Good day, welcome to the second quarter 2021 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. 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 bbl per day of crude were leaving the basin on rail.
Specific to ONEOK, we estimate 30%-40% of DAPL crude oil volume is from the producers whose gas volumes are dedicated to our gathering and processing business in the Williston Basin. About half of those volumes have alternate methods of crude transportation currently available. This means that approximately 200 million cubic feet per day of 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 de-leveraging 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. 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 de-leveraging goals. We still intend to manage our leverage below four times as business strengthens to pre-COVID-19 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 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 one-time 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 de-leveraging. We also expect total capital expenditures, including maintenance capital, to range from approximately $300 million-$400 million in the second half of 2020. Total annual capital expenditures, including maintenance and growth, of $300 million-$400 million will be maintained until producer activity levels provide visibility to volume growth warranting expanded capacity. 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, ONEOK 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. Let's take a closer look at current activity across our operations. In the Rockies region, we've seen a sharp increase in volumes in July, as Terry mentioned. Total NGL raw feed throughput volume from the region has reached more than 200,000 bbl 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. 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 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. 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. It includes a minimum volume commitment. During the second quarter, curtailments varied greatly across our producers.
Some curtailed nearly 100% of their production. 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 rates. 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 of 2020.
In the Mid-Continent region, second quarter average NGL raw feed throughput volumes of 521,000 bbl per day increased compared with the first quarter 2020, and volumes from this region have reached over 600,000 bbl per day in July, a 15% increase compared with the second quarter 2020 average. Ethane volumes in the Mid-Continent averaged 260,000 bbl per day in June 2020 compared with the second quarter 2020 average of 210,000 bbl per day. A more than 20% increase driven by nearly all our Mid-Continent plant connections entering recovery during the quarter. We expect ethane recovery on our system to continue through the remainder of the year due to strong petchem demand and favorable ethane extraction economics.
In the Permian Basin, the connection of two new third-party processing plants in the first half of 2020 and the full completion of our 80,000 barrel per day West Texas LPG pipeline expansion in June position us well for future growth in the basin. With the expansion complete, we will continue to transition volumes away from third-party offloads onto West Texas LPG. We are currently offloading 25,000 bbl per day, which will provide full transportation and fractionation revenue when they move onto our system in the future. Terry, that concludes my remarks.
Thank you, Kevin. With a challenging quarter behind us, there are opportunities ahead. What we've seen proven time and time again is that producers in the midstream industry are resilient, innovative, and able to find solutions when market conditions are tough. We saw it in 2015 and 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'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 one 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. We'll go ahead and take our first question from Jeremy Tonet 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 DAPL headwinds there, curious if it also takes into account the High Plains pipe that could be shut? 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?
Yeah, Jeremy, it's 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 and 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 NGL Pipeline into crude service. We're evaluating that and looking at all of our options and watching that closely. Yes, that is something that's physically possible.
Okay. Thank you. Looking at kind of the second half guidance here and trying to parse one half to the second half, how should we kind of think about Rockies and Mid-Con well connects in relative to the first half, given the sort of rig count and pricing environment we're in? Maybe secondly, specific to G&P, what sort of pricing assumptions go into 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 half of this year?
Yeah, there's a couple questions in there. I'll answer your last one first. Yeah, like we said, we do believe that if we see this environment sustain, we'll see that fee rate improve. Obviously, that's going to help on the POP side if you get some pricing strength as well. What was your first question in that second grouping again?
Just about well connects in the second half relative to what we saw in the first half, just given what we're seeing on the rig count side and the pricing environment.
Yeah. 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. Again, recent conversations with producers, they're having conversations in this environment about completing DUCs, potentially bringing completion crews back. 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. What I'd add, Kevin, is based on producer discussions, as Kevin mentioned, and 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. What producers have told us is they want to complete these wells before winter in anticipation of more demand. In addition to that, some of our larger producers have indicated to us that they're going to run one to two rig programs
Through the remainder of the year on our acreage. We've got some line of sight to increase DUC completions as well as increased well connects forthcoming. Hope that gives you a little more color.
Great. Thank you very much.
Once again, that is star one to ask a question. If you find that your question has been answered, you may remove yourself from the queue by pressing star two. We'll take our next question from Tristan Richardson with SunTrust.
Hey, good morning, guys. Just appreciate all your commentary on sort of the new range for EBITDA. I guess just thinking about higher LPG prices and the volume improvement you talked about in July, as well as C2 recovery, and enhanced well completions. Do these dynamics help add up to really support a run rate EBITDA as we look towards the end of this year, somewhere much closer to the high end of that range of outcomes you provided last quarter, namely the $3 billion type of EBITDA range?
Yeah, this is Kevin again. 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 is what supported that kind of the upper end of that range that we talked about. 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. 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. Walt, I think you've spoken in the past on the 2021 CapEx opportunity being just generally lower than 2020. 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 a kind of a bookend way to think about out year spend?
No, I just said in my prepared remarks that we would be in that $300 million- $400 million range for 2021, including maintenance and growth, 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 EBITDA level north of $3 billion. We're in a great position here where we don't have to jump on the CapEx level until producer activity warrants that for growth.
I appreciate it. Sorry, I missed that figure. Thank you guys very much.
Thank you.
We'll take our next question from Shneur Gershuni with UBS.
Hi, good morning, everyone. Good day, everyone, as well. Just maybe I wanted to just start off with your dividend comments that you made in the prepared remarks. 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, obviously with COVID, potentially with 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 re-reviewing your rating matter?
Just wondering if you can sort of give us different paths and different outcomes as to how you're thinking and would be recommending the dividend to the board?
Shneur, this is Terry. 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? We've looked at a number of scenarios and the key variable, a key variable, of course, is DAPL. What happens? The key question. 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, that even with a DAPL shutdown, we could see mid to high single digit growth in EBITDA over what we've experienced or expect in 2020. 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%-15% EBITDA growth over what we experienced or expect in 2020. In both of those scenarios, we don't see a need to have to take a dividend action. As Walt indicated, capital spending would be very modest, $300 million-$400 million range. Given that outlook, certainly we don't think it's appropriate to take any action at this point in time. Walt, anything you could add to that?
No, just to top off. 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 de-leveraging from what it would've 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 curtailed volumes back on and the trend that that's showing us at this point in time.
I think that's it. Shneur, the only thing I would emphasize, and we said it a couple of times in our opening remarks, but is this BCF and a half a day, particularly in the Williston Basin. That deliverability is connected to our system and doesn't really depend on a whole bunch of rigs coming back into the basin. As we think about 2021, our growth, that is our throughput growth on our G&P business, is a function of capturing and accelerating that capture of that BCF and a half a day. 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, really appreciate that. A better answer than I expected. Maybe it's a good way to transition. You answered this a little bit in the prior questions to some of the questions you've received in your prepared remarks. When we think about the drivers for a strong second half recovery, and as we sort of think about 2021 as you just talked about. If I remember, and I'm dating myself a little bit here, back to the 2013, 2014, 2015 cycle, Bakken needed something in the neighborhood of like 200 rigs. In the most recent cycle, the Bakken 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 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, 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 were a little muddy. I'll make sure if I don't answer your question, make sure you jump by [inaudible] here. Yeah, 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. They continually have shown they can deliver more volume with less capital, is what that ultimately goes to. 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 1.4-1.5 type range of BCF a day of volume. You're probably in the 30-40 completions per month on our acreage, and we think that's absolutely doable.
That we do believe the quality of the wells will continue to improve.
Kevin, I would add another data point to that.
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, the past six months or so, I wouldn't say experimenting, but working with longer laterals, as long as 3 mi . 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. To the 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.
Sure, 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. As you look at crude oil forecast, then you've got to apply the strengthening gas to oil ratios. 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. That's another factor when you look at the basin of what's going on the gas side, don't just focus on what's going on the crude oil side.
That makes perfect sense. Really appreciate the call today, guys. That was very helpful. Thank you.
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 marks 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. I think the other key piece that the market's struggling with is what base declines look like. 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 take that?
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. Just under, interested to see if you guys have a view on what a PDP profile might look across your system.
Similar to other shale plays, but we see typically, or what we run in our models, in year one, your 50%, 55% decline rate. Year two, that's 20%-25%. Year three, 15%. Just maintain and step down from there. Your first year is your, obviously as you know, is your largest decline in a shale play. We run that at 50%, 55% range.
Okay. You all feel comfortable that 30-40 completions a month would be sufficient to fully offset that base?
We do.
On the flaring side of things, I think we've heard from producers that the wells that were flaring were preferentially shut in. 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? 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. What we expect to see that the results here in third quarter relative to our flaring percentages, is we've completed some pretty good sized trunk lines into an area, here at Fort it's been very limited in being able to get gas egress. 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. 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 with Wells Fargo Securities.
Great. Thanks, everyone. Appreciate it. One question I wanted to ask was just about ethane recovery. Can you talk about I'm assuming you're not seeing much increase in the Bakken, but 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 ethane recoveries are not improving out of there. The economics at this time don't warrant that. We have, as we mentioned, seen good ethane recovery increases in the Mid-Continent. What I'd tell you today is that in June and July, the average percentage of ethane in our y- grade, it's 45%. We are up over 60,000 bbl 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. 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. We do predict that to continue through the rest of the year.
Great. Then a somewhat related question. There's 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 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 is kind of shelved here for a while till Bakken levels recover? Thanks.
Michael, this is Chuck. I would say, we answered a similar question in Q1. 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 forecasts, I think an expansion will definitely be needed in time.
Great. Thank you so much.
We'll take our next question from Jean Ann Salisbury, Bernstein.
Good morning. Just a follow-up on the Bakken NGL to crude conversion potential. Recognizing that it's still in early development, would this require Overland Pass to convert to crude as well?
Be able to move crude down the Bakken pipeline is physically possible. We would probably move it into the Cushing area.
Okay. It would just be before you hit Overland Pass.
Yes.
Great. Thank you. Just a quick one. What's the latest estimate of when you would be a federal cash taxpayer?
Nothing's really changed from a 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 Belvieu two 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 just optimize the timing of that. We don't expect to be a meaningful taxpayer yet still for several years. 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 Sibal with Seaport Global Securities.
Yeah. Hi. Good morning, guys. Can you hear me?
Yes, we can hear you.
Yeah. Thanks for all the clarity on the call. I just had one follow-up question on the leverage metrics. In the press release yesterday, you had indicated the covenant-based leverage 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? 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? How frequent is that expectation kind of revised? Thanks.
Could you repeat the first part of your question, please?
In the press release, you had indicated that the covenant-based leverage was tracking at 4.5x. When I look at your debt balances versus LTM EBITDA, I come up with a higher number. I was just trying to reconcile that disconnect.
Yeah. Okay. Yeah. The covenant calculation does not track exactly to GAAP. Under the bank covenant, there is a provision that allows for an EBITDA assumption associated with CapEx that either come into service or will come into service down the road, and that scales down over a period of time. There's a mismatch. There always has been a slight mismatch between the GAAP and the covenant calculation. At this point, the covenant calculation is at 4.5 times versus the covenant at five times.
Okay, got it. Thanks.
Okay, bye.
We'll take our next question from Michael Lapides 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 Belvieu? 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're seeing frac-wise? Does not having export capacity, especially given LPG exports have kind of 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 or what you're seeing your competitive peers who are in fracs in FLB as well?
We, right now, because of the way our system is set up, all our fracs can be a Belvieu frac. 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. Right now, as we look forward, we have plenty of frac capacity through 2020 or until we see a much better improvement into producer productivity that we would need to bring MB-5 back on. We're in pretty good shape on the frac capacity side. In terms of do we need an export dock or 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.
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 commitments across the dock. At this time, we don't see that it's a hindrance not to have those docks. 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. 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?
Yeah.
Michael, we're having difficulty hearing you.
Okay, 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 and how big of a step up? You gave a lot of detail about what July looked like across throughput, across multiple basins, and in gas. I'd love just 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've brought more ethane on, and that capacity has always been there. We're sitting a little over 80% of what our frac utilization will be. As we continue to grow into the third quarter, as we have already seen that volume increase that we talked about in July, we still move up maybe closer to the 90%, the 85%-90%, but still leaves us plenty of frac capacity.
Got it. One final one if I may. Terry, when you and the board 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? You 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 source of equity capital, if equity capital's needed.
Yeah, Michael, there are a couple of different aspects to that. As it related to de-leveraging, any dividend action that would've been considered from a de-leveraging standpoint would've taken quite a bit of time to actually have an impact. Where with the equity offering, there was an immediate impact from a credit standpoint. The other side of that also as well is that, as we see the business going forward, and that 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. 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.
We needed to make a positive step on the de-leveraging standpoint, and the quickest way to do that was to do the equity offering. 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 go down that path.
Michael, the only thing I'd add to 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. It remains a high priority. Certainly that was in the mix in terms of the capital allocation decisions that we were making.
Got it. Thank you, guys. Much appreciated.
Yeah. Thank you.
We'll take our next question from Craig Shere, Tuohy Brothers .
Thanks for taking the questions. 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? Would any concurrent upsizing needed on Elk Creek be done in the same timeframe?
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. We continue to look through that. As we continue to evaluate that more, we'll have a better understanding of what it takes to convert to crude.
Are we looking at something that could be a couple of years or could it be comfortably quicker than that if you had to go that route, if the market needed it?
Oh, I don't think it's a couple of years, but it will take some time.
All right. Thanks. Walt, I apologize, I guess I'm a little confused about the CapEx guidance. I thought I read the second half will be an absolute $300 million-$400 million. Then do I understand that ongoing, until there's a lot of more clarity on COVID and upstream volume, that the annual rate into 2021 will be $300 million-$400 million?
That's correct, Craig. You got that piece. As we finish up 2020, we've got things like the North Water lateral, which has the minimum volume commitment that we're finishing up, and wrapping up some of those types of projects. As we get into 2021, we'll be able to continue to keep that $300 million-$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. We've got some significant headroom that's there, and we can obviously prioritize those cash flows as we grow into it towards our de-leveraging goals.
Very good. Last question. Storage and ethane recovery were 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?
I think the contango that represented itself or presented 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.
Should that mostly all be in the fourth?
You'll see that not only in storage, 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. We've sold it throughout the third and fourth quarter. 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. It will be spread through the second half of the year if you think of storage as well.
Great, thank you.
We'll take our final question from Derek Walker with Bank of America.
Thank you, guys. Appreciate you squeezing me in here. Maybe just a couple clarification questions. If I heard right earlier in the Q&A portion, referencing kind of a DAPL impact. I believe you referenced if there's extended shutdown, it would be sort of a mid to single EBITDA growth year-over-year. If it wasn't shut down, it would be 12%-15% kind of year-over-year. That was an EBITDA growth rate. Would that also be the $2.6 billion number for 2020? Just want to make sure I heard that right.
That's correct. That's what you base it.
Okay.
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. I think in your formal remarks, you also referenced some cost efficiencies, whether it's coming from a variety of angles, whether it's optimization. Power savings, if you capture $50 million in the first half of the year, then you talk about $120, I think, relative to your 2020 plan. I guess, as 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. We absolutely believe those cost savings are attainable. As we move through the year, our team has done a fantastic job with finding opportunities. Some of those opportunities, you identify them, but it takes a little bit of time to actually go implement them. We've been doing that. We do believe, even with the volume strengthening, that we'll realize those savings in the back half of the year.
Got it. Thank you very much. Appreciate the time, guys.
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.