ONEOK, Inc.

Good day and welcome to the second quarter 2020 One Oak earnings call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Andrew Viola. Please go ahead, sir.

Thank you, Sarah, and good morning, everyone, and welcome to One Oak's second quarter 2020 earnings call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. After our prepared remarks, we'll be available to take your questions. During the Q&A session, we would appreciate it if you limit yourself to one question and one clarifying follow-up so we could fit in as many of you as we can. A reminder that statements made during this call that might include one of the expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. Our first speaker this morning is Terry Spencer, President and Chief Executive Officer. Terry?

Thanks, Andrew. Good morning, and thank you all for joining us today. As always, we appreciate your continued trust and investment in One Oak. 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 Kelly, Senior Vice President, Natural Gas. I'd like to start by commending our employees for continuing to operate safely and responsibly and remaining focused on providing excellent customer service in a challenging environment. In recent weeks, we've seen cases of COVID-19 increase across the country, and 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 MGL raw feed volumes are exceeding first quarter average MGL 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 curtailed volumes recover to more normalized levels, 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 NGO-rich basins in the U.S. These assets are supported by 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 one oak, 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 One Oak, 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. And about half of those volumes have alternate methods of crude transportation currently available. This means that approximately 200 million cubic feet per day of the nearly 1.5 billion cubic feet per day currently connected to our system is associated with crude oil production that may not have an immediate alternative takeaway option. From the constant conversations we have with our producer customers in the basin, they remain committed to finding solutions to takeaway 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 Wilson 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 dividend, 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 pull 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've found ways to successfully navigate industry challenges before, and they will again.

With that, I will 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. And 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 our deleveraging goals. We still intend to manage our leverage below four times as business strengthens to pre-COVID levels. and to maintain 3.5 times as our long-term aspirational goal. Both transactions were successful in that respect. As we sit today, we have ample liquidity in balance sheet strength and flexibility. We ended the second quarter with no borrowings outstanding on 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 early repayment of our term loan, resulting in a one-time impact earnings per share of $0.09 in the second quarter. With yesterday's earnings announcement, we said we expect 2020 net income and adjusted EBITDA results to be at the low end of our previously provided outlook ranges. As we return to volumes achieved during the early March 2020, we expect our earnings run rate to be in line with our previous expectations, and to provide a continued path to due leveraging. We also expect total capital expenditures, including maintenance capital, to range from approximately $300 to $400 million in the second half of 2020. Total annual capital expenditures, including maintenance and growth, of $300 to $400 million will be maintained until producer activity levels provide visibility to volume growth warranting expanded capacity. But we remain flexible with the ability to scale capital back up quickly as our customers' needs evolve. Last week, the Board of Directors declared a dividend of 93.5 cents 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'll now turn the call over to Kevin for a closer look at our operations. Thank you, Walt. The backdrop we're seeing related to activity and 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 or 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 MGL raw feed throughput volumes and 20% in natural gas processed volumes. Our natural gas pipeline 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 MGL 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 processed in the region have reached 945 million cubic feet per day in July, a nearly 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 are positioned to resume activity as commodity prices and the demand outlook improves. We are 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 sustain, 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 and volumes being flared. The latest data shows 220 million cubic feet per day was still flaring in the basin, with 125 million of that on One Oaks 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 MGL pipeline in September of this year, earlier than our previous target date of the fourth quarter. This new lateral will connect with an expanding third-party plant and will provide MGL takeaway in an area of Williams County which has historically had limited MGL transportation options. We expect the lateral will provide additional MGL volume to our system as we exit 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 percent of proceeds and fee components also vary across our customer contracts. Curtailments on large producer contracts with higher fees and lower POP 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 regions. Given what we see today, with curtailed volumes continuing to return, we expect the average feed rate for the gathering and processing segment to reach pre-COVID levels of approximately 90 cents per MMBTU in the fourth quarter 2020. In the mid-continent region, second quarter average MGL raw feed throughput volumes of 521,000 barrels per day increased compared with the first quarter 2020. and volumes from this region have reached over 600,000 barrels per day in July, a 15% increase compared with the second quarter 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 pet chem 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 barrel per day West Texas LPG pipeline expansion in June position us well for future growth from the basin. With the expansion complete, we will continue to transition volumes away from third-party offloads on to West Texas LPG. We are currently offloading 25,000 barrels per day, which will provide full transportation fractionation revenue when they move onto our system in the future. Terry, that concludes my remarks.

Thank you, Kevin. With the 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 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 One Oak perspective, our management team will continue to be proactive and innovative in how we can become even more efficient. We'll 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 am 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 when 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 SASB 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.

If you would like to ask a question, please signal by pressing star 1 on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. please try to limit yourself to one follow-up question. Again, that is star one to ask a question. And we'll go ahead and take our first question from Jeremy Tomei from J.P. Morgan.

Hey, good morning. This is Charlie. Appreciate all the color in the opening remarks. Just as you noted with your updated guidance reflecting potential dabble headwinds there, curious if it also takes into account the high plains pipe that could be shut.

And also, secondly, I was curious, you know, should a DAPL shutdown commence, can you address the possibility to temporarily repurpose an NGL pipeline to crude service, you know, if that would make sense and kind of what the puts and takes of that would be?

Yeah, Jeremy, this is Kevin. The first question as far as, you know, a DAPL 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 enough other pipeline capacity in rail transportation to handle the volumes that are currently being curtailed. As it relates to the second question, yes, we physically could convert the smaller Bakken MGL pipeline into 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 kind of second half guidance here and trying to parse one half to the second half, how should we kind of think about Rockies and Midtown Well Connects relative to the first half, given the sort of rig count and pricing environment we're in? And then maybe secondly, specific to GMP, what sort of pricing assumptions go into, you know, to point you towards what you gave us on guidance? Maybe put differently, that $30 million decline you saw related to the pop exposure contracts, would you expect that to reverse in the back after this year? Yeah. Yeah, there's a couple questions in there. I'll answer your last one first. I mean, yeah, like we said, we do believe that if we see this environment sustained, we'll see that fee rate improve. And obviously, that's going to help on the top side if you get some pricing strength as well. And what was the first question in that second grouping? It's about well-connected. 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? Yeah, we are seeing, I mean, we, again, the 2020 numbers really aren't dependent on WellConnects as far as new, you know, rigs and things like that. That's more, again, of a 2021, you know, impact. We, again, recent conversations with producers, we are having conversations in this environment about completing ducts, potentially bringing completion crews back. So we don't have, it's not like we've got rig counts going to 40 in the next two months or something. Chuck, do you have anything to add to that?

Yeah, I mean, what I did is, Based on producer discussion, as Kevin mentioned, we see on the drill schedule that are provided by our producers to us. Ducks 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 acres. So, you know, we've got some line of sight to increase Doug's completions as well as increased WellConnect's forthcoming. So I hope that gives you a little more color. Great. Thank you very much.

Once again, that is Star 1 to ask a question. If you find that your question has been answered, you may remove yourself from the queue by pressing Star 2. We'll take our next question from Tristan Richardson with SunTrust.

Good morning, guys.

Just appreciate all your commentary on sort of a new range for EBITDA. I guess just thinking about, you know, higher LPG prices and the volume improvement we've talked about in July, as well as C2 recovery and enhanced well completions. Do these dynamics all 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 Yeah, 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 OPEX situation, You know, those types of volume levels was what supported that, you know, kind of the upper end of that range that we talked about. So as we get the curtailed 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 as the volumes come back, we would expect the flaring numbers to go down. So that's why we have the confidence in those numbers, that that's what gets you to that run rate that we're looking at towards the upper end of the range. Great. And then, Walt, I think we've spoken in the past on the 2021 CapEx opportunity being, you know, just generally lower than 2020 for Now that we're kind of halfway through the year, should we think of the spend opportunity next year as something sub a billion dollars, or is there kind of a bookend way to think about how you're spent? No, 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 is generating growth that we need to expand capacity. As Terry mentioned, we have all the assets in place to get us back to that IDCA level north of $3 billion. And so we're in a great position here where you 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.

We'll take our next question from Shmerick Orsini with UBS.

Hi. Good morning, everyone. Good to hear everyone as well. Just maybe I wanted to just start off with your dividend comments that you made in the prepared remarks. You know, you had mentioned that it could potentially be a lever down the road and so forth. When you sort of think about things, you've got a lot of headwinds, you know, obviously with COVID, potentially with DAPL, which can impact CapEx for the base and for 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. You know, is the $2.6 billion, you know, guidance range for this year enough to maintain the dividend? What levels are you thinking about, you know, would become an area where you would become concerned? Is it a $2.4 billion run rate? You know, how much does S&P re-reviewing your rating matter? Just wondering if you can sort of give us, you know, different paths and different outcomes as to how you're thinking and would be recommending the dividend to the board.

This is Terry. I'll just make a comment and then Walt can follow up. We think about 2021, I think this gets to the core of your question. How do we think about this business going forward? We've looked at a number of scenarios. The key variable, a key variable, of course, is DAPL. What happens? The key question is, is DAPL going to be shut down? Is it going to continue to operate? As we think about that scenario and we think about 2021, even with a DAPL shutdown, we could see mid to high single digit growth and even over what we've experienced or expect in 2020. So in 2021, we could see that mid to high single digit. If we're fortunate and DAPL doesn't become an issue for 2021, we could see 12% to 15% EBITDA growth over what we experienced or expect in 2020. So in both of those scenarios, we don't see a need to have to take a dividend action. And as Walt indicated, capital spending would be a very, very modest $300 million to $400 million range. So given that outlook, certainly we don't think it's appropriate to take any action at this point in time. Walt, anything you can add to that?

No, just to talk about it, we obviously stay in touch with the rating agencies. They saw that the action that we took with the LCD was a proactive step to accelerate the leveraging from what it would have been if we had not done that. We're very focused on that credit rating and pleased to see the strength that we're seeing from the producer activity bringing retail volumes back on and the trend that that's showing us at this point in time.

The only thing I would emphasize, and we've said it a couple of times in our opening remarks, but is this BCF and a half a day, particularly in the Wilson 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 Bakken. 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 a point we can't emphasize enough today.

Well, I really appreciate that. Better answer than I expected. Maybe it's a good way to transition. You know, you've answered this a little bit in the prior questions to some of the questions you've received in the prepared remarks. But when we think about the drivers for a strong second half recovery and as we sort of think about, you know, 21 as you just talked about, If I remember, and I'm dating myself a little bit here back to the 13, 14, 15 cycle, the BACA needed something like 200 rigs. In the most recent cycle, the BACA needed 50 rigs and you could see growth. Do you see that trend on efficiency continuing and that maybe we're zeroing in on the wrong type of rig count for the falcon to be able to generate enough ducks for you to be able to maintain and potentially grow production? You know, could we see something where 30 is really the more normal run rate that can sort of run, you know, a 1.4, 1.5 million barrel type market? Just kind of wondering what you're seeing in terms of thoughts on efficiencies and how things are moving around. Kevin, I'll start. You were a little muddy, so if I don't answer your question, make sure you jump back in here. The reserves have been fantastic in the Bakken. 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 volume 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 that. In that 1.4 to 1.5 type range of BCF a day of volume, you're probably in the 30 to 40 completions per month on our acreage. And we think that's absolutely doable. But we do believe that the quality of the wells will continue to improve.

Kevin, I would add another point.

Go ahead, Chuck.

Another data point I'd add, Schnur, 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 less wells will be needed for the increased deliverability that they're seeing due to those longer laterals. 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 the 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 So as you look at crude oil forecast, then you've got to apply the strengthening gas to oil ratios. And you can see some of the materials we've provided on the presentation that shows what that's done over time. And it's continued to strengthen to where now it's north of 2.2. So that's another factor when you look at the basin of what's going on on the gas side. Don't just focus on what's going on on the crude oil side. That makes perfect sense. We really appreciate the call today, guys. That was very helpful. Thank you.

We'll take our next question from Colton Bean with Tudor Pickering and Colts & Co.

Appreciate the comments there on some of the green shoots of activity and how you might return to those March levels. I think if we look at getting back to the 1.5 DCF day, understandably, reversal of shut-ins is a large component of that. But I think the other key piece that the market is 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 producing over the last couple of months, how those have fared?

Chuck, do you want to go? Yeah, this is Chuck. Could you repeat the last part of your question? I didn't quite hear from the decline on.

Yeah, 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 throughput base and then ultimately growth, I think the base decline has been debated.

So just I'm interested to see if you guys have a view on what a PDP profile might look across your system.

Yeah, so similar to other sales plays, what we see typically or what we run in our models, and you're one, you're 50%, 55% decline rate. Year two, and that's 20% to 25%. Year three, 15%, and then just maintain and step down from there. So your first year, obviously, as you know, is your large decline in a shale place. We run that at the 50%, 55% range.

Okay, and so you all feel comfortable that 30 to 40 completions in one would be sufficient to fully offset that base?

We do.

And on the flaring side of things, I think we've heard from producers that the wells that were flaring were preferentially shut in.

So if you look at that $125 million that's being flared on one of the acres 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?

Yeah, what we've done here in the second quarter to help with the flaring, you won't really see that until third quarter. We expect to see the results here in third quarter relative to our flaring percentages. We've completed some pretty good-sized trunk lines into an area here before that's been very, very limited in being able to get gas egress. So put 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.

We'll take our next question from Michael Blum.

Great. Thanks, everyone. Appreciate it. One question I wanted to ask was just about FAA and recovery. Can you talk about – I'm assuming you're not seeing much increase in the volume, but I really wanted to talk about that and also – to the extent you are seeing increased recoveries in the mid-con, how that's trending, and any way to quantify that.

Thanks. Michael, this is Sheridan. You are correct out of Bakken where ethnic recoveries are not improving out of near the economics at this time. Don't warrant that. But we have, as we mentioned, seen good ethnic recovery increases in the mid-continent. And what I tell you today is that In June and July, the average percentage of ethane in our wide grade 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, is contingent on that. So I think we, as mentioned in our remarks, all the ethane or substantially all the ethane that's in the mid-continent that can come out is coming out at this time. And we do predict that to continue through the rest of the year.

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

Thanks. Michael, this is Chuck. I would say, you know, we answered a similar question in Q1, and at the time, again, with things in flux and trying to forecast, you know, we 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 process Should be forthcoming, just can't tell you when. I would say it is pushed out, you know, probably 12 months anyway. We just need a better line of sight on some longer-term forecasts, but I think an expansion will definitely be needed in time. Great. Thank you so much.

We'll take our next question from Janann Salisbury, Bernstein.

Good morning. Just a follow-up on the Bakken NGL to create conversion potentials. I'm recognizing that it's still in early development, but would this require Overland Pass to convert to crude as well?

We would probably move it into the currency area.

Okay. So it would just be before you hit Overland Pass? 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's really changed from the tax standpoint other than the fact that obviously the rate of our EBITDA is going to be lower than we had expected in 2020. If anything, it's moved out a little bit because the assets that we ultimately will complete in Bear Creek II and MB-5 down the road when growth is back and those are needed, that depreciation will come at a later date and we'll be able to optimize the timing of that. for several years and eventually we will get into a situation where there are some limitations that are currently out there on the utilization of NOLs, but that's still a few years down the road.

Great. That's all for me.

Thank you very much. We'll take our next question from Sunil Sobhavit of Seaport Global Securities.

Yeah, hi, good morning, guys. Can you hear me? Yes, we can hear you. Yeah, so thanks for all the clarity on the call. I just had one follow-up question on the leverage metrics. When the press release yesterday, you indicated the covenant-based leverage tracking at 4.5x. So it seems like to me that there is a fair bit of project EBITDA baked into that based on, you know, projects which did not contribute to EBITDA yet. First, is that correct? And secondly, you know, when you dig 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, you know, how 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 versus LTM, I come up with a higher number. So I was just trying to reconcile that disconnect.

Yeah, okay. Yes. The covenant calculation does not track exactly to GAAP. Under the bank covenant, there is a provision that allows for an EBIT assumption associated with CapEx that's either coming into service or will come into service down the road, and that scales down over a period of time. So there's a There's a mismatch. There always has been a slight mismatch between the GAAP and the covenant calculation. And at this point, the covenant calculation is at four and a half times versus the covenant at five times.

Okay, Goddard, thanks.

We'll take our next question. question from Michael with Goldman Sachs.

Hey, guys. Thank you for taking my question. Can you comment a little bit about what you're seeing in FRAC volumes at Bellevue? And I'm kind of going back a little bit to kind of what the trend is. Could you kind of call that data out a little bit about what you've seen FRAC-wise? And Are you seeing, does not having export capacity, especially given LPG exports have held up relatively strong during this last three or four-month period, does not having a dock capacity or export capacity actually impact you at the frac level, your volumes relative to maybe what you think of what you're seeing in your competitive peers who are in fracs and FW as well? Yeah. Right now, because of the way our system is set up, all our fracks can be a Bellevue frack. So when you look across our system, we have plenty of frack capacity because any of the volume that we frack in the mid-continent with the Sterling system, we can make that volume show up in Mont Bellevue. So right now, as we look forward, we have plenty of frack capacity through 2020 or until we see a much better improvement into producer capacity. productivity that we would need to bring MB5 back on. So we're in pretty good shape on the frac capacity side. In terms of do we need an export to offer, does that impact us on the frac side? It does not at this time. Right now, there's more export capacity than frac capacity, really. And so we are able to contract and have contracted a lot of our volumes in a short period of time to exporters because they need that volume to fulfill their So at this time, we don't see that it's a hindrance not to have a dock. Of course, if we look into the future, that's still something on our list that we would like to look at at a period of time when we see more supply come online that would warrant additional dock capacity. But at this time, we do not see it as a hindrance or as a competitive disadvantage to us. Now, that's super helpful. Can you just talk a little bit about what you think the utilization rate and the quarter was for your tracks and how July is looking for your dock?

Could you repeat that again?

Michael, we're having difficulty hearing you. Guys, could y'all talk a little bit about what you think your crack utilization rate was in the quarter and what you're seeing in July and how people have stepped up? You kind of gave a lot of detail about what July looked like across throughput, across multiple basins, and in gas. I'd love just kind of the same level of detail on the crack side. Right now, we are over 80% on our frac utilization. Now, we've seen a big step up on that because we've brought more ethane on, and that capacity has always been there. But we're sitting a little over 80% of what our frac utilization will be. And so as we continue to grow into the third quarter, and have already seen that volume increase that we talked about in July, we still move up closer to the, maybe closer to the 90%, to 85%, 90%, and still leave us plenty of track capacity. Got it. And then one final one, if I may. Terry, when you and the board kind of evaluate capital allocation, and I know you talked today about not needing to do anything with the dividend, how do you think about the balance between evaluating the dividend versus evaluating the incremental equity issuances if needed. I mean, you kind of have the shelf outstanding for the forward sale agreement. I'm just trying to think about how you and the board think about what's the right kind of source of equity capital if equity capital is needed. There are a couple of different aspects to that. I mean, is it related to due leveraging dividends? 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 where with 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, and the COVID has a defined period of time that it will take to play through. I don't think any of us know exactly what that defined period of time is, but to the extent that it's measured in quarters, we didn't believe that that meant that we should be adjusting our dividend for a quarter or two or more of disruption. So we needed to make a positive step on the leveraging standpoint, and the quickest way to do that was to do the equity offering. And then as we see the strength of the business coming back and that we'll be there to support that dividend in the long term, we've continued to get on that path.

And, Michael, the only thing I'd add to you, Walt's comments is that 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. And certainly that was in the mix in terms of the capital allocation decisions that we were making.

Got it. Thank you, guys. Much appreciated.

Thank you. We'll take our next question from Craig Schiff, Dewey Brothers.

Thanks for taking the questions, and it sounds like a wonderful outlook heading into the second half here. That's great clarity. On potentially repurposing the DOC and NGL pipeline, how long would that take, and would any concurrent upsizing needed on Elk Creek be done in the same timeframe? Very good, Sherrod, and we're still evaluating all of the aspects of that. turning it into crude or if that's warranted or what needs to be done. So we continue to look through that. So as we continue to evaluate that more, we'll have a better understanding of what it takes to convert it to crude. Are we looking at something that could be a couple years? It could be comfortably quicker than that if you had to go that route, if the market needed it. I don't think it's a couple years, but it will take some time. All right, thanks. And, 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 ongoing, until there's a lot more clarity on COVID and, you know, upstream volume, that the annual rate into 21 will be $300 million to $400 million? That's correct. As we finish up 2020, we've got things like the north lateral that have the minimum volume commitment that we're finishing up and wrapping up some of those types of projects. But if we get into 2021, we'll be able to continue to keep that $300 million to $400 million range, including maintenance CapEx, until we see a pickup in volumes that would get us above the level that we had been originally forecasting for 2020. So we've got some significant headroom there, and we can obviously prioritize those cash flows as we grow into it towards our deleveraging goals. Very good. And last question, storage and ethane recovery 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 uplift, 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? Yeah, I think the contango that represented itself in the second quarter, because of how we sold that product out forward, we will see that benefit show up in the second half of the year. And should that be most of the fourth quarter? You'll see that in the ISOM unit as well. Should we see most of that in the fourth quarter? Yeah, you could see some of it in the fourth quarter. I mean, we've sold it throughout the third and fourth quarter. So you could see it through the remainder of the year. A lot's going to happen on the swing in prices through that period of time. But it will be spread through the second half of the year, or I can think of short term.

Great, thank you.

We'll take our final question from Derek Walker with America.

Thank you, guys, for choosing me in here.

Maybe just a couple of clarification questions if I heard it right in your earlier portion referencing kind of the DAPL impact. I believe it was referenced that if there's extended shutdown, it would be sort of a kind of mid-to-single EBITDA growth year-over-year, and one check down would be 12% to 15% kind of year-over-year EBITDA growth rate. And is that also the $2.6 billion number for 2020, just want to make sure I heard that right?

That's correct. That's what he's basing it. Those percentages that I provided earlier are based upon the low end of the range that we provided for 2020. You base it off of that.

Okay, perfect.

And then I think in your formal remarks, you have to reference some cost efficiencies, whether it's coming from a variety of angles. I think there's optimization to power saving. If you capture $50 million in the first half of the year, you talk about $120 as relative to your 2020 plan. Like I said, if you start to see things recover in the second half, do you feel most of that cost savings is sustainable, or do you see some of that coming back? Yeah, this is Kevin. Yeah, we absolutely believe those cost savings are attainable. I mean, as we move through the year and, you know, 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 go implement, and we've been doing that. So we do believe even with, you know, the volume – volume strengthening that will realize those savings in the back half of the year.

Got it. Thank you very much.

Appreciate your time, guys. That concludes today's question and answer session. Mr. Zagala, I'd like to turn the conference back to you.

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.

This concludes today's call. Thank you for your participation. You may now disconnect.