Energy Transfer Reports Second Quarter 2021 Results

Energy Transfer LP (NYSE:ET) (“ET” or the “Partnership”) today reported financial results for the quarter ended June 30, 2021.

ET reported net income attributable to partners for the three months ended June 30, 2021 of $626 million, an increase of $273 million compared to the same period the previous year. For the three months ended June 30, 2021, net income per limited partner unit (basic and diluted) was $0.20 per unit.

Adjusted EBITDA for the three months ended June 30, 2021 was $2.62 billion compared to $2.44 billion for the three months ended June 30, 2020. The increase was largely driven by improved earnings from several of the Partnership’s core segments.

Distributable Cash Flow attributable to partners, as adjusted, for the three months ended June 30, 2021 was $1.39 billion compared to $1.27 billion for the three months ended June 30, 2020. The increase in distributable cash flow was primarily due to the higher Adjusted EBITDA.

Key accomplishments and current developments:

Operational

• In June 2021, the Partnership commenced service on its Cushing to Nederland expansion project, which utilizes a crude oil pipeline previously servicing the Permian Basin. The new service provides connectivity to transport crude oil barrels from the Denver-Julesburg Basin and Cushing, Oklahoma to ET’s Nederland, Texas terminal.
• During the second quarter of 2021, the Partnership continued to ramp up volumes at its newly expanded Nederland, Texas terminal. As a result, when combined with Energy Transfer’s Marcus Hook Terminal on the east coast, ET exported more NGLs than any other company worldwide in the months of May and June.
• The Partnership recently commenced work on its Permian Bridge project, which converts existing pipeline assets to connect ET’s natural gas gathering and processing assets in the Delaware Basin with Midland Basin assets.

Strategic

• In May 2021, ET’s acquisition of Enable Midstream Partners, LP (“Enable”), which was announced in February 2021, was approved by a vote of the Enable unitholders. ET and Enable continue to work toward obtaining Hart-Scott-Rodino Act (“HSR”) clearance for the merger. ET continues to expect the transaction to close in the second half of 2021.
• In June 2021, ET’s patented Dual Drive Technologies natural gas compression system was awarded a 2021 GPA Midstream Environmental Excellence Award for its impact on reducing CO2 emissions.
• In July 2021, ET signed a memorandum of understanding with the Republic of Panama to study the feasibility of a proposed Trans-Panama Gateway LPG pipeline and the potential creation of a new strategically located NGL hub.

Financial

• During the second quarter of 2021, the Partnership reduced outstanding debt by approximately $1.5 billion, utilizing cash from operations and proceeds from its recent $900 million Series H preferred unit offering. Year-to-date in 2021, ET has reduced its long-term debt by approximately $5.2 billion.
• In May 2021, two credit rating agencies affirmed ET’s investment grade ratings and revised ET’s outlook from negative to stable.
• As of June 30, 2021, the Partnership’s $6.00 billion revolving credit facilities had an aggregate $5.02 billion of available capacity, and the leverage ratio, as defined by the credit agreement, was 3.14x.
• For the three months ended June 30, 2021, the Partnership invested approximately $355 million on growth capital expenditures.
• In July 2021, ET announced a quarterly distribution of $0.1525 per unit ($0.61 annualized) on ET common units for the quarter ended June 30, 2021.

ET benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership’s multiple segments generate high-quality, balanced earnings with no single segment contributing more than 30% of the Partnership’s consolidated Adjusted EBITDA for the three months ended June 30, 2021. The vast majority of the Partnership’s segment margins are fee-based and therefore have limited commodity price sensitivity.

Conference Call information:

The Partnership has scheduled a conference call for 3:30 p.m. Central Time, Tuesday, August 3, 2021 to discuss its second quarter 2021 results and provide a partnership update. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on the Partnership’s website for a limited time.

Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with a strategic footprint in all of the major domestic production basins. ET is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (“NGL”) and refined product transportation and terminalling assets; NGL fractionation; and various acquisition and marketing assets. ET also owns Lake Charles LNG Company, as well as the general partner interests, the incentive distribution rights and 28.5 million common units of Sunoco LP (NYSE: SUN), and the general partner interests and 46.1 million common units of USA Compression Partners, LP (NYSE: USAC). For more information, visit the Energy Transfer LP website at www.energytransfer.com.

Sunoco LP (NYSE: SUN) is a master limited partnership with core operations that include the distribution of motor fuel to approximately 10,000 convenience stores, independent dealers, commercial customers and distributors located in more than 30 states, as well as refined product transportation and terminalling assets. SUN’s general partner is owned by Energy Transfer LP (NYSE: ET). For more information, visit the Sunoco LP website at www.sunocolp.com.

USA Compression Partners, LP (NYSE: USAC) is a growth-oriented Delaware limited partnership that is one of the nation’s largest independent providers of natural gas compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers and transporters of natural gas and crude oil. USAC focuses on providing compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities and transportation applications. For more information, visit the USAC website at www.usacompression.com.

Forward-Looking Statements

This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission, including the Partnership’s Quarterly Report on Form 10-Q to be filed for the current period. In addition to the risks and uncertainties previously disclosed, the Partnership has also been, or may in the future be, impacted by new or heightened risks related to the COVID-19 pandemic, and we cannot predict the length and ultimate impact of those risks. The Partnership has also been, and may in the future be, impacted by the winter storm in February 2021 and the resolution of related contingencies, including credit losses, disputed purchases and sales, litigation and/or potential legislative action. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.

The information contained in this press release is available on our website at www.energytransfer.com.

There are material limitations to using measures such as Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio, including the difficulty associated with using any such measure as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as operating income, net income and cash flow from operating activities.

Definition of Adjusted EBITDA

We define 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 last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Adjusted EBITDA reflects 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 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 Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.

Definition of Distributable Cash Flow

We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest 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 deferred income taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow.

Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.

On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ET’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:

• For subsidiaries with publicly traded equity interests, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to our partners includes distributions to be received by the parent company with respect to the periods presented.
• For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiaries, but Distributable Cash Flow attributable to partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest.

For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related adjustments and non-recurring expenses that are included in net income are excluded.

Definition of Distribution Coverage Ratio

Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by distributions expected to be paid to the partners of ET in respect of such period.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

Intrastate Transportation and Storage

Transported volumes increased primarily due to volume ramp-ups in the Permian.

Segment Adjusted EBITDA. For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment increased due to the net effects of the following:

• an increase of $52 million in transportation fees due to revenues related to Winter Storm Uri of $39 million, as well as increased firm transportation volumes from the Permian, partially offset by the expiration of certain contracts on our Regency Intrastate Gas System; and
• an increase of $13 million in retained fuel revenues primarily due to higher gas prices; partially offset by
• a decrease of $11 million in realized natural gas sales and other primarily due to lower optimization volumes with shifts to long-term third-party contracts from the Permian to the Gulf Coast;
• a decrease of $9 million in realized storage margin due to lower storage optimization; and
• an increase of $7 million in operating expenses primarily due to higher cost of fuel consumption from higher gas prices.

Interstate Transportation and Storage

Transported volumes decreased primarily due to foundation shipper contract expirations and a shipper bankruptcy on our Tiger system, as well as lower utilization resulting from unfavorable market conditions on our Panhandle and Trunkline systems, partially offset by increased short-term firm and interruptible utilization on our Rover system.

Segment Adjusted EBITDA. For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:

• a decrease of $38 million in revenues primarily due to a $30 million decline as a result of shipper contract expirations on our Tiger system and a $14 million decline due to a shipper bankruptcy during 2020 also on our Tiger system. These decreases were partially offset by an increase of $6 million from interruptible and short-term firm transportation volumes sold primarily on our Rover system due to increased demand on the system;
• an increase of $4 million in operating expenses primarily due to higher employee costs of $12 million, partially offset by credit losses recorded in 2020 related to a shipper bankruptcy;
• an increase of $5 million in selling, general and administrative expenses primarily due to higher allocated overhead costs and employee costs; and
• a decrease of $26 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $19 million decrease from our Fayetteville Express Pipeline joint venture as a result of the expiration of foundation shipper contracts, a $4 million decrease from our Citrus joint venture resulting from higher employee costs and maintenance project costs and a $3 million decrease from our Midcontinent Express Pipeline joint venture as a result of lower revenue due to capacity sold at lower rates.

Midstream

Gathered volumes and NGL production increased compared to the same period last year primarily due to increases in the Permian, Ark-La-Tex, South Texas and North Texas regions, partially offset by volume declines in the Northeast and Mid-Continent/Panhandle regions.

Segment Adjusted EBITDA. For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:

• an increase of $111 million in non-fee-based margin due to favorable NGL prices of $75 million and natural gas prices of $36 million;
• an increase of $15 million in non-fee-based margin due to increased throughput in the Permian region and the ramp-up of recently completed assets in the Northeast region; and
• an increase of $19 million in fee-based margin due to volume growth in the Permian region; partially offset by
• an increase of $30 million in operating expenses due to increases of $19 million in employee costs, $4 million in outside services, $3 million in allocated overhead costs and $2 million in maintenance project costs; and
• an increase of $7 million in selling, general and administrative expenses due to higher allocated overhead costs.

NGL and Refined Products Transportation and Services

NGL transportation volumes increased primarily due to the initiation of service on our propane and ethane export pipelines into our Nederland Terminal in the fourth quarter of 2020, higher volumes from the Eagle Ford region and higher volumes on our Mariner East and West pipeline systems.

Refined products transportation volumes increased due to recovery from COVID-19 related demand reduction in the prior period.

NGL and refined products terminal volumes increased primarily due to increased export volumes at our Nederland Terminal due to the initiation of service on our propane and ethane export pipelines in the fourth quarter of 2020, higher throughput volumes on our Mariner East and West pipeline systems and increased throughput at our refined product terminals due to recovery from COVID-19 related demand reduction in the prior period.

Segment Adjusted EBITDA. For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

• an increase of $40 million in transportation margin primarily due to a $27 million increase due to higher export volumes feeding into our Nederland Terminal and a $17 million increase from higher throughput on our Mariner pipeline system;
• an increase of $34 million in terminal services margin primarily due to a $22 million increase in ethane export fees at our Nederland Terminal, a $10 million increase due to higher throughput at our Marcus Hook Terminal, an increase of $9 million in loading fees due to higher LPG export volumes at our Nederland Terminal and a $5 million increase due to higher throughput at our refined product terminals. These increases were partially offset by an $11 million decrease resulting from an expiration of a third-party contract at our Nederland Terminal in the second quarter of 2020;
• an increase of $15 million in storage margin primarily due to a $9 million increase in fees generated from exported volumes, as well as increases related to blending activity due to a more favorable pricing environment and the timing of cavern withdrawals; and
• an increase of $10 million in fractionators and refinery services margin primarily due to a more favorable pricing environment impacting our refinery services business; partially offset by
• an increase of $40 million in operating expenses primarily due to a $19 million increase in utilities cost, a $12 million increase in employee related costs and an $8 million increase in allocated corporate overhead costs; and
• an increase of $8 million in selling, general and administrative expenses primarily due to corporate cost reductions in 2020.

Crude Oil Transportation and Services

Crude transportation volumes were higher on our Texas pipeline system and Bakken pipeline, driven by a recovery in crude oil production in these regions as a result of higher crude oil prices as well as a recovery in refinery utilization. Volumes on our Bayou Bridge pipeline were also higher, driven by more favorable crude oil differentials for shippers. Crude Terminal volumes were lower primarily due to reduced export demand.

Segment Adjusted EBITDA. For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:

• a decrease of $5 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $35 million decrease from our Texas crude pipeline system due to lower average tariff rates, a $17 million decrease (excluding unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business due primarily to storage trading gains realized in the second quarter of 2020 due to favorable market conditions and a $2 million decrease in throughput at our crude terminals primarily driven by lower export demand; partially offset by a $33 million increase due to higher volumes on our Bakken Pipeline and a $17 million increase due to higher volumes on our Bayou Bridge pipeline;
• an increase of $19 million in operating expenses primarily due to the timing of higher utility expenses resulting from Winter Storm Uri and timing of maintenance projects;
• an increase of $2 million in selling, general and administrative expenses primarily due to higher corporate allocations to the crude segment; and
• a decrease of $8 million in Adjusted EBITDA related to unconsolidated affiliates due to lower volumes on White Cliffs pipeline from lower crude oil production.

Investment in Sunoco LP

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impacts of the following:

• an increase in the gross profit on motor fuel sales of $12 million primarily due to a 27.6% increase in gallons sold, partially offset by a 16.6% decrease in gross profit per gallon sold; and
• an increase in non-motor fuel sales of $12 million primarily due to increased credit card transactions, merchandise gross profit and franchise fee income; partially offset by
• an increase in operating expenses and selling, general and administrative expenses primarily due to higher maintenance and advertising costs.

Investment in USAC

The Investment in USAC segment reflects the consolidated results of USAC.

Segment Adjusted EBITDA. For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment decreased due to the net impacts of the following:

• a decrease of $16 million in segment margin primarily due to a decrease in demand for compression services driven by continued capital discipline and optimization of existing compression service requirements by existing customers; partially offset by
• a decrease of $6 million in operating expenses primarily due to sales tax refunds received in the current period; and
• a decrease of $5 million in selling, general and administrative expenses primarily due to a $2 million decrease in the provision for expected credit losses and a $2 million decrease in severance charges related to the departure of an executive.

All Other

For the three months ended June 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased primarily due to the net impacts of the following:

• an increase of $8 million from power trading activities;
• an increase of $14 million due to the realization of amounts in excess of book values on previously reserved receivables in our marketing business;
• an increase of $11 million primarily due to higher gas revenue and lower power costs at our compressor equipment business;
• an increase of $7 million due to lower allocated utility expense;
• an increase of $9 million due to lower corporate expenses; and
• an increase of $4 million primarily due to increased service fees and foreign currency fluctuations at Energy Transfer Canada.

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