Energy Transfer LP

Good afternoon, and welcome to the Energy Transfer Third Quarter 2022 Earnings Conference Call. All participants will be in a listen-only mode. Should you need any assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your telephone keypad. To withdraw a question, please press star, then two. Please note this event is being recorded today. I would now like to turn the conference over to Tom Long, co-CEO. Please go ahead, sir.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Third Quarter 2022 Earnings Call. I'm also joined today by Mackie McCree and other members of the senior management team who are here to help answer your questions after the prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon, as well as the slides posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Security Exchange Act of 1934. These statements are based upon 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 10Q for the quarter ended September 30, 2022, which we expect to be filed this Thursday, November 3rd. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. I'll start today by going over our third quarter financial results. We were pleased to report another strong quarter during which we generated consolidated adjusted EBITDA of $3.1 billion, which was up approximately 20% compared to $2.6 billion for the third quarter of 2021. In the third quarter, we experienced a non-recurring $126 million charge in the crude oil segment related to the resolution of a prior year legal matter. In addition, we had an approximately $130 million negative impact due to the timing of the recognition of gains on hedged inventory in the NGL and refined product segment. Absent these two items, adjusted EBITDA for the third quarter would have been $3.34 billion. Results for the third quarter benefited from higher volumes across all of our segments, including record volumes in the midstream, intrastate, crude oil, and through our fractionators. In addition, the acquisition of the ENABLE assets in December of 2021 contributed to our growth over the prior period. DCF, attributable to the partners, as adjusted was $1.6 billion for the third quarter of 2022 compared to $1.3 billion for the third quarter of 2021. This resulted in excess cash flow after distributions of approximately $760 million. On an incurred basis, we had excess DCF of approximately $265 million after distributions of $819 million and growth capital of approximately $500 million. On October 25th, we announced a quarterly cash distribution of 26.5 cents per common unit, or $1.06 on an annualized basis. This distribution will be paid on November 21st to unit holders of record as of the close of business on November 4th. This distribution represents a more than 70% increase over the third quarter of 2021. As a reminder, future increases to the distribution level will be evaluated quarterly with the ultimate goal of returning distributions to the previous level of 30.5 cents per quarter or $1.22 on an annualized basis while balancing our leverage target, growth opportunities, and unit buybacks. As of September 30, 2022, the total available liquidity under our revolving credit facility was approximately $2.32 million. Now turning to our results by segment, I'll start with the NGL and refined products. Adjusted EBITDA was $634 million compared to $706 million for the same period last year. This change was primarily due to the previously mentioned $130 million negative impact due to the timing of the recognition of gains on hedged NGL inventory during the current period. We expect to fully realize the offsetting gains on our financial derivatives and physical forward sales as the majority settle in the fourth quarter, with a small amount settling in the first quarter of 2023. Adjusting for the non-cash timing matter around hedging, adjusted EBITDA for the third quarter would have been $764 million. Results in this segment were otherwise driven by higher fractionation transportation, terminal services, and storage margins related to increased volumes and higher rates. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.9 million barrels per day compared to 1.8 million barrels per day for the same period last year. This increase was primarily due to higher volumes on our NGL pipelines that deliver into our needle and terminal, as well as a record volumes on the combined Mariner East pipelines. And our average fractionated volumes set a new partnership record, averaging 940,000 barrels per day compared to 884,000 barrels per day for the third quarter of 2021. NGL export volume significantly exceeded the third quarter of last year, driven by record ethane exports out of both Nederland and Marcus Hook. At Nederland, this was driven by the second tranche of satellite's contract going into effect on July 1st, which doubled the volume commitments from the initial term. Year to date, we have loaded approximately 29 million barrels of ethane out of Nederland, and for full year 2022, we expect to load more than 40 million barrels of ethane out of Nederland, with that increasing to approximately 60 million barrels for 2023. In total, we continue to export more NGLs than any other company or country with our percentage of worldwide NGL exports remaining at approximately 20% of the world market. For midstream, adjusted EBITDA was $868 million compared to $556 million for the third quarter of 2021. This was primarily due to the increased throughput in all of our operating regions, favorable natural gas, and NGL prices, and the acquisition of the Enable assets in December of 2021. Gathered gas volumes were a record 19.1 million MMBTUs per day compared to 13 million MMBTUs per day for the same period last year. Excluding Enable, gathered gas volumes on our legacy assets were also a partnership record for the third quarter. Permian Basin Inlet volumes remain at or near record highs. We continue to utilize the Permian Bridge daily to optimize our available processing capacity as we await the completion of two new plants that are currently under construction. For the crude oil segment, adjusted EBITDA was $461 million compared to $496 million for the same period last year. Earnings were offset by a $126 million charge related to the resolution of a prior year legal matter. Absent this charge, adjusted EBITDA would have been $587 million for the third quarter of 2022. These results were otherwise driven by improved performance on our Bakken pipeline, increased throughput at our Gulf Coast terminals, stronger refinery utilization, and higher export demand, as well as the addition of the Enable assets in December of 2021. Crude oil transportation volumes increased to a record 4.6 million barrels per day compared to 4.2 million barrels per day for the same period last year, driven by higher crude oil prices and strong refinery demand, as well as the addition of the Ted Collins Link and Cushing South pipelines, and increased throughput through our Houston Terminal. Excluding Enable, crude oil transportation volumes were also a record for the third quarter. In our interstate segment, adjusted EBITDA was $409 million compared to $334 million for the third quarter of 2021. During the quarter, we benefited from increased rates, higher production in the Haynesville shell that drove greater utilization on Tiger, improved demand on trunk line and line CP, as well as the addition of the other interstate-enabled assets. We continue to see heavy utilization on many of our interstate pipelines, including Tiger, FGT, SESH, and Rover. And for our intrastate segment, adjusted EBITDA was $301 million compared to $172 million for the third quarter of last year. This was primarily due to higher optimization opportunities, increased retained fuel revenues related to higher natural gas prices, as well as the addition of the Enable assets. Utilization of our HPL system remains strong due to the increased demand for gas takeaway, and our RIGS pipeline system continues to flow at or near capacity due to increased activity in the Haynesville. Turning to a brief update on our M&A activity, in August of this year, we completed the sale of our 51% interest in Energy Transfer Canada for cash proceeds of approximately $300 million. The sale reduced our consolidated debt by approximately $850 million. It also allowed us to divest of these non-core assets at an attractive valuation and utilize the cash proceeds to further deleverage our balance sheet and redeploy capital within our U.S. footprint. And in September of this year, we completed our acquisition of the Woodford Express LLC which owns a mid-continent gas gathering and processing system for approximately $485 million. This bolt-on opportunity provided roughly 400 million cubic foot per day of cryogenic gas processing and treating capacity in Grady County, Oklahoma, as well as more than 200 miles of low and mid-pressure gathering lines in the heart of the scoop play. The assets are already connected to our inter- and intrastate systems, as well as our gas gathering system. The system is supported by dedicated acreage with long-term, predominantly fixed-fee contracts. Now looking at recent developments at our ongoing growth projects. Year-to-date, Lake Charles LNG has executed six LNG offtake agreements for an aggregate of nearly 8 million tons per annum, including a 20-year LNG agreement with Shell NALNG LLC that was executed in August. As we have previously stated, we expect to finance a significant portion of the capital cost of this project by means of the sale of equity in the project to infrastructure funds and possibly to one and more industry participants in conjunction with LNG offtake agreements. We have recently signed non-binding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the project and we're now targeting FID by the end of the first quarter of 2023. Upon completion of the LNG project, we expect to realize significant incremental cash flows from transportation of natural gas on our trunkline pipeline system and other energy transfer pipelines upstream from Lake Charles. We believe that our Lake Charles LNG project will provide an important contribution towards solving the growing global energy demand. As a reminder, our Mariner East pipeline system is fully commissioned and capable of transporting more than 365,000 barrels per day, including ethane. As we have previously mentioned, we completed work at our Marcus Hook terminal to allow us to increase ethane exports out of Marcus Hook. As a result, we reached a new record for ethane exports out of our Marcus Hook terminal in the third quarter. NGL demand, both in the U.S. as well as from overseas customers, continues to increase, and we have sufficient commitments to move forward with an ethane export expansion. Even though we expect to expand our ethane export capabilities at both our Marcus Hook and Needland terminals, these commitments provide us with the optionality to initially expand at either terminal. Construction of Frac 8 continues this schedule, and we expect it to be in service in the third quarter of 2023, which will bring our total Montbellevue fractionation capacity to over 1.1 million barrels per day. Construction of our new 200 million cubic foot per day gray wolf processing plant in the Delaware Basin is underway. This plant is supported by new commitments and growth from existing customer contracts and remains on schedule to be in service by the end of 2022. Construction is underway on the bare plant, our second 200 million cubic foot per day processing plant, also located in the Delaware Basin, which was accelerated to meet growing demand. We expect this plant to be in service in the second quarter of 2023. In addition, given the significant amount of demand we're seeing, we are evaluating the necessity and potential timing of adding another processing plant in the region. Mainline construction of the Gulf Run pipeline was recently finished, and we expect to complete a modification of compression by the end of this year. Gulf Run, which is a 42-inch interstate natural gas pipeline with 1.65 BCF per day of capacity, will provide natural gas transportation between our upstream pipeline network and from the Hainesville Shell for delivery to the Gulf Coast, connecting some of the most prolific natural gas producing regions in the U.S., with the LNG export market. It is backed by a 20-year commitment for 1.1 BCF per day from Golden Pass LNG, and we recently concluded a non-binding open season on Gulf Run due to the growing product demand. We're pleased with the results of the open season and customer discussions are ongoing, which will likely necessitate additional facilities beyond the initial design of the 1.65 BCF per day. Modernization and de-bottlenecking work on our ACES pipeline continues, which will add an incremental 60,000 MCF per day of much-needed capacity out of the Permian Basin. We expect it to be partially in service by the end of this year, with full service by the end of January of 2023. In addition to these ongoing projects, we continue to evaluate and have customer discussions regarding a number of other projects that over the long term could provide significant upside to our business. These include the Warrior Pipeline project, which is the most optimal solution for customers to transport gas out of the Permian, as well as opportunities to develop a pet chem project along the Gulf Coast or acquire pet chem facilities. We remain optimistic that we can bring these projects to FID and look forward to sharing any significant updates on these projects at the appropriate time. On the alternative energy front, our focus remains on reducing emissions across our pipelines, including pursuing a number of projects related to carbon capture and sequestration, enhanced oil recovery for use in the food and beverage industries, as well as sequestering CO2 from our proposed Lake Charles LNG liquefaction facility. We'll be excited to update you once we have a project and specific agreement in place Looking at our growth capital spend for the nine months ended September 30, 2022, energy transfer spent approximately $1.3 billion on organic growth projects, primarily in the midstream, interstate, and NGL refined product segment, excluding sun and USA compression capex. For full year 2022, we expect growth capital expenditures to be near the high end of our range of $1.8 to $2.1 billion. Over 90% of our 2022 growth capital spend is comprised of projects that are already online or are expected to be online and contributing cashflow before the end of 2023 at very attractive returns. We will provide our 2023 growth capital outlook on our fourth quarter earnings call. For 2022 adjusted EBITDA guidance Given our strong performance for the first nine months of the year, as well as continued demand for our products and services, we now expect our adjusted EBITDA to be between $12.8 billion and $13 billion. This is up compared to our previous guidance of $12.6 billion to $12.8 billion. Overall, our outlook is strong as we have a stable business that has demonstrated its ability to manage through various market cycles. And we expect future growth to be supported by production improvements, improved market conditions, increased utilization of our existing assets, as well as strong domestic and international demand for our products. We remain bullish about the future of our industry and the growing worldwide demand for crude oil, natural gas, and natural gas liquids. We expect to reach our leverage target range of four to four and a half times by the end of 2022. and we will continue to strategically allocate our cash flow in a manner that best positions us to further improve our financial flexibility and leverage, invest in high-returning growth projects, and return value to our unit holders. As we look for additional ways to address existing and new demand for our products, we will continue to pursue strategic growth projects that enhance our existing asset base and generate attractive returns as part of our capital allocation strategy. This concludes our prepared remarks. Operator, please open the line up for our first question.

We will now begin the question and answer session. To ask a question, you may press star, then 1 on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star, then 2. We ask that you please limit yourself to only one question and one follow-up. At this time, we will take our first question, which will come from Jeremy Tonant with JP Morgan. Please go ahead.