Oneok Inc (OKE) — Q2 2020 Earnings Call Transcript

Thanks, Andrew. Good morning and thank you all for joining us today. 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 of 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 of Natural Gas Liquids and Chuck Kelley, Senior Vice President of Natural Gas. I'd like to start by commending our employees who are continuing to operate safely and responsibly and remain focused on providing extra customer service in a challenging environment. In recent weeks, we've seen cases of COVID-19 increase across the country. In response, we've asked employees who are able to continue working virtually. For those critical employees who are reporting in person to operating sites, we continue to ensure that enhanced safety protocols are in place for their safety and for the safety of their families and communities. Second quarter results were interrupted by the pandemic's effect on worldwide crude oil demand, extensive production curtailments across our operations and low commodity prices. After bottoming out in May and June, volume trends across our operating areas have sharply increased in recent weeks as customers have started to bring production back online with the recent stability in commodity prices providing positive momentum as we enter the second half of 2020. As a matter of fact, many of our facilities during July have returned to pre-COVID levels. For example, our July average total NGL raw feed volumes are exceeding first quarter average NGL volumes, benefiting from higher propane plus volumes in the Permian Basin and increased ethane recovery in the Mid-Continent. Williston Basin volumes have also strengthened significantly off the lows experienced in May. The earnings impact we saw in the second quarter reflects significant production curtailments in the Williston Basin where our earnings on a per unit of throughput are some of the highest due to the broad level of services we provide our customers. As curtail volumes recover to more normalized level, so too will our earnings. While volume trends are greatly improving, there remains continued global demand uncertainty due to COVID-19. We expect 2020 earnings to be at the low end of our previously provided outlook ranges, which Walt will discuss shortly. Despite these challenges, we continue to deliver value to our investors through the prudent management of our large strategic and integrated assets located in the most prolific NGL-rich basins in the U.S. These assets are supported by a strong, stable customer base and growing demand for the products we deliver. There have been many reports written on the possible implications of a DAPL shutdown for ONEOK, so I'll get right to it. Many producers in the region are developing contingency plans to address their oil transportation needs. While DAPL does currently provide meaningful crude takeaway capacity from the region, there are alternatives through other pipelines and substantial rail capacity. It wasn't long ago that nearly 800,000 barrels per day of crude were leaving the basin on rail. Specific to ONEOK, we estimate 30% to 40% of DAPL crude oil volume is from the producers whose gas volumes are dedicated to our gathering and processing business in the Williston Basin. About half of those volumes have alternate methods of crude transportation currently available. This means that approximately 200 million cubic feet per day of nearly 1.5 billion cubic feet per day currently connected to our system is associated with crude oil production that may not have immediate alternative takeaway options. From the constant conversations we have with our producer customers in the basin, they remain committed to finding solutions to take away constraints. In our view, any impact from a DAPL shutdown would mostly impact 2021, providing some time for more solutions to develop. Even in an extended shutdown scenario, we estimate our 2021 Williston Basin natural gas processing volumes could approach our first quarter 2020 average of more than 1.1 billion cubic feet per day due to curtailed volumes returning, the capture of flared gas, and the completion of drilled but uncompleted wells. Kevin will provide some additional data points during his remarks. At the beginning of 2020, we had all the assets in place to produce annual EBITDA of more than $3 billion. Our extensive infrastructure that now has substantial available capacity is still there, providing significant operating leverage to the upside, and no additional capital spending is needed to realize that earnings potential. As it relates to our dividends, with our business improving and volume strengthening, we don't see the need to take action on the dividends. We do recognize that it is a lever we could use if our deleveraging expectations are not being met. Financially, we've taken the proactive steps to provide ample liquidity and protect our investment-grade credit ratings during the pandemic while continuing to return long-term value to our shareholders. Our employees and management team are doing an excellent job in unusual conditions, and I have tremendous confidence in them to see us through to the other side of this downturn. They found ways to successfully navigate industry challenges before, and they will again. With that, I'll turn the call over to Walt.

Thank you, Terry. Instead of a typical run-through of our quarterly financial performance, which was well detailed in yesterday's news release, I'll walk through a few of the strategic financial decisions we made during the second quarter and how those have positioned us for the remainder of the year. We completed two proactive capital market transactions, raising capital of more than $2.4 billion during the second quarter, providing us additional liquidity and balance sheet flexibility in a still uncertain market environment. In May, we completed a $1.5 billion senior notes offering and used a portion of the proceeds to repay the remaining $1.25 billion of our term loan agreement, which was maturing in 2021. In June, we completed a public offering of common stock resulting in net proceeds of $937 million. Both of these transactions were undertaken to strengthen our balance sheet and provide a clear and accelerated path towards equity leveraging goals. We still intend to manage our leverage below 4x as business strengthens to pre-COVID levels and to maintain 3.5x as our long-term aspirational goal. Both transactions were successful in that respect. As we sit today, we have ample liquidity and balance sheet strength and flexibility at the end of the second quarter with no borrowings outstanding and our $2.5 billion credit facility and more than $945 million of cash. Interest expense increased in the second quarter primarily due to the settlement of interest rate hedges related to the earliest repayment of our term loan, resulting in a one-time impact on earnings per share of $0.09 in the second quarter. With yesterday's earnings announcement, we certainly expect 2020 net income and adjusted EBITDA results to be at the lower end of our previously provided outlook ranges. As we return to volumes achieved during the early March 2020 period, we expect our earnings run rate to be in line with our previous expectations and to provide a continued path to deleveraging. We also expect total capital expenditures, including maintenance capital, to range from approximately $300 million to $400 million in the second half of 2020. Total annual capital expenditures, including maintenance and growth of $300 million to $400 million, will be maintained until producer activity levels provide visibility to volume growth warranting expanded capacity. However, we remain flexible with the ability to scale capital back up quickly as our customers' needs arise. Last week, the Board of Directors declared a dividend of $0.935 or $3.74 per share on an annualized basis. We continue to look for cost efficiencies across our operations. So far this year, we have implemented measures across our systems, including optimizing assets, power savings, and discretionary spending reductions totaling approximately $50 million. We expect additional cost-saving measures in the second half of the year to result in total 2020 savings of approximately $120 million compared with our 2020 plan. I'm now going to turn the call over to Kevin for a closer look at our operations.

Thank you, all. The backdrop we're seeing related to activity in volumes across our system has greatly improved since second quarter lows in May and June. Our recent conversations with producers have been focused on bringing wells back online, resulting in increasing volumes on our system, and in some cases, producers are beginning to add completion crews and drilling rigs. Comparing our lowest average total monthly volume levels in the second quarter with our highest volumes reached so far in July, we've seen increases of more than 25% in NGL raw feed throughput volume and 20% in natural gas processed volumes. Our natural gas pipelines segment continues to provide stable fee-based earnings with firm contracted capacity totaling nearly 95%. The importance of this segment's stable and predictable earnings is highlighted during times of market uncertainty and underscores the strong demand for natural gas we continue to see from our customers, including electric generation facilities, utilities, and industrial markets. Now let's take a closer look at current activity across our operations. In the Rockies region, we've seen a sharp increase in volumes in July, as Terry mentioned. Total NGL raw feed throughput volume from the region has reached more than 200,000 barrels per day in July, a nearly 50% increase from May lows. Natural gas volumes produced in the region have reached 945 million cubic feet per day in July, also nearly a 35% increase from June lows. There are approximately 10 rigs currently operating in the basin, with about half on our dedicated acreage. Drilled but uncompleted wells in the basin total more than 950, with approximately 400 on our dedicated acreage. Our customers in the basin are some of the most well-capitalized producers in the industry and have communicated they're positioned to resume activity as commodity prices and the demand outlook improves. We're frequently asked what price it would take for producers to bring rigs back to the basin. But the important point right now is the price it takes to bring curtailed wells back online. We believe that if current market conditions are sustained, the remaining curtailed production will come back online during the third quarter of 2020. In the Williston Basin, we had approximately 1.5 billion cubic feet per day of natural gas connected to our system in March, which includes volume that had been captured on our system in volumes being flared. The latest data shows 220 million cubic feet per day is still flaring in the basin, with 125 million of that on ONEOK's dedicated acreage, which provides a continued volume uplift opportunity for us in 2020. Our completed infrastructure is in place to capture this volume, and no new drilling activity is needed to reach our pre-COVID volume levels. We are on track to complete the extension of our Bakken NGL pipeline in September of this year, earlier than our previous target date of the fourth quarter. This new pipeline lateral will connect with an expanding third-party plant and will provide NGL takeaway in an area of Williams County, which historically had limited NGL transportation options. We expect the lateral will provide additional NGL volumes to our system as we enter the end of 2020, and it includes a minimum volume commitment. During the second quarter, curtailments varied greatly across our producers. Some curtailed nearly 100% of their production, and some curtailed virtually none. The percentage of proceeds and fee components also vary across our customer contracts. Curtailments on large producer contracts with higher fees and lower PLP components were the primary contributor to our lower average fee rate. Another factor was that we experienced greater curtailments in our higher fee Rockies region compared with our lower fee Mid-Continent region. Given what we see today, with curtailed volumes continuing to return, we expect the average fee rates for the gathering and processing segment to reach pre-COVID levels of approximately $0.90 per MMBtu in the fourth quarter of 2020. In the Mid-Continent region, second quarter average NGL raw feed throughput volumes of 521,000 barrels per day increased compared with the first quarter of 2020. Volumes from this region had reached over 600,000 barrels per day in July, a 15% increase compared with the second quarter of 2020 average. Ethane volumes in the Mid-Continent averaged 260,000 barrels per day in June 2020 compared with the second quarter 2020 average of 210,000 barrels per day, a more than 20% increase driven by nearly all our Mid-Continent plant connections entering recovery during the quarter. We expect ethane recovery on our system to continue through the remainder of the year due to strong petchem demand and favorable ethane extraction economics. In the Permian Basin, the connection of two new third-party processing plants in the first half of 2020 and the full completion of our 80,000 barrels per day West Texas LPG pipeline expansion in June position us well for future growth in the basin. With the expansion complete, we will continue to transition volumes away from third-party offloads onto West Texas LPG. We are currently offloading 25,000 barrels per day, which will provide full transportation and fractionation revenue when they move onto our system in the future. Terry, that concludes my remarks.

Thank you, Kevin. With a challenging quarter behind us, there are opportunities ahead. What we've seen proven time and time again is that producers in the midstream industry are resilient, innovative and able to find solutions when market conditions are tough. We saw it in 2015 and in 2016 when producers were able to drive significant efficiencies in their drilling programs, and again in 2018, when the midstream industry worked together to add Gulf Coast fractionation capacity. From the ONEOK perspective, our management team will continue to be proactive and innovative in how we can become even more efficient. We remain focused on creating value for our stakeholders and continue to prioritize the long-term sustainability of our businesses. The events of 2020 have certainly been disruptive but have not distracted us from focusing on the right things. I'm proud of the resilience and focus with which our employees have approached the last several months in keeping our employees and assets safe and I am inspired by the way our employees and the company are navigating important social issues within our communities with compassion, understanding, empathy, and generosity. We will provide more detail on these important issues and many others in our upcoming environmental, social, and governance report, which will be available on our website in the coming weeks. This report is particularly important in times like these, and staying focused on the right things is more important than ever. The report includes expanded disclosures in each of the ESG categories and will mark an adoption of the savvy sustainability reporting standards. While ESG reporting isn't new to us, this report will be our 12th annual publication. Our sustainability journey continues, and we remain committed to continuous improvement of our ESG performance and disclosures to our stakeholders. With that, operator, we're now ready for questions.

Hey, good morning. This is Charlie. I appreciate all the color in the opening remarks. Just as you noted with your updated guidance reflecting potential Apple headwinds there, I'm curious if it also takes into account the High Plains pipe that could be shut. And also, secondly, I was curious, should Apple shutdown commence, can you address the possibility to temporarily repurpose an NGL pipeline to crude service, if that would make sense, and kind of what the puts and takes of that would be?

Yes, Jeremy. It's Kevin. The first question, as far as the Apple shutdown, we really don't see much impact at all to 2020. As we said, we see that more as a 2021 issue as curtailed production comes back. We believe there will be another pipeline capacity in rail transportation to handle the volumes that are currently being curtailed. And as it relates to the second question, yes, we physically could convert the smaller Bakken NGL pipeline to crude service. We're evaluating that, and looking at all of our options, and watching that closely. But yes, that is something that's physically possible.

Thank you. And then looking at the second half guidance here and trying to parse one half to the second half, how should we kind of think about Rockies and mid Conway connects relative to the first half, given the sort of rig count pricing environment we're in? And then maybe secondly, specific to GMP, what sort of pricing assumptions go into pointing you towards to what you gave us on guidance? Maybe said differently, that $30 million decline you saw related to the POP exposure contracts, would you expect that to reverse in the back half of this year?

There's a couple questions in there. I'll answer your last and first. And yes, like we said, we do believe that if we see this environment sustained, you'll see that that fee rate improve. And obviously, that's going to help on the POP side if you get some pricing strength as well. And what was the first question in that second grouping?

It's about well connects in the second half relative to what we saw in the first half, just given what we're seeing on the rig count side and the pricing environment.

Yes. The 2020 numbers are not contingent on well connections in relation to new rigs. This is more relevant for 2021. Recently, we have had discussions with producers about completing drilled but uncompleted wells and possibly bringing completion crews back. We do not expect rig counts to increase significantly in the next couple of months. Chuck, do you have anything to add?

Yes, I mean, what I did was based on producer discussions, as Kevin mentioned, if we're seeing on the drill schedules that are provided by our producers, DUCs are currently being completed here in Q3, as Kevin mentioned. We've also got some line of sight to Q4 with additional completions. And what producers have told us is they want to complete these wells before winter in anticipation of more demand. And in addition to that, some of our larger producers have indicated to us that they're going to run one to two rig programs through the remainder of the year on our acreage. So, we've got some line of sight to increase DUC completions as well as increased well connects forthcoming. So, hope that gives you a little more color.

Great. Thank you very much.

Good morning, guys. Just appreciate all your commentary on the new range for EBITDA. But I guess just thinking about higher LPG prices and the volume improvement we've talked about in July, as well as teaching recovery and enhanced well completions, do these timing factors add up to really support a run rate EBITDA as we look towards the end of this year, somewhere much closer to the high-end of that range of outcomes you provided last quarter, namely the $3 billion type of EBITDA range?

This is Kevin again. And yes, I do think it supports that. If you think about where we were, not necessarily first quarter average, but you think about where our volumes were right as we entered into the COVID and the OPEC situation, those types of volume levels supported that upper end of that range that we talked about. So, as we get to curtail production to come back online, and I think a key point in that is those March numbers included substantial gas that was flaring. Since that time, we've put additional infrastructure in place, and if the volumes come back, we would expect the flaring numbers to go down. So that's why we have the confidence in those numbers. If that's what you choose to that run rate that we're looking at, towards the upper end of the range.

Great. You mentioned that the 2021 CapEx opportunity would not be lower than 2020. Now that we are halfway through the year, do you expect that spending opportunity for next year to be under $1 billion? Or can you provide some guidance on how you plan to allocate that spending?

I just said in my prepared remarks that we would be in that $300 million to $400 million range for 2021, including maintenance and growth. And we will sustain that level of CapEx as long as producer activity, indelible producer activity, is generating growth that we need to expand capacity. It's very flexible. We have all the assets in place to get us back to readiness for that EBITDA north of $3 billion. And so, we're in a great position here where we don't have to jump on the CapEx level until producer activity warrants that for growth.

I appreciate it. Sorry, I missed that figure. Thank you, guys, very much.

Thank you.

Hi, good morning, everyone. Good to hear everyone is well. Just maybe wanted to just start off with your dividend comments that you made in the prepared remarks. You'd mentioned that it could potentially be another down the road and so forth. When you sort of think about things, you've got a lot of headwinds obviously with COVID, potentially with Apple, which can impact CapEx for the basis of your producer customers. I was wondering if you can give us the case studies or scenarios as to how you think about the dividend, either being maintained or potentially being reduced in the $2.6 billion guidance range for this year enough to maintain the dividend. What levels are you thinking about would become an area where you would become concerned as a $2.4 billion run rate? How much does SMP reviewing your rating matter? Just wondering if you can sort of give us different paths and different outcomes as to how you're thinking and would be recommending the dividend to the board.

So Shneur, this is Terry. I'll just make a comment, and then Walt can follow up. As we consider 2021, this really touches on the core of your question about the future of our business. We've analyzed several scenarios, and a crucial factor is Apple. Key questions include whether Apple will be shut down or continue to operate. Looking at those scenarios for 2021, even with a potential Apple shutdown, we anticipate mid to high single-digit EBITDA growth compared to what we expect for 2020. If we're fortunate and Apple remains unaffected in 2021, we could see 12% to 15% EBITDA growth over our 2020 expectations. In both scenarios, we believe there’s no need to take any actions regarding the dividend. As Walt mentioned, capital spending will also be modest, in the range of $300 million to $400 million. Given this outlook, we certainly don't feel it's appropriate to take any action at this time. Walt, do you have anything to add?

We obviously stay in touch with the rating agencies. They saw that the activity definitely equity is a proactive step to accelerate the leveraging from other real benefit not on that, and we're focused on cultivating, and we're pleased to see the strength that we're seeing from the producer activity bringing retail volumes back on the trend that that's showing us in this point in time.

It's Sheridan. The only thing I would emphasize, and we've said it a couple of times in our opening remarks, but that is this BCF and a half a day, particularly in the Williston Basin, that deliverability is connected to our system and doesn't really depend on a whole bunch of rigs coming back into the basin. As we think about 2021, our growth that is our throughput growth on our GMP business is a function of capturing and accelerating that capture of that BCF and a half a day. So you think about this first-quarter 2020 volume of about 1.1 BCF a day in the BOC, and as you think about 2021, that number we expect to grow as we move throughout the year. And it's a function of capturing that BCF and a half a day of deliverability that's already there. That's the point we can't emphasize enough today.

I really appreciate that; it's a better answer than I expected. It might be a good way to transition. You've addressed this a bit in previous questions related to the prepared remarks. When we discussed the factors contributing to a strong recovery in the second half, looking back at the cycles of 2013, 2014, and 2015 in the Bakken, do you see a continuing trend in efficiency? Should we focus on the right rig count for the Bakken to generate enough DUCs to maintain and possibly grow production? Do you envision a scenario where a normal run rate of around 30 could lead to a conservative market of 1.4 to 1.5 million barrels? I'm curious about your thoughts on efficiencies and how the situation is evolving.

Shneur, it's Kevin. I'll start. You were a little muddy, so I'll make sure — if I don't answer your question, make sure you jump back in here. I mean, we continue to — the reserves have been fantastic in the Bakken, and producers have been year-over-year delivered better and better wells. The rigs have gotten more and more efficient. So, they continually have shown they can deliver more volumes with less capital is what that ultimately goes to. So, I think that's part of the story that over time, you won't need as many wells or completions to keep your volumes at certain levels. I think we've talked about it in that 1.4 to 1.5 type range of the BCF a day volume. You're probably 30 to 40 completions per month on our acreage. And we think that's absolutely doable. And we do believe the quality of the wells will continue to improve.

Another data point I'd add, Shneur, is we work closely with all of our producers, and a couple of them have been the past six months or so, I wouldn't say experimenting, but working with longer laterals as long as three miles. And based on the results of this, we're being told that fewer wells will be needed for the increased deliverability that they're seeing through those longer laterals. So for that part of your question regarding continued either technological enhancements or efficiencies, I would say the producers didn't dial anything back, and we're really seeing some good results from some of these folks with much longer laterals now.

One last thing on this topic, and I apologize. I should have brought this up sooner because we haven't mentioned it in our remarks either. Just to remind everybody, the gas to oil ratios continue to strengthen. So, if you look at the crude oil forecast and you've got to apply the strengthening gas to oil ratios, and you can see some of the materials we provided on the presentation that show what that's done over time, and it's continued to strengthen to where now it's more than 2.2. So, that's another factor. We look at the basin of what's going on the gas side. Don't just focus on what's going on the crude oil side.

That makes perfect sense. We really appreciate the color today, guys. That was very helpful. Thank you.

Appreciate the comments around the green shoots of activity and how you might return to those marks level. So I think we will be getting back to the 1.5 BCF a day, understandably, a reversal of shut-ins is a large component of that. But I think the other point that the market's struggling with is what base declines look like. So, can you update us on how the wells that you've had still connected to your system have been producing over the last couple of months out of the chair — how does it fare?

This is Chuck. Could you repeat the last part of your question? I didn't quite hear it; from the decline on?

Yes, Chuck. I think in terms of understanding what level of completions we might need to see to get back to something that looks like a more stable production rate and ultimately growth, I think the basic line has been to some there. Interested to see if you guys have a view on when a PDP profile might work across your system.

So, similar to other shale plays, we see typically or what we run in our models — and you're wondering 50%, 55% decline rate year two, and that's 20% to 25%, year three, 15% and then maintaining stuff down from there. So your first year is your — obviously, as you know, is your larger trial decline in shale plays. We run at a 50%, 55% range.

Okay, and you all feel comfortable that 30 to 40 completions a month would be sufficient to fully offset that base?

We do.

And on the planning side of things, I think we've heard from producers that wells that were flaring were preferentially shut-in. So if you looked at that $125 million that's been flared on one of the acreage today, would you expect that to increase as you bring wells back online? Or alternatively, have you still been connecting to wells that are actually shut-in today to accelerate that gas capture?

What we've done here in the second quarter to help people flaring — you won't really see that until third — we expect to see the results here in the third quarter relative to our flaring percentages, as we've completed some pretty good sized trunk lines into an area air flow that's been very, very limited and been able to get gas egress. So, we put in a couple of 20-inch trunk lines completed and tied in wells that had been flaring, as well as some new wells that were getting ready to come on. So, some of our infrastructure obviously is going to help on that 125 million a day.

Understood. Appreciate it.

Great, thanks, everyone. Appreciate it. One question I wanted to ask was just about ethane recovery. Can you talk about — I'm assuming you're not seeing much increase in the vacuum, but really wanted to talk about that? And also, to the extent you are seeing increased recoveries in the Mid-Continent, how that's trending and any way to quantify that? Thanks.

Michael, this is Sheridan. You are correct about Bakken where — and their targets are not improving, and the economics at this time don't warrant that. But we have, as we mentioned, seen good ethane recovery increases in the Mid-Continent. And what I'd tell you today is that in June and July, the average percentage of ethane in a wide rig is 45%. We are up over 60,000 barrels a day more ethane in the Mid-Continent than we were in the first quarter, and over 50,000 what we experienced in the second quarter. That's for June, and July has continued on that. So I think we — as mentioned in our remarks, all the ethane or substantially all the ethane within the Mid-Continent that can come out is coming out. And we do predict that and continue through the rest of the year.

Great. And then a somewhat related question. There have been a lot of discussions about the gas dynamics in the Bakken, given the BTU issues. Obviously, that's obviously changed a bit. But just curious, your views, if you think any of the proposed expansions, including how the northern border — are any of those still in play, or do you think that whole expansion discussion's kind of shelved here for a while until Bakken levels recover?

Michael, this is Chuck. We answered a similar question in Q1. And at the time, again, with things in flux and trying to forecast, we're kind of — as far as we were experiencing or working on expansions, kind of pushed that out a little bit. I think it's fair to say that an expansion should be forthcoming. I just can't tell you when. I would say it has been pushed out probably 12 months anyway. We just need a better line of sight on some longer-term forecasts, but I think that expansion will definitely be needed in time.

Great. Thank you so much.

Good morning. Just a follow-up on the Bakken NGL to crude conversion potential; recognizing that it's still in early development, but would this require overland pass to convert to crude as well?

Be able to move through the Bakken pipeline, physically possible, we would probably move it into the currency area.

Okay. So, it would just be before you hit ever like that?

Yes.

Great, thank you. And then just a quick one. What's the latest estimate of when you would be a federal cash taxpayer?

Well, nothing really changed from a tax standpoint, other than the fact that obviously, the rate of the EBITDA is going to be lower than expected in 2020. So, if anything, it smoothed out a little bit because the assets that we ultimately will complete, will come into play down the road, and that depreciation will come at a later date and we'll be able to optimize the economy. So, we don't expect to be a LIFO taxpayer for several years. Eventually, we'll get into a situation where there are some limitations that are currently out there on the utilization that allows, but that's still a few years down the road.

Great. That's all for me. Thank you very much.

Hi. Good morning, guys. Can you hear me?

Yes, we can hear you.

So, thanks for all the clarity on the call. I just had one follow-up question on the leverage metrics. In the press release yesterday, you indicated the covenant-based average tracking at 4.5x. So, it seems like to me that the EBITDA baked into that based on projects, which did not contribute to EBITDA yet. First, is that correct? And secondly, when you bake that EBITDA into the covenant metrics, is that based on cash flows, which are contracted, or is it more driven by your expectation, and then frequent is that expectation kind of revised? Thanks.

Could you repeat the first part of your question?

So, in the press release, you had indicated that the covenant-based leverage was tracking at 4.5x. So, when I look at your debt balances, I come up with a higher number. So, I'm just trying to reconcile that disconnect.

The covenant calculation does not match exactly to GAAP under the bank covenant. There is a provision that allows for an EBITDA assumption associated with CapEx that's either come into service or will come into service down the road, and that scales down over a period of time. So, there's always been a slight mismatch between the GAAP and the covenant calculation. At this point, the covenant calculation is at 4.5 times versus the covenant at 5 times.

Hey, guys. Thank you for taking my question. Can you comment a little bit about what you're seeing in back volumes at Bellevue? And I'm kind of going back a little bit to kind of what the trend that could be. Can I call that data out a little bit about what you've seen frac-wise? And are you saying does not having export capacity, especially given LPG exports have kind of held up relatively strong during the last three or four months period, does not having a dock capacity or export capacity actually impact you at the price levels, our volumes relative to maybe what you think or what you're seeing your competitive peers one faction that has helped you as well?

Currently, our system allows all our fracs to be processed at the Bellevue frac. This means we have ample frac capacity because any volume we frac in the midcontinent using the sterling system can be reflected in Mont Bellevue. At the moment, we have sufficient frac capacity through 2020, unless we see a significant increase in producer productivity that would necessitate bringing in additional capacity. Overall, we're in a strong position regarding frac capacity. As for the need to export, it doesn't affect us right now. We currently have more export capacity than needed, allowing us to have contracts to meet the demands from exporters who require that volume to meet their commitments. Therefore, not having a dock is not a current issue for us. In the future, we may consider additional capacity if supply increases, but at this point, we don’t view it as a drawback.

No, that's super helpful. Can you talk a little bit about what you think utilization rate in the quarter was for your fracs and how July's looking?

Right now, we are over 80% on our frac utilization. We've seen a big step up on that because we've bought more ethane on. That capacity has always been there. But we're sitting about a little over 80% of what our frac utilization would be. And so, as we continue to grow into the third quarter, we have already seen that volume increase that we talked about in July. We still move closer to that — maybe closer to the 90%, the 85%, 90%, which still leaves us plenty of frac capacity.

Understood. I have one last question for you, Terry. With your position on the board, how do you assess capital allocation? You mentioned earlier that there’s no immediate need to change the dividend. How do you weigh the decision between maintaining dividends and considering additional equity issuances if necessary? I'm curious about how you and the board view potential sources of equity capital if it becomes required.

A couple of different aspects. It's related to deleveraging any dividend action that would have been considered from a deleveraging standpoint would have taken quite a bit of time to actually have an impact wherewith the equity offering there was an immediate impact from the credit standpoint. The other side of that also as well is that as we see the business going forward in that the COVID has a defined period of time that it will take to play through and provided we know exactly what that defined of time is that to the extent that it's measured in quarters, we didn't believe that that meant that we should adjust our dividend for a quarter or two or more disruptions. We needed to make a positive step on the deleveraging standpoint, and the quickest way to do that was to do the equity offering. Then as we see the strength of the business coming back and that would be there to support that dividend in the long term, we continue to get on that path.

Michael, the only thing I'd add from a priority standpoint, maintaining that investment-grade credit rating is extremely important to the company and important to this board so it remains a high priority. Certainly, that was in the mix in terms of the capital allocation decisions we were making.

Got it. Thank you, guys, much appreciated.

Thanks for taking the question. It sounds like a wonderful artwork heading into the second half here. That's great clarity. On potentially repurposing the dock and NGL pipeline, how long would that take and would any concurrent upsizing needed on outreach be done in the same timeframe?

Very good, Shere. We're still evaluating all the aspects of that turning them into crude or repurposing. What needs to be done? So we continue to look through that. As we continue to evaluate that more, we'll have a better understanding of what it takes to convert to crude.

Are we looking at something that could be a couple of years? It could be comfortably quicker than that if you had to go that route the market needed?

I don't think it's a couple of years, but it will take some time.

All right, thanks. Walt, I apologize. I guess I'm a little confused about the CapEx guidance. I thought I read the second half will be an absolute $300 million to $400 million, but then do I understand that's ongoing until there's a lot of more clarity on COVID and upstream volume that the annual rate in 2021 will be $300 million to $400 million?

That's correct. As we finish up the 2020, we'll be in that commitment, finishing up, and we have enough projected to see that business pick up, and we will maintain that level of capital expenditures as we pull growth near the end of the year.

Very good. Last question on storage and ethane recovery, which was spoken of a lot on the first-quarter call. I think we already addressed ethane. I know storage is only maybe tens of millions of uplifts, but I don't know, Sheridan, maybe you want to talk about when exactly that might be hitting. I know it's a hedged position. What should we be looking for into the second half?

I think the contango that represented itself will present itself in the second quarter because of how we sold that product out for, and we will see that benefit show up in the second half of the year. You'll see that in the Isom unit as well.

Should we see most of that in the fourth quarter?

Yes, you could see some of that in the fourth quarter. We've sold it throughout the third and fourth quarter, so you can see it through the remainder of the year. A lot is going to happen on this week in prices through that period of time, but it will be spread through the second half of the year if I can think so far.

Great, thank you.

Thank, you guys. Wishing you a good new year. Maybe just a couple of clarification questions if I heard it right here early in the Q&A portion referencing a DAPL impact. I believe we referenced if we extended the intended shutdown it would be mid to single EBITDA growth year-over-year and 1% down of the 12% to 15% year-to-year. A lot of the EBITDA growth rate and that also the $2.6 billion number for 2020 before mature. Is that right?

That's correct. That's what you based it in. Those percentages that I provided earlier are based upon the lower end of the range that we provided for 2020, the basis of that.

Okay, perfect. Then I think the formal market definition efficiencies was it coming from Rodney Vegas with his opposition to power saving captured 50 million for the year and you talk about 120 is relative to your 2020 plan. Like I say, if you start to see things recover in the second half do you feel most of that profit is sustainable or do you see some not coming back?

This is Kevin. Yes, we absolutely believe those cost savings are attainable. As we move through the year we've taken — our team has done a fantastic job of finding opportunities and some of those opportunities you identify them, but it takes a little bit of time to actually get in, and we've been doing that. So, we do believe, even with the volume strengthening that we'll realize those savings in the back half of the year.

Got it. Thank you very much.

Well, thank you, Sarah. Our quiet period for the third quarter starts when we close our books in early October and extends until we release earnings in late October. We'll provide details for that conference call at a later date. Thank you for joining us and have a good day.