Energy Transfer LP

Greetings, and welcome to the Energy Transfer Third Quarter Earnings Call. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator or technical assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Tom Long, Chief Financial Officer. Thank you, Mr. Long. You may begin.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Third Quarter 2020 Earnings Call. We really appreciate you joining us today. I'm also joined today by Kelsey Warren, 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 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 third quarter of 2020. 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 will find a reconciliation of our non-GAAP measures on our website. We expect our 10Q to be filed tomorrow, November the 5th. Starting with a few third quarter highlights, we generated adjusted EBITDA of $2.87 billion in DCF attributable to the partners of Energy Transfer as adjusted of $1.69 billion. And our excess cash flow after distributions was approximately $1.28 billion. On an incurred basis, we had excess DCF of nearly $550 million after distributions of $412 million and growth capital of approximately $730 million. We expect significant excess cash flow over the distributions and growth capital going forward. Our third quarter adjusted EBITDA included approximately $250 million of earnings uplift, about half of which was related to one-time items. The other half was primarily from optimization activities related to our various marketing and optimization groups. One of our core strengths in providing significant upside to our earnings potential is our commercial team's ability to keep our diversified asset base highly utilized by capturing basis differentials and contango storage opportunities created from market and weather volatility. Our NGL segment continued to stand out during the third quarter with NGL transportation volumes setting another record primarily driven by record volumes on our Mariner East and Texas NGL pipeline systems. And our fractionation volumes also reached a new high during the quarter. due to an additional ramp-up of volumes on FRAC 7, which went into service earlier this year. And in early September, we were pleased to announce that we completed our Lone Star Express expansion project significantly under budget and ahead of schedule. Now turning to our recent distribution announcement, on October 26th, we announced a quarterly cash distribution of 15.25 cents, per ET common unit or 61 cents on an annualized basis. This distribution will be paid November 19th to unit holders of record as of the close of business on November the 6th. The reduction of the distribution is a proactive decision to strategically accelerate debt reduction as we continue to focus on achieving our leverage target of four to four and a half times on a rating agency basis and a solid investment grade rating. We expect that the distribution reduction will result in approximately $1.7 billion of additional cash flow on an annualized basis that will be directly used to pay down debt balances and maturities. This is a significant step in Energy Transfer's plan to create more financial flexibility and lessen our cost of capital. Once we reach our leverage target, we are looking at returning additional capital to unit holders. This will come through unit buybacks and or distribution increases with the mix being dependent upon our analysis of market conditions at the time. Turning to the 2020 outlook, we now expect to come in at the high end of our adjusted EBITDA guidance range as a result of better company performance. Looking more closely at our cost reduction measures, which are underway in our corporate offices, as well as at our field operations. During the third quarter, we identified additional opportunities to leverage our infrastructure to drive operational efficiencies and optimize our assets, and have recognized approximately $400 million in G&A and OpEx savings year to date. And for full year 2020, we now expect to achieve cost savings of over $500 million relative to our original budget. And for our growth capital, we now expect 2020 growth capital expenditures to be less than $3.3 billion. This represents a further reduction of over $100 million from our guidance provided last quarter as a result of projects coming in under budget. Our spend for the remainder of 2020 consists of several projects that we expect to be completed by year-end 2020, including the next phase of Mariner East, Orbit, and other NGL export projects. These projects will enhance our existing portfolio and provide near and long-term value. We will see a significant reduction in growth capital spend in the years ahead, with our forecast of approximately $1.3 billion in 2021 and $500 to $700 million per year in 2022 and 2023. Our evaluation process for new projects continues to be very stringent, and our threshold for returns is the highest it has ever been. I'll now walk through the recent developments on our major projects. We'll start with Dakota Access. The appeal process with respect to the Lake Owyhee litigation is ongoing. Oral arguments in the case took place earlier today. We still expect a decision from the DC Circuit Court of Appeals by the end of the year. We continue to believe that our legal position in the case are strong, and we are confident that our pipeline will continue to operate as normal. The pipeline remains in service today, and like all of our assets, we will continue to operate it safely and efficiently. We continue to move forward with the Bakken pipeline capacity optimization, and on October the 15th, we received regulatory approval from the Illinois Commerce Commission which was the last remaining state regulatory approval required for us to move forward with the optimization project. The initial phase of the optimization will accommodate the volume commitments made by shippers during open seasons. We now expect this additional capacity to be in service late in the third quarter of 2021. Next, the Ted Collins link is an efficient way to increase the utilization of existing assets. while providing market connectivity between our Nederland and Houston terminals. It will ultimately allow us to transport up to 275,000 barrels per day of crude oil from West Texas and Nederland to our Houston terminal and is expected to be in service in the fourth quarter of 2021. Now onto our Mariner East system. During the third quarter, we saw the highest average quarterly volumes yet through the Mariner East pipeline system with year-to-date 2020 NGL volumes up 40% over year-to-date 2019. Utilization of our Mariner pipelines and our Marcus Hook terminal continued to increase, leading to record amounts of propane transported through the pipeline, as well as strong butane and ethane utilization. The system continues to demonstrate flexible optionality for shippers, including the ability to handle ethane spot cargoes as well as provide multiple local market connections for ethane, propane, and butane. Customers at Marcus Hook are currently taking advantage of this flexibility by placing barrels for the upcoming winter season into local markets, and we're prepared to handle this demand with strategic NGL reserves at Marcus Hook. Additionally, our Mariner system will have the ability to bring natural gasoline to Marcus Hook for gasoline blending and local consumption by early in the second quarter of 2021. We are eagerly awaiting the next significant phase of the Mariner East projects, which we expect to be in service by the end of this year, with the final phase expected to be completed in the second quarter of 2021. Also, our 50,000 barrel per day LPG expansion at the Marcus Hook Terminal is now expected to be in service in late 2020, ahead of expectations. The Mariner East system, in conjunction with the Marcus Hook terminal, continues to provide the most efficient transportation route for liquids in the Northeast and provides customers the optimal way to reach the best markets for their product. And we are very excited to announce Pennsylvania Access, which will utilize part of our Mariner East system to bring refined products from the Midwest supply regions through our Allegheny Access pipeline system into Pennsylvania. and to markets in the Northeast. This project will require minimal capital, which is already included in our budget, and will add significant revenue and synergies with our existing refined products pipeline and terminal assets. We anticipate a fourth quarter 2020 startup for early volumes to be able to flow from Ohio into Pennsylvania and to upstate New York markets. As I mentioned earlier on the call, we were pleased to announce that our 24-inch 352-mile Lone Star Express expansion was completed under budget and ahead of schedule. This project adds over 400,000 barrels per day of NGL pipeline capacity from the Permian Basin to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. LPG demand continues to remain strong, and our LPG expansion projects at Nederland will bring our total export capacity to approximately 500,000 barrels per day further integrating our Mont Bellevue assets with our Nederland assets. Construction of our orbit ethane export joint venture with satellite petrochemical is nearing completion. This 180,000 barrels per day project will be ready for commercial service in the fourth quarter of this year, with the first ships now arriving by the end of the year for commissioning. Next, I want to take a moment to provide a renewables update. Last week, we published our 2019 Community Engagement Report, which highlights our pipeline safety management programs and our performance data, risk management, and emissions reduction programs. It also covers our stakeholder outreach and community investment activities. As a company, we are committed to identifying and implementing cost-effective emission reductions and prevention opportunities, including the reduction of our carbon footprint. As a result, we make significant investments each year in technology to reduce emissions and improve our overall operations performance and efficiency. Today, approximately 20% of the electrical energy we purchase originates from renewables, and we expect that will continue to grow. We continue to actively look at renewable power deals that will allow us to increase our use of power generated by renewable sources. Additionally, we have approximately 18,000 solar panels located at pipeline metering stations across the country. We also own a gas-fired electric generation company that uses renewable natural gas in Pennsylvania to generate electricity, helping to power Pennsylvania homes. Our dual drive compressors, which have a patented technology that allows for switching between electric motors and natural gas engines to drive compressors, offers the industry a more efficient compression solution, helping to reduce greenhouse gas emissions. More recently, we entered into our first-ever dedicated solar contract for which a 28-megawatt solar facility is currently under construction. This will deliver low-cost clean power to energy transfer under a 15-year power purchase agreement and demonstrates our commitment to reducing our environmental footprint by integrating alternative energy sources when economically beneficial. We are also evaluating opportunities to better utilize our available capacity to transport CO2 in the Northeast and are looking into the potential to bring renewable diesel into West Texas via our JC Nolan pipeline. As the energy industry continues to evolve and customer demand for these services increases, we will look for additional ways to further integrate alternative energy sources into our business when economically beneficial. Now let's take a closer look at our third quarter results. Consolidated adjusted EBITDA was $2.87 billion compared to $2.81 billion for the third quarter of 2019. This was a result of strong performance from our NGL and refined product segment, as well as some uplift from optimization activities. DCF tripled to the partners as adjusted was $1.69 billion for the third quarter compared to $1.55 billion for the third quarter of 2019. This is primarily due to the increase in adjusted EBITDA along with a decrease in maintenance capital expenditures. Now turning to results by segment, we'll start with the NGL and refined products. Adjusted EBITDA was $762 million compared to $667 million for the same period last year. This increase was primarily due to record NGL transportation and fractionation volumes as well as higher optimization gains from the sale of NGL components at Mont Bellevue. 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 the record volumes on our Mariner East pipeline system as well as increased throughput on our pipelines out of the Permian Basin and North Texas regions as a result of higher liquids production from both wholly owned and third-party gas plants. On our fractionators, utilization rates remained high during the third quarter with average fractionated volumes increasing to 877,000 barrels per day compared to 713,000 barrels per day for the third quarter of 2019. Looking at our crude oil segment, adjusted EBITDA was $631 million compared to $726 million for the same period last year. This was primarily due to lower volumes on the Bakken pipeline and our Texas crude pipelines as a result of lower production and reduced demand due to COVID-19, as well as a decrease in our crude oil acquisition and marketing business related primarily to fewer optimization opportunities. These items were partially offset by the contributions from the SIM group assets, which we acquired in 2019, as well as an increase related to trading gains realized from Contango storage positions. For Midstream, adjusted EBITDA was $530 million compared to $411 million for the third quarter of 2019. This was primarily due to the recognition of $103 million related to the restructuring and assignment of certain gathering and processing contracts in the Arklatex region. In addition, operating expenses decreased $33 million. Gathered gas volumes were 12.9 million MMBTUs per day compared to 14 million MMBTUs per day for the same period last year. Lower volumes in South Texas and North Texas were partially offset by volume growth in the Permian, as well as the addition of assets acquired in 2019 in the Mid-Continent Panhandle region. For our interstate segment, adjusted EBITDA was $425 million compared to $442 million for the third quarter of 2019. This was primarily the result of a scheduled contract rate step down in January 2020 at our Lake Charles LNG facility, which we have referenced on previous calls this year, as well as less capacity sold on our panhandle and trunk line systems. These were partially offset by increased margin from the transwestern and rover systems due to increased demand in firm transportation. And in our intrastate segment, adjusted EBITDA was $203 million compared to $235 million in the third quarter of last year, primarily due to lower revenues from pipeline optimization activities as a result of the drop in spreads, partially offset by reduced operating costs. Beginning in 2021, we expect to have less exposure to spreads as we have locked in additional volumes under long-term contracts with third parties. Now moving on to CapEx update. For the nine months ended September 30th, 2020, energy transfer spent slightly under $2.5 billion on organic growth projects, primarily in the NGL and refined products and midstream segments, excluding Sun and USAC CapEx. And as I mentioned earlier, For full year 2020, we now expect to spend less than $3.3 billion on organic growth, primarily in our NGL and refined products and midstream segments. We're in the final stages of several significant growth projects, which will help support our future growth, and we believe that there are exciting days ahead for the partnership as we're taking meaningful actions to build and improve our industry-leading franchise. And we currently expect our 2021 growth capex expenditures to be approximately $1.3 billion, and growth capital in 2022 and 2023 to be between $5 and $700 million per year. Looking briefly at our liquidity position, as of September 30, 2020, total available liquidity under our revolving credit facility was approximately $2.65 billion, and our leverage ratio was 4.24 times for the credit facility. And as a reminder, we have no additional maturities in 2020, and looking ahead, we have very manageable maturities of 1.4 billion in 2021, which will be more than covered with the additional retained cash flow from the reduction in distributions. In conclusion, throughout the third quarter, activity consistently improved around our Permian midstream assets across the Mariner East complex, and through our NGL fractionation assets. Looking ahead, the near and long-term value that our ongoing growth projects will contribute is very clear, and we will continue to leverage our expansive footprint to drive operational efficiencies. In addition, we continue to emphasize the importance of capital discipline throughout the organization, as demonstrated by our growth capital reductions throughout 2020. We remain committed to our investment grade rating, and our recent distribution reduction will allow us to accelerate our deleveraging strategy by immediately using excess cash to pay down debt. In addition, our capital discipline and growth capital reductions announced throughout this year demonstrate our commitment to generating excess cash flow. Combined with Energy Transfer's best-in-class asset base, We believe these actions will better position the partnership for continued long-term success. Operator, please open the line up for our first question.

Thank you. Our first question comes from Eve Siegel with Siegel Asset Management Partners. Please proceed with your question.