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Text: These statements are based on our current beliefs, as well as certain assumptions and information currently available to us and are discussed in more detail in our quarterly report on Form 10-Q for the quarter ended September 30, 2021, which we expect to be filed tomorrow, November 4.
I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, all of which are non-GAAP financial measures.
You'll find a reconciliation of our non-GAAP measures on our website.
I'd like to start today by looking at some of our third quarter highlights.
We generated adjusted EBITDA of $2.6 billion and DCF attributable to the partners of Energy Transfer, as adjusted, of $1.3 billion.
Our excess cash flow after distributions was approximately $900 million.
On an incurred basis, we had excess DCF of approximately $540 million after distributions of $414 million and growth capital of approximately $360 million.
Operationally, our NGL transportation and fractionation and NGL refined products terminals volumes reached new records during the quarter largely driven by growth in volumes, beating our Mont Belvieu fractionators and Nederland Terminal.
As the market continues to recover, we are well-positioned to benefit from increasing demand and higher margins.
Switching gears to an update on the acquisition of Enable Midstream Partners, which will provide increased scale in the Mid-Continent and Ark-La-Tex regions and improved connectivity for our natural gas and NGL transportation customers.
We expect the combination of energy transfers and enables complementary assets to allow us to provide flexible and competitive service to our customers as we pursue additional commercial opportunities utilizing our improved connectivity and increased footprint.
As a reminder, we expect the combined company to generate more than $100 million of annual run rate cost synergies, and this is before potential commercial synergies.
We continue to believe that the transaction will close before the end of the year.
I'll now walk you through recent developments on our growth projects, starting with our Cushing South pipeline.
In early June, we commenced service to provide transportation for approximately 65,000 barrels per day of crude oil from our Cushing terminal to our Nederland terminal, providing access for Powder River and DJ Basin barrels to our Nederland terminal being an upstream connection with our White Cliffs Pipeline.
This pipe is already being fully utilized.
And as we mentioned on our last call, we are moving forward with Phase 2, which will increase the capacity to 120,000 barrels per day.
Phase 2 is expected to be in service early in the second quarter of 2022 and is underpinned by third-party commitments.
As a reminder, minimal capital spend is required for this phase.
Next, construction on the Ted Collins link is progressing and is now expected to be in service late in the first quarter of 2022.
The Ted Collins link will give us the ability to fully load and export unblended low-gravity Bakken and WTI barrels out of the Houston market, showcasing Energy Transfer's unique ability to provide a net Bakken barrel to markets along the Gulf Coast.
Now turning to our Mariner East system.
We have commissioned the next significant phase of the Mariner East project, which brings our current capacity on the Mariner East pipeline system to approximately 260,000 barrels per day.
Year-to-date, NGL volumes through the Mariner East pipeline system and Marcus Hook terminal are up 12% over the same period in 2020.
We are awaiting the issuance of a permit modification for the conversion of the final directional drill to an open cut, which will allow us to place the final segment of Mariner East into service in the first quarter of 2022.
Our Pennsylvania Access project, which will allow refined products to flow from the Midwest supply regions into Pennsylvania, New York and other markets in the Northeast, will begin moving refined products this winter.
Now for a brief update on our Nederland terminal.
As a reminder, with the completion of the remaining expansions of our LPG facilities at Nederland, earlier this year, we are now capable of exporting more than 700,000 barrels per day of NGLs from our Nederland terminal.
And when combined with our export capabilities from our Marcus Hook terminal, as well as our Mariner West pipeline, which exports ethane to Canada, our total NGL export capacity is over 1.1 million barrels per day, which is among the largest in the world.
At our expanded Nederland terminal, NGL volumes continued to increase during the third quarter, including export volumes under our Orbit ethane export joint venture, which has remained strong.
Year-to-date through September, we have loaded more than 16 million barrels of ethane out of this facility.
And in total, our percentage of worldwide NGL exports has doubled over the last 18 months to nearly 20%, which was more than any other company or country for the third quarter of 2021.
Looking ahead, we expect our total NGL export volumes from Nederland to continue to increase throughout next year.
In addition, demand for supply to refineries remain strong, and our crude oil storage at Nederland is fully contracted.
At Mont Belvieu, we recently brought on a 3 million-barrel high-rate storage well, which takes our NGL storage capabilities at Mont Belvieu to 53 million barrels.
And our Permian Bridge project, which connects our gathering and processing assets in the Delaware Basin with our G&P assets in the Midland Basin was placed into service in October and is already being significantly utilized.
This project allows us to move approximately 115,000 Mcf per day of rich gas out of the Midland Basin and to operate existing capacity more efficiently while also providing access to additional takeaway options.
In addition, it can easily be expanded to 200,000 Mcf per day when needed.
Lastly, in July, we announced the signing of a memorandum of understanding with the Republic of Panama to study the feasibility of jointly developing a proposed Trans-Panama gateway pipeline.
We believe this project would create the most liquid and attractive LPG supply hub in the world and are excited about the opportunity it presents.
Now for an update on our alternative energy activities, where we have continued to make progress on a number of fronts.
In September, we entered into a 15-year power purchase agreement with SB Energy for 120 megawatts of solar power from its Eiffel Solar project in Northeast Texas.
This is the second solar project we are participating in and these agreements provide a good fixed price per megawatt hour on a generated basis.
So we only pay for power actually generated and delivered to us.
We're also continuing to explore several opportunities for solar, wind, and forestry carbon credit projects on our existing acreage in the Appalachian region.
In particular, we're continuing to jointly pursue solar and wind development on the Energy Transfer track in Kentucky with a large utility company, and we are in discussions with other large renewable energy developers.
On the carbon capture front, our Marcus Hook project looks financially attractive based upon preliminary cost estimates and design feasibility studies.
This project would involve capturing CO2 from the flue gas and delivering it to customers for industrial applications and is used in food and beverage industries.
We're also pursuing several carbon projects related to our assets, including projects involving the capture of CO2 from processing plants for use in enhanced oil recovery or sequestration.
We continue to believe that our franchise will allow us to participate in a variety of projects involving carbon capture or other innovative uses as we continue to reduce our carbon footprint.
Lastly, we expect to publish our annual corporate responsibility report for our website shortly.
Now let's take a closer look at our third quarter results.
Consolidated adjusted EBITDA was $2.6 billion, compared to $2.9 billion for the third quarter of 2020.
DCF attributable to the partners as adjusted was $1.31 billion for the third quarter, compared to $1.69 billion for the third quarter of 2020.
While we saw higher volumes across the majority of our segments, including record volumes in the NGL and refined products segment, these benefits do not offset the significant optimization gains in the third quarter of 2020 related to our various optimization groups, as well as the onetime $103 million gain in our midstream segment.
In addition, the third quarter of 2021 included higher utilities and other winter storm Uri-related expenses.
On October 26, we announced a quarterly cash distribution of $0.1525 per common unit or $0.61 on an annualized basis.
This distribution will be paid on November 19 to unitholders of record as of the close of business on November 5.
Turning to our results by segment, and we'll start with the NGL and refined products.
Adjusted EBITDA was $706 million, compared to $762 million for the same period last year.
Higher terminal services and transportation margins related to the increased throughput on our Nederland and Mariner East pipelines in the third quarter of 2021 were offset by a $55 million decrease in our optimization businesses at Mont Belvieu and in the Northeast, as well as increased opex and G&A.
NGL transportation volumes on our wholly owned and joint venture pipelines increased to a record 1.8 million barrels per day, compared to 1.5 million barrels per day for the same period last year.
This increase was primarily due to increased export volumes feeding into our Nederland terminal from the initiation of service on our propane and ethane export projects, higher volumes from the Eagle Ford region, as well as increased volumes on our Mariner East and Mariner West pipeline systems.
And our fractionators also reached a new record for the quarter with an average fractionated volumes of 884,000 barrels per day, compared to 877,000 barrels per day for the third quarter of 2020.
Throughout 2021, we have continued to add volumes to our system and are well-positioned to capture additional volumes and capitalize on new opportunities as demand improves.
For our crude oil segment, adjusted EBITDA was $496 million, compared to $631 million for the same period last year.
The improved performance on our Bakken and Bayou Bridge pipelines as a result of recovering volumes in the third quarter of 2021 did not offset approximately $100 million of onetime items in the third quarter of 2020.
In addition, we had approximately $20 million in other optimization reductions, as well as increased opex and G&A expense year-over-year.
For midstream, adjusted EBITDA was $556 million, compared to $530 million for the third quarter of 2020.
This was largely the result of a $156 million increase related to favorable NGL and natural gas prices, as well as volume growth in the Permian and the ramp-up of recently completed assets in the Northeast, which were partially offset by a decrease of $103 million due to the restructuring and assignment of certain contracts in the Ark-La-Tex region in the third quarter of 2020.
Gathered gas volumes were 13 million MMBtus per day, compared to 12.9 million MMBtus per day for the same period last year due to higher volumes in the Permian, Ark-La-Tex and South Texas regions.
Permian Basin volumes continue to be strong and Midland inlet volumes remained at/or near record highs.
As a result, we are already utilizing our Permian Bridge project to enhance the efficiency of our processing in the area by moving some volumes over to our Delaware Basin processing plants.
In our Interstate segment, adjusted EBITDA was $334 million, compared to $425 million for the third quarter of 2020 primarily due to contract expirations at the end of 2020 on Tiger and FEP, as well as a shipper bankruptcy on Tiger and lower demand on Panhandle and Trunkline partially offset by an increase in transported volumes on Rover due to more favorable market conditions.
And for our intrastate segment, adjusted EBITDA was $172 million, compared to $203 million in the third quarter of last year.
This was primarily due to lower optimization volumes as a result of third-party customers shifting to long-term contracts from the Permian to the Gulf Coast and lower spreads, as well as an increase in operating expenses, which were largely offset by increased transportation volumes out of the Permian and an increase in retained fuel revenues and storage margin.
While it impacted us over the comparison period, the additional long-term contracting of third-party customers from the Permian to the Gulf Coast is expected to benefit us going forward as the Waha to Katy basis differential has tightened significantly.
To reduce volatility within our earnings and protect us from falling basis differentials, like we saw from the third quarter of 2020 to the third quarter of 2021, we have strategically taken steps to lock in additional volumes under fee-based long-term contracts, which are exceeding current differentials.
Now turning to our 2021 adjusted EBITDA guidance.
Our full year 2021 adjusted EBITDA remains $12.9 billion to $13.3 billion.
As a reminder, this range excludes any contributions from the announced Enable acquisition.
And moving to a growth capital update, for the nine months ended September 30, 2021, Energy Transfer spent $1.08 billion on organic growth projects, primarily in the NGL refined products segment, excluding SUN and USA Compression capex.
For full year 2021, we continue to expect growth capital expenditures to be approximately $1.6 billion, primarily in the NGL refined products, midstream, and crude oil segment.
After 2022 and 2023, we continue to expect to spend approximately $500 million to $700 million per year.
Now looking briefly at our liquidity position.
As of September 30, 2021, total available liquidity under our revolving credit facilities was approximately $5.4 billion, and our leverage ratio was 3.15 times per the credit facility.
During the third quarter, we utilized cash from operations to reduce our outstanding debt by approximately $800 million.
And year-to-date, we have reduced our long-term debt by approximately $6 billion.
We have done a lot of heavy lifting over the last few years as we work to accelerate our debt reduction, improve our leverage, and best position ourselves to return value to our unitholders.
We expect to generate a significant amount of cash flow in 2022, and paying down debt continues to be our top priority.
Additionally, our strong performance in 2021 opens the door for the potential to begin returning value to our unitholders in the form of distribution increases and/or buybacks beginning next year.
During the third quarter, we continue to see volumes recover across several of our systems, as well as improve fundamentals.
In addition, our Nederland and Mariner East expansion projects drove record volumes in our NGL and refined products segment, and we expect total NGL exports to grow throughout 2022.
Overall, our assets continued to generate strong cash flow, which allowed us to internally fund our growth projects and further reduce debt in the third quarter.
We remain committed to maintaining and improving our investment-grade rating and continue to place a significant amount of emphasis on capital discipline, deleveraging, and maintaining financial flexibility.
We continue to be excited about the acquisition of Enable, and we believe we will be able to use our enhanced footprint to improve efficiencies and pursue new commercial opportunities.
How we participate in the evolving energy world is a key focus, and we continue to make progress on a number of our alternative energy projects, which we can enhance and effectively grow our energy franchise with preliminary cost estimates looking favorable.
Operator, please open the lineup for our first question.

user
for full year of 2021, et expects its adjusted ebitda to be $12.9 billion to $13.3 billion.

assistant