Sunoco LP

Greetings and welcome to Energy Transfer's second quarter earnings call. At this time, all participants are on a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. I would now like to turn the conference over to today to Mr. Tom Long, CFO. Thanks, sir. You may begin.

Thank you operator and good afternoon everyone and welcome to the energy transfer second quarter 2020 earnings call and thank you for 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 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 our Form 10-Q for the second 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'll find a reconciliation of our non-GAAP measures on our website. And we expect our 10Q to be filed tomorrow, August 6th. Let me start today with a short update regarding our operations. The COVID-19 pandemic continues to impact how we go about our daily lives and how business is conducted. However, I am pleased to say that today our field operations have continued uninterrupted. This is a testament to the hard work of our employees who remain focused on the safe and efficient operations of our assets during these stressful times. Now turning to the second quarter 2020 highlights, We generated adjusted EBITDA of $2.44 billion and DCF attributable to the partners of ET as adjusted of $1.27 billion. And our coverage ratio for the quarter was 1.54 times, which resulted in excess cash flow after distributions of $448 million. During the second quarter, the COVID-19 pandemic and the associated drop in crude oil prices led to significant volume shut-ins throughout many of the producing regions in the country. We have also seen a reduction in spreads on our crude and natural gas pipelines from the Permian to the Gulf Coast, as well as crude spreads from the Bakken to the Gulf Coast. Offsetting these headwinds, our NGL segment continued to set records during the second quarter, with our transportation volumes reaching new highs, primarily driven by record volumes on our Mariner E system, as well as strong volumes across our Texas NGL pipelines. And our fractionation volumes reached another record during the quarter due to the addition of FRAC 7 earlier this year. In addition, gathering and processing volumes on our Midland Basin system also reached new highs near the end of the second quarter. Now turning to our 2020 outlook, as the energy industry continues to face demand destruction and other challenges associated with the COVID-19 pandemic, pandemic due to the uncertainty of the pace of recovery, we are revising our 2020 adjusted EBITDA guidance range to $10.2 billion to $10.5 billion. This reflects our latest expectations during these unprecedented times, including a slower recovery than initially forecasted. Although we believe that we reached the bottom during the second quarter, our revised guidance reflects a more conservative ramp up than our previous expectations. We are encouraged by the signs of recovery that we are experiencing, as current production volumes in the Midland Basin through our processing plants, volumes across the Mariner East complex, and volumes through our Texas NGL fractionation assets are all currently above pre-COVID levels. As we look ahead, we continue to expect our fully integrated, diversified asset base, along with contributions related to the addition of the SIM group assets the ramp up of Mariner East, Fract 7, and Panther 2, as well as the projects that went into service in 2019 to help offset some of the impacts from lower volumes in certain basins, narrower spreads, and lower commodity prices. Operationally, we continue to seek out opportunities to leverage our extensive infrastructure to drive operational efficiencies and optimize our assets where possible. As we mentioned on our last call, we have undertaken cost reduction measures both in our corporate offices as well as our field operations. Year to date, we have already recognized approximately $200 million in G&A and OPEX savings, and we now expect to achieve cost savings of approximately $400 million for full year 2020 relative to our budget. We also continue to carefully evaluate our growth capital expenditures. Given the current state of our industry and the number of assets that are not fully utilized across the midstream space today, our evaluation process for new projects is very stringent and our threshold for returns is the highest it has ever been. That being said, upon further review of projects spent today, completion dates, and the economic impact of delaying particular projects, We now expect our 2020 growth capital expenditures to be approximately $3.4 billion. This represents a reduction of $200 million from our previous guidance or a total reduction of $600 million from our original guidance of $4.0 billion and is primarily related to delaying some growth capital spend. Approximately 80% of the growth capital spend in 2020 will be spent on projects that are expected to be in service in 2020 or early 2021. This includes Mariner East, the Lone Star Express expansion, and the Orbit and other NGL export projects at Needlem. As we think about our future capital spend, we currently expect our 2021 growth capital expenditures to be approximately $1.3 billion, and we now expect growth capital in 2022 and 2023 to be in the range of $500 to $700 million per year. We remain committed to generating free cash flow and still expect to be free cash flow positive in 2021 after growth capital and equity distributions. Looking more closely at our growth projects, I'll now walk you through recent developments. We continue to move forward with the Bakken pipeline capacity optimization. The initial phase of the optimization above the pipe's current capacity of 570,000 barrels per day will accommodate the volume commitments made by shippers during recent open seasons. We now expect this additional capacity to be in service 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 Needland to our Houston terminal and is expected to be in service in the fourth quarter of 2021. Moving to Mariner East system, I am pleased to say that we saw the highest average quarterly volumes yet through the Mariner East pipeline. with volumes for the first half of 2020 up nearly 50% over the first half of 2019. Utilization of our Mariner pipelines and our Marcus Hook terminal continues to increase, with record amounts of propane and butane transported through the pipelines. We are also seeing strong ethane utilization, which is expected to grow in the fourth quarter of this year. The system continues to demonstrate flexible optionality for shippers. with 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. Additionally, our Mariner system will have the ability to bring natural gasoline to Marcus Hook for gasoline blending and local consumption by early 2021. Both domestic and international demand for all natural gas liquids has remained strong, even while motor fuel demand has waned because of COVID-19. We are eagerly awaiting the next significant phase of the Mariner East project, which we now expect to be in service by the end of this year, with the final phase completed in the second quarter of 2021. Also, our 50,000 barrels per day expansion at the Marcus Hook Terminal will provide additional chilling and storage capacity and is expected to be in service in the first quarter of 2021. 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. Now looking at moving to Lone Star and looking at Fract 7 was placed into service in the first quarter of this year and began ramping up. All seven of our Fracts are running full today. We're in the final stages of construction on our 24-inch, 352-mile Lone Star Express expansion, which will add 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. We continue to expect the expansion to be in service in the fourth quarter of 2020. Also, we have converted some of our underground storage facilities at Mont Bellevue to allow the storage of significant amounts of natural gasoline and diesel to take advantage of the profitable contango opportunities. LPG demand has remained strong, and our LPG expansion projects in Needland will bring our total export capacity to approximately 500,000 barrels per day by the end of 2020, further integrating our Montbellevue assets with our Needland assets. Construction of our orbit ethane export joint venture with Satellite Petrochemical, who is a great partner, is nearing completion. This 180,000 barrel per day project will be ready for commercial service in the fourth quarter of this year with the first ships arriving in November for commissioning. Now let's take a closer look at our second quarter results. Consolidated adjusted EBITDA was $2.44 billion compared to $2.83 billion for the second quarter of 2019. The change from the prior period was primarily due to the impact of lower volumes and prices among several of our core operating segments. DCF, attributable to the partners as adjusted, was $1.27 billion for the second quarter compared to $1.6 billion for the second quarter of 2019. This is primarily due to the decrease in adjusted EBITDA. Distribution coverage ratio for the second quarter was 1.54 times. In July, Energy Transfer announced a distribution of 30.5 cents per common unit for the second quarter or $1.22 per common unit on an annualized basis. This distribution is consistent with the first quarter of 2020 and will be paid August the 19th to unit holders of record as of the close of business on August the 7th. Looking at our results by segment for NGL and refined products, adjusted EBITDA was $674 million compared to $644 million for the same period last year. This increase was primarily due to record NGL transportation and fractionation volumes, which were partially offset by a decrease in terminal services margin. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.4 million barrels per day compared to 1.3 million barrels per day for the same period last year. This increase was primarily due to 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. Second quarter average fractionated volumes increased to 836,000 barrels per day compared to 701,000 barrels per day for the second quarter of 2019. Now for our crude oil segment, adjusted EBITDA was $519 million compared to $752 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 unprecedented shut-ins, as well as a decrease in our crude oil acquisition and marketing business related primarily to well shut-ins leading to unfulfilled producer supply commitments and unfavorable pricing conditions. These items were partially offset by contributions from the SIM group assets, as well as a positive inventory valuation adjustment of $14 million compared to the second quarter of 2019. For midstream, adjusted EBITDA was $367 million compared to $412 million for the second quarter of 2019. This was primarily due to lower NGL and gas prices, which impacted results by $39 million, as well as a decrease related to volume shut-ins in South and North Texas. which were partially offset by $23 million reduction in operating expenses. Gathered gas volumes were 13 million MMBTUs per day compared to 13.1 million MMPTUs per day for the same period last year. Lower volumes in south and west Texas were nearly offset by volume growth in the northeast and the addition of SIM group assets in the mid-continent Panhandle region. In our interstate segment, adjusted dial was $403 million compared to $460 million for the second quarter of 2019. This was primarily the result of additional revenue recognized in the second quarter of 2019, as well as lower rates on LNG that we mentioned on our last call, and less capacity sold on our panhandle and trunk line systems. These were partially offset by increased margin from the transwestern system due to increased demand in firm transportation. As for our intrastate segment, adjusted EBITDA was $187 million compared to $290 million in the second quarter of last year, primarily due to lower revenue from the pipeline optimization activities as a result of the significant drop in spreads. 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. Moving on to a CapEx update, for the six months ended June 30, 2020, energy transfers spent approximately $1.8 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 approximately $3.4 billion on organic growth, primarily in the NGL and refined products and midstream segments, of which approximately 80% will be on projects expected to be in service in 2020 or early 2021. 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 500 and $700 million per year. Looking briefly at our liquidity position as of June 30th, 2020, total available liquidity under revolving credit facilities was approximately $2.9 billion and our leverage ratio was 4.29 per the credit facility. As a reminder, we have no additional maturities in 2020 and looking ahead, we have a very manageable maturities of $1.4 billion in 2021. We continue to target a rating agency leverage ratio of four to four and a half times. In conclusion, the second quarter, we saw challenges. With some volumes picking up across a number of our assets, and our Mariner East pipeline recently reaching new highs, we expect this positive momentum to continue as we enter the second half of the year. Throughout the remainder of 2020, we will continue to look for efficiencies and optimization opportunities across our footprint, and our fully integrated multi-product assets are well positioned as our industry works toward a recovery. In addition, we anticipate further ramp up of our recent projects to contribute additional near and long-term value. However, we know that it is imperative to remain disciplined when it comes to spending, and as our growth capital reductions demonstrate, our capital expenditure approval process is increasingly stringent. We remain committed to our investment grade rating and improving our leverage metrics as we navigate through the current market disruption. And above all, we continue to emphasize safety and project execution, and we are continually impressed by our employees' dedication and resilience during these challenging times.

This is Tom Mason, the General Counsel of Energy Transfer, and I wanted to inform you that we just received the decision related to our motions to stay from the Court of Appeals. We are still reviewing this decision, but the good news is that the Court of Appeals granted our stay of the portion of the district court order that required Dakota Access to shut the pipeline down and empty it of oil. The Court of Appeals also denied a stay of the other part of the district court order, which vacated the easement for the pipeline at Lake Oahe. As a result, no court order stops Dakota Access from continuing to operate the pipeline. The Court of Appeals contemplates further proceedings at the District Court following determinations by the Army Corps under its regulations regarding the continued operation of the pipeline in light of the easement being vacated. The Court of Appeals also ordered an expedited schedule for determining the merits of the appeal by the Army Corps and Dakota Access as to whether an environmental impact statement will be required. This rule is expected by the end of the year. We will continue to review the substance of today's court decision, and we will need to run the course with this litigation. We believe our legal positions are strong, and we are confident that the pipeline will continue to operate. With this, I turn it over to the operator to open our first question.