341 | |
Less: Net income attributable to redeemable noncontrolling interests | | | | | 13 | | | 12 | |
Net income, net of noncontrolling interests | | | | | 1,269 | | | 3,288 | |
Less: General Partner’s interest in income | | | | | 1 | | | 3 | |
Less: Preferred Unitholders’ interest in income | | | | | 106 | | | — | |
Income available to Common Unitholders | | | | | $ | 1,162 | | | $ | 3,285 | |
Basic Income per Common Unit: | | | | | | | |
Weighted average common units | | | | | 3,083.5 | | | 2,702.8 | |
Basic income per common unit | | | | | $ | 0.38 | | | $ | 1.22 | |
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Diluted Income per Common Unit: | | | | | | | |
Income available to Common Unitholders | | | | | $ | 1,162 | | | $ | 3,285 | |
Dilutive effect of equity-based compensation of subsidiaries (1) | | | | | 1 | | | — | |
Diluted income available to Common Unitholders | | | | | $ | 1,161 | | | $ | 3,285 | |
Weighted average common units | | | | | 3,083.5 | | | 2,702.8 | |
Dilutive effect of unvested restricted unit awards (1) | | | | | 17.0 | | | 5.8 | |
Weighted average common units, assuming dilutive effect of unvested restricted unit awards | | | | | 3,100.5 | | | 2,708.6 | |
Diluted income per common unit | | | | | $ | 0.37 | | | $ | 1.21 | |
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(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.
7.DEBT OBLIGATIONS
Senior Notes
In February 2022, the Partnership redeemed its $300 million aggregate principal amount of 4.65% Senior Notes due February 2022 using proceeds from its Five-Year Credit Facility (defined below).
In April 2022, Dakota Access redeemed its $650 million aggregate principal amount of 3.625% Senior Notes due April 2022 using proceeds from contributions made by the partners of Dakota Access. The Partnership indirectly owns 36.4% of the ownership interests in Dakota Access.
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, as amended in April 2022, matures on April 11, 2027. The amended 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 March 31, 2022, the Five-Year Credit Facility had $2.95 billion of outstanding borrowings, of which $1.45 billion consisted of commercial paper. The amount available for future borrowings was $2.02 billion, after accounting for outstanding letters of credit in the amount of $30 million. The weighted average interest rate on the total amount outstanding as of March 31, 2022 was 1.32%.
Sunoco LP Credit Facility
As of March 31, 2022, the Sunoco LP Credit Facility (as described in the Partnership’s Form 10-K filed on February 18, 2022) had $1.00 billion of outstanding borrowings and $6 million in standby letters of credit and, as amended in April
2022, matures in April 2027. The amount available for future borrowings at March 31, 2022 was $494 million. The weighted average interest rate on the total amount outstanding as of March 31, 2022 was 2.40%.
USAC Credit Facility
As of March 31, 2022, USAC had $566 million of outstanding borrowings and no outstanding letters of credit under the USAC Credit Facility (as described in the Partnership’s Form 10-K filed on February 18, 2022). As of March 31, 2022, USAC had $1.03 billion of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $224 million. The weighted average interest rate on the total amount outstanding as of March 31, 2022 was 3.17%.
Energy Transfer Canada Credit Facilities
As of March 31, 2022, the Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility (both as described in the Partnership’s Form 10-K filed on February 18, 2022) had outstanding borrowings of C$308 million and C$6 million, respectively (US$247 million and US$5 million, respectively, at the March 31, 2022 exchange rate). As of March 31, 2022, the KAPS Facility had outstanding borrowings of C$241 million (US$193 million at the March 31, 2022 exchange rate). The Energy Transfer Canada credit facilities are reflected in liabilities held for sale on the Partnership’s consolidated balance sheet as of March 31, 2022.
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 March 31, 2022. For the quarter ended March 31, 2022, our leverage ratio, as calculated pursuant to the covenant related to our revolving credit facility, was 3.55x.
8.REDEEMABLE NONCONTROLLING INTERESTS
Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of March 31, 2022 included a balance of $477 million related to the USAC Preferred Units and a balance of $16 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. As of December 31, 2021, redeemable noncontrolling interests included a balance of $477 million related to the USAC Preferred Units, a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership, and a balance of $291 million related to Energy Transfer Canada preferred shares. The Energy Transfer Canada preferred shares were reflected in current liabilities held for sale as of March 31, 2022.
For additional information on the Partnership’s redeemable noncontrolling interest, see Note 7 to the Partnership’s Form 10-K filed on February 18, 2022.
9.EQUITY
Energy Transfer Common Units
Changes in Energy Transfer common units during the three months ended March 31, 2022 were as follows:
| | | | | |
| Number of Units |
Number of common units at December 31, 2021 | 3,082.5 | |
Common units issued under the distribution reinvestment plan | 1.2 | |
| |
Common units vested under equity incentive plans and other | 1.0 | |
Number of common units at March 31, 2022 | 3,084.7 | |
Energy Transfer Repurchase Program
During the three months ended March 31, 2022, Energy Transfer did not repurchase any of its common units under its current buyback program. As of March 31, 2022, $880 million remained available to repurchase under the current program.
Energy Transfer Distribution Reinvestment Program
During the three months ended March 31, 2022, distributions of $12 million were reinvested under the distribution reinvestment program. As of March 31, 2022, a total of 16 million Energy Transfer common units remained available to be issued under the existing registration statement 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, 2021 were as follows:
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Quarter Ended | | Record Date | | Payment Date | | Rate |
December 31, 2021 | | February 8, 2022 | | February 18, 2022 | | $ | 0.1750 | |
March 31, 2022 | | May 9, 2022 | | May 19, 2022 | | 0.2000 | |
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Energy Transfer Preferred Units
In connection with the merger of Energy Transfer, ETO, and certain of ETO’s subsidiaries (the “Rollup Mergers”) on April 1, 2021, as described in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021, all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with identical distribution and redemption rights.
As of March 31, 2022, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units and 900,000 Series H Preferred Units.
The following table summarizes changes in the Energy Transfer Preferred Units:
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| Preferred Unitholders | | |
| Series A | | Series B | | Series C | | Series D | | Series E | | Series F | | Series G | | Series H | | Total |
Balance, December 31, 2021 | $ | 958 | | | $ | 556 | | | $ | 440 | | | $ | 434 | | | $ | 786 | | | $ | 496 | | | $ | 1,488 | | | $ | 893 | | | $ | 6,051 | |
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Distributions to partners | (30) | | | (18) | | | (8) | | | (9) | | | (15) | | | — | | | — | | | — | | | (80) | |
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Net income | 15 | | | 9 | | | 8 | | | 9 | | | 15 | | | 8 | | | 27 | | | 15 | | | 106 | |
Balance, March 31, 2022 | $ | 943 | | | $ | 547 | | | $ | 440 | | | $ | 434 | | | $ | 786 | | | $ | 504 | | | $ | 1,515 | | | $ | 908 | | | $ | 6,077 | |
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Cash Distributions on Energy Transfer Preferred Units
Distributions declared on the Energy Transfer Preferred Units were as follows:
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Period Ended | | Record Date | | Payment Date | | Series A (1) | | Series B (1) | | Series C | | Series D | | Series E | | Series F (1) | | Series G (1) | | Series H (1) | |
December 31, 2021 | | February 1, 2022 | | February 15, 2022 | | $ | 31.250 | | | $ | 33.125 | | | $ | 0.4609 | | | $ | 0.4766 | | | $ | 0.475 | | | $ | — | | | $ | — | | | $ | — | | |
March 31, 2022 | | May 2, 2022 | | May 16, 2022 | | — | | | — | | | 0.4609 | | | 0.4766 | | | 0.475 | | | 33.750 | | | 35.625 | | | 32.500 | | |
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(1)Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.
Noncontrolling Interests
For the three months ended March 31, 2022, noncontrolling interests included the ETO preferred units, which were converted into Energy Transfer Preferred Units on April 1, 2021 in connection with the Rollup Mergers, as described in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021.
The Partnership’s consolidated financial statements also include noncontrolling interests in Sunoco LP and USAC, both of which are publicly traded master limited partnerships, as well as other less-than-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, 2021 were as follows:
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Quarter Ended | | Record Date | | Payment Date | | Rate |
December 31, 2021 | | February 8, 2022 | | February 18, 2022 | | $ | 0.8255 | |
March 31, 2022 | | May 9, 2022 | | May 19, 2022 | | 0.8255 | |
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USAC Cash Distributions
Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2021 were as follows:
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Quarter Ended | | Record Date | | Payment Date | | Rate |
December 31, 2021 | | January 24, 2022 | | February 4, 2022 | | $ | 0.525 | |
March 31, 2022 | | April 25, 2022 | | May 6, 2022 | | 0.525 | |
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| | | | | | |
USAC’s Warrant Exercise
As of March 31, 2022 and December 31, 2021, USAC had outstanding two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. On April 27, 2022, the tranche of warrants with the right to purchase 5,000,000 common units with a strike price of $17.03 per common unit was exercised in full by the holders. The exercise of the warrants was net settled by USAC for 534,308 of its common units.
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
| | | | | | | | | | | |
| March 31, 2022 | | December 31, 2021 |
Available-for-sale securities | $ | 14 | | | $ | 19 | |
Foreign currency translation adjustment | 22 | | | 13 | |
Actuarial loss related to pensions and other postretirement benefits | 12 | | | 5 | |
Investments in unconsolidated affiliates, net | 1 | | | (11) | |
| | | |
Total AOCI, net of tax | 49 | | | 26 | |
Amounts attributable to noncontrolling interest | (6) | | | (3) | |
Total AOCI included in partners’ capital, net of tax | $ | 43 | | | $ | 23 | |
10.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
Winter Storm Impacts
Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income and also affected the results of operations in certain segments. The recognition of the impacts of Winter Storm Uri during 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.
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 is set to commence on March 6, 2023.
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 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 March 16, 2022, the United States District Court requested briefing from the parties on whether it could stay the FERC ALJ proceedings, while also staying the federal court litigation, until the Supreme Court decides a case that could affect the outcome of the federal lawsuit. The parties filed those briefs on April 5, 2022. The parties have agreed to request a status conference before the federal district court. 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. Enforcement Staff has provided Rover with a notice pursuant to Section 1b.19 of the FERC regulations that Enforcement Staff intends to recommend that the FERC pursue an enforcement action against Rover and the Partnership. The company disagrees with Enforcement Staff’s findings and intends to vigorously defend against any potential penalty. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover to show cause why it 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 filed its answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. 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.
Other FERC Proceedings
By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently 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 NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding. This matter remains pending before the FERC.
In May 2021, the FERC commenced an audit of SPLP for the period from January 1, 2018 to present to evaluate SPLP’s compliance with its FERC oil tariffs, the accounting requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s Form No. 6 reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, Energy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enter 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 table below reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2022 | | 2021 |
ROW expense | | | | | $ | 14 | | | $ | 6 | |
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. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise 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 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 March 31, 2022 and December 31, 2021, accruals of approximately $163 million and $144 million, respectively, were reflected on our consolidated balance sheets related to contingencies 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 $600 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.
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 Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“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.
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. It is anticipated that the completion and publication of a draft EIS will not occur until the end of April 2022 at the earliest. 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.
The pipeline continues to operate pending completion of the EIS. The USACE now estimates that the EIS will be complete by the end of 2022 or early 2023. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Dakota Access pipelines; however, Energy Transfer expects 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.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL LLC’s (“Lone Star”), now known as Energy Transfer GC NGLs LLC, 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 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 March 31, 2022, Sunoco Defendants are defendants in four cases, including one case initiated by the State of Maryland, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco, and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. (“ETMT”).
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.
Litigation Filed By or Against Williams
In April and May 2016, The William Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, LE GP, LLC, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Energy Transfer Defendants”), alleging that Energy Transfer Defendants breached their obligations under the Energy Transfer-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that Energy Transfer Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) issuing the Partnership’s Series A convertible preferred units (the “Issuance”), and (c) making allegedly untrue representations and warranties in the Merger Agreement.
After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of Energy Transfer Defendants and issued a declaratory judgment that Energy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims related to the Issuance nor the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. Energy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to Energy Transfer for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause.
Trial was held regarding the parties’ amended claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court did not reach a decision on Williams’ tax-related claims. A final judgment has not yet been entered. Energy Transfer Defendants’ deadline to file an appeal to the Delaware Supreme Court has not yet been set.
Energy Transfer Defendants cannot predict the ultimate outcome of the Williams Litigation nor can the Energy Transfer Defendants predict the amount of time and expense that will be required to resolve the Williams Litigation.
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 seeking to recover 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, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for 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.
Revolution
On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries.
The Pennsylvania Office of Attorney General (“AG”) has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.
On February 2, 2022, the AG issued a press release related to the Revolution pipeline, and released a Grand Jury Presentment and filed a criminal complaint against ETC Northeast Pipeline, LLC in Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania, with respect to nine misdemeanor charges related to various alleged violations of the Clean Streams Law associated with the construction of the Revolution pipeline. The Partnership will defend itself vigorously against these charges.
Chester County, Pennsylvania Investigation
In December 2018, the former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines.
Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the prescribed time period.
In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.
On April 22, 2021, the Chester County DA filed a Complaint and Consent Decree in the Court of Common Pleas of Chester County, Pennsylvania constituting a settlement agreement between the Chester County DA and the Partnership. A status conference was held on May 10, 2021, and an Amended Consent Decree was filed on June 16, 2021, which was approved and entered by the Court on December 20, 2021.
Delaware County, Pennsylvania Investigation
On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the Pennsylvania Attorney General’s Office (the “AG”), at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the AG served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. The Partnership has complied with the subpoena. On October 5, 2021, the AG held a press conference related to the Mariner East pipelines, released a Grand Jury Presentment and subsequently filed a criminal complaint against Energy Transfer in the Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania with respect to 47 misdemeanor charges related to the discharge of industrial waste and pollution and one felony charge related to the failure to report information related to the discharges. The Partnership will defend itself vigorously against these charges. On October 13, 2021, the AG announced that he is running for Governor of Pennsylvania.
Shareholder Litigation Regarding Pennsylvania Pipeline Construction
Four purported unitholders of Energy Transfer filed derivative actions against various past and current 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 limited partnership agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania. 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.); and King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.). 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 McCrea and Matthew 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. Fact discovery is ongoing. 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 (R&M), LLC (now known as Energy Transfer R&M) and 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 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 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. Sunoco 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. 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. However, ETMT intends to vigorously appeal the entirety of the Order, including an appeal of the partial denial of the injunction and denial of the Motion to Modify to the 10th Circuit. Additionally, a Petition for Writ of Certiorari was filed with the United States Supreme Court on April 28, 2022 seeking review of the 10th Circuit’s dismissal of ETMT’s appeal.
Energy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.
On April 8, 2022, Energy Transfer LP (“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,” and together with Culberson and Culberson Equity, “Defendants”). 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 Defendants asserting claims for declaratory judgment and breach of contract. Plaintiffs contend that Defendants 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 Defendants' put notice is void. Defendants have answered the lawsuit. Culberson also filed a counterclaim for breach of contract. The lawsuit is pending in the 193rd Judicial District Court in Dallas County, Texas. On April 27, 2022, Defendants filed an application for a temporary restraining order, temporary injunction, and permanent injunction. The Court held a hearing on the application on April 28, and denied the injunction. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.
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. 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 March 31, 2022, the Partnership had been named as a PRP at approximately 34 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 table below 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 require disclosure in our consolidated financial statements.
| | | | | | | | | | | |
| March 31, 2022 | | December 31, 2021 |
Current | $ | 50 | | | $ | 46 | |
Non-current | 239 | | | 247 | |
Total environmental liabilities | $ | 289 | | | $ | 293 | |
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 three months ended March 31, 2022 and 2021, the Partnership recorded $4 million and $6 million, respectively, of expenditures related to environmental cleanup programs.
Our pipeline operations are subject to regulation by the DOT 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 potential exists that 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 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 but 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, 2021 | $ | 459 | |
Additions | 266 | |
Revenue recognized | (209) | |
Other | (10) | |
Balance, March 31, 2022 | $ | 506 | |
| |
Balance, December 31, 2020 | $ | 290 | |
Additions | 249 | |
Revenue recognized | (165) | |
Balance, March 31, 2021 | $ | 374 | |
The balances of Sunoco LP’s contract assets and contract liabilities were as follows:
| | | | | | | | | | | | | |
| March 31, 2022 | | December 31, 2021 | | |
Contract balances: | | | | | |
Contract assets | $ | 168 | | | $ | 157 | | | |
Accounts receivable from contracts with customers | 637 | | | 463 | | | |
| | | | | |
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 expected contract consideration 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 table below.
As of March 31, 2022, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $40.94 billion, of which $1.32 billion related to Energy Transfer Canada. The Partnership expects to recognize this amount as revenue within the time bands illustrated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ending December 31, | | | | |
| | 2022 | | | | | | | | |
| | (remainder) | | 2023 | | 2024 | | Thereafter | | Total |
Revenue expected to be recognized on contracts with customers existing as of March 31, 2022 | | $ | 5,170 | | | $ | 6,202 | | | $ | 5,347 | | | $ | 24,222 | | | $ | 40,941 | |
12.DERIVATIVE ASSETS AND LIABILITIES
Commodity Price Risk
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 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 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 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:
| | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2022 | | December 31, 2021 |
| Notional Volume | | Maturity | | Notional Volume | | Maturity |
Mark-to-Market Derivatives | | | | | | | |
(Trading) | | | | | | | |
Natural Gas (BBtu): | | | | | | | |
Fixed Swaps/Futures | 605 | | | 2022-2023 | | 585 | | | 2022-2023 |
Basis Swaps IFERC/NYMEX (1) | (14,598) | | | 2022 | | (66,665) | | | 2022 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Power (Megawatt): | | | | | | | |
Forwards | 709,920 | | | 2023-2029 | | 653,000 | | | 2023-2029 |
Futures | (555,582) | | | 2022-2024 | | (604,920) | | | 2022-2023 |
Options – Puts | 119,200 | | | 2022-2023 | | (7,859) | | | 2022 |
Options – Calls | (238,400) | | | 2022-2023 | | (30,932) | | | 2022 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
(Non-Trading) | | | | | | | |
Natural Gas (BBtu): | | | | | | | |
Basis Swaps IFERC/NYMEX | 13,505 | | | 2022-2023 | | 6,738 | | | 2022-2023 |
Swing Swaps IFERC | (27,273) | | | 2022-2023 | | (106,333) | | | 2022-2023 |
Fixed Swaps/Futures | (2,238) | | | 2022-2023 | | (63,898) | | | 2022-2023 |
Forward Physical Contracts | (16,437) | | | 2022-2024 | | (5,950) | | | 2023 |
| | | | | | | |
NGLs (MBbls) – Forwards/Swaps | 10,709 | | | 2022-2024 | | 8,493 | | | 2022-2024 |
Crude (MBbls) – Forwards/Swaps | 2,639 | | | 2022-2023 | | 3,672 | | | 2022-2023 |
Refined Products (MBbls) – Futures | (4,225) | | | 2022-2024 | | (3,349) | | | 2022-2023 |
| | | | | | | |
Fair Value Hedging Derivatives | | | | | | | |
(Non-Trading) | | | | | | | |
Natural Gas (BBtu): | | | | | | | |
Basis Swaps IFERC/NYMEX | (18,675) | | | 2022 | | (40,533) | | | 2022 |
Fixed Swaps/Futures | (18,675) | | | 2022 | | (40,533) | | | 2022 |
Hedged Item – Inventory | 18,675 | | | 2022 | | 40,533 | | | 2022 |
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
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 utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
| | | | | | | | | | | | | | | | | | | | |
Term | | Type(1) | | Notional Amount Outstanding |
March 31, 2022 | | December 31, 2021 |
| | | | | | |
July 2022(2) | | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | | $ | 400 | | | $ | 400 | |
July 2023(2) | | Forward-starting to pay a fixed rate of 3.78% and receive a floating rate | | 200 | | | 200 | |
July 2024(2) | | Forward-starting to pay a fixed rate of 3.88% and receive a floating rate | | 200 | | | 200 | |
(1)Floating rates are based on 3-month LIBOR.
(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
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.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, 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 are 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 our statement of operations or statement of comprehensive income (loss).
Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value of Derivative Instruments |
| | Asset Derivatives | | Liability Derivatives |
| | March 31, 2022 | | December 31, 2021 | | March 31, 2022 | | December 31, 2021 |
Derivatives designated as hedging instruments: | | | | | | | | |
Commodity derivatives (margin deposits) | | $ | 15 | | | $ | 46 | | | $ | (37) | | | $ | (3) | |
| | 15 | | | 46 | | | (37) | | | (3) | |
Derivatives not designated as hedging instruments: | | | | | | | | |
Commodity derivatives (margin deposits) | | 408 | | | 173 | | | (435) | | | (156) | |
Commodity derivatives | | 79 | | | 53 | | | (39) | | | (52) | |
Interest rate derivatives | | — | | | — | | | (273) | | | (387) | |
| | 487 | | | 226 | | | (747) | | | (595) | |
Total derivatives | | $ | 502 | | | $ | 272 | | | $ | (784) | | | $ | (598) | |
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 | | March 31, 2022 | | December 31, 2021 | | March 31, 2022 | | December 31, 2021 |
Derivatives without offsetting agreements | | Derivative liabilities | | $ | — | | | $ | — | | | $ | (273) | | | $ | (387) | |
Derivatives in offsetting agreements: | | | | | | | | |
OTC contracts | | Derivative assets (liabilities) | | 79 | | | 53 | | | (39) | | | (52) | |
Broker cleared derivative contracts | | Other current assets (liabilities) | | 423 | | | 219 | | | (472) | | | (159) | |
Total gross derivatives | | 502 | | | 272 | | | (784) | | | (598) | |
Offsetting agreements: | | | | | | | | |
Collateral paid to OTC counterparties | | Other current assets | | (38) | | | — | | | 38 | | | — | |
Counterparty netting | | Derivative assets (liabilities) | | (389) | | | (43) | | | 389 | | | 43 | |
Counterparty netting | | Other current assets (liabilities) | | — | | | (150) | | | — | | | 150 | |
Total net derivatives | | $ | 75 | | | $ | 79 | | | $ | (357) | | | $ | (405) | |
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 March 31, |
| | | | | | | 2022 | | 2021 |
Derivatives not designated as hedging instruments: | | | | | | | | | |
Commodity derivatives – Trading | Cost of products sold | | | | | | $ | 17 | | | $ | 3 | |
Commodity derivatives – Non-trading | Cost of products sold | | | | | | (17) | | | (42) | |
| | | | | | | | | |
Interest rate derivatives | Gains (losses) on interest rate derivatives | | | | | | 114 | | | 194 | |
| | | | | | | | | |
Total | | | | | | | $ | 114 | | | $ | 155 | |
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. 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. Inventory 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.
The following tables present financial information by segment:
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2022 | | 2021 |
Revenues: | | | | | | | |
Intrastate transportation and storage: | | | | | | | |
Revenues from external customers | | | | | $ | 1,475 | | | $ | 3,976 | |
Intersegment revenues | | | | | 157 | | | 924 | |
| | | | | 1,632 | | | 4,900 | |
Interstate transportation and storage: | | | | | | | |
Revenues from external customers | | | | | 547 | | | 501 | |
Intersegment revenues | | | | | 19 | | | 24 | |
| | | | | 566 | | | 525 | |
Midstream: | | | | | | | |
Revenues from external customers | | | | | 1,131 | | | 578 | |
Intersegment revenues | | | | | 2,794 | | | 2,094 | |
| | | | | 3,925 | | | 2,672 | |
NGL and refined products transportation and services: | | | | | | | |
Revenues from external customers | | | | | 5,245 | | | 3,397 | |
Intersegment revenues | | | | | 1,032 | | | 593 | |
| | | | | 6,277 | | | 3,990 | |
Crude oil transportation and services: | | | | | | | |
Revenues from external customers | | | | | 5,926 | | | 3,500 | |
Intersegment revenues | | | | | — | | | — | |
| | | | | 5,926 | | | 3,500 | |
Investment in Sunoco LP: | | | | | | | |
Revenues from external customers | | | | | 5,397 | | | 3,469 | |
Intersegment revenues | | | | | 5 | | | 2 | |
| | | | | 5,402 | | | 3,471 | |
Investment in USAC: | | | | | | | |
Revenues from external customers | | | | | 159 | | | 155 | |
Intersegment revenues | | | | | 4 | | | 3 | |
| | | | | 163 | | | 158 | |
All other: | | | | | | | |
Revenues from external customers | | | | | 611 | | | 1,419 | |
Intersegment revenues | | | | | 104 | | | 93 | |
| | | | | 715 | | | 1,512 | |
Eliminations | | | | | (4,115) | | | (3,733) | |
Total revenues | | | | | $ | 20,491 | | | $ | 16,995 | |
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2022 | | 2021 |
Segment Adjusted EBITDA: | | | | | | | |
Intrastate transportation and storage | | | | | $ | 444 | | | $ | 2,813 | |
Interstate transportation and storage | | | | | 453 | | | 453 | |
Midstream | | | | | 807 | | | 288 | |
NGL and refined products transportation and services | | | | | 700 | | | 647 | |
Crude oil transportation and services | | | | | 593 | | | 510 | |
Investment in Sunoco LP | | | | | 191 | | | 157 | |
Investment in USAC | | | | | 98 | | | 100 | |
All other | | | | | 54 | | | 72 | |
Adjusted EBITDA (consolidated) | | | | | 3,340 | | | 5,040 | |
Depreciation, depletion and amortization | | | | | (1,028) | | | (954) | |
Interest expense, net of interest capitalized | | | | | (559) | | | (589) | |
Impairment losses | | | | | (300) | | | (3) | |
Gains on interest rate derivatives | | | | | 114 | | | 194 | |
Non-cash compensation expense | | | | | (36) | | | (28) | |
Unrealized gains (losses) on commodity risk management activities | | | | | (45) | | | 46 | |
Inventory valuation adjustments (Sunoco LP) | | | | | 120 | | | 100 | |
Losses on extinguishments of debt | | | | | — | | | (7) | |
Adjusted EBITDA related to unconsolidated affiliates | | | | | (125) | | | (123) | |
Equity in earnings of unconsolidated affiliates | | | | | 56 | | | 55 | |
| | | | | | | |
Other, net | | | | | (59) | | | (15) | |
Income before income tax expense | | | | | 1,478 | | | 3,716 | |
Income tax (expense) benefit | | | | | 9 | | | (75) | |
| | | | | | | |
| | | | | | | |
Net income | | | | | $ | 1,487 | | | $ | 3,641 | |