Energy Transfer LP

Welcome to the Energy Transfer Q2 2022 Earnings Conference Call. My name is Darrell and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. During the question and answer session, if you have a question, please press zero, then one on your touchtone phone. As a reminder, this conference is being recorded. I will now turn the call over to Tom Long, Energy Transfer's co-CEO. Mr. Long, you may begin.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Second 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 our 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 10-Q for the quarter ended June 30, 2022, which we expect to be filed tomorrow, August 4. I'll also refer to adjusted EBITDA and Distributable Cash Flow, or DCF, both of which are non-GAAP financial measures. You will find a reconciliation of our non-GAAP measures on our website. I'd like to start today by looking at some of our second quarter highlights. We were pleased to report another strong quarter during which we generated adjusted EBITDA of $3.23 billion and DCF attributable to the partners of Energy Transfer as adjusted was $1.88 billion. This resulted in excess cash flow after distributions of approximately $1.17 billion. On an incurred basis, we had excess DCF of approximately $730 million after distributions of $710 million and growth capital of approximately $440 million. On July 26, we announced a quarterly distribution of 23 cents per common unit, or 92 cents on an annualized basis, which represents a more than 50% increase over the second quarter of 2021. As a reminder, future increases to 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. Operationally, our diverse asset base saw throughput increases across all of our segments as rig counts continued to improve across the US. And we saw record midstream volumes as well as record throughput on our NGL transportation pipelines, Mont Bellevue fractionators, and terminals. In addition, construction continues to progress on several of our growth projects, which I will provide more details on shortly. I'll start with a brief update on the sale of Energy Transfer Canada. In March of this year, we announced a definitive agreement to sell our 51% interest in Energy Transfer Canada for cash proceeds of approximately $270 million. In addition, the sale is expected to reduce our consolidated debt by approximately $550 million. This sale allows 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 US footprint. The transaction remains on track, and we continue to expect it to close this month. This week, Energy Transfer signed an agreement to acquire Woodford Express LLC, a mid-continent gas gathering and processing system, for approximately $485 million. This bolt-on opportunity will provide a roughly 450 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 Clay. 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 with active proven producers. We're excited to add these strong assets, quality customer contracts and established operations to our footprint in the mid-continent, all at an attractive valuation that will be immediately accretive to energy transfer unit holders. This transaction is expected to close by the end of the third quarter of this year, subject to regulatory review and other customary closing conditions. Now I'll walk you through recent developments and other growth projects. Year-to-date, Lake Charles LNG has executed five LNG offtake agreements for an aggregate of 5.8 million tons per annum. The purchase price in all these agreements is indexed to the Henry Hub benchmark, plus a fixed liquefaction charge, and the LNG will be delivered onto customer vessels on a FOB basis. The agreements will become fully effective upon the satisfaction of the conditions precedent by Energy Transfer LNG, including reaching FID. We are also in active negotiations with a number of other high-quality customers as we expect to make announcements of additional off-take agreements in the weeks ahead. As we 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 or more industry participants in conjunction with LNG off-take agreements. We continue to work toward achieving FID for this project by the end of this year, and we expect that our anticipated announcements of additional long-term LNG offtake agreements over the next several weeks will keep us on track for meeting this objective. Upon completion of the LNG project, we expect to realize significant incremental cash flows from transportation of natural gas on our trunk line pipeline system and other energy transfer pipelines upstream from Lake Charles. Recent events in Europe highlight the importance of LNG from the United States, a country with abundant natural gas supply and government support for LNG exports. These events have caused companies around the world to place increased importance on long-term security of natural gas supply. We believe our Lake Charles LNG project will be a significant factor in the long-term solutions for global energy needs. Looking at the Mariner East pipeline system, which is fully commissioned and capable of transporting more than 365,000 barrels per day, including ethane. For the second quarter of 2022, NGL volumes through both the Mariner East pipeline system and Marcus Hook terminal reached new records. And in July, we set a monthly throughput record for the combined Mariner East pipes, and we continue to see strong utilization of these pipes. In addition, We recently completed work at the terminal to allow us to increase the ethane exports out of Marcus Hook, and we continue to evaluate all options to achieve incremental ethane and LPG exports out of Marcus Hook until we complete an expansion of the terminal. At our expanded Nederland terminal, NGL export volumes were very strong during the second quarter, including export volumes under our ethane export joint venture. We hit a record in the second quarter for ethane exports, and year to date, we have loaded nearly 18 million barrels of ethane out of the facility. The second tranche of Satellite's contract went into effect on July 1st, which doubles the volume commitments from the initial term, and we loaded the first vessel under this demand base agreement in July. For full year 2022, we continue to expect to load more than 40 million barrels of ethane, with that increasing to as high as 60 million barrels for 2023. In total, we continue to export more NGLs than any other company or country, and our percentage of worldwide NGL exports remains at approximately 20% of the world market. We continue to see increase in NGL demand both in the U.S. as well as from overseas customers seeking additional supply from the U.S., and we have sufficient commitments to move forward on 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 of initially expanding at either terminal. In addition, due to the significant tightening and fractionation capacity, we recently resumed construction on Frac 8, which was more than half funded when construction was paused in 2020. Frac 8 is expected to be in service in the third quarter of 2023 and will bring our total mock value fractionation capacity to over 1.1 million barrels per day. In the second quarter, our Permian Basin plant inlet processing volumes were approximately 2.2 BCF per day, which is a new record. And due to significant producer demand and continued growth around Permian Basin gathering and processing assets, we are adding additional capacity to meet increasing production from the Basin. Construction of our new 200 million cubic foot per day Ray 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 this year. We are also moving forward with a second 200 million cubic foot per day processing plant in the Permian Basin. A portion of the growth capital associated with the Bayer plant was included in our previous forecast but we have accelerated some spend into 2022 to expedite the completion of this plant in order to meet growing demand. This plant is expected to be serviced 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. Once in service, the volumes from the tailgate of these plants will utilize our gas and NGO pipelines, for takeaway, providing revenue streams for our intrastate and NGL segments on top of the incremental revenue for our midstream segment. In the meantime, we continue to heavily utilize the Permian Bridge project to provide operational flexibility between our processing facilities in the Delaware and the Midland Basin. Crew terminal throughput increased nearly 20% over the second quarter of last year, driven by increased upstream pipeline throughput the Strategic Petroleum Reserve drawdown, and additional market connectivity via the Ted Collins Link. At our needle and terminal, we have recently seen record crude volumes destined for the refinery and export markets. Overall, we expect to see exports continue to stay strong, largely due to the Ted Collins Link, which provides our systems with more market connectivity and access to deeper water, as well as a quality management program which ensures a higher quality Midland WTI barrel as desired by our customers. We continue to make progress on the construction of the Gulf Run Pipeline, which is a 42-inch interstate natural gas pipeline with 1.65 BCF per day of capacity. Gulf Run is backed by a 20-year commitment for 1.1 BCF per day from Golden Pass LNG, and will provide natural gas transportation between the Haynesville Shale and the Gulf Coast, connecting some of the most prolific natural gas producing regions in the U.S. with the LNG export market. Gulf Run remains on schedule to be complete by the end of this year. We recently completed a non-binding open season on Gulf Run due to growing producer demand. We were pleased with the results of the open season, and customer discussions are ongoing, which will likely necessitate additional facilities beyond the initial design of 1.65 BCF per day. Turning to the Warrior Pipeline project, which is the most optimal solution for customers to transport gas out of the Permian in regard to timing, cost, flexibility, and access to premium markets. We are still evaluating the construction of this new intrastate pipeline from the Midland Basin to our extensive pipeline network south of the DFW area and remain optimistic that we can bring this project to FID. In the meantime, Modernization and de-bottlenecking work on our ACES pipeline continues, which will add an incremental 60 million cubic foot per day of much needed capacity out of the Permian Basin. This capacity is expected to be available by the end of this year. We also continue to evaluate opportunities in the petrochemical space, which would include developing a project along the Gulf Coast, as well as potential M&A opportunities. We're in discussions with a number of high-quality customers as we work to secure long-term tolling type commitments prior to reaching FID. We also intend to have a significant partnership with one or more industry participants. If we are able to reach FID on this project, the ethylene and propylene production units would be synchronized into a world-class facility, providing unique feedstock and product flexibility. This would allow our customers to capitalize on access to the lowest cost feedstock through our comprehensive pipeline system, as well as unparalleled access to downstream domestic and international markets through our pipelines, our underground storage facilities, and our export terminals. Now for an update on our alternative energy activities. We are continuing to focus on efforts on reducing emissions across our pipelines. We have established an internal task force to coordinate these efforts in conjunction with third-party consultants. We recently entered into a letter of intent with Capture Point Solutions to pursue the joint development of a carbon capture and sequestration hub in Louisiana. This project would involve the installation of carbon capture equipment on several natural gas treating plants in the Hainesville area and the transport by pipeline of CO2 to a sequestration site that Capture Point is developing. Preliminary cost estimates as well as projections of cash flow and tax credits indicate that this project will generate an attractive financial return. We continue to pursue a number of projects related to carbon capture, including sequestration, enhanced oil recovery, and utilization projects. We are in active discussions with several developers of CO2 sequestration sites in close proximity to our existing facilities in other regions. as well as our proposed Lake Charles LNG liquefaction facility. That would be good candidates for carbon capture and sequestration. Now let's take a closer look at our second quarter results. Consolidated adjusted EBITDA was $3.33 billion compared to $2.62 billion for the second quarter of 2021. ECF tripled to the partners as adjusted was $1.88 billion for the second quarter of 2022 compared to $1.39 billion for the second quarter of 2021. Results for the second quarter included higher transportation volumes across all of our segments, as well as a full quarter contribution from the Enable assets that were acquired in December of 2021. On July 26th, we announced a quarterly cash distribution of 23 cents per common unit, or 92 cents on an annualized basis. This distribution will be paid on August 19th the unit holders of record as of the close of business on August the 8th. This distribution represents a more than 50% increase over the second quarter of 2021. Turning to our results by segment and starting with NGL and refined products, custody bidow was $763 million compared to $736 million for the same period last year. This was primarily due to higher fractionation margin, higher transportation margin, as well as higher terminal service margin related to increased throughput at our Nederland and Marcus Hook terminals in the second quarter of 2022. NGL transportation volumes on our wholly owned and joint venture pipelines increased to a record 1.9 million barrels per day compared to 1.7 million barrels per day for the same period last year. This increase was primarily due to a ramp up in volumes through our propane and ethane export pipelines into our Nederland terminal. and higher volumes from the Permian and Eagleford regions, as well as record volumes on our Mariner East pipelines. And our average fractionated volumes were also a record at 938,000 barrels per day compared to 833,000 barrels per day in the second quarter of 2021. For our crude oil segment, adjusted EBITDA was $562 million compared to $484 million for the same period last year. This was primarily due to improved performance on our Bakken pipeline despite significant weather impacts during the quarter, increased throughput at our Gulf Coast terminals, as well as the addition of the Enable assets in December of 2021. Crude oil transportation volumes increased to 4.3 million barrels per day compared to 4 million barrels per day for the same period last year, driven by higher crude oil prices and strong refinery demand. From midstream, adjusted EBITDA was $903 million compared to $477 million for the second quarter of 2021. This was primarily due to the acquisition of the Enable assets in December of 2021 and an increase related to favorable NGL and natural gas prices, as well as significant increases throughout the majority of our operating regions. Gathered gas volumes were 18.3 million MMBTUs per day compared to 13.1 million MBM BTUs per day for the same period last year due to the addition of the Enable assets, increased production in South Texas and in the Northeast, as well as additional gathering capacity from the Permian Bridge pipeline in West Texas. Permian Basin volumes continue to be strong, and Permian Basin inlet volumes remain at or near record highs. we are utilizing the Permian Bridge daily to optimize our available processing capacity as well as increasing our processing capacity in the area to accommodate incremental demand we are seeing. In our interstate segment, adjusted EBITDA was $397 million compared to $331 million for the second quarter of 2021. During the quarter, we benefited from the addition of the Enable assets as well as increased rates and higher utilization on the Transwestern, Tiger, Rover, and Frontline systems due to more favorable market conditions and volume growth. We continue to see heavy utilization on many of our interstate pipelines, including Tiger, FGT, SESH, and Rover. And toward the end of the second quarter, basis spreads on our interstate pipelines began to widen, creating stronger demand for capacity across our interstate network and we expect that to continue throughout the rest of this year. And for our interest rate segment, adjusted EBITDA was $218 million compared to $224 million in the second quarter of last year. Absent benefits from winter storm URI in both quarters, this segment would have been up approximately $30 million due to an increase in retained fuels related to higher natural gas prices. This was partially offset by lower storage optimization opportunities. Utilization of our HPL system remains strong due to increased demand from gas takeaway, and our RIGS pipeline system continues to flow at or near capacity due to increased activity in the Hainesville. Now turning to our 2022 adjusted EBITDA guidance, given our strong performance in the second quarter, as well as continued demand for our products as we move through the rest of the year, we now expect our adjusted EBITDA to be between $12.6 billion to $12.8 billion. This is up compared to our previous guidance of $12.2 billion to $12.6 billion. And moving to a growth capital update for the six-month end of June 30, 2022, energy transfer spent approximately $825 million on organic growth projects, primarily in the midstream, interstate, and NGL refined product segment, excluding sun and USA compression captex. For full year 2022, we continue to expect growth capital expenditures to be between $1.8 to $2.1 billion, and we will likely be near the high end of that range as we have added new projects related to incremental demand that we are now seeing. These projects include the addition of capital related to Frac 8, accelerated spend on new processing facilities in the Permian, and a new connection for Gulf Run. which are all offset by deferral of some spend 2023 based upon project timing. Now looking briefly at our liquidity position as of June 30, 2022, total available liquidity under a revolving credit facility was approximately $2.44 billion. We continue to expect to generate a significant amount of cash flow this year which will be strategically allocated in a manner that best positions us to continue to improve our leverage, invest in high returning growth projects, return value to our unit holders. And we expect to continue to pay down debt throughout this year and beyond with excess cash flow from operations. We also expect to reach our leverage target range by the end of this year and going forward expect our strong coverage and balance sheet strength to allow us to further prioritize growth within our capital allocation strategy. Our strong second quarter in performance was driven by significant volume growth across all of our segments as a result of improved production and increased demand, which we expect to continue throughout 2022. In addition, the Enable assets acquired at the end of 2021 continue to outperform our internal budget during the second quarter. We expect production improvements, market conditions, and strong domestic and international demand for our products to positively impact all of our segments for the remainder of this year. We are pleased with the progress we have made toward reaching our leveraged target range, and we remain focused on improving our financial flexibility and paying down debt in order to further strengthen our balance sheet. In addition, we will continue to evaluate returning additional capital to our equity unit holders through distribution growth on a quarterly basis. We remain bullish about the future of our industry and the growing worldwide demand for natural gas and natural gas liquids. As we look for additional ways to address existing and new demand for our products, we will continue to evaluate and pursue strategic growth projects that enhance our existing asset base and generate attractive returns as part of the capital allocation strategy. Operator, please open the line up for our first question.

And once again, if anyone has a question, it's 01 on your touchtone phone. If you wish to be removed from the queue, it's 02. And I'm standing by for questions. Our first question comes from Jeremy Tonnett from JP Morgan. Go ahead, Jeremy.