Oneok Inc (OKE) — Q1 2020 Earnings Call Transcript

Thanks, Andrew. Good morning and thank you all for joining us today. And as always, we appreciate your continued trust and investment in ONEOK. Joining me on today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs, and Kevin Burdick, Executive Vice President and Chief Operating Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President Natural Gas Liquids; and Chuck Kelley, Senior Vice President Natural Gas. On behalf of ONEOK, we hope you, your families and your colleagues are healthy as we all navigate and cope with the uncertainties surrounding the COVID-19 pandemic. As an essential critical infrastructure business, our employees continue daily work. We remain focused on operating safely and responsibly and on providing the essential services that our communities and customers rely on us for. We've asked all employees to work from home who are able and we've increased safety protocols for those critical employees continuing to work on-site. We've offered additional support to employees through temporary benefit adjustments and human resources programs and are prioritizing open communication with employees, our Board of Directors, and the financial community related to our COVID-19 response efforts. The current environment and worldwide impacts of this pandemic are clearly unprecedented. But as you know, COVID-19 is not the only challenge facing the energy industry right now. The commodity price collapse and resulting recent pullback in crude oil production across the country is greatly impacting our industry. As described in the earnings release, we did not provide what one would call a traditional guidance update, but we did provide a range of possible outcomes for 2020. Providing specific volume and commodity price guidance would not be appropriate for us due to the number of potential variations of outcomes that are possible for price forecasts, curtailment quantities, and the duration and pace of economic recovery on a worldwide basis among other factors. That said, we have performed a scenario analysis and based on currently available information, we believe the range of possible 2020 adjusted EBITDA results will likely be between $2.6 billion and $3.0 billion. While this wide range indicates potential challenges, it also presents opportunities and as we are well positioned to realize earnings growth in 2020 and 2021 as NGL markets remain resilient and storage capacity is at a premium despite the challenges our industry faces. Now, I'd like to comment on the recent dividend announcement, which we prudently held flat at $0.935 per share for the quarter. As we look to the future, we expect our business to generate sufficient cash flow to pay the dividend. Our decision to significantly reduce capital spending until growth opportunities return puts us in a good position to continue returning value to our shareholders. As we always do, each quarter we'll work with our Board to assess our forward views of future cash flows and the dividend as appropriate. We've been through cycles before and we have a long track record of delivering on expected results. And most importantly, the fundamentals of our business have not changed. Our strong balance sheet and liquidity provide important financial flexibility. Our extensive and integrated assets including available storage in key market centers are competitively well positioned. Our fee-for-service business model mitigates our direct commodity exposure, including the stability of our natural gas pipelines business, which has nearly 100% take-or-pay contract structures with primarily financially strong, electric and utility customers. Our customers are some of the most resilient and well-capitalized in the industry, with decades of proven reserves. And the demand for NGLs in the U.S. and abroad remains, and there are signs that international demand is beginning to recover. All these factors provide the foundation for a resilient business that we believe is built to weather these kinds of uncertain market conditions and provide a platform to resume growth when it makes sense. The natural gas and NGL reserves in the basins served by our systems haven't moved. The reserves are still there and we believe our ability to serve them is stronger than ever. Many of our capital growth projects have recently come online or are nearing completion. These projects have driven volume growth across our businesses, including reducing the amount of flaring in the Williston Basin as we expected up until the pandemic. And as we have done in previous commodity cycles, we're able to adjust the scale and timing of our growth projects to best fit the needs of our customers. We made proactive adjustments early on in this cycle to better align our capital investments with our customers' needs and we will continue to be flexible and responsive to those needs as our view of the market evolves. Kevin will provide more detail on these projects in a moment. As history shows, how you react in markets like this will have lasting impacts for quarters and years to come. Swift financial and operational decisions made at ONEOK in 2015 and 2016, while difficult at the time, set us up well for a transformational period of growth over the past few years. We're now in a great position with available integrated capacity across our system once market conditions improve. With that, I will turn the call over to Walt.

Thank you, Terry. I'll start with some brief comments on our first quarter financial performance, our liquidity, and then our capital allocation strategy as we move forward. ONEOK reported a net loss of $142 million in the first quarter of 2020, which includes a non-cash impairment charge of $642 million or $1.17 per share. Excluding these non-cash impairment charges, ONEOK's EPS was $0.83 per share for the first quarter. First quarter adjusted EBITDA totaled $701 million, a 10% increase compared with the first quarter of 2019. Natural gas liquids and natural gas volume growth, higher average fee rates, and higher contracted natural gas transportation capacity all contributed to year-over-year earnings growth. Distributable cash flow for the first quarter of 2020 was $522 million, up 7% compared with the fourth quarter of 2019. And we reported healthy dividend coverage of 1.35 times. We also generated $136 million of distributable cash flow in excess of dividends paid during the quarter. Earlier this month, the Board of Directors declared a dividend of $0.935 or $3.74 per share on an annualized basis. We recorded impairment charges in the first quarter of 2020 related primarily to long-lived assets and goodwill in the natural gas gathering and processing segment. Our asset impairment charges related to gathering and processing assets in Western Oklahoma, Kansas, and the Powder River Basin. The timing of these charges was triggered by significant adverse changes in the market environment during the first quarter. From a liquidity standpoint, in early March, we completed a $1.75 billion senior notes offering and used a portion of the proceeds to repay amounts outstanding under our commercial paper program, providing us increased liquidity and balance sheet flexibility during this uncertain market environment. Our March 31 net debt-to-EBITDA on an annualized run rate basis was 4.86 times, and we ended the first quarter with no borrowings outstanding on our $2.5 billion credit facility and more than $530 million of cash. We are still targeting leverage of four times or less, but due to the current environment, the timeline for reaching target leverage from operating cash flows has been pushed out. As Terry mentioned, with yesterday's earnings announcement, we provided a 2020 outlook. The 2020 net income is now likely to be in the range of $500 million to $900 million, which reflects the impairment charges. And adjusted EBITDA is likely to be in the range of $2.6 billion to $3 billion. As Terry said, the range of possible results from our multivariable scenario analyses led us to this 2020 outlook to give our investors a sense of what we view are likely outcomes in the current environment. As the industry recovers, we will update if appropriate. From a capital allocation perspective, in early March we suspended an additional expansion on the West Texas LPG pipeline, the Demicks Lake III plant, and reduced the scope of the expansion on the Elk Creek pipeline. Yesterday, we announced that we paused several projects and reduced our 2020 growth capital expenditures further. So far in 2020, we have reduced forecasted capital expenditures by $900 million compared with our original 2020 guidance provided in late February. Kevin will discuss these adjustments to growth capital in a moment. We now expect growth capital to range between $1.4 billion and $1.8 billion this year, which includes more than $900 million that we've already spent in the first quarter, as we completed Arbuckle II, Demicks Lake II, MB-4 and 45,000 barrels per day of the West Texas LPG expansion. Only approximately 40% of our 2020 capital expenditures is left to spend over the remaining three quarters. Looking ahead, we can continue to significantly scale back capital. If commodity prices remain depressed and producer activities remain low, we could potentially operate in a $300 million to $400 million annual capital expenditure range, which would include limited routine growth spending in alignment with our producers' needs and maintenance capital. Our flexibility to scale back capital and to adjust to our customers' needs is a significant financial tool we can use in this environment to help preserve balance sheet strength and liquidity. On the other side of the equation, we stand ready to resume these projects as producer activity returns. I'll now turn the call over to Kevin for a closer look at our completed growth projects and operations.

Thank you, Walt. In the first quarter of 2020, we experienced volume growth across our system compared to the same period in 2019. NGL raw feed throughput volumes increased by 6%, and natural gas processed volumes rose by 5% year-over-year. The natural gas pipeline segment has continued to generate strong fee-based earnings, achieving 100% contracted capacity in the first quarter. This segment accounts for over 15% of ONEOK's EBITDA, contributing to stable earnings and resilience in fluctuating commodity price conditions. As Terry and Walt mentioned, the unpredictable commodity price and demand landscape complicates forecasts for our future volumes and segment performance. Nevertheless, we can share relevant data to outline our current volume and activity levels across operations. Let's begin with an update on our growth projects. During the first quarter, we successfully completed and put into operation the Arbuckle II Pipeline and the final capacity of our MB-4 fractionator in Mont Belvieu, both of which are fully contracted. We also wrapped up 45,000 barrels per day of our 80,000 barrel per day West Texas LPG Pipeline system expansion, with the remaining capacity, which experienced weather-related delays, expected to be finalized in May. Our Demicks Lake II processing plant was completed in January, boosting our processing capacity in the basin to over 1.5 billion cubic feet per day. Projects finished in the fourth quarter of 2019 were ramping up as anticipated until the commodity downturn occurred in March. Demicks Lake I, completed in October of last year, reached near full capacity of 200 million cubic feet per day during the first quarter. The total NGL raw feed throughput volume from the Rocky Mountain region, which includes both the Elk Creek and Bakken NGL Pipelines, hit 240,000 barrels per day in March before the downturn. Compared to the fourth quarter of 2019, we noted over a 7% increase in Rocky Mountain region raw feed throughput volumes as new processing plants and expansions connected to our NGL system. The volumes achieved in the first quarter, combined with the basin quality and our customer base, instill confidence that growth will resume once demand recovers. These assets are well-positioned to capture natural gas and NGL volumes for our customers when demand rebounds. Yesterday, we announced a pause in the majority of construction activities for several of our remaining capital growth projects, including the expansion of our Bear Creek processing plant in the Williston Basin, the construction of the MB-5 fractionator in Mont Belvieu, additional Mid-Continent fractionation expansions, and the third phase of the West Texas LPG Pipeline system. The choice to pause these projects reflects the evolving needs of our customers and our adaptable stance in this uncertain commodity price climate. We can quickly restart the paused projects when our customers resume their activities. Now, let's examine the current activity across our operations. Presently, our customers' production plans are changing in response to market dynamics. Many have announced cuts in rig activity and are in some cases reducing existing production. In the Williston Basin, about 30 rigs are currently active, with roughly half on our dedicated acreage. Many of the curtailed wells have been older vintage wells, producing lower volumes at higher costs, while others were previously flaring, which has not impacted our volume. Additionally, some wells taken offline have opened capacity for previously flaring wells to flow onto our system. These three factors have resulted in less volume coming off our system than expected. Given the substantial backlog of flared gas, total production does not need to fully rebound for our processing capacity to be maximally utilized. Based on recent flaring data from North Dakota, around 400 million cubic feet per day are flaring in the basin, with over 200 million of that on ONEOK's dedicated acreage. As Terry noted, our customers in the Williston Basin are some of the most stable and well-capitalized in the industry. We've seen one customer file for bankruptcy protection this year, but they continue to flow volume. We do not anticipate significant bankruptcy risk among our largest customers in the region, and smaller-scale private producers account for about 15% of our total production from the area. In the Permian Basin, approximately 70% of our NGL volume comes from the Midland Basin, which is among the most resilient basins in the U.S. As the expansion of our West Texas LPG Pipeline is completed in May, we will shift volumes from existing third-party NGL offloads to our pipeline. We currently offload about 50,000 barrels per day and anticipate moving an additional 20,000 barrels per day to our system in the third quarter of this year, with the rest expected in the first quarter of 2021. This transition will allow us to collect full transportation and fractionation fee rates on that volume. Moreover, our overall propane and fractionation capacity is highly utilized, ranging from 85% to 90%, and more than half of our 27 million barrels of underground NGL storage is accessible to seize market opportunities. We are adding 1.5 million barrels of storage in the third quarter of this year and expect to finish an additional 1.5 million barrels in 2021. We have also increased our brine storage capacity in Mont Belvieu by 3.5 million barrels. In the NGL markets, we are witnessing robust seasonal demand for propane in Conway at our rail racks and on our north system from wholesalers, as well as in Mont Belvieu from exporters. This demand is contributing to the relatively strong price of propane compared to crude. Petrochemical facilities in both Conway and Mont Belvieu continue to show strong demand for ethane, pushing prices near recovery economics in the Mid-Continent. Terry, that concludes my remarks.

Thank you, Kevin. Our recent project completions and the volumes we've seen materialize prior to this downturn provide confidence in the growth behind our system that is available to capture once demand recovers. ONEOK's strong record of delivering on our expected results, combined with our competitive, integrated asset position and high-quality customer base and the best resource plays are fundamentals of our business that provide us with a foundation for stability, even through difficult commodity cycles. We have been through downturns before, and we know how to position ourselves for success as conditions improve. To our employees, both those continuing to work remotely and those who are still reporting to a facility or field location, thank you for your continued work, flexibility and dedication to our company. We're focused on maintaining essential services for our customers and your commitment to continuing to operate responsibly is exceptional. During a very difficult time, you have risen to the challenge by remaining committed to the health and well-being of our company, families, and communities. While the near-term view of the world is changing every day, the long-term fundamentals of our strategic business remain strong and well-positioned for continued growth, when global energy demand recovers. With that, operator, we're now ready for questions.

Hi. Good morning, guys. Thank you very much for a lot of the color today. I just wanted to start-off with the – I guess, we'll call it an outlook or guidance. I do appreciate a lot of the color that you gave in terms of some of the inputs when you're talking about why your system will be impacted less and the offload opportunities. I was wondering, if you could share with us your views as to how you get to the upper end and conversely to the lower end of that outlook? What conditions in the Williston or elsewhere needs to play out to basically end up at your higher end or end up at your lower end?

Sure. This is Kevin. Yeah. I mean, there's a variety of things that's – as we kind of laid out the permutations you look at, when you consider the variability of all the inputs we're looking at that's the reason for the outlook. So obviously, if you get to the upper end demand – for example demand comes back more quickly. Prices recover more quickly. Producers respond more quickly. So at the end of the day, you're getting the volume on your system quicker. On the low end of the range, it's just prolonged. And by prolonged, it could be anything from just how producers respond to how the demand recovers.

Do you have anything specific with respect to like when shot is come back and so forth? Is there any sort of cadence that we should be thinking about?

No. I mean, we're not going to – again, we're not going to provide specifics on that, because there's a variety of ways you could get to each – to the high end and there's a variety of ways you could get to the low end as well. So we're not going to get into how long, because that would just be kind of factoring in one variable.

Thank you. Good morning. Maybe we could start with the NGL segment, the Bakken rate. It looks like it came down. I'm guessing that's partly due to Elk Creek coming online, which I think has a lower rate. But should we think that you moved some more volumes from Bakken NGL Pipeline and Overland Pass onto this line, or was there anything else we should factor in? And is this $0.28 level a good run rate going forward or should we expect that it could trend a little lower through the remainder of the year?

Christine, this is Sheridan. There are two factors to consider. First, while we were transporting volume from Bakken, we charged customers a higher fee, particularly those who came on for Elk Creek. Now that Elk Creek is operational, they have returned to a previously contracted lower rate. Looking ahead, the $0.28 rate we see today seems to be a solid rate moving forward. Our pricing is not influenced by the specific pipeline we utilize, whether it’s Bakken, Elk Creek, or OPPL, as the rates charged to customers are based on a bundled service that includes both transportation and fractionation. Therefore, our pricing remains unaffected by the particular pipelines employed.

Okay. So even though the rate came down the margin is higher that's how we should think about it?

Well, as the rate came down obviously we aren't railing as much volume. So our costs have come down as well, but I think going forward $0.28 is what you will see going forward. Obviously, that does have some impact on how much is coming out of the Powder River Basin on that line, which is at a lower fee and how much is coming out of the Bakken.

Okay. Great. Thank you.

Good morning.

Good morning.

I was hoping you could provide more details about Northern Border and your thoughts on the necessity of extracting ethane this year, considering the changes in Bakken and Canadian gas prices. I'm trying to get a clearer understanding of the situation. Thank you.

Hey, Jeremy, this is Chuck. TransCanada operates Northern Border, so I’ll answer your question based on our 50% ownership in the Northern Border Pipeline as a partner. We’ve been monitoring the situation closely, especially lately as the volumes from Bakken and Canada have shifted a bit. The pipeline is particularly focused on anything above 1,100. This is a fluid situation, and as the mix shifts between Canada and Bakken, you’ll see changes in the BTU blend in Northern Border and downstream. Currently, the pipeline plans to file their tariff with an initial upper limit of 1,100 starting June 1. Northern Border has held several meetings with shippers, markets, and all interested parties regarding this limit. It’s important that the BTU specifications are established to meet the downstream deliverability requirements in Chicago.

Yes. Makes sense. Thanks for that. And then maybe going to the GP segment just with the average fee kind of moving lower there quarter-over-quarter and it seemed like there was a POP influence there that kind of drove that. I was wondering if you could provide a little bit more color on kind of what were some of the drivers and how you might expect that to change in this environment?

Sure. So as we've discussed in our 10-K and our 10-Qs under a certain percentage of proceed contracts with fees, our contractual rates or percentages may increase or decrease. And these are based on several thresholds in the contracts, production volume, commodity prices, and system pressures that we're obligated to provide or the producer's obligated to meet. So our average rate can be impacted by those factors and also impacted if volumes increase or decrease on contracts that have different POP percentages or fee rates. So for example, we have several large producers who may have contracts that are more fee-based than POP, and if they're currently curtailing, you'd see the impact of that on our fee rate. Consequently, it would come down. Again, we can't speculate what kind of contract mix we're going to see over time as producers are making decisions frankly weekly as to what wells are going to be produced and certainly at what production level volumes. So we can't necessarily forecast that average rate, but that gives you the understanding of what's behind how that average fee rate is developed and thought about.

Good morning guys. Appreciate all the commentary on operations as well as the liquidity and capital and how the balance sheet is preparing for this. Can you talk about the investment-grade profile? It seems like the rating agencies are willing to take a long-term view, I mean looking out past the short-term disruptions of 2020. But to the extent leverage remains elevated, can you talk about just the priority of the investment-grade profile?

Well we speak regularly to the rating agencies. And while we've had a market imbalance and it's delayed the pace of our leverage reduction, it hasn't reduced our expectation or desire to reduce leverage. We believe our assets are in a position to support the growth in the basin we serve once the imbalance is rectified and that the rating agencies recognize that. Our credit ratings are very important to us and we've demonstrated by our actions in the past that if the current demand reduction ends up being longer in duration, we have several tools at our disposal to reduce leverage. And we've already taken the first action in this regard by pausing our capital projects to preserve cash flow. We continuously evaluate our options to manage the balance sheet and look prudently to maintain our credit ratings going forward.

Appreciate it. Thank you guys very much.

First question just on growth and the durability of earnings here and forgive me for asking about 2021 just given the tough visibility right now. But as we talk to investors, that's still where a lot of the focus is at this point, so just wondering if you could talk to some of the high-level drivers of growth or even what a flat scenario would look like in 2021 versus 2020 and if you could maybe tie that to your ability to cut CapEx to those baseline levels you mentioned. So in other words is it really a heavy lift to maintain EBITDA levels next year?

This is Kevin. As we discuss 2021, I acknowledge that there's a lot of uncertainty at the moment. However, I want to emphasize our strong confidence in the basins where we operate, as the resources in those areas remain intact. Moving forward, we have considerations like the flare gas that will be available to capture when production ramps up again in the Bakken. This will lead to increased volumes for our natural gas processing plants and the NGL segment. Additionally, it's important to note that with the available capacity, we can achieve this growth with very minimal capital investments as we approach 2021, assuming these volumes return and conditions improve.

And Kevin, I think the only thing I would add is that we have been in this situation before where we built up some headroom in our businesses and were able to generate cash flow. With the outlook for 2021 showing very low capital expenditures, we will find ourselves back in that situation. Considering this, the free cash flow generation of the business is quite significant.

I would like to point out that as you consider the ranges we've presented and the resilience of the business, there are considerable curtailments factored into some of these numbers. It's important to keep in mind the lower end of the range, though I can't provide specific details as that would be financial guidance. When assessing potential outcomes, we've accounted for a notable percentage of production that we expect could be curtailed in one of these scenarios, which is reflected in the figures provided. This alone highlights the strength of our business. Unfortunately, we can't share specific details, and while we would like to, doing so wouldn't be appropriate. However, we feel very confident in our position despite the challenges the industry faces; we believe we are in a strong position.

Yes. And I can appreciate a tough question to answer now. So I appreciate you all taking a swing at it. Second one just to follow up on the CapEx. Can you just talk a little bit about why the Arbuckle extension and expansion are still in the backlog? Is that something that can still come out at some point, or is that really needed as part of the broader network right now?

I'm sorry. You were – this is Kevin. Could you repeat that question? You were a little jumbled as it came through.

Yes. Sorry. I'm sick of using this cell phone. So just wondering if you guys could walk through the decision to lead the Arbuckle extension and expansion in the backlog. Is that something that can still come out at a future point, or is that really needed at this point for the broader network?

'Okay. Yes. The extension remained in as we think about that. That pipeline was important because it allows us to move Bakken barrels all the way to Mont Belvieu. So we wanted that connectivity. And also keep in mind these projects kind of proceed at different paces and many of them are further along or not further along. So that goes into our consideration as well and why that one is still in the schedule.

Hi. Good morning, everyone.

Good morning.

I just want to talk a little bit about the dynamics in the Bakken, particularly as it relates to the flared gas. So – and I guess my question is if you get shut-ins and reduced drilling activity, will you see a reduction in flared gas as well just naturally? And will that generally going to quantify or any rule of thumb to think about how that would impact the number of well connects you would need to do based on that change in flared gas?

Michael, it's Kevin. I'll start and Chuck or others may have some comments. But yes, like we said in our prepared remarks, there's multiple dynamics that could go on impacting flared gas. We have seen some wells shut in that had previously been flaring. So that doesn't impact our volumes obviously. We've also seen some situations where some gas was taken off-line. But other gas that was flaring due to some pipeline or compression constraints started flowing on the system. So effectively it was replaced which would bring flaring down. So yes, I do think these – the curtailments will bring flaring down in a couple of different ways. But the key point there is I think with our capacity – and we had continued to build out some gathering lines as we move through the first quarter. As those volumes come back, we believe we're going to have the capacity to capture the gas much more fully than we did say in the January or February timeframe.

Okay. Great. Thank you very much, guys.

If ethane price were to rise to the $0.30 or $0.40 range next year, would that be enough incentive for you to recover the gas in the Bakken, even if it didn't cover your full midstream tariffs? And do you have the contractual capability to do that?

Did you say $0.30 to $0.40 ethane values?

Yes. Yes for ethane. Yes.

We have the capability to adjust our rates if needed to economically bring ethane on. This flexibility exists not just in the Bakken or Williston but also in the Mid-Continent. If we identify an opportunity to adjust our rates slightly to increase volume, we will do so. However, we must be mindful of market prices; bringing on additional volume from another basin could reduce volume from a currently flowing basin. We consider all these factors. To answer your question, we do have the ability to adjust our NGL rates from the Williston Basin.

This is Sheridan. We could add to that to your comments about ethane is what you're seeing in the Mid-Continent with the strength in ethane prices today and natural gas prices being as weak, what could affect us in 2020 fairly significantly if this continues is we could see producers and processors begin to extract ethane in the Mid-Continent and other places as well, right?

That's very true because the numbers right now are very, very close to recovery economics in the Mid-Continent. And if you take everything into consideration increased propane recoveries when you're in, ethane recovery you could make an argument that in May, we could see some more ethane come out of the Mid-Con that we hadn't predicted.

Okay. Thank you.

Yeah. Thanks.

So, just really a quick one. I think last quarter, Chuck, you may have mentioned that you guys were looking at a proceeding agreement for residue gas takeaway out of the Bakken. Can you just update us on where you stand with that, and if that project has been impacted at all by the production outlook?

Sure, Colton. With everything changing, our producer forecast is also evolving, and we're assessing when we will fully require that project. As it stands, we were considering the fourth quarter of 2022, but I'm not entirely sure if that timeline has been adjusted. We're still looking into it.

Got it. Appreciate that.

Hi, everyone. Thank you for taking my questions, and I'm glad to hear everyone is doing well. Can you discuss the cadence of your guidance for 2020? The reason I'm asking is that in the first quarter, you reported around $700 million of EBITDA. The midpoint of your guidance suggests you will maintain around $700 million of EBITDA each quarter. However, the first quarter results came before the shut-ins and production cuts. What factors are helping you maintain that $700 million quarterly run rate? Could you provide a high-level overview of the positives and negatives?

This is Kevin. Michael, I would think about it like this: in the first quarter, we typically see winter impacts, and we were bringing many of these assets online. As we look at January and February, it wasn't until early March that we noticed the volume increasing as anticipated. If we experience curtailments through April, May, and June, we will likely see a decline as we progress through the second quarter, followed by a recovery in the latter half of the year. Therefore, it is reasonable to expect a decline in the second quarter, with a recovery in the second half.

And is that recovery predicated on Bakken producers re-ramping up production starting in the fourth quarter? And at the current strip price, does that give them the economic incentive to do so, so quickly?

Bakken volumes will certainly be a factor. However, with our West Texas expansion, the other assets we have brought online, and the developments we're seeing in the NGL markets along with opportunities in inventory storage and marketing, there are many possibilities that could emerge as we progress through the second quarter and into the latter part of the year.

Got it. And then one last one. Just curious, if you're thinking about the potential for any repurposing of any of your existing assets? I mean lots of moving parts across oil gas NGLs. Just curious if there are opportunities whether in storage, whether in existing older pipe to repurpose things given what's just going on in the marketplace.

Michael, this is Sheridan. We are continually evaluating our options. As we mentioned before, we believe there might be a chance to repurpose the West Texas Pipeline for crude oil, should an opportunity arise. We are actively looking at these possibilities as we move forward. Currently, storage is a significant focus for everyone, especially given the current price dynamics we are assessing. At this moment, we believe our storage is better utilized for NGL rather than other products, but we are still considering the potential to repurpose assets for different services.

Got it. Thank you, guys. Much appreciate it.

Hey. Good morning, everybody. Thanks for taking..

Hey, Chris.

I have two questions, Terry, if I could. The first you followed I think from Tristan's your line of inquiry just about credit rating. I don't know if that one's for you or Walt maybe it involves more of a Board read-through. But can you just walk us through how you guys think about leverage and the rating? You've talked about capital declines that are possible. Certainly, I think, I was reading into that like how low could the spending be next year. But I guess what I'm getting after is at what point does the dividend come into conversation? Walt, you had mentioned sort of multiple levers and you talked about CapEx first. And I'm just curious how everybody thinks about those components put together.

Well, I think it's fair to say that we continually evaluate all options available. But I think it's really important to understand that with the CapEx that we've reduced, we will be cash flow positive definitely in the third and fourth quarter and into 2021. So deleveraging will happen. It's just a question of the pace if there are things that we might do to accelerate that pace. If that makes sense, we'll go down that path. But I think Terry addressed our view on the dividend while we look at it on a quarterly basis we will be earning cash flow to pay it going forward. That's our expectation.

I'm sorry if I overlooked that in the prepared statement. I appreciate the discussion on NGLs and have been contemplating it. Similar to what Sheridan mentioned, I'm interested in the focus on crude storage. We obviously track purity product NGL storage. There's also significant Y-grade capacity that is fungible. I'm wondering if you foresee any concerns regarding the NGL storage situation. Additionally, do you have any updates on how Belvieu and Conway might be impacted as we witness shut-ins in the Mid-Con or Rocky regions? Thanks.

Chris, this is Sheridan. I believe we are in a solid position regarding our NGL storage capacity. Currently, it's a seasonal period when storage levels are typically low, which would usually prompt more building in a standard year. However, this year is unusual. Right now, we are experiencing strong demand for NGL products, particularly propane, which is being sought after by exporters. There are times in Mont Belvieu when our current production cannot meet the demand from our usual buyers. This demand for propane is why it is trading favorably compared to crude oil. We are also noticing similar trends in the ethane market, where petrochemical companies are still showing significant demand. We've even had to decline some requests for ethane because we anticipate we won't have enough supply in the coming month. If we can recover more ethane, we hope to meet those demands, but for now, the strong demand for our two primary products suggests we have ample storage capacity. This not only supports our regular operations but also allows us to take advantage of opportunities presented by the current contango market.

So Chris, I want to reiterate something that Sheridan mentioned earlier regarding the propane storage inventory being at a seasonal level. We actually have plenty of capacity. This is the time of year when propane retailers start to store product, and I just wanted to clarify that point.

Hey, guys. Thanks for taking my question. Sorry to push on the dividend a little bit. But when it comes to maintaining the investment-grade ratings, based on your current projections if you're at the lower end of your EBITDA range, you're going to be above that all important five times marker which is a trigger for downward high yield if it's sustained for a longer period of time. So without a serious recovery in EBITDA in 2021, it just seems like you only need to be pulling additional levers to maintain that investment-grade rating if things end up being worse than expected. So I'm just wondering how do you weigh in maintaining a dividend versus staying in the investment-grade rating?

Dan, I would tell you that we speak to the rating agencies regularly. I don't know that I necessarily agree entirely with your expectations of where leverage will be on a long-term basis here. And we've spoken about the dividend three times now. So we're not going to get back into it.

All right. Thank you.

Good morning everyone. I'm still unclear about the footnote on page five. Is the change in the drop from $0.92 to $0.85 related to NGL and crude prices? With the decrease in NGL prices from Q1 to Q2 and the rise in shut-ins, should we expect that rate to decline further? Is this a reasonable run rate to consider?

Becca this is Kevin. Chuck spoke to that earlier to the earlier question about what drives that fee rate change and that disclaimer. So yes, there are thresholds that he mentioned that are dependent on a variety of things. And we're not going to provide an update at this point of what we think that range would be. But we can tell you that as we've factored in all those scenarios that various outcomes have gone into the $2.6 billion to $3 billion EBITDA range that we provided.

Thank you.

Hi everyone. Thanks for taking my questions. So it looks like you've done a lot of really good work here on the scenario analysis. And with respect to this kind of $2.6 billion lower end of EBITDA kind of outcome, I think it seems like you have pretty good confidence that that's the low end. What would have to happen in order for that EBITDA to be below that end?

We're not going to provide that information. As we mentioned, we reviewed several scenarios that took into account various price, volume, and producer activity outcomes. We believe the EBITDA will likely range between $2.6 billion and $3.0 billion, and that's the information we're sharing at this time.

Elvira, as I indicated earlier, the numbers consider substantial curtailments and a significant duration of this downturn. So I think that's about as much as we can give you.

No. That's really helpful. And then just my last follow-up question here is in some of these conversations that you've had with some of maybe your Bakken producer customers, at what point would you expect activity to pick up? And when I say that I mean, at what commodity price? And maybe you can think back to that 2015, 2016 time period?

Well this is Kevin. I think there are a couple of factors at play. First, if they are reducing gas production, we need to consider what price would motivate them to resume that production. Although I can't provide a specific figure, they are analyzing their variable production costs, which will differ among producers and locations. This indicates that a lower price is significant. Looking ahead, the next area of activity will be completions. There are still over 400 drilled but uncompleted wells in the basin, and that will require a certain price for activity to resume. As prices increase, we will monitor these factors, and the curtailed gas production will return first, followed by the addition of completion crews and producers working through their uncompleted wells.

Elvira, I think it's fair to say that if we experience this continued downturn, the quicker producers address the supply and demand imbalance, the sooner there will be a recovery. That’s our perspective on it.

Good morning. First, let me just congratulate you on holding off on the less-economic initial forays in the long desired crude gathering and export terminal opportunities. Sometimes what we don't do is more important than what we do. With respect to in-flight growth projects that are now on hold, do you see a pecking order among them in terms of what might come online first or resumed first?

No, I don't think we would view it that way. As we engage with our customers in each of our basins, that will guide our perspective. If we continue to observe significant growth from the Permian until the recent downturn, then the West Texas expansion would definitely be reconsidered. Likewise, in the Bakken, if we notice activity in specific areas, it's important to note that Bear Creek is geographically isolated. Therefore, it would depend on certain producers expressing interest in resuming activity in a specific part of the Bakken. These types of factors would determine when Bear Creek can come back online. Ultimately, the decisions will be made on a producer-by-producer and processor-by-processor basis.

I think the other thing to note is that I've experienced these cycles many times. One trend we've observed in the gathering and processing sector over the years is that during downturns, discussions often arise about midstream companies consolidating assets, shutting down underutilized facilities, and offloading gathering systems. It's important to recognize that the impact of these discussions can vary depending on whether they lead to revenue benefits or cost savings. We may see more of these conversations as we move forward.

Terry, I'm sorry. So you could see yourself as a potential consolidator on some distressed assets?

Sure. We might identify facilities that make more sense to temporarily idle while we deliver volumes to someone with available capacity.

So just to say I hear a thing that in an operational way, there's an opportunity to consolidate and find good economic outcomes between multiple different companies.

You achieve that through offload processing deals or, if you are the recipient, through an onload processing deal. It does not require ownership. Thank you, Walt.

I got you. And I don't know if Walt wants to chime in again and sorry for beating a dead horse. We've had some questions about dire worst-case leverage conditions and potential additional levers. I want to focus more on patience. So, if credit isn't deteriorating to untenable levels, but lower for longer lasts much longer than perhaps envisioned today, is there a limit to how many years you're willing to wait for organic improvement in your targeted net debt-to-EBITDA ratio?

Yes, Craig. That's quite a hypothetical question. I would suggest you speak to the rating agencies about their perspective on timing. For investment-grade companies, the view tends to be longer-term rather than focused on quarter-to-quarter results. As we move forward, we see ourselves naturally reducing leverage and we will explore other opportunities that could assist with that. However, if you look years into the future, everything is on the table. But that's quite a hypothetical scenario.