Energy Transfer (ET) Q3 2026 earnings review
Energy Transfer raises its profit plan, but capital spending jumps
Energy Transfer, the operator of 140,000 miles of US oil and gas pipelines, grew third-quarter profit while committing billions to new construction. Consolidated Adjusted EBITDA rose 31% to $5.0 billion, and the partnership raised its full-year profit outlook by $850 million. However, by our math, profit outside its publicly traded Sunoco and USA Compression subsidiaries grew 19%, and the updated full-year plan points to fourth-quarter growth slowing to 14%.
| Adjusted EBITDA ex Sunoco and USAC | +19% from a year ago by our math (vs +31% consolidated) |
|---|---|
| Intrastate gas transported | 15,759 BBtu/d +14% from a year ago, a partnership record |
| FY26 Adjusted EBITDA outlook | Raised $850M middle of the range: $19.8B (+24% from 2025) |
| 2027 growth capital outlook | ~$7.0B +27% above the 2026 plan midpoint |
⚖️ Verdict: ⚪ Neutral
The story is unchanged because new pipeline fees are arriving on schedule, but temporary trading gains and a much bigger spending bill offset the raise. Phase I of the Hugh Brinson pipeline entered full service ahead of schedule and lifted Texas gas volumes 14%, yet $336 million of the quarter's profit jump came from oil and gas marketing gains that the company says will partly reverse. At the same time, management unveiled a $2.6 billion buyout of Vaquero Midstream and a $7 billion capital budget for 2027.
The question now is whether rising fees from new gas pipelines can outrun fading trading gains and the cost of funding nearly $10 billion in 2027 investments. One view is that contracted power-plant and data-center pipelines will easily cover the bill; the other is that $200 million of upcoming derivative losses and falling crude pipeline fees will squeeze cash flow as debt rises. Fourth-quarter results and the Vaquero closing details in February will test which side is right.
🐂 Bull Case
New Texas Pipeline Lifts Gas Volumes 14%
Energy Transfer's intrastate segment moves natural gas inside Texas and connects Permian Basin producers to power plants and hubs. On September 1, "Phase I of the Hugh Brinson Pipeline was placed into full service, ahead of schedule", the company said. The partnership expects to finish Phase II in the first quarter of 2027 and bring the full project in under budget.
- Intrastate gas transported: 15,759 billion British thermal units per day (BBtu/d), up 14% from a year ago
- Intrastate Adjusted EBITDA: $346 million, up 50% from $230 million a year ago
- Realized gas sales and other: up $82 million during the pipeline's early ramp-up
- Third-party transportation fees: up $36 million on new contracts tied to Hugh Brinson
This matters because the Texas pipeline network had shrinking volumes in the first half of the year, and Hugh Brinson reversed that trend in a single month. Phase I ran at full capacity for only one-third of the quarter, so fourth-quarter results will capture a full three months of these new shipper contracts.
What to watch: fourth-quarter intrastate transported volumes when full-year results arrive in February. A reading well above 15,759 BBtu/d will confirm that full-quarter flows from Hugh Brinson are lifting base fee revenue.
New Mississippi Pipeline Expands Gas Network
The pipeline operator is signing long-term contracts to supply natural gas to power plants and industrial buyers across the US. In November, the partnership approved the 215-mile South Mississippi Pipeline Project, which will carry 1.2 billion cubic feet per day (Bcf/d) of gas by 2030. "The Partnership has secured long-term, demand-based transportation agreements to support the construction of a 36-inch pipeline", Energy Transfer said.
The group will own 51% of the $1.6 billion Mississippi line, while shippers own the rest. It also started a 15-year contract for 250,000 million British thermal units per day (MMBtu/d) on its Rover system on November 1 and signed deals for 150,000 MMBtu/d to feed two new Missouri power plants. In Texas, it opened the Mustang Draw II processing plant and approved a tenth natural gas liquids fractionator at Mont Belvieu.
What to watch: the final capacity of the South Mississippi pipeline after its customer bidding window closes. An increase above 1.2 Bcf/d would show that southeastern utilities need even more gas capacity than the initial design.
Fourth Raise Pushes Profit Plan Up $850M
Energy Transfer tracks its operating performance using Adjusted EBITDA, which measures partnership earnings before interest, taxes, depreciation and non-cash items. The partnership raised its full-year 2026 Adjusted EBITDA outlook to $19.7–19.9 billion from $18.8–19.1 billion. That $850 million boost at the middle of the range is the fourth raise this year, and the largest of the sequence.
Third-quarter Adjusted EBITDA reached $5.03 billion, beating the $4.47 billion quarterly pace that the prior full-year plan implied by our math. Because the partnership already earned $15.03 billion in the first nine months, the raised outlook leaves $4.77 billion for the fourth quarter at the middle of the range. That implies 14% growth from a year ago, down from 31% in the third quarter.
What to watch: fourth-quarter Adjusted EBITDA against the implied $4.77 billion target. Beating that figure would show that new pipeline fees are offsetting the fade of summer trading gains.
🐻 Bear Case
Acquisitions and Trading Drove Most Profit Growth
Energy Transfer highlighted a 31% jump in consolidated Adjusted EBITDA, which rose by $1.19 billion to $5.03 billion, and pointed to record volumes across its pipelines. However, the partnership consolidates 100% of two publicly traded subsidiaries, Sunoco LP and USA Compression Partners (USAC), even though it owns only 15% of Sunoco's units and 32% of USAC's units.
- Sunoco LP and USAC Adjusted EBITDA: up $598 million from a year ago "primarily due to recent acquisitions"
- Adjusted EBITDA excluding Sunoco and USAC: up 18.7% from a year ago by our math, vs 31.1% consolidated
- Crude and NGL marketing gains: up $336 million on favorable market conditions
- Expected future derivative losses: $200 million ($100 million in NGL and $100 million in crude)
Inside the standalone business, trading gains in natural gas liquids (NGL) and crude oil added $336 million, "which we anticipate will be partially offset with $100 million in realized derivative losses in future periods" in each of those two segments, the company said. Stripping out Sunoco, USAC, and those $336 million of trading gains leaves core profit growth of 8.1% by our math. Gross margin also fell 9.3 percentage points as cost of products sold rose to 82.3% of revenue from 73.0% on Sunoco's fuel purchases.
What to watch: realized derivative losses in the NGL and crude oil segments over the next two quarters. When those $200 million of losses hit, headline profit growth will slow toward the single-digit core rate.
Capital Bill Jumps Toward $10B Next Year
The partnership is stepping up spending on both new construction and acquisitions at the same time. In October, Energy Transfer agreed to buy Vaquero Midstream, a natural gas gathering and processing operator, "in a bolt-on transaction for approximately $2.6 billion, including cash and equity consideration", the company said. The deal is scheduled to close in the fourth quarter.
Alongside the buyout, management set its first 2027 growth capital spending plan at approximately $7 billion, a 27% jump from the $5.5 billion middle of the 2026 range by our math. Between Vaquero and the 2027 buildout, the pipeline group faces nearly $9.6 billion of growth commitments over the next five quarters while carrying $68.84 billion of long-term debt.
What to watch: the cash-versus-equity split on the Vaquero closing and fourth-quarter long-term debt. Relying heavily on debt to fund both Vaquero and the $7 billion project slate would push leverage toward the top of the company's target range.
Core Crude Pipeline and Gathering Fees Fell
While marketing desks profited from price swings, fee revenue on several crude oil and liquid pipelines declined. In the crude oil segment, transportation revenue dropped by $50 million and gathering revenue fell by $22 million from a year ago because shippers moved fewer barrels on the Bakken Pipeline and Bayou Bridge systems.
Crude terminal volumes also slipped 2.2% to 4,167 thousand barrels per day (MBbls/d) on lower Gulf Coast throughput. In the NGL segment, transportation margin fell $17 million, hurt by a $22 million intercompany imbalance on the Gulf Coast pipeline and refinery outages. The $193 million crude marketing gain masked these volume drops, but marketing profits swing with oil spreads while pipeline fees are recurring.
What to watch: crude transportation and gathering fee revenue in the fourth-quarter segment table. Another drop would show that Bakken and Bayou Bridge volume losses are an ongoing drag on base cash flow.
Risks this quarter didn't answer
Three standing operational and legal risks received no update in the third-quarter earnings release.
- New Mexico data-center pipeline delay: no update on the regulatory reroute for the Green Chili lateral serving Oracle; the quarterly filing or call remarks will show if the timeline slipped further.
- Dakota Access Pipeline (DAPL) open capacity: no update on refilling roughly 250,000 barrels per day of space after Enbridge rerouted a partner project, or on the federal easement renewal; the filing's segment and legal notes will test this.
- Tax and legal disputes: the interstate segment lapped a $43 million prior-year Rover property tax reduction, but the release gave no update on remaining Ohio tax assessments or the Williams antitrust case; the filing's commitments footnote will carry the details.
💲 Other KPIs
Cash available for common unit distributions, excluding one-offs, rose 33.1% from a year ago to $2.52 billion, accelerating from 32.1% growth in the second quarter. The partnership declared $1.18 billion in partner distributions ($0.3425 per unit), leaving a coverage ratio of 2.14 times by our math and $1.34 billion of retained cash to help fund capital projects.
Long-term debt rose 9.1% from $63.10 billion a year ago and increased $445 million from the second quarter. In August, the pipeline group used proceeds from new junior subordinated notes to redeem $900 million of 6.50% Series H preferred units, cutting preferred equity to $2.48 billion. Available borrowing space on its $5.0 billion credit facility stood at $4.41 billion.
Natural gas gathered from wellheads rose 6.3% from a year ago to a partnership record, speeding up from 3.8% growth in the second quarter. New and upgraded Permian processing plants lifted NGL production by 10.4% to 1,269 MBbls/d, driving a 15.0% increase in midstream segment Adjusted EBITDA to $864 million.
🔮 Guidance
Raised. The partnership lifted the middle of its full-year profit plan by $850 million, pointing to 23.9% growth for the year by our math. By our math, that leaves $4.77 billion for the fourth quarter, or 14.0% growth from a year ago against 31.1% in the third quarter. It is the fourth raise this year, and the largest yet: +$150M, +$750M, +$550M, +$850M.
Cut. Management lowered its 2026 project spending plan by $250 million at the middle of the range, which still represents a 22.2% increase over 2025 spending by our math. Because the company spent $3.93 billion in the first nine months, the revised plan leaves $1.57 billion for the fourth quarter by our math, up 12.1% from a year ago as Hugh Brinson came in under budget.
Raised. The company set its first formal 2027 project spending target at roughly $7 billion, well above its earlier qualitative floor of $5 billion-plus per year. By our math, that is a 27.3% step-up from the 2026 plan's midpoint as construction ramps up on the Desert Southwest pipeline, Mustang Draw, and the new Bear II and Frac X facilities.
❓ Key Questions
How will Energy Transfer pay for the $2.6B Vaquero buyout?
The release says the price includes cash and equity but gives no split. Because 2027 construction spending is also jumping to $7 billion, investors need to know how much new debt and unit dilution the deal requires.
When will the $200M of derivative losses hit earnings?
Management warned that $100 million of NGL marketing gains and $100 million of crude marketing gains will reverse through realized derivative losses in future periods. The timing determines whether those losses drag down fourth-quarter or 2027 results.
Why did Bakken and Bayou Bridge crude fees fall $72M?
Crude transportation and gathering revenues fell $50 million and $22 million on lower Bakken and Bayou Bridge pipeline volumes. Management has not explained whether shippers shifted to rival pipelines or if contractual rates stepped down.
Has the New Mexico data-center pipeline cleared permitting?
Last quarter management admitted a regulatory delay on the Green Chili lateral serving Oracle in New Mexico. The third-quarter release did not mention the project, leaving open when those contracted gas volumes will start flowing.