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ONEOK Inc
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Thank you for standing by. Good day and welcome to the First Quarter 2020 ONEOK Earnings Call. Today's conference is being recorded.
At this time, I would like to turn the conference over to Andrew Ziola. Please go ahead sir.
Thank you, Paula and good morning everyone, and welcome to ONEOK's First 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’d limit yourself to one question.
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. And as always, we appreciate your continued trust and investment in ONEOK.
Joining me on today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs and Kevin Burdick, Executive Vice President and Chief Operating Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President Natural Gas Liquids; and Chuck Kelley, Senior Vice President Natural Gas.
On behalf of ONEOK, we hope you, your families and your colleagues are healthy as we all navigate and cope with the uncertainties surrounding the COVID-19 pandemic. As an essential critical infrastructure business, our employees continue daily work. We remain focused on operating safely and responsibly and on providing the essential services that our communities and customers rely on us for. We've asked all employees to work from home who are able and we've increased safety protocols for those critical employees continuing to work on site.
We've offered additional support to employees through temporary benefit adjustments and human resources programs and are prioritizing open communication with employees, our Board of Directors and the financial community related to our COVID-19 response efforts. The current environment and worldwide impacts of this pandemic are clearly unprecedented. But as you know, COVID-19 is not the only challenge facing the energy industry right now. The commodity price collapse and resulting recent pullback in crude oil production across the country is greatly impacting our industry.
As described in the earnings release, we did not provide what one would call a traditional guidance update, but we did provide a range of possible outcomes for 2020. Providing specific volume and commodity price guidance would not be appropriate for us due to the number of potential variations of outcomes that are possible for price forecasts, curtailment quantities and the duration and pace of economic recovery on a worldwide basis among other factors.
That said, we have performed a scenario analysis and based on currently available information, we believe the range of possible 2020 adjusted EBITDA results will likely be between $2.6 billion and $3.0 billion. While this wide range indicates potential challenges, it also has opportunity and as we are well positioned to realize earnings growth in 2020 and 2021 as NGL markets remain resilient and storage capacity is at a premium despite the challenges our industry faces.
Now, I'd like to comment on the recent dividend announcement, which we prudently held flat at $0.935 per share for the quarter. As we look to the future, we expect our business to generate sufficient cash flow to pay the dividend. Our decision to significantly reduce capital spending until growth opportunities return puts us in a good position to continue returning value to our shareholders.
As we always do, each quarter we'll work with our Board to assess our forward views of future cash flows and the dividend as appropriate. We've been through cycles before and we have a long track record of delivering on expected results. And most importantly, the fundamentals of our business have not changed. Our strong balance sheet and liquidity provide important financial flexibility. Our extensive and integrated assets including available storage in key market centers are competitively well positioned.
Our fee-for-service business model mitigates our direct commodity exposure, including the stability of our natural gas pipelines business, which has nearly 100% take-or-pay contract structures with primarily financially strong, electric and utility customers.
Our customers are some of the most resilient and well capitalized in the industry with decades of proven reserves. And the demand for NGLs in the U.S. and abroad remains and there are signs that international demand is beginning to recover.
All these factors provide the foundation for a resilient business that we believe is built to weather these kinds of uncertain market conditions and provide a platform to resume growth when it makes sense.
The natural gas and NGL reserves in the basins served by our systems haven't moved. The reserves are still there and we believe our ability to serve them is stronger than ever. Many of our capital growth projects have recently come online or are nearing completion.
These projects have driven volume growth across our businesses including reducing the amount of flaring in the Williston Basin as we expected up until the pandemic. And as we have done in previous commodity cycles, we're able to adjust the scale and timing of our growth projects to best fit the needs of our customers.
We made proactive adjustments early on in this cycle to better align our capital investments with our customers' needs and we will continue to be flexible and responsive to those needs as our view of the market evolves. Kevin will provide more detail on these projects in a moment.
As history shows, how you react in markets like this will have lasting impacts for quarters and years to come. Swift financial and operational decisions made at ONEOK in 2015 and 2016, while difficult at the time, set us up well for a transformational period of growth over the past few years. We're now in a great position with available integrated capacity across our system once market conditions improve.
With that, I will turn the call over to Walt.
Thank you, Terry. I'll start with some brief comments on our first quarter financial performance, our liquidity and then our capital allocation strategy as we move forward.
ONEOK reported a net loss of $142 million in the first quarter of 2020, which includes a non-cash impairment charge of $642 million or $1.17 per share. Excluding these non-cash impairment charges, ONEOK's EPS was $0.83 per share for the first quarter.
First quarter adjusted EBITDA totaled $701 million, a 10% increase compared with the first quarter of 2019. Natural gas liquids and natural gas volume growth, higher average fee rates and higher contracted natural gas, transportation capacity, all contributed to year-over-year earnings growth.
Distributable cash flow for the quarter -- for the first quarter 2020 was $522 million, up 7% compared with the fourth quarter of 2019. And we reported healthy dividend coverage of 1.35 times. We also generated $136 million of distributable cash flow in excess of dividends paid during the quarter.
Earlier this month, the Board of Directors declared a dividend of $0.935 or $3.74 per share on an annualized basis. We recorded impairment charges in the first quarter of 2020 related primarily to long-lived assets and goodwill in the natural gas gathering and processing segment.
Our asset impairments charges related to gathering and processing assets in Western Oklahoma, Kansas and the Powder River Basin. The timing of these charges was triggered by significant adverse changes in the market environment during the first quarter.
From a liquidity standpoint, in early March, we completed a $1.75 billion senior notes offering and used a portion of the proceeds to repay amounts outstanding under our commercial paper program, providing us increased liquidity and balance sheet flexibility during this uncertain market environment.
Our March 31 net debt-to-EBITDA on an annualized run rate basis was 4.86 times, and we ended the first quarter with no borrowings outstanding on our $2.5 billion credit facility and more than $530 million of cash. We are still targeting leverage of four times or less, but due to the current environment the time line for reaching target leverage from operating cash flows has been pushed out.
As Terry mentioned, with yesterday's earnings announcement we provided a 2020 outlook. The 2020 net income is now likely to be in the range of $500 million to $900 million, which reflects the impairment charges. And adjusted EBITDA is likely to be in the range of $2.6 billion to $3 billion. As Terry said, the range of possible results from our multivariable scenario analyses led us to this 2020 outlook to give our investors a sense of what we view are likely outcomes in the current environment. As the industry recovers, we will update if appropriate.
From a capital allocation perspective, in early March we suspended an additional expansion on the West Texas LPG pipeline, the Demicks Lake III plant and reduced the scope of the expansion on Elk Creek pipeline. Yesterday, we announced that we paused several projects and reduced our 2020 growth capital expenditures further. So far in 2020, we have reduced forecasted capital expenditures by $900 million compared with our original 2020 guidance provided in late February. Kevin will discuss these adjustments to growth capital in a moment.
We now expect growth capital to range between $1.4 billion and $1.8 billion this year, which includes more than $900 million that we've already spent in the first quarter, as we completed Arbuckle II, Demicks Lake II, MB-4 and 45,000 barrels per day of the West Texas LPG expansion. Only approximately 40% of our 2020 capital expenditures is left to spend over the remaining three quarters.
Looking ahead, we can continue to significantly scale back capital. If commodity prices remain depressed and producer activities remain low, we could potentially operate in a $300 million to $400 million annual capital expenditure range, which would include limited routine growth spent in alignment with our producers' needs and maintenance capital. Our flexibility to scale back capital and to adjust to our customers' needs is a significant financial tool we can use in this environment to help preserve balance sheet strength and liquidity. On the other side of the equation, we stand ready to resume these projects as producer activity returns.
I'll now turn the call over to Kevin for a closer look at our completed growth projects and operations.
Thank you, Walt. We saw volume growth across our system in the first quarter of 2020, compared with the first quarter 2019. NGL raw feed throughput volumes increased 6% and natural gas processed volumes increased 5% year-over-year. The natural gas pipeline segment continues to deliver strong fee-based earnings as our total capacity reached 100% contracted in the first quarter.
This segment, which represents more than 15% of ONEOK's EBITDA, provides solid fee-based earnings and stability, even through volatile commodity price environments. As Terry and Walt discussed, the volatile commodity price and demand environment makes predicting our future volumes or segment-level performance very challenging, but we can provide certain data points based on the information we have at this time to help frame up the current volume and activity levels that we're seeing across our operations.
Let's start with an update on our growth projects. During the first quarter, we completed and placed into service the Arbuckle II Pipeline and the remaining capacity of our MB-4 fractionator in Mont Belvieu which is 100% contracted. We also completed 45,000 barrels per day of our fully contracted 80,000 barrel per day West Texas LPG Pipeline system expansion. The remaining capacity of the expansion, which was delayed due to weather during the first quarter, is expected to be completed in May.
We completed our Demicks Lake II processing plant in January, bringing our total processing capacity in the basin to more than 1.5 billion cubic feet per day. The projects that were completed in the fourth quarter 2019 were ramping, as expected, until the commodity collapse in March. Demicks Lake I, which was completed in October of last year, reached near full capacity of 200 million cubic feet per day in the first quarter.
Total NGL raw feed throughput volume from the Rocky Mountain region, which includes volume on both the Elk Creek and Bakken NGL Pipelines, reached 240,000 barrels per day in March prior to the collapse. Compared with the fourth quarter of 2019, we saw a more than 7% increase in Rocky Mountain region raw feed throughput volumes, as new processing plants and plant expansions were connected to our NGL system.
The volumes we reached in the first quarter combined with the quality of the basin and our customer base give us confidence that growth will resume once demand recovers. These assets put us in a great position to capture natural gas and NGL volumes for our customers when that occurs.
We announced yesterday that we are pausing the majority of construction activities on several of our remaining capital growth projects including the expansion of our Bear Creek processing plant in the Williston Basin, construction of the MB-5 fractionator in Mont Belvieu, additional Mid-Continent fractionation expansions and the third expansion of the West Texas LPG Pipeline system. The decision to pause these projects reflects the changing needs of our customers and our ability to be flexible through this uncertain commodity price environment. The projects we paused can all be restarted quickly when our customers' activity resumes.
Now let's take a closer look at our current -- at the current activity across our operations. As we sit today, the production plans of our customers continue to evolve as market dynamics shift. Many of our customers have announced a reduction in rig activity and in some cases are curtailing existing production. In the Williston Basin, there are currently approximately 30 rigs operating with around half of those on our dedicated acreage. Many of the wells that have been curtailed on our acreage to date have been older vintage wells that produce lower volumes at a higher cost to producers. Other wells taken off-line by producers were previously flaring, so they have not reduced our volume.
We have also seen wells curtail that have opened up capacity for wells previously flaring to flow onto our system. These three factors have resulted in less volume coming off our system than you would expect. And given the significant backlog of flared gas, total production won't have to recover fully for our processing capacity to be highly utilized. Based on the latest reported natural gas flaring data out of North Dakota, approximately 400 million cubic feet per day was flaring in the basin with more than 200 million of that on ONEOK's dedicated acreage.
As Terry mentioned, our customers in the Williston Basin are some of the most stable and well capitalized in the industry. We've had one customer this year file for bankruptcy protection. However, they continue to flow volume. We do not foresee additional significant bankruptcy risk among our largest customers in the region. And smaller scale private producers make up approximately 15% in aggregate of our total production from the region. In the Permian Basin, approximately 70% of our NGL volume is from the Midland Basin, one of the most resilient basins in the U.S.
As our West Texas LPG Pipeline expansion is fully completed in May, we will continue to transition volumes away from offloads, we currently have with third-party NGL pipelines onto our pipeline. We are currently offloading approximately 50,000 barrels per day and we expect to move 20,000 barrels per day over to our system in the third quarter of this year with the remainder in the first quarter of 2021. As these volumes move onto our system, we'll be able to collect full transportation and fractionation fee rates on that volume.
Additionally, our system-wide propane plus fractionation capacity remains highly utilized at approximately 85% to 90% and over half of our 27 million barrels of underground NGL storage is available to capture opportunities in the market. We're adding 1.5 million barrels of storage in the third quarter of this year and expect to complete an additional 1.5 million barrels of storage in 2021. We have also added 3.5 million barrels of brine storage in Mont Belvieu, substantially increasing our capacity.
In the NGL markets, we are seeing seasonally strong demand for propane in Conway at our rail racks and on our north system from wholesalers, as well as in Mont Belvieu from exporters. This demand is contributing to the strong relative price of propane to crude. Petrochemical facilities in both Conway and Mont Belvieu continue to have strong demand for ethane driving the price to near recovery economics in the Mid-Continent.
Terry, that concludes my remarks.
Thank you, Kevin. Our recent project completions and the volumes we've seen materialize prior to this downturn provide confidence in the growth behind our system that is available to capture once demand recovers.
ONEOK's strong record of delivering on our expected results combined with our competitive, integrated asset position and high-quality customer base and the best resources plays are fundamentals of our business that provide us with a foundation for stability, even through difficult commodity cycles. We have been through downturns before, and we know how to position ourselves for success as conditions improve.
To our employees, both those continuing to work remotely and those who are still reporting to a facility or field location, thank you for your continued work, flexibility and dedication to our company. We're focused on maintaining essential services for our customers and your commitment to continuing to operate responsibly are exceptional.
During a very difficult time, you have risen to the challenge by remaining committed to the health and well-being of our company, families and communities. While the near-term view of the world is changing every day, the long-term fundamentals of our strategic business remains strong and well positioned for continued growth, when global energy demand recovers.
With that, operator we're now ready for questions.
Thank you. [Operator Instructions] And our first question will come from Shneur Gershuni with UBS.
Hi. Good morning, guys. Thank you very much for a lot of the color today. I just wanted to start-off with the – I guess, we'll call it an outlook or guidance. I do appreciate a lot of the color that you gave in terms of some of the inputs when you're talking about why your system will be impacted less and the offload opportunities. I was wondering, if you could share with us your views as to how you get to the upper end and conversely to the lower end of that outlook? What conditions in the Williston or elsewhere needs to play out to basically end up at your higher end or end up at your lower end?
Sure. This is Kevin. Yeah. I mean, there's a variety of things that's – as we kind of laid out the permutations you look at, when you consider the variability of all the inputs we're looking at that's the reason for the outlook. So obviously, if you get to the upper end demand – for example demand comes back more quickly. Prices recover more quickly. Producers respond more quickly. So at the end of the day, you're getting the volume on your system quicker. On the low end of the range, it's just prolonged. And by prolonged, it could be anything from just how producers respond to how the demand recovers.
Do you have anything specific with respect to like when shot is come back and so forth is there any sort of cadence that we should be thinking about?
No. I mean, we're not going to – again, we're not going to provide specifics on that, because there's a variety of ways you could get to each – to the high end and there's a variety of ways you could get to the low end as well. So we're not going to get into how long, because that would just be kind of factoring in one variable.
And moving on we'll go to Christine Cho with Barclays.
Thank you. Good morning. Maybe we could start with the NGL segment, the Bakken rate. It looks like it came down. I'm guessing that's partly due to Elk Creek coming online, which I think has a lower rate. But should we think that you moved some more volumes from Bakken NGL Pipeline and Overland Pass onto this line, or was there anything else we should factor in? And is this $0.28 level a good run rate going forward or should we expect that it could trend a little lower through the remainder of the year?
Christine, this is Sheridan. I think, there's two factors in there. One is, while we were railing volume out of Bakken, we were charging customers a higher fee for that service, especially the ones that were came on for Elk Creek. And as Elk Creek has come on, they've come back to a rate that we contracted with them, which was lower than the $0.30 rate.
So I think that as we go forward the $0.28 rate, we see today is a good going forward run rate. Our rates are not determined by which pipeline we use if we put barrels on Bakken or Elk Creek or what we put on OPPL, because the rates you are seeing are -- we charge our customer from a bundled service from a transportation and fractionation. So it's not impacted by which pipelines we use.
Okay. So even though the rate came down the margin is higher that's how we should think about it?
Well, as the rate came down obviously we aren't railing as much volume. So our costs have come down as well, but I think going forward $0.28 is what you will see going forward. Obviously, that does have some impact on how much is coming out of the Powder River Basin on that line, which is at a lower fee and how much is coming out of the Bakken.
Okay. Great. Thank you.
Moving on, we'll go to Jeremy Tonet with JPMorgan.
Good morning.
Good morning.
I was just hoping that you could share a little bit more as far as Northern Border kind of key content there and any thoughts you guys could provide with regards to the need or lack of need to extract ethane going forward this year just given kind of the mix shift between Bakken gas going on the price and Canadian gas going on the price. Just trying to get a better sense of what's going on -- what could be going on there? Thanks.
Hey, Jeremy, this is Chuck. So as you know TransCanada is the operator of Northern Border. So I'm going to answer your question based on our 50% of ownership of Northern Border Pipeline as a partner. So we've been watching over the past quarter in particular as volumes have kind of changed a little bit between Bakken and receipts coming in from Canada as volumes have changed a little bit in the Bakken into the pipeline.
So obviously, the pipeline is concerned about anything above 1,100. And this is a fluid situation. As that ratio changes and the mix between Canada and the Bakken you'll see that BTU blend mix in Northern Border and then consequently downstream. So, where the pipeline is today, we understand they're going to go ahead and file their tariff and set an upper limit. I believe it's 1,100 to start June 1.
And Northern Border has held numerous formal meetings with shippers, markets, downstream pipes all interested parties regarding that limit. And frankly, the limit -- the BTU spec just needs to be put in place to meet the downstream deliverability requirements in Chicago.
Yes. Makes sense. Thanks for that. And then maybe going to the GP segment just with the average fee kind of moving lower there quarter-over-quarter and it seemed like there was a POP influence there that kind of drove that. I was wondering if you could provide a little bit more color on kind of what were some of the drivers and how you might expect that to change in this environment?
Sure. So as we've discussed in our 10-K and our 10-Qs under a certain percentage of proceed contracts with fees our contractual rates or percentages may increase or decrease. And these are based on several thresholds in the contracts production volume commodity prices system pressures that we're obligated to provide or the producer's obligated to meet.
So our average rate can be impacted by those factors and also impacted if volumes increase or decrease on contracts that have different POP percentages or fee rate. So for example we have several large producers who may have contracts that are more fee-based than POP and if they're currently curtailing, you'd see the impact of that on our fee rate. Consequently, it would come down. Again, we can't speculate what kind of contract mix we're going to see over time as producers are making decisions frankly weekly as to what wells are going to be produced and certainly at what production level volumes. So we can't necessarily forecast that average rate, but that gives you the understanding of what's behind how that average fee rate is developed and thought about.
And moving on we'll go to Tristan Richardson with SunTrust.
Good morning guys. Appreciate all the commentary on operations as well as the liquidity and capital and how the balance sheet is preparing for this. Can you talk about the investment-grade profile? It seems like the rating agencies are willing to take a long-term view, I mean looking out past the short-term disruptions of 2020. But to the extent leverage remains elevated can you talk about just the priority of the investment-grade profile?
Well we speak regularly to the rating agencies. And while we've had a market imbalance and it's delayed the pace of our leverage reduction, it hasn't reduced our expectation or desire to reduce leverage. We believe our assets are in a position to support the growth in the basin we serve once the imbalance is rectified and that the rating agencies recognize that.
Our credit ratings are very important to us and we've demonstrated by our actions in the past that if the current demand reduction -- end up being longer in duration, we have several tools at our disposal to reduce leverage. And we've already taken the first action in this regard by pausing our capital projects to preserve cash flow. We continuously evaluate our options to manage the balance sheet and look prudently to maintain our credit ratings going forward.
Appreciate it. Thank you guys very much.
Moving on we'll go to Spiro Dounis with Credit Suisse.
First question just on growth and the durability of earnings here and forgive me for asking about 2021 just given the tough visibility right now. But as we talk to investors that's still where a lot of the focus is at this point, so just wondering if you could talk to some of the high-level drivers of growth or even what a flat scenario would look like in 2021 versus 2020 and if you could maybe tie that to your ability to cut CapEx to those baseline levels you mentioned. So in other words is it really a heavy lift to maintain EBITDA levels next year?
This is Kevin. When we think -- I mean we start talking 2021 granted that is -- that's out there given the uncertainty today. But the key I'd come back to is, where our assets are located we've got tremendous confidence in the basins where we operate. Those resources are still there.
As we look forward when you consider the flare gas that's still available to capture as production comes back up online in the Bakken, that's going to drive additional volumes for our natural gas processing plants and the NGL segment. And I think you hit on the other key point is, with this available capacity, we can do that with extremely minimal capital as we think about 2021 as these volumes come back and the environment improves.
And Kevin I think -- the only thing I'd add to that is we've been in this situation before where we had built up some headroom in our businesses and we're able to harvest cash flow. And so with the prospect of 2021, CapEx spending being very low we'll be right back to that particular situation. So when you start looking at that the free cash flow generation of the business is pretty significant.
Okay. Understood. And then…
I guess the only other comment that, I would make as you think about these ranges that we've put out there and the durability of the business we -- in this range of potential outcomes there are built into some of these numbers pretty significant curtailments, okay?
And so you have to think about the lower end of the range and I'm not going to give you specifics because then I'd be giving you financial guidance, okay? But as we look at the potential outcomes, there's a pretty significant percentage of production that we've assumed to be curtailed in one of these scenarios and that's reflected in these numbers.
So I think that just in and of itself explains the durability of the business. And unfortunately we can't give you specific – specifics. We'd like to but we can't. Probably as I said in the call, it wouldn't be appropriate for us to do that. But we feel really good about how well positioned in spite of all the things that – the headwinds that the industry faces we're in a pretty darn good position.
Yes. And I can appreciate a tough question to answer now. So I appreciate you all taking a swing at it. Second one just to follow up on the CapEx. Can you just talk a little bit about why the Arbuckle extension expansion are still in the backlog? Is that something that can still come out at some point, or is that really needed as part of the broader network right now?
I'm sorry. You were – this is Kevin. Could you repeat that question? You were a little jumbled as it came through.
Yes. Sorry. I'm sick of using this cell phone. So just wondering if you guys could walk through the decision to lead the Arbuckle extension and expansion in the backlog. Is that something that can still come out at a future point, or is that really needed at this point for the broader network?
Okay. Yes. The extension remained in as we think about that. That pipeline was important because it allows us to move Bakken barrels all the way to Mont Belvieu. So we wanted that connectivity. And also keep in mind these projects kind of proceed at different paces and many of them are further along or not further along. So that goes into our consideration as well and why that one is still in the schedule.
Got it. Thanks, everyone.
And moving on we'll go to Michael Blum with Wells Fargo.
Hi. Good morning, everyone.
Good morning.
I just want to talk a little bit about the dynamics in the Bakken, particularly as it relates to the flared gas. So – and I guess my question is like as you get shut-ins and reduced drilling activity, will you see a reduction in flared gas as well just naturally? And will that generally going to quantify or any rule of thumb to think about how that would impact the number of well connects you would need to do based on that change in flared gas?
Michael, it's Kevin. I'll start and Chuck or others may have some comments. But yes, like we said in our prepared remarks, there's multiple dynamics that could go on impacting flared gas. We have seen some wells shut in that had previously been flaring. So that doesn't impact our volumes obviously.
We've also seen some situations where some gas was taken off-line. But other gas that was flaring due to some pipeline or compression constraints started flowing on the system. So effectively it was replaced which would bring flaring down.
So yes, I do think these – the curtailments will bring flaring down in a couple of different ways. But the key point there is I think with our capacity – and we had continued to build out some gathering lines as we move through the first quarter. As those volumes come back, we believe we're going to have the capacity to capture the gas much more fully than we did say in the January or February time frame.
Okay. Great. Thank you very much, guys.
And next we'll go to Jean Ann Salisbury with Bernstein.
If ethane price were to rise to the $0.30 or $0.40 range next year, would that be enough incentive for you to recover the gas in the Bakken, even if it didn't cover your full midstream tariffs? And do you have the contractual capability to do that?
Did you say $0.30 to $0.40 ethane values?
Yes. Yes for ethane. Yes.
We always have the ability to flex our rates if we need to to be able to bring ethane on, on an economic basis. So that is always out there that we have the ability not only in the Bakken or Williston, we also have that ability in the Mid-Continent. So if we see the opportunity to be able to flex our rates a little bit to bring volume on we will do that. We also have to be cognizant of is if the market is bounced at certain prices, if we bring more volume on from another basin, it could push out volume from a basin that is flowing today. So we take all those things into consideration. But to answer your question, we do have that ability to flex our rates -- our NGL rates out of the Williston Basin.
This is Sheridan. We could add to that to your comments about ethane is what you're seeing in the Mid-Continent with the strength in ethane prices today and natural gas prices being as weak, what could affect us in 2020 fairly significantly if this continues is we could see producers and processors begin to extract ethane in the Mid-Continent and other places as well, right?
That's very true, because the numbers right now are very, very close to recovery economics in the Mid-Continent. And if you take everything into consideration increased propane recoveries when you're in, ethane recovery you could make an argument that in May, we could see some more ethane come out of the Mid-Con that we hadn't predicted.
Okay. Thank you.
Yeah. Thanks.
Next we'll go to Colton Bean with Tudor, Pickering, Holt & Company.
So, just really a quick one. I think last quarter, Chuck, you may have mentioned that you guys looking at a proceeding agreement for residue gas takeaway out of the Bakken. Can you just update us on where you stand with that, and if that project has been impacted at all by the production outlook?
Sure, Colton. Yeah. I mean with everything evolving, our producer forecast evolving and what have you in the basin like anything we've kind of taken a step back and we're trying to determine when we see the full need for that project. The way it sits today, I was looking -- we were looking at potentially fourth quarter of 2022. I'm not quite sure honestly, if that's been moved out yet or not. We're still evaluating that.
Got it. Appreciate that.
And next we'll go to Michael Lapides with Goldman Sachs.
Hi, guys. Thank you for taking my questions and glad to hear everybody and their friends are all well. Can you just talk -- Shneur mentioned this in the first question, just the cadence within your guidance for 2020. And the only reason I ask that is first quarter you did around $700 million of EBITDA. The midpoint of your guidance would imply you keep doing around $700 million of EBITDA each quarter. But the first quarter impact was before all the shut-ins and before all the production cuts. Just kind of what's offsetting that? Like what keeps you kind of at that $700 million quarterly run rate? Can you just high level kind of the puts and the takes a little bit?
This is Kevin. Michael the way I guess I would think about that is, you got to remember in the first quarter we always have a winter impact and we were bringing -- we are bringing a lot of these assets online. And so we moved -- as we think about January and February, it wasn't really till we came out in early March that we saw some of the volumes pick up like we expected.
Clearly, if you see curtailments as we move through April, May and June, obviously, you're going to see a step down as you move through the second quarter, but then recovery back as we move our way through the back half of the year. So yes, you would expect to see a step down in the second quarter with that recovery in the back half.
And is that recovery predicated on Bakken producers, re-ramping up production starting in the fourth quarter? And at the current strip price, does that give them the economic incentive to do so, so quickly?
Clearly Bakken volumes would be a component of that. But again with our West Texas expansion, with the other assets we brought online, with what we're seeing in the NGL markets and for marketing inventory storage type opportunities, there's a lot of things that I think could -- as we move through the second quarter that could play out for the back half of the year.
Got it. And then one last one. Just curious, if you're thinking about the potential for any repurposing of any of your existing assets? I mean lots of moving parts across oil gas NGLs. Just curious if there are opportunities whether in storage, whether in existing older pipe to repurpose things given what's just going on in the marketplace.
Michael, we can -- this is Sheridan. We continue to always look at that. And as we expressed earlier, we thought there was always an opportunity to maybe repurpose West Texas Pipeline for crude oil that was -- if that opportunity would manifest itself. So we continue to look at those opportunities as we continue to go forward. Obviously, storage right now is a big commodity that everybody is looking at with the shape of the prices right now that we continue to evaluate. Right now we do think our storage is better used as NGL to play that part of the structure of the market than it is in other product, but we do continue to evaluate the ability to repurpose assets into other service.
Got it. Thank you, guys. Much appreciate it.
We'll go to Chris Sighinolfi with Jefferies.
Hey. Good morning, everybody. Thanks for taking..
Hey, Chris.
I have two questions, Terry if I could. The first you followed I think from Tristan's your line of inquiry just about credit rating. I don't know if that one's for you or Walt maybe it involves more of a Board readthrough. But can you just walk us through how you guys think about leverage and the rating? You've talked about capital declines that are possible. Certainly, I think, I was reading into that like how low could the spending be next year. But I guess what I'm getting after is at what point does the dividend come into conversation? Walt, you had mentioned sort of multiple levers and you talked about CapEx first. And I'm just curious how everybody thinks about those components put together.
Well because -- I think it's fair to say that we continually evaluate all options available. But I think it's really important to understand that with the CapEx that we've reduced that we will be cash flow positive definitely in the third and fourth quarter and into 2021. So deleveraging will happen. It's just a question of the pace if there are things that we might do to accelerate that pace. If that makes sense we'll go down that path. But I think Terry addressed our view on the dividend while we look at it on a quarterly basis we will be earning cash flow to pay it going forward. That's our expectation.
Okay. I'm sorry, if I missed that in the prepared statement. And then I want to follow up -- I appreciate the NGL conversation. We've been thinking about it. Similarly to Sheridan some of the things that you and Kevin have talked about. I'm curious and there's a lot of focus on crude storage. We obviously get purity product NGL storage reported. There's Y-grade capacity, obviously, that's significant behind that and fungible. And I'm just wondering if there's anything that you're seeing that would lead to concerns around an NGL storage situation. And as it pertains to that any update you guys can give as we start to get Mid-Con or Rocky shut-ins what Belvieu Conway might do? Thanks.
Chris, this is Sheridan. I would say in terms of NGL storage capacity we feel we are in a great position on our NGL storage capacity. One is we're at a seasonal time when storage capacity is low where you'd see more building in a normal year. Obviously, this is an abnormal year. But also at this time right now we are seeing great demand for the NGL products.
Propane is really being demanded from exporters. Even at times in Mont Belvieu we can't supply with our current production all the needs from people buying product down there that we typically sell to. So propane -- that's why we're seeing propane trade so well versus crude. And we also are seeing that phenomenon on the ethane market that the petchems are still having a very good demand that we've actually had to turn some people away for that we typically supply ethane to because we don't see that we'll have that product in the next month.
Now if more ethane comes on through recovery we will be able to satisfy those needs, but we are seeing very good demand for our two biggest products which leads to that we think we have plenty of storage capacity not only for regular operations, but also to be able to capture some of the opportunities that the market are giving us in the contango market that we're seeing.
So Chris, I'm just going to add -- reiterate one thing that Sheridan said earlier in his answer was with respect to propane storage inventory is at a seasonal level. The capacity is -- actually we've got plenty of capacity. So this is the time of year when propane retailers start putting product in hold. And -- so I just want to make sure that was clear.
And next we'll go to Dan Lungo with Bank of America.
Hey, guys. Thanks for taking my question. Sorry to push on the dividend a little bit. But when it comes to maintaining the investment-grade ratings, based on your current projections if you're at the lower end of your EBITDA range, you're going to be above that all important five times marker which is a trigger for downward high yield if it's sustained for a longer period of time. So without a serious recovery in EBITDA or -- in 2021, it just seems like you only need to be pulling additional levers to maintain that investment-grade rating if things end up being worse than expected. So I'm just wondering how do you weigh in maintaining a dividend versus staying in the investment-grade rating?
Dan, I would tell you that we speak to the rating agencies regularly. I don't know that I necessarily agree entirely with your expectations of where leverage will be on a long-term basis here. And we've spoken about the dividend three times now. So we're not going to get back into it.
All right. Thank you.
And next we'll go to Becca Followill with U.S. Capital Advisors.
Good morning guys. I'm still confused about this page five the footnote. Is it -- is the change in the drop from $0.92 to $0.85 tied to NGL prices crude prices? With the decline in NGL prices from Q1 to Q2 and the increased shut-ins are we going to see that rate drop further? Is it a good run rate to use?
Becca this is Kevin. Chuck spoke to that earlier to the earlier question about what drives that fee rate change and that disclaimer. So yes, there are thresholds that he mentioned that are dependent on a variety of things. And we're not going to provide an update at this point of what we think that range would be. But we can tell you that as we've factored in all those scenarios that various outcomes have gone into the $2.6 billion to $3 billion EBITDA range that we provided.
Thank you.
Moving on we'll go to Elvira Scotto with RBC Capital Markets.
Hi, everyone. Thanks for taking my questions. So it looks like you've done a lot of really good work here on the scenario analysis. And with respect to this kind of $2.6 billion lower end of EBITDA kind of outcome, I think it seems like you have pretty good confidence that that's the low end. What would have to happen in order for that EBITDA to be below that end?
We're not -- Elvira, we're not going to go there as far as providing that information. Like we said, we ran a variety of scenarios that considered a variety of different price, volume, producer activity outcomes. And we believe that the EBITDA is likely to fall within that $2.6 billion to $3.0 billion range. And that's what we're providing at this point.
Elvira, as I indicated earlier, the numbers consider substantial curtailments and a significant duration of this downturn. So I think that's about as much as we can give you.
No. That's really helpful. And then just my last follow-up question here is in some of these conversations that you've had with some of maybe your Bakken producer customers, at what point would you expect activity to pick up? And when I say that I mean, at what commodity price? And maybe you can kind of -- you can think back to that 2015, 2016 time period?
Well this is Kevin. And I think there's a couple of dynamics there. One is, if they're curtailing gas, what price does it take to have them bring curtail gas back. And without giving a specific number, obviously they're looking at what their variable cost to produce is. That will vary by producer and it'll vary by location. So that's what will go into that. So clearly, that's a lower price. As we think about the next tranche would be completions. There's still 400-plus DUCs in the basin. So that we -- that's going to have a price -- that activity would come back. So, as we move -- as prices improve, those are the things that we'll watch as the curtail gas will come back first and then you'll start seeing completion crews added and producers work off their DUCs.
Elvira, I think -- thanks. Terry. I think it's fair to say that if we see a -- this continued downturn, the faster producers curtail and correct the supply and demand imbalance the faster there'll be a recovery. That's how we look at it.
And moving on, we'll go to Craig Shere with Tuohy Brothers.
Good morning. First, let me just congratulate you on holding off on the less-economic initial forays in the long desired crude gathering and export terminal opportunities. Sometimes what we don't do is more important than what we do. With respect to in-flight growth projects that are now on hold, do you see a pecking order among them in terms of what might come online first or resumed first?
No I don't know that we would look at it that way. I think it'll be -- as we talk to our customers in each of our basins, we'll -- that's what we'll look at. So, if we continue to see -- we've seen some really strong growth out of the Permian up until the collapse and if we see that continue, then obviously the West Texas expansion would be back on the table. And similarly in the Bakken, if we saw certain areas. And remember with Bear Creek, it is a very -- it's a geographically isolated area. So, it would be specific producers, showing a desire to get activity back in a certain area of the Bakken. So that's the type of thing that would cause Bear Creek to come back online. But it'll be producer-by-producer, processor-by-processor type discussions that will drive those projects.
Craig I think the other thing that you could see and I've been through this -- through these cycles so many times I can't count. But I think the thing we've seen in the G&P space over the years is that when you get into these down cycles, people start talking that is midstream companies start talking about asset consolidation and shutting underutilized facilities down and underutilized gathering systems and doing offloads. And you could see those kinds of things that it's going to matter which side of the coin you're on could brought by either revenue benefit or cost savings benefit. So, we could see some of those discussions happening as we go forward.
Terry, I'm sorry. So you could see yourself as a potential consolidator on some distressed assets?
Sure. Well we could potentially -- there might be facilities that we believe make more sense that we could idle for a period of time and deliver volumes to somebody who has available capacity.
So just to say I hear a thing that in an operational way, there's an opportunity to consolidate and find good economic outcomes between multiple different companies.
Exactly. You do that through offload processing deals or onload -- if you're the receiver you do that through an onload processing deal. It doesn't involve ownership. Thanks Walt.
I got you. And I don't know if Walt wants to chime in again and sorry for beating a dead horse. We've had some questions about dire worst-case leverage conditions and potential additional levers. I want to focus more on patience. So, if credit isn't deteriorating to untenable levels, but lower for longer lasts much longer than perhaps envisioned today, is there a limit to how many years you're willing to wait for organic improvement in your targeted net debt-to-EBITDA ratio?
Yes, Craig. That's a quite hypothetical question. I would tell you that -- I would point you to talk to the rating agencies about their view on timing. I think for investment-grade companies, it tends to be a little bit longer view than quarter-to-quarter. And so, as we see this playing out, we see ourselves naturally delevering and we're going to look at other opportunities that might help that along. But I would say if you get out years into this sure everything is on the table. But you're -- that's pretty hypothetical.
And this concludes the conference call and I'll pass it back to Mr. Ziola.
All right. Thank you everyone. Our quiet period for the second quarter starts when we close our books in early July and extends until we release earnings in late July. We'll provide details for that conference call at a later date. Again thank you all for joining us and the IR team will be available throughout the day and the week in case you have more follow-up questions. Thank you, very much and have a good day.
And once again, that does conclude today's conference. We'd like to thank everyone for their participation. You may now disconnect.