[ET] Energy Transfer: Q3 2026 Earnings Test Fee Volumes as Spreads Fade

Energy Transfer is a US midstream energy company listed as a limited partnership. It runs pipelines, processing plants, fractionators, storage and export terminals for natural gas, natural gas liquids (NGLs), crude oil and refined products[1]. Third quarter 2026 (three months ended September 30, 2026) results are scheduled for 2026-11-03, according to the Drillr earnings calendar[2], which makes Energy Transfer Q3 2026 earnings the next read on whether its growth rests on fees or spreads. In the latest disclosed quarter, the second quarter of 2026, adjusted EBITDA was $5.07 billion, up 31% year over year; distributable cash flow attributable to partners, as adjusted, was $2.59 billion, up 32%; and net income per common unit was $0.59[3]. The partnership does not give quarterly guidance. On August 4 it raised full-year 2026 adjusted EBITDA guidance from $18.2-$18.6 billion to $18.8-$19.1 billion and set growth capital spending at $5.6-$5.9 billion[3]. Subtracting first-quarter adjusted EBITDA of $4.94 billion[4] and the second-quarter result from the full-year range implies roughly $8.8-$9.1 billion for the second half. Analyst estimates compiled by Drillr show an average third-quarter EPS of $0.40 per unit from 10 analysts (range $0.341-$0.458), an average third-quarter revenue estimate of about $31.04 billion from 5 analysts, and an average full-year EPS of $1.709 per unit from 13 analysts[5].

Three things matter most in the third-quarter report. The first is whether the NGL and refined products segment can still grow year over year once export premiums fade: second-quarter segment adjusted EBITDA was $1.31 billion, and $212 million of its $275 million year-over-year increase came from marketing margin[3], while management said the updated full-year guidance does not assume that market volatility continues into the second half[6]. The second is whether reservation fees on the Texas intrastate network can replace the spread income it is losing: the intrastate segment's $377 million of second-quarter EBITDA relied mainly on a $113 million gain from wider basis differentials, while transportation fees added only $5 million[3], and Hugh Brinson Phase I will not be fully contracted until January 1, 2027[6]. The third is whether midstream growth can shift to processing volumes: second-quarter midstream margin rose $205 million, of which $88 million came from NGL prices and $83 million from volumes[3]. Together these figures will show how much of the growth behind the two full-year guidance raises in the first half[4][3] comes from durable fee volumes and how much from spreads that can fade.

Company Background and Business Structure

Energy Transfer changed both its legal domicile and its listing venue in 2026, though neither change touches its operating segments. Its common units represent limited partner interests and the partnership is managed by the board of its general partner; on July 6, 2026, it converted from a Delaware partnership to a Texas partnership under a plan of conversion[7]. On September 3 it approved moving its common units and its 9.250% Series I fixed-rate perpetual preferred units from the New York Stock Exchange to the Texas Stock Exchange (TXSE); NYSE trading ended at the close on October 2, TXSE trading began on October 5, and the tickers ET and ETprI stayed the same[8].

The partnership reports seven operating segments, and consolidated adjusted EBITDA was $15.98 billion in 2025 versus $15.48 billion in 2024[1]. By segment, NGL and refined products transportation and services earned $4.14 billion, midstream gathering and processing $3.16 billion, crude oil transportation and services $2.94 billion, the investment in Sunoco LP $2.05 billion, interstate natural gas transportation and storage $1.94 billion, intrastate natural gas transportation and storage $1.21 billion, and the investment in USAC $614 million[1]. Sunoco LP and USAC are two listed partnerships that Energy Transfer consolidates, and after Sunoco LP completed its acquisition of Parkland on October 31, 2025, a large volume of fuel distribution revenue entered the consolidated accounts[1]; Sunoco segment revenue reached $14.26 billion in the second quarter of 2026 versus $5.39 billion a year earlier[3].

Customers include oil and gas producers, refiners, petrochemical companies, utilities and power plants, and export buyers, and no single customer accounted for more than 10% of consolidated revenue in 2025[1]. Fees come in several forms: intrastate pipelines charge a fixed demand fee for reserved capacity, a transportation fee on actual throughput, or fuel retention; the NGL segment relies mainly on dedicated and take-or-pay contracts, the latter carrying minimum throughput commitments that customers pay whether or not they ship; and midstream processing includes percent-of-proceeds arrangements, under which the partnership sells residue gas and NGLs at market prices and remits an agreed share of the proceeds to producers[1]. The partnership also buys and sells natural gas, NGLs and refined products on its own account to earn spreads, so consolidated revenue includes large commodity sales that move with market prices and is a poor gauge of operating scale.

Financial History and Current Position

Energy Transfer's revenue and net income swing widely with commodity prices, so the partnership's adjusted EBITDA is the better guide to operating trends. According to Drillr financial data, consolidated revenue peaked at $89.88 billion in 2022 and was $82.63 billion in 2025, while net income fell from $5.47 billion in 2021 to $3.94 billion in 2023 and was $4.90 billion in 2025. By contrast, 2025 adjusted EBITDA was $15.98 billion, up about 3%; operating cash flow was $10.15 billion (versus $11.51 billion in 2024), capital spending exceeded $6 billion, distributions to partners were $4.73 billion and to noncontrolling interests $1.73 billion, debt rose by a net $4.82 billion, and total debt reached $68.33 billion at year-end (versus $59.76 billion a year earlier)[1].

Growth accelerated sharply in the first two quarters of 2026, partly because of the Sunoco consolidation. First-quarter adjusted EBITDA was $4.94 billion, up 20%, and distributable cash flow attributable to partners, as adjusted, was $2.70 billion[4]; second-quarter adjusted EBITDA was $5.07 billion (versus $3.87 billion a year earlier), net income attributable to partners was $2.09 billion (versus $1.16 billion), operating income was $3.57 billion, and revenue was $34.33 billion (versus $19.24 billion), with Sunoco segment revenue up about $8.87 billion year over year[3]. As the base for the third-quarter comparison, the partnership reported in November 2025 that adjusted EBITDA for the prior-year quarter was $3.84 billion and net income per common unit was $0.28, and said at the time that several one-time items weighed on that quarter.

The cash and debt position shows that growth capital still relies partly on borrowing. First-half capital spending totaled $3.48 billion, and the leverage ratio under the five-year credit facility covenant was 3.01x at June 30[9]; second-quarter growth capital spending was $1.10 billion, maintenance capital spending $307 million, and interest expense $934 million (versus $865 million)[3]. In July the partnership issued $650 million of Series 2026A and $1.10 billion of Series 2026B junior subordinated notes due 2057, totaling $1.75 billion, with the Series 2026A notes initially bearing 6.550% a year[10]. The quarterly distribution declared for the second quarter was $0.34 per unit ($1.36 annualized), up more than 3% year over year and the nineteenth consecutive increase; distributable cash flow attributable to partners was $2.59 billion that quarter against $1.17 billion of distributions to limited partners, roughly 2.2x coverage[3].

Operating Model

Energy Transfer's revenue splits into fees and commodity sales, and profit is driven by fee volumes and spreads rather than by revenue size. Fee revenue roughly equals reserved capacity or minimum volume commitments multiplied by contract rates, plus actual throughput multiplied by transportation, processing and loading fees, and take-or-pay and dedicated contracts dominate on the NGL and intrastate pipelines[1]. Commodity revenue equals the volume of natural gas, NGLs and refined products bought and sold on the partnership's own account multiplied by market prices; it creates almost equal cost of products sold, so profit is only the spread, and in the second quarter cost of products sold was $26.94 billion out of $34.33 billion of consolidated revenue[3].

Consolidated adjusted EBITDA equals segment margin minus operating and administrative expenses plus EBITDA from unconsolidated affiliates, summed across segments; quarterly swings come mainly from spreads and prices, while fee volumes from new projects arrive with a clear lag. Second-quarter adjusted EBITDA rose $1.2 billion year over year: the Sunoco segment rose from $454 million to $982 million, contributing about $528 million, while NGL added $275 million, midstream $116 million, crude oil $102 million ($834 million versus $732 million), intrastate $93 million and interstate $11 million[3]. Management said most of the second-quarter guidance raise came from segment beats, with midstream, intrastate and crude each about $100 million ahead and NGL more than $200 million ahead, and that Hugh Brinson Phase I, Mustang Draw II and Frac 9 will contribute little to 2026 earnings, with most of their contribution in 2027[6].

Distributable cash flow equals adjusted EBITDA minus interest, preferred unit distributions, current income taxes and maintenance capital spending, less the noncontrolling shares of Sunoco, USAC and joint ventures, plus distributions received from Sunoco and USAC. Cash left over after roughly 2.2x second-quarter coverage funds growth capital together with new debt[3], and management's long-term targets are leverage of 4.0x to 4.5x and annual distribution growth of 3% to 5%[6]. On October 6 the partnership announced it would acquire Vaquero Midstream for about $2.6 billion[11], so profit changes flow first into distributable cash flow, while growth capital and acquisition spending determine how much of that must be supplemented by borrowing.

Industry and Competitive Position

Energy Transfer's competitive advantage comes from the reach and scale of its asset base, and several volume measures hit partnership records in the second quarter of 2026. NGL transportation volumes, NGL exports, crude oil transportation volumes and midstream gathered volumes rose 13%, 25%, 4% and 4% year over year, all partnership records[3]. Management said total deliverability to Mont Belvieu now exceeds 1.3 million barrels per day, Permian takeaway pipelines are about 95% utilized, and the Mont Belvieu fractionators are fully utilized[6]; in June the partnership announced a fully subscribed Nederland export expansion that adds 240,000 barrels per day of ethane export capacity and 55,000 barrels per day of LPG capacity, along with two new NGL ship docks[3].

The concentrated start-up of Permian takeaway pipelines is changing natural gas and NGL pricing in Texas, which brings Energy Transfer both new volume and new pressure. Management said Hugh Brinson and other new pipelines will add about 4.5 Bcf/d of Permian egress by the first quarter of 2027 and that the Waha spread narrowed faster than expected; the new capacity has pulled market rates down from earlier levels, but management believes rates have bottomed and that future contracting will be at higher current market rates[6]. In the second quarter the partnership completed upgrades to Lone Star Express, adding more than 90,000 barrels per day of Permian NGL takeaway, and signed long-term transportation and fractionation agreements for about 300,000 barrels per day on its y-grade assets extending into the 2030s[3].

Energy Transfer competes with midstream companies such as Enterprise Products, Kinder Morgan, Targa and Williams, and the available peer comparison has clear limits. The 10-K says NGL segment fees are negotiated at market rates and compete with regional regulated pipelines and fractionators; in December 2025 the partnership suspended development of the Lake Charles LNG project to focus capital on natural gas pipeline projects with better risk/return profiles[1]. The partnership does not disclose absolute NGL export volumes, the Waha basis or commodity price sensitivities, and competitors' comparable figures lack verifiable sources, so any judgment of competitive position must rest on the partnership's own volume disclosures and variance explanations.

Core Debates

Did the NGL segment’s second-quarter jump come from contracted throughput or from conflict-driven export premiums, and can it still grow year over year in the third quarter as spreads fade?

This question decides whether the first-half guidance raises can last, because the NGL and refined products segment is Energy Transfer's largest profit source. The segment earned $4.14 billion of adjusted EBITDA in 2025, about 26% of the consolidated total[1]; the partnership raised full-year guidance twice in the first half of 2026, lifting the midpoint by $750 million in the first quarter[12] and by another $500 million in the second quarter, with the NGL segment beating by more than $200 million[6]. If that outperformance came mainly from spreads, it will fade in the second half; if it came mainly from throughput and terminal fees, growth can carry into 2027.

The second-quarter variance explanation shows that NGL growth came from both marketing premiums and fee volumes. Segment adjusted EBITDA was $1.31 billion versus $1.03 billion a year earlier; within the increase, marketing margin rose $212 million ($140 million from export and domestic supply premiums and $70 million from refined product spreads), terminal services rose $71 million (mainly export loading volumes and rates at Nederland and Marcus Hook), transportation rose $28 million, storage and fractionation each rose $12 million, and operating expenses rose $54 million, of which $28 million reflected one-time credits in the prior-year period[3]. NGL transportation volumes reached 2,641 MBbls/d (up 13%) and terminal volumes 1,864 MBbls/d (versus 1,553), with transportation and export volumes both setting partnership records[3].

An alternative reading holds that more than half of the second-quarter increase came from premiums rather than fees. Management said the updated full-year guidance does not assume continued market volatility in the second half[6], and on the first-quarter call it said about $300 million of roughly $500 million of outperformance against plan would probably be considered one-time[12]. Based on figures the partnership released in November 2025, NGL segment adjusted EBITDA in the prior-year third quarter was $1.054 billion and marketing margin fell only $3 million year over year, containing almost no premium, while NGL transportation volumes were 2,487 MBbls/d and terminal volumes 1,660 MBbls/d, so whether the third quarter can grow year over year depends mainly on fee volumes. The transmission chain runs from higher Permian processing volumes to more NGL transportation and fractionation, then to export loadings at Nederland and Marcus Hook, generating transportation, terminal and fractionation fee margin; international buyers turning to US supply, meanwhile, lift export premiums that flow into marketing margin.

Three third-quarter measures can test this debate, and neither outcome has been confirmed yet. The first is whether segment adjusted EBITDA exceeds the prior-year $1.054 billion and approaches $1.2 billion; the second is whether NGL transportation volumes hold near 2,700 MBbls/d with growth of at least 5%; the third is how the variance explanation splits marketing margin from fee margin, and whether Frac 9, as management said, is still on track for late 2026[6]. If marketing margin turns negative year over year and segment EBITDA falls below the prior-year level, or slower Permian processing drags transportation volume growth below 5%, first-half growth relied mainly on spreads; if marketing margin falls but the segment still grows year over year, fee volumes are the main support.

As Hugh Brinson relieves Permian takeaway and the Waha spread narrows, can reservation fees on the Texas intrastate network replace the spread income it loses?

This question matters because the intrastate segment's profit source is shifting from spreads to reservation fees. The Texas intrastate network long earned spreads from Permian takeaway bottlenecks, and narrower spreads in 2025 already cut segment adjusted EBITDA from $1.36 billion to $1.21 billion, a decline of $145 million[1]. Hugh Brinson converts that profit from spreads into reservation fees, lowering spread income in the short term and raising long-term contract income; the partnership said Phase I would be capable of flowing its full 1.5 Bcf/d capacity by September 1, 2026[3], so the third quarter is the first full quarter after Phase I reached capacity and will show which force is larger.

Second-quarter intrastate growth came mainly from spreads rather than transportation fees. Segment adjusted EBITDA was $377 million (versus $284 million), with realized natural gas sales and other up $113 million year over year, mainly on wider basis differentials and including $21 million from early Hugh Brinson commissioning volumes; transportation fees rose only $5 million on higher reservation revenue from long-term third-party contracts, while storage optimization fell $10 million[3]. Intrastate gas transported actually fell from 14,229 to 13,814 BBtu/d over the same period because of lower third-party use of firm capacity[3]; the segment earned about $437 million in the first quarter versus about $344 million a year earlier[12].

Management acknowledged that the spread narrowed faster than expected, which could leave the third quarter in a gap between fading spreads and reservation fees that have not yet fully arrived. On the call, management said the Waha spread narrowed faster than expected and that Phase I's full capacity will be fully contracted only by January 1, 2027, with limited full earnings contribution in 2026[6]. Based on figures the partnership released earlier, the intrastate segment earned only $230 million in the prior-year third quarter, when the spread line fell $101 million year over year, transportation fees rose $10 million and volumes were 13,861 BBtu/d, so that low base could still allow year-over-year growth. The transmission chain runs from Phase I adding Permian egress, to a narrower Waha spread, to lower income from buying gas cheaply at Waha and selling it in East Texas and Houston; at the same time, long-term contract customers begin paying reservation fees and transportation fee revenue rises.

Third-quarter intrastate results can test whether reservation fees are starting to replace spreads. The measures are whether segment adjusted EBITDA exceeds $230 million and approaches $300 million, whether the spread line in the variance explanation turns negative and the transportation fee increase exceeds $30 million, and whether Hugh Brinson Phase I is running at the full 1.5 Bcf/d and Phase II remains on track for the first quarter of 2027[6]. If spread income drains faster than reservation fees ramp and segment EBITDA drops back below $230 million, or contract customers pay later so that fee growth before 2027 is limited, the current understanding weakens; if the spread line is not negative year over year, or the fee increase is large enough to offset the spread decline, reservation fees have started to do their job.

With new Permian processing capacity just online, can third-quarter midstream growth come mainly from volumes rather than, as in the second quarter, half from NGL prices?

The quality of midstream growth determines whether volumes feeding the downstream NGL business can keep expanding. Midstream is the first link that brings gas from the wellhead into the network, earned $3.16 billion of adjusted EBITDA in 2025, about 20% of the consolidated total, and supplies the downstream NGL transportation, fractionation and export businesses[1]. Second-quarter midstream margin rose $205 million, with volumes contributing $83 million, NGL prices $88 million and natural gas prices $11 million[3]; if prices fall back, whether volume growth alone can sustain year-over-year gains determines whether the segment's growth can last.

Second-quarter midstream volumes set records, but costs also rose noticeably. Segment adjusted EBITDA was $884 million (versus $768 million), gathered volumes were 22,142 BBtu/d, up 4% and a partnership record, and NGLs produced were 1,243 MBbls/d (versus 1,181); operating expenses rose $97 million, including $46 million of environmental reserves, a $39 million adjustment of prior-period estimates and $15 million of employee costs[3]. The 275 MMcf/d Mustang Draw I processing plant placed in service in June[3] is already running near full capacity[6]; for comparison, full-year 2025 gathered volumes were 21,205 BBtu/d and NGLs produced 1,149 MBbls/d[1].

An alternative reading holds that volume growth alone has not yet produced steady year-over-year gains. First-quarter midstream EBITDA was about $887 million, below about $925 million a year earlier[12], and about half of second-quarter profit growth came from NGL prices; on the other hand, the combined $85 million of environmental reserves and estimate adjustments in the second quarter may not recur, and if they do not, third-quarter costs would improve. Based on figures the partnership released earlier, prior-year third-quarter midstream EBITDA was $751 million, with gathered volumes of 21,581 BBtu/d and NGLs produced of 1,149 MBbls/d, while NGL prices reduced margin by $25 million and natural gas prices added $32 million year over year. Under percent-of-proceeds contracts, year-over-year NGL price changes directly amplify or offset volume growth, and operating expenses are the cost-side variable.

Third-quarter midstream results can separate the contributions of volumes and prices. The measures are whether segment adjusted EBITDA exceeds $751 million and approaches $830 million, how much volumes and NGL prices each contribute in the variance explanation, whether gathered volumes and NGL production set new records, and whether Mustang Draw II stays on track for the fourth quarter[6]. Management itself lists slower-than-expected Permian production growth after new egress opens as a risk[6]; if lower NGL prices offset volume gains and midstream EBITDA falls below the prior-year level, or producers respond to new takeaway more slowly than expected and processing volumes stall, the durability of the segment's growth comes into question.

Risks and Falsifiers

Each of the five risks below maps to a specific financial line and an observable falsifier, and they are linked to the three core debates.

The first risk is misreading the accounting basis: after Sunoco LP acquired Parkland, consolidated revenue and net income changed scale sharply, so comparisons based on revenue or revenue margin can misstate Energy Transfer's operating trend. In the second quarter the Sunoco segment had $14.26 billion of revenue and $982 million of adjusted EBITDA, about 19% of consolidated adjusted EBITDA[3], yet what Energy Transfer's partners actually receive from it is only Sunoco's distributions. If the Sunoco segment's third-quarter increase comes mainly from integrating the completed acquisition, and the other segments' adjusted EBITDA growth does not depend on the Sunoco consolidation, this risk will not change the assessment of the core business.

The second risk is faster capital spending combined with acquisition outlays, which would raise leverage and interest costs. Growth capital guidance for 2026 is $5.6-$5.9 billion, and first-half capital spending already reached $3.48 billion[9]; the Vaquero acquisition is valued at about $2.6 billion[11]; total debt was $68.33 billion at the end of 2025[1], second-quarter interest expense was $934 million (versus $865 million)[3], and in July the partnership issued another $1.75 billion of junior subordinated notes[10]. If third-quarter growth capital stays within full-year guidance and the credit agreement leverage ratio remains clearly below the top of management's 4.0x-4.5x target range[6], this risk has not materialized.

The third risk is that falling international spreads or weaker export demand erase the $140 million of export and domestic supply premiums earned in the second quarter. The NGL segment earned $4.14 billion of adjusted EBITDA in 2025[1], and second-quarter marketing margin rose $212 million year over year, about 77% of the segment's increase[3]. If the third-quarter marketing margin increase is no more than half of the segment increase and segment EBITDA is at least $1.2 billion, fee volumes can sustain growth on their own.

The fourth risk is that concentrated Permian takeaway additions keep narrowing the Waha spread and reduce the partnership's income from buying and selling gas on its own account. The intrastate segment earned $1.21 billion of adjusted EBITDA in 2025[1], and the spread line contributed $113 million year over year in the second quarter, more than the segment's total increase of $93 million[3]. If the third-quarter spread line is not negative year over year, or the fee increase offsets the spread decline and segment EBITDA is at least $300 million, this concern is falsified.

The fifth risk is that Permian producers resume drilling and completions more slowly than expected once takeaway opens, leaving new processing capacity underused. The midstream segment earned $3.16 billion of adjusted EBITDA in 2025, and the partnership's 2026 capital plan includes about $1.23 billion of midstream growth capital[1], on top of the Vaquero acquisition[11], so the new processing capacity needs enough production to fill it. If third-quarter gathered volumes are at least 22,500 BBtu/d and the volume contribution is at least $60 million, this risk has not appeared.

What to Watch Next

• NGL segment: whether adjusted EBITDA beats the prior-year $1.054 billion and nears $1.2 billion even as marketing margin fades (second-quarter base $1.31 billion, marketing margin up $212 million), how marketing and fee margin split, and whether Frac 9 starts up by late 2026. Marketing margin turning negative with EBITDA below last year would falsify the fee-driven reading.
• NGL volumes: whether transportation volumes hold near 2,700 MBbls/d from 2,641 MBbls/d, with growth of at least 5% confirming and growth below 5% falsifying.
• Intrastate segment: whether EBITDA nears $300 million from $377 million in the second quarter and stays above the prior-year $230 million, with fee growth above $30 million confirming reservation fees are taking over, and whether Hugh Brinson Phase I runs at full capacity with Phase II on track for the first quarter of 2027.
• Midstream segment: whether EBITDA beats the prior-year $751 million and nears $830 million from $884 million, with gathered volumes of at least 22,500 BBtu/d and a volume contribution of at least $60 million, and whether Mustang Draw II enters service in the fourth quarter.
• Leverage and capital: whether growth capital stays within the $5.6-$5.9 billion guidance after $3.48 billion of first-half spending, and whether leverage stays below 4.5x from 3.01x as Vaquero closes.

Conclusion

Two forces drive Energy Transfer's profit: contracted fees on pipelines, terminals and processing plants, and spread income from NGL export premiums, the Waha basis and commodity prices. Second-quarter 2026 adjusted EBITDA was $5.07 billion, up 31%, and full-year guidance has been raised to $18.8-$19.1 billion[3], yet a meaningful share of the increase in each of the NGL, intrastate and midstream segments came from spreads or prices. The central unresolved relationship is whether fee volumes from Hugh Brinson, Mustang Draw and the Nederland expansion can carry growth as spreads recede.

Two independent interpretations both treat Hugh Brinson as the key variable, but they emphasize different consequences. TIKR's Gian Estrada argues that the real winner of the second quarter was the intrastate natural gas business, driven by wider basis differentials as bottlenecked Permian gas found an outlet, and notes that EBITDA margin on revenue fell to 14.76%, framing Energy Transfer as an "income-and-modest-growth case" rather than a story of the market repricing the units[13]; that margin, however, reflects the revenue expansion from Sunoco's consolidation of Parkland and does not show weaker pipeline profitability. AEGIS Hedging's Jay Stevens instead lists Hugh Brinson's start-up as one of the main reasons the Waha spread narrowed quickly, saying it unleashed pent-up shut-in and drilled-but-uncompleted volumes, while noting that more than 11 Bcf/d of new Permian egress has been sanctioned through 2029 and that forward Waha basis strips have weakened by roughly $0.10 since August 24[11]. Taken together they point to the same tension: the basis gains TIKR credits are exactly what is most likely to fade once Hugh Brinson runs full, while the forward weakening AEGIS describes shows the spread has not disappeared; both are outside interpretations rather than earnings forecasts, and no citable sell-side research was found after August 4, 2026.

The combination that would materially strengthen the current understanding is this: the NGL segment stays above the prior-year $1.054 billion as marketing margin fades, intrastate fee growth begins to offset the spread decline, midstream volume contributions exceed price contributions, and leverage stays below the top of the 4.0x-4.5x target range[6]. Conversely, if the year-over-year gains in all three segments still come mainly from marketing margin, spreads and NGL prices, or if marketing margin and the spread line turn negative while fee volume growth is too small to fill the gap, the first-half guidance raises reflected mostly a one-time market windfall.

Sources

[1] ET FY2025 10-K filed 2026-02-19 · 2026-02-19 · 10-K · https://www.sec.gov/Archives/edgar/data/1276187/000127618726000013/et-20251231.htm

[2] Drillr earning_call_calendar ET updated 2026-10-16 · 2026-10-16 · Drillr earnings calendar

[3] ET Q2 2026 8-K earnings release filed 2026-08-04 · 2026-08-04 · 8-K · https://www.sec.gov/Archives/edgar/data/1276187/000127618726000033/ex991eterq22026.htm

[4] ET Q1 2026 8-K earnings release filed 2026-05-05 · 2026-05-05 · 8-K · https://www.sec.gov/Archives/edgar/data/1276187/000127618726000021/ex991eterq12026.htm

[5] Drillr analyst_financial_estimates ET Q3 2026 retrieved 2026-10-26 · 2026-10-26 · Drillr analyst estimates · https://gateway.drillr.ai/mcp/private

[6] ET Q2 2026 earnings call 2026-08-04 · 2026-08-04 · earnings-call · https://gateway.drillr.ai/mcp/private

[7] ET 8-K12B Texas redomiciliation filed 2026-07-06 · 2026-07-06 · 8-K · https://www.sec.gov/Archives/edgar/data/1276187/000119312526295529/d109647d8k12b.htm

[8] ET 8-K TXSE listing transfer filed 2026-09-10 · 2026-09-10 · 8-K · https://www.sec.gov/Archives/edgar/data/1276187/000127618726000044/et-20260903.htm

[9] ET Q2 2026 10-Q filed 2026-08-06 · 2026-08-06 · 10-Q · https://www.sec.gov/Archives/edgar/data/1276187/000127618726000038/et-20260630.htm

[10] ET 8-K junior subordinated notes filed 2026-07-08 · 2026-07-08 · 8-K · https://www.sec.gov/Archives/edgar/data/1276187/000119312526298149/d86030d8k.htm

[11] AEGIS Hedging Basis Brief: Waha Gas 2026-10-23 · 2026-10-23 · AEGIS Hedging · https://aegis-hedging.com/insights/basis-brief-waha-gas

[12] ET Q1 2026 earnings call 2026-05-05 · 2026-05-05 · earnings-call · https://gateway.drillr.ai/mcp/private

[13] TIKR blog on Energy Transfer Q2 2026 earnings 2026-08-05 · 2026-08-05 · TIKR · https://www.tikr.com/blog/energy-transfers-q2-earnings-reveal-the-real-winner-intrastate-natural-gas