Energy Transfer LP

Greetings. Welcome to the Energy Transfer First Quarter Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If an owner should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to your host, Tom Long. Mr. Long, you may begin.

Thank you, Operator, and good afternoon, everyone, and welcome to the Energy Transfer First Quarter 2021 Earnings Call. And thank you for joining us today. 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 our 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 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 March 31st, 2021, which we expect to be filed tomorrow. I'll also refer to adjusted EBITDA distributable cash flow, or DCF, and distribution coverage ratio, 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 first quarter highlights. We generated adjusted EBITDA of $5.04 billion, and DCF, attributable to the partners of ET, as adjusted, of $3.91 billion. Our excess cash flow after distributions was approximately $3.5 billion. On an incurred basis, we had excess DCF of approximately $3.14 billion after distributions of $412 million and growth capital of approximately $360 million. The increased results were primarily due to one-time impacts from winter storm URI in February, largely driven by our significant ability to transport large volumes of natural gas from our storage facilities and from market hubs in Texas to power plants, cities, and to LDCs throughout the state. Taking a closer look at the performance of our assets during winter storm URI, as the winter storm approached, we had ample advanced warning which allowed us to pre-position employees and prepare our assets for this historic winter storm. And throughout the storm, our Texas pipelines, processing plants, and compressor stations performed extremely well. Our extensive experience in operating pipelines combined with a significant amount of both long and short-term preparation allowed us to continue operating reliably throughout the storm. As part of our standard design process, we have spent a significant amount of time and effort determining which components and systems are particularly susceptible to extreme weather conditions or process disruption. In the event of severe cold temperatures, we have taken various measures to winterize these components. Our long-term preparation has included the installation of heat tracing on our pipeline systems and at our processing plants to keep piping and internal fluids above freezing point. We also know that it takes considerable investments to maintain one of the largest systems in the industry. And over the past three years, we have spent approximately $1.5 billion for maintenance related to our assets with approximately half of that spent on our Texas assets. Going back to 2014, We have been investing in and developing a dry gas fuel system in West Texas, which provides a reliable fuel source to our compressors while preventing freezing. In the days leading up to the storm, we injected additional natural gas into our pipelines as line pack prior to the storm that not only served as additional storage, but also allowed us to place natural gas volumes as close to our customers as possible. And we brought in specialized equipment that was strategically allocated across our systems to help prevent freezing, including hot starts for engines, steam trucks, steam generators, and methanol injection units. Our employees, including operations personnel and mechanics, were deployed to key assets and to those facilities at greatest risk during freezing operating conditions. This included more than 25 facilities on our pipelines and more than 25 processing plants across Texas. These key facilities were manned 24 hours a day from February 13th through the 18th, which resulted in approximately 50,000 hours of overtime worked by our employees. This pre-deployment preparation allowed us to resolve and prevent most operational issues once the storm arrived. To manage through the storm, we did everything within our control to keep our plants running and circulating fluids and field compression idling so that we were prepared to deliver gas to customers as soon as volumes returned to our facilities. We utilized our Texas storage facilities where we have 63 BCF of working storage capacity. Withdrawals from these facilities reached a peak rate of approximately 1.7 BCF during the storm. Additionally, we did everything we could to purchase and or transport natural gas from other areas including bringing gas in from out of state for delivery to our customers. We conserved power everywhere we could, including facilities like Mont Bellevue, where we reduced power by shutting down our fractionators, and we also switched from electric to gas on our dual-drive compressor units, leaving in excess of approximately 200 megawatts per hour on the grid. This storm highlighted and emphasized the importance of having reliable, flexible assets and an experienced operations team. I've said it before, but we truly believe our operations team is second to none, and their efforts during the winter storm Uri were extraordinary. In a year where we celebrate our 25th anniversary, we had a history of reliable service through multiple extreme adverse weather events, and our performance this time was no exception. Not a surprise here, but we now have opportunities to lock in longer-term contracts for storage and firm transportation capacity. Switching gears to an update on the acquisition of Enable Midstream Partners, which we expect will provide increased scale in the MidCon and Arklatex regions and improve connectivity for our natural gas and NGL transportation businesses. On April 7th, the SEC declared the registration statement on Form S-4 effective. And on April 12th, the two largest Enable unit holders, CenterPoint and OG&E, delivered written consents to approve the merger, which is sufficient to approve the transaction. The transaction is subject to HSR and other customary closing conditions. The combination of energy transfers and Enable's complementary assets will allow the new, larger company to provide superior, flexible, and competitive service to our customers as we pursue additional commercial opportunities. The combined company also expects to achieve significant cost savings while enhancing our ability to serve customers. Integration teams from both companies are currently engaged in the integration planning process, and we continue to expect the combined company to generate more than $100 million of annual run rate cost synergies before factoring in potential financial and commercial synergies. I will now walk through recent developments on our major growth projects, starting with Dakota Access. On May 3rd, the Army Corps filed a status report informing the court that it has not changed its position related to the continued operations of the pipeline. The Army Corps also advised the court that it expects the environmental impact statement to be completed by March of 2022. We continue to cooperate with the Army Corps related to their preparation of the EIS process. Dakota Access is a world-class asset, and we expect it to continue flowing oil reliably, safely, and efficiently as it has done for the past four years. Dakota Access is critical to this country for jobs, tax revenue, and for energy security and independence. Next, construction on the Ted Collins Link is progressing, and we expect it to be in service early in the fourth quarter of 2021. This project will ultimately allow us to transport up to 300,000 barrels per day of crude oil from West Texas and Nederland to our Houston terminal upon full completion. In April, we announced that we will post a joint tariff for Crude Oil Transportation Service to move ET and third-party Powder River and DJ Basin barrels through our Cushing and White Cliffs pipeline to our Nederland terminal. Joint tariff service is expected to commence by June 1st of this year. Upon completion of the first phase, we will be able to transport approximately 65,000 barrels per day of crude oil from the DJ Basin and Cushing area to Nederland, expandable to 120,000 barrels per day. Now turning to our Mariner East system, first quarter of 2021, NGL volumes through the Mariner East pipeline system increased more than 20% over the first quarter of 2020, and we are experiencing very strong demand on Mariner East for April and May. On April 1st, we began transporting natural gasoline through Mariner East to our Marcus Hook terminal for gasoline blending and local consumption. We also recently completed the final drill necessary to commission 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. We continue to expect the next significant phase of the Mariner East projects to be in service in the second quarter of 2021. And the final phase of Mariner East pipeline is expected to be completed in the third quarter of 2021. Our Mariner East pipeline system and Marcus Hook terminal provide the most efficient transportation route for liquids in the Northeast providing customers the optimal way to reach the highest price markets for their products. Now for a brief update on our recently completed projects at our Nederland terminal. We have completed the expansions of our LPG facilities along with construction of a new 20-inch pipeline that directly links our fractionation and storage assets at Mont Bellevue to our Nederland export terminal in the fourth quarter of 2020. Volumes on these assets began ramping up in the first quarter of this year, and we expect them to continue to increase throughout the year. We are now capable of loading nearly 500,000 barrels per day of LPGs at our Needland terminal, which we expect to consistently remain above 80% utilized year-round. And on our 180,000 barrels per day ethane export joint venture with Satellite Petrochemical, We have now loaded three VLECs under this joint venture, each with over 900,000 barrels of ethane, and we have loaded three additional ships with ethane out of our Nederland terminal, bringing our total ethane loaded out of this facility to nearly three and a half million barrels through April. Our NGL franchise at Nederland and Mont Bellevue now have four pipeline systems capable of moving large volumes of ethane propane, butane, and natural gasoline from our fractionators and our storage facilities at Mont Bellevue to our Needland Terminal. As a reminder, with the completion of our LPG and orbit expansions at our Needland Terminal, as well as expansions completed at our Marcus Hook Terminal in Northeast at the end of 2020, our total NGL export capacity is now just over 1 million barrels per day, which supports the strong international demand for NGL exports from the U.S. Lastly, we are pleased to announce that we are moving forward with our Permian Bridge project, which will connect our gathering and processing assets in the Delaware Basin with our GMP assets in the Midland Basin. For this project, we will convert approximately 55 miles of an existing 24-inch NGL pipeline into rich gas service and utilize it to tie our Midland and Delaware Basin assets together. This will allow us to move approximately 115,000 MCF per day of rich gas out of the Midland Basin and operate existing capacity more efficiently, while providing access to additional takeaway options. This project is included in our revised 2021 growth capital guidance and saves us significant capital by being able to fully load our entire Permian Basin processing assets before we commit to building another cryogenic processing plant. This conversion is expected to be completed in the fourth quarter of 2021. Now for a quick update on our alternative energy activities in February, we announced that we have created an alternative energy group to focus on renewable energy projects such as solar and wind farms, either as a power purchaser or in partnership with third party developers. And we'll also look to develop renewable diesel and renewable natural gas opportunities. We have significantly ramped up our export of propane and ethane for power generation that in many cases displaced diesel and other fuels that cause greater CO2 emissions. We recently saw the startup of the Maplewood II solar project, and we are utilizing power from this solar farm to help run our assets in West Texas, including three cryogenic plants in the region, as well as numerous compressor and pump stations. We are in advanced discussions to support a significantly larger solar project with a long-term power purchase agreement that we anticipate announcing in the next few weeks. We are also in discussions with our solar developers regarding the utilization of some of our existing acreage in the Northeast. We continue to pursue several carbon capture and sequestration projects related to our gathering and processing facilities in Texas. that we believe will generate attractive returns through structures that would provide third parties with the benefit of federal tax credits and provide us with annual cash flows with very low capital requirements. Our engineering and commercial teams are currently developing a carbon capture project related to our markets of terminal that would involve carbon utilization for commercial application and based upon preliminary cost estimates and customer feedback, This project looks feasible without the benefit of federal tax credits. We are also reviewing our ESG profile as reported by external ESG rating groups, and we are working to improve our profile scoring, partially resulting from improved communications to address various inaccuracies and misrepresentations. And we are also expanding our ESG metrics reporting through industry-recognized reporting templates. Now let's take a little closer look at our first quarter results. Consolidated adjusted EBITDA was $5.04 billion compared to $2.64 billion for the first quarter of 2020. DCF attributable to the partners as adjusted was $3.91 billion for the first quarter compared to $1.42 billion for the first quarter of 2020. The increased results were primarily driven by our ability to transport natural gas from our storage facilities and market hubs in Texas to power plant cities and to LDCs throughout the state during the historic freezing conditions. On April 22nd, we announced a quarterly cash distribution of 15.25 cents per common unit or 61 cents on an annualized basis. This distribution will be paid on May 19th to unit holders of record as of the close of business on May 11th. Turning to our results by segment, starting with our intrastate segment, adjusted EBITDA was $2.8 billion compared to $240 million in the first quarter of last year. This increase of approximately $2.6 billion was primarily due to the higher natural gas storage withdrawals related to winter storm URI. For 2021, as I already mentioned, we are now seeing new opportunities as producers look to lock in firm transportation and storage. For NGL and refined products, adjusted EBITDA was $647 million compared to $663 million for the same period last year. This was primarily due to a $37 million impact related to lower producer volumes from West Texas on our Texas NGL pipelines and feeding our Mont Bellevue fractionators during the storm URI, as well as COVID-19 related volume reductions. These decreases were partially offset by higher margins from our Mariner East system and Needle and Terminal. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.5 million barrels per day compared to 1.4 million barrels per day for the same period last year. This increase was primarily due to increased volumes on our Mariner East pipeline system, as well as increased export volumes feeding into our Needle and Terminal from the initiation of service on our propane and ethane export projects. On our fractionators, average fractionated volumes were 726,000 barrels per day compared to 804,000 barrels per day for the first quarter of 2020. Transportation and fractionation volumes have been increasing in the second quarter and are currently back to above first quarter 2020 levels. For crude oil segment, adjusted EBITDA was $510 million compared to $591 million for the same period last year. This was primarily due to lower volumes through our Texas and Bakken crude pipelines and terminals as a result of COVID-19 demand reductions, as well as lower rates along our Texas crude pipelines and a $20 million impact from winter storm URI. Since the end of the first quarter, we have seen Permian Basin crude volumes increase on our system as drilling picks up and more ducts are being completed. For midstream, adjusted EBITDA was $288 million compared to $383 million for the first quarter of 2020. This was largely the result of a $167 million impact due to winter storm Uri as well as lower volumes which were partially offset by favorable natural gas and NGL prices and reduced operating expenses. Gathered gas volumes were 12 million MMBTUs per day compared to 13.3 million MMBTUs per day for this period last year due to lower volumes in our South Texas, our MidCon and Panhandle area, Permian and North Texas regions, much of which was due to the winter storm. This was partially offset by volume growth in the Arklatex region. We are starting to see production pickup in Permian Basin Inlet volumes reaching a monthly record in April. This growth is also expected to have a positive complementary impact on our NGL segment from additional production of NGLs out of our West Texas processing plants. In our interstate segment, adjusted EBITDA was $453 million compared to $404 million for the first quarter of 2020, primarily due to an $88 million positive impact from our ability to utilize our pipelines to bring additional natural gas to the mid-continent region during the February storm, as well as reduced operating expenses. These were partially offset by contract expirations on TIGER and on FEP. For 2021, our previous full year adjusted EBITDA guidance was $10.6 billion to $11 billion, which we announced during the week of winter storm URI. These numbers included an expected impact of approximately $200 million related to the storm. Given our ability to utilize our extensive natural gas storage and transportation assets to provide a significant amount of natural gas for consumption during winter storm URI, In total, we now expect to realize approximately $2.4 billion from the storm for full year 2021, inclusive of $100 million of expenses, which may be incurred throughout 2021 related to the storm. As a result, we're updating our full year adjusted EBITDA guidance to $12.9 billion to $13.3 billion, excluding any contribution from the announced enable acquisition. This is up approximately $100 million compared to our previous adjusted EBITDA guidance, excluding the impacts of winter storm URI. Our system was designed to be reliable and flexible, even under adverse operating conditions, and combined with the significant amount of preparation our team completed prior to the storm, we believe this highlights just how valuable our assets and our employees are to energy transfer. Now moving to a growth capital update. For the first quarter ended March 31st, 2021, energy transfer spent $360 million on organic growth projects, primarily in the NGL and refined product segment, excluding Sun and USAC CapEx. For full year 2021, we now expect growth capital expenditures to be approximately $1.6 billion. The increase from our previous forecast of $1.45 billion is primarily due to the addition of several small opportunistic projects, primarily in the midstream segment, as well as the acceleration of some project spend from 2022 into 2021. We continue to focus on aligning capital outlay with customer needs and remain disciplined in regards to all spending. These new projects are focused on improving optionality around our existing assets. The Permian Bridge which is a new project I discussed earlier on the call, involves converting a portion of an NGO line in the Permian into rich gas service in order to connect our Midland and Delaware Basin GMP assets together. We remain disciplined, and for 2022 and 2023, we continue to expect to spend approximately $500 to $700 million per year. Now looking briefly at our liquidity position, as of March 31, 2021, Total available liquidity under our revolving credit facility was approximately $5.08 billion, and our leverage ratio was 3.23 times per the credit facility. The additional cash flows achieved from the winter storm also allowed us to accelerate the timing of our debt reductions. During the quarter, we were able to repay approximately $3.7 billion in debt with cash flow from operations, which equates to a permanent reduction to our run rate leverage of approximately a third of a turn. We continue to focus on accelerating debt reduction and achieving our leverage target of four to four and a half times on a rating agency basis. Once we have reached our leverage target, we will look to return additional capital to unit holders in the form of unit buybacks and or distribution increases, with the mix dependent upon our analysis of market conditions at the time. we remain committed to maintaining and improving our investment-grade rating. In concluding remarks, the performance of our Texas intrastate and storage assets during winter storm URI demonstrates the value of having a strong, reliable, and extensive geographical footprint, which allowed us to meet critical demand throughout the extreme adverse weather event. In addition, our employees deserve a significant amount of credit for their dedication during the extremely difficult weather conditions. Our strong first quarter results helped accelerate the pay down of debt. Capital discipline and deleveraging continue to be among our top priorities. Looking ahead, we remain excited about the acquisition of Enable, which we view as a strategic opportunity to expand our scale and midstream connectivity while remaining consistent with our goal of improving our financial position through deleveraging. Our long-term business outside of the winter storm is returning to pre-COVID levels and will be enhanced by further ramp-ups from our LPG and ethane export projects at our needle and terminal. In addition, April and May volumes are shaping up favorably. We also continue to explore development of alternative energy projects and opportunities to reduce our environmental footprint. Operator, please open the line up for our first question.

Thank you. At this time, we will be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Please limit to one question and one follow-up question. Our first question is from Gabe Maureen with Mizuho. Please proceed with your question.