歐尼克 (OKE) 2020 Q2 法說會逐字稿

Good day, and welcome to the Second Quarter 2020 ONEOK Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you, Sarah, and good morning, everyone, and welcome to ONEOK'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 ONEOK's 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 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.

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 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 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 NGL 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 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, 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 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 dividend, with our business improving and volume strengthening, we don't see the need to take action on the dividend. 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 2 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 the proceeds -- 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 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. 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 onetime impact to 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 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. 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 $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'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 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 the 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 processed in the region have reached 945 million cubic feet per day in July and 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 totaled 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 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 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 lateral will connect with an expanding third-party plant and will provide NGL takeaway in an area of Williams County, which has historically had limited NGL transportation options. We expect the lateral will provide additional NGL 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 fee 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 region. Given what we see today, with curtailed volumes continuing to return, we expect the average fee rate for the gathering and processing segment to reach pre-COVID levels of approximately $0.90 per MMBtu in the fourth quarter 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 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 2 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 and fractionation revenue when they move on to 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 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 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 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.

(Operator Instructions) And we'll go ahead and take our first question from Jeremy Tonet from JPMorgan.

This is Charlie. I appreciate all the color in the opening remarks. Just as you noted with your updated guidance reflecting potential DAPL headwinds there, curious if it also takes into account the high plains pipe that could be shut? And also secondly, I was curious, should a DAPL 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 (sic) [Charlie], this is Kevin. The first question, as far as 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. And as it relates to the second question, yes, we physically could convert the smaller Bakken NGL Pipeline into crude service. We're evaluating that and looking at all of our options and watching that closely. And -- but yes, that is something that's physically possible.

Okay. And then looking at kind of at second half guidance here and trying to parse one half to the second half, how should we kind of think about Rockies and Mid-Con 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 G&P, what sort of pricing assumptions go into -- to point you towards what you gave us on guidance? Maybe you 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?

Yes. There's a couple of questions in there. I'll answer your last one first. I mean, yes, we -- like we said, we do believe that if we see this environment sustain, you'll see that, that fee rate improve. And obviously, that's going to help on the POP side if you get price -- some pricing strength as well. And what was the first -- your 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 price environment.

Yes. We are seeing -- I mean we -- again, the 2020 numbers really aren't dependent on well connects as far as new rigs and things like that. That's more, again, of a 2021 impact. We -- again, recent conversations with producers, we are -- they are having conversations in this environment about completing DUCs, potentially bringing completion crews back. So we don't have -- it's not like we've got rig counts go into 40 in the next 2 months or something.

Chuck, do you have anything to add to that?

Yes. I mean, what I had to tell you is based on producer discussions, as Kevin mentioned, what we see on the drill schedules that are provided by our producers to us, 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 1 to 2 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 little more color.

(Operator Instructions) We'll take our next question from Tristan Richardson with SunTrust.

Just appreciate all your commentary on sort of the new range for EBITDA. But I guess just thinking about higher LPG prices and the volume improvement you've talked about in July as well as C2 recovery and enhanced well completions. Does 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 outcome you provided last quarter, namely the $3 billion type of EBITDA range?

Yes. 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 was what supported that 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. As -- since that time, we 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. And that's what gets you to that run rate that we're looking at towards the upper end of the range.

Great. And then what -- I think you've spoken in the past on the 2021 CapEx opportunity being just generally lower than 2020 or kind of halfway through the year, should we think of the spend opportunity next year is something sub $1 billion? Or is there kind of a bookend way to think about how's your spend?

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 -- until 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 EBITDA level 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.

We'll take our next question from Shneur Gershuni with UBS.

Just maybe I wanted to just start off with the -- with your dividend comment that you made in the prepared remarks. You had mentioned that it could potentially be a lever down the road and so forth. When we sort of think about things, you've got a lot of headwinds, obviously, the COVID, potentially the DAPL, which can impact CapEx for the basin 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? Is 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? Is it a $2.4 billion run rate? How much does S&P rereviewing your rating matter? Just wondering if you could 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. So I'll just make a comment and then Walt can follow up. As we think about 2021, I think this gets to the core of your question is how do we think about this business going forward? And we've looked at a number of scenarios, and the key variable -- a key variable, of course, is DAPL, what happens is the key question. So is DAPL going to be shut down? Or is it going to continue to operate? As we think about that scenario and we think about 2021, and even with the DAPL shutdown, we could see mid-to-high single-digit growth in EBITDA over what we've experienced in '20 -- 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 to add to that?

No. Just to top up, we obviously stay in touch with the rating agencies. They saw that the action that we took with the equity was a proactive step to accelerate deleveraging from what it would have been if we had not done that, and we're very focused on that credit rating. And -- but we're pleased to see the strength that we're seeing in the -- from the producer activity, bringing curtailed volumes back on and the trend that that's showing us at this point in time.

I think that -- Shneur, the only thing I would -- Shneur, the only thing I would emphasize, and we said it a couple of times in our opening remarks that if this 1.5 Bcf 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, the -- our growth, that is our throughput growth on our G&P business is a function of capturing and accelerating that capture of that 1.5 Bcf 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 1.5 Bcf a day of deliverability that's already there. That's a point we can't emphasize enough today.

Well, I really appreciate that. A better answer than I expected. Maybe it's a good way to transition. 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 '21, as you just talked about, if I remember, and I'm dating myself a little bit here back at the 13, 14, 15 cycle Bakken you did something in the neighborhood of like 200 rigs. In the most recent cycle, the Bakken you did 50 rigs, and we 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 Bakken to be able to generate enough DUCs for you to be able to maintain and potentially grow production? Could we see something where 30 is really the more normal run rate that can sort of run a 1.4 million, 1.5 million barrel type market. Just kind of wondering on what you're seeing in terms of thoughts on efficiencies and how things are moving around?

Shneur, this is Kevin. I'll start. You're a little muddy. And so make sure -- if I don't answer your question, make sure you jump back in here. Yes, I mean, we continue to -- 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 had 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 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. And -- but we do believe the quality of the wells will continue to improve.

Kevin, I would add another data point.

Go ahead, Chuck.

Another data point I'd add, Shneur, is we work closely with all of our producers, and a couple of them have been in the past 6 months or so, I wouldn't say experimenting, but working with longer laterals as long as 3 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 the 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 a much longer laterals now.

And Shneur, 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 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 that -- 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.

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

Appreciate the comments there around some of the green shoots of activity and how you might return to those marked levels. I think as we look at getting back to the 1.5 Bcf a 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. And so can you update us on how the wells that you have still connected to your system producing over the last couple of months, how those have fared?

Chuck, do you want to take that?

Yes. This is Chuck. Could you repeat the last part of your question, I didn't quite hear, decline -- 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 throughput rates and then ultimately growth. I think the base decline has been debated. So just on there, interested to see if you guys have a view on what a TGP profile might look across your system?

Yes. So similar to other shale plays, what we see typically or what we run in our models in year 1, 50%, 55% decline rate; year 2, in the 20% to 25%; year 3, 15% and then just maintain and step down from there. So your first year is, obviously, as you know, is your large decline in a shale play. So we run that at 50%, 55% range.

Okay. And so you all feel comfortable that 30 to 40 completions in 1 could be sufficient to fully offset that base?

We do.

And then on the flaring side of things, I think we've heard from producers that the wells that we're flaring were preferentially shut-in. So if you look at that 125 million that's being flared on ONEOK 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?

Yes. What we've done here in the second quarter to help with the flaring, you won't really see that until third -- we expect to see that -- 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 here for it's been very, very limited and 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 we're getting ready to come on. So some of our infrastructure, obviously, is going to help on that 125 million a day.

We'll take our next question from Michael Blum.

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 Bakken, but I really want 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?

Michael, this is Sheridan. You are correct out of Bakken, where any recoveries are not improving out of 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 our y-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 has continued 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. There have been a lot of discussion about the gas dynamics in the Bakken given the Btu issues. Obviously -- that's obviously changed a bit. But just curious of 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's kind of shelved here for a while until Bakken levels recover?

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

We'll take our next question from Jean Ann Salisbury of Bernstein.

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?

(technical difficulty) be able to move (technical difficulty) the Bakken pipeline physically possible. We would probably move it into the (inaudible) area.

Okay. So it just would be before you hit (inaudible)?

Yes.

Great. 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. So if anything, it's moved out a little bit because the assets that we ultimately will complete in Bear Creek 2 and MB-5 down the road when growth is back and those are needed, will mean that, that depreciation will come at a later date, and we'll be able to just optimize the timing of that. So we don't expect to be a meaningful taxpayer yet still for several years. And eventually, we'll get into a situation where there are some limitations that are currently out there on the utilization of NOLs, but it's still a few years down the road.

We'll take our next question from Sunil Sibal with Seaport Global Securities.

Can you hear me?

Yes, yes. Yes, we can hear you.

I just had one follow-up question on the leverage metrics. In the press release yesterday, you had indicated a covenant-based deleverage tracking at 4.5x. It seems like to me that there is a fair bit of project 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 how frequent is that expectation kind of revised?

Could you repeat the first part of your question, please?

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, we're -- which is LTM EBITDA, I come up with a higher number. So I was just trying to reconcile that disconnect?

Yes. Okay. Yes. So in -- the covenant calculation does not track exactly to GAAP. Under the bank's covenant, there is a provision that allows for an EBITDA assumption associated with CapEx that's come into -- either come into service or will come into service down the road and that scales down over a period of time. And so 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 4.5x versus the covenant at 5x.

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

Can you comment a little bit about what you're seeing in frac volumes at Belvieu? And I'm kind of going back a little bit to kind of what's the trend, could you kind of call that data out a little bit about what you're seeing frac-wise? And are you saying that not having export capacity, especially given LPG exports have kind of held up relatively strong during the last 3- or 4-month period, that not having a dock capacity or export capacity actually impact you at the frac level, your volumes relative to maybe what you think or what you're seeing your competitive peers around fracs and at Belvieu as well?

We -- right now, because of the way our system is set up, all our fracs can be a Belvieu frac. So when you look across our system, we have plenty of frac capacity because any of the volume that we frac in the Mid-Continent with the Sterling system, we can make that volume show up in Mont Belvieu. So right now, as we look forward, we have plenty of frac capacity through 2020 or until we see a much better improvement into a producer productivity that we would need to bring MB-5 back on. So we're in pretty good shape on the frac capacity side. In terms of do we need an export 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 volumes in a short period of time to exporters because they need that volume to fulfill their commitments across the dock. So at this time, we don't see that it's a hindrance not to have the dock. Of course, as we look into the future, that's still something on our list that we would like to look 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.

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

Could you repeat that again?

Yes. Could you just talk…

Michael, we are having difficulty hearing you.

Guys, could you all talk a little bit about what you think your frac utilization rate was in the quarter? And what you're seeing in July? I mean, help me with the step up. You kind of gave a lot of detail about what July looked like across setup, throughput across multiple basins and in gas. I'd love just kind of the same level of detail on the frac side.

Right now, we are over 80% on our frac utilization. We've seen a big step-up on that because we brought more ethane on, and that doesn't -- that capacity has always been there. But we're sitting about 80% -- a little over 80% of our frac utilization will be. And so as we continue to grow into the third quarter, as we see it, have already seen that volume increase that we talked about in July. We still move up closer to the -- maybe closer to the 90% -- 85%, 90% and still leaves us plenty of frac capacity.

Got it. And then one final one, if I may. Terry, will you and the Board kind of evaluate capital allocation? 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 like -- kind of source of equity capital if equity capital is needed?

Yes, Mike, there are a couple of different aspects to that. I mean, is it related to deleveraging, any dividend action that would when considered from a deleveraging standpoint, would have taken quite a bit of time to actually have an impact here 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 that the COVID is a -- has a defined period of time that it will take the play through, and if there is anybody who knows exactly what that defined period of time is, that to the extent that it's measured in quarters, we didn't believe that it got meant that we should be adjusting our dividend for a quarter or 2 or more of disruptions. So we needed to make a positive step on the deleveraging 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, it will 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 Walt's comment is that from a priority standpoint, maintaining 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.

We'll take our next question from Craig Shere, Tuohy Brothers.

It sounds like a wonderful outlook heading into the second half here. That's great clarity. On potentially repurposing the Bakken NGL Pipeline, how long would that take? And would any concurrent upsizing needed on Elk Creek be done in the same time frame?

Craig, this is Sheridan. We're still evaluating all 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 through.

Are we looking at something that could be a couple of years? Or could it 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 of years, but it will take some time.

All right. And, well, 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 of -- more clarity on COVID and upstream volume that the annual rate into '21 will be $300 million to $400 million?

That's correct, Craig. Yes. As we finish up 2020, we've got things like the north laterals that has the minimum volume commitments that we're finishing up and wrapping up some of those types of projects. But as we get into 2021, we'll be able to continue to keep that $300 million to $400 million range, including maintenance CapEx. And obviously a pickup in volumes would get us above the level that we had been originally forecasting for 2020. So we've got some significant headroom with there, and we can obviously prioritize those cash flows as we go in towards our deleveraging goals.

Very good. And last question on storage and ethane recovery was spoken up 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?

Yes. I think the contango that represented itself or presented 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.

And should that be mostly in the fourth quarter or…

It is not only in fourth quarter you'll see that in the IFM unit as well.

Should we see most of that in the fourth quarter?

Yes, 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 what's going to happen on the swinging prices through that period of time, but it will be spread through the second half of the year, our contango storage flow.

We'll take our final question from Derek Walker with [Bank of] America.

Maybe just a couple of clarification questions. If I heard it right in your -- earlier in the Q&A portion, referencing kind of a DAPL impact. I believe we referenced that due to the extended shutdown, it would be sort of a kind of mid-to-single EBITDA growth year-over-year. And if it won't shutdown, it 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 you base. 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 the formal remarks, you also referenced some cost efficiencies. Was it coming from a variety of angles such as optimization to power saving. If you capture $50 million in the first half of the year and we talk about $120 million I think relative to your 2020 plan. I guess as we start to see things recover in the second half, we feel most of that cost savings is sustainable or do you see some of that coming back?

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

That concludes today's question-and-answer session. Mr. Ziola, I'd like to turn the conference back to you.

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.

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