Oneok Inc (OKE) — Q2 2019 Earnings Call Transcript

Thanks, Andrew. Good morning and thank you all for joining us today. As always, we appreciate your continued interest and investment in ONEOK. Joining me on today's call is Walt Hulse, Chief Financial Officer, 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. It's an exciting time for ONEOK as we begin placing some of the largest capital growth projects in our history into service. Our projects remain on or ahead of schedule and on budget. The southern section of Elk Creek pipeline began employing NGLs on July 15 from the Rockies region into the Mid-Continent, with the northern section still on target to be completed in the fourth quarter. Last week, we announced additional low-cost expansion projects across our system, which continue to demonstrate ONEOK's ability to incrementally grow with our customers. These projects will help address NGL transportation and fractionation needs of producers and will further address flaring in North Dakota with added natural gas processing capacity. All our projects, including these recent expansions, are built to meet the needs of our customers and are backed by long-term contracts. We continue to see strong producer activity levels across the basins where we operate with NGL and natural gas volume growth that is in line with our expectations so far this year. Now, more than halfway through the year, our confidence in our 2019 financial expectations and 2020 earnings outlook has strengthened significantly. With our projects remaining on or ahead of schedule, we expect accelerated earnings growth leading into 2020 and beyond and additional cash flow to reinvest in our business, reduce leverage and continue to return value to shareholders. With that, I will turn the call over to Walt for comments on our second quarter results.

Thank you, Terry. Our second quarter 2019 net income totaled $312 million, or $0.75 per share, an 11% increase year-over-year. And second quarter adjusted EBITDA totaled $632 million, a 5% increase year-over-year. Distributable cash flow in the second quarter 2019 was $540 million, up 19% from the second quarter 2018, with a healthy dividend coverage of 1.51 times. We also generated more than $180 million of distributable cash flow in excess of dividends paid in the second quarter 2019. During the second quarter, we paid a dividend of $0.865 per share. And last week, we announced a dividend increase to $0.89 per share, or $3.56 per share on an annualized basis. This increase further underscores our confidence in the increasing cash flow we expect to generate from projects we have recently completed or will complete in the coming months. The dividend is payable on August 14 to shareholders of record on August 6. Our June 30 net debt to EBITDA on a trailing 12-month basis was 4.2 times. With the earnings expected from these projects, we expect to be at 4 times debt to EBITDA run rate in the fourth quarter of 2020 or first quarter of 2021, with deleveraging continuing in the quarters to follow. Our liquidity remains strong as we ended the second quarter with the full $2.5 billion available on our credit facility and more than $270 million of cash on hand. We announced additional natural gas and NGL expansion projects last week that we expect to provide attractive returns for minimal capital invested. We do not expect these projects to impact our 2019 growth capital guidance range of $2.5 billion to $3.7 billion, as most of the spending will happen in 2020 and 2021. Because of the accelerated timing on some of our projects, we anticipate ending the year towards the higher end of our capital guidance range. As spending on our large pipeline projects winds down early next year, we expect capital expenditures in 2020 to be lower than 2019. Producer activity, project timing and additional committed volumes on our system all add up to an impressive backdrop for ONEOK's growth. As we sit today, we are even more confident in our outlook that our 2020 adjusted EBITDA will increase by greater than 20% with an emphasis on the greater than when compared with our 2019 guidance midpoint. I'll now turn the call over to Kevin for a closer look at our operating performance.

Thank you, Walt. We continue to see strong producer activity across our operations driving increases in both NGL and natural gas volumes in the second quarter. Total NGL raw feed throughput volume increased nearly 110,000 barrels per day or 11% year-over-year, and increased 80,000 barrels per day or 8% compared with the first quarter of 2019. Natural gas volumes processed increased more than 150 million cubic feet per day or 9% year-over-year and increased more than 80 million cubic feet per day or 4% compared with the first quarter 2019. Let's take a closer look at our volume growth and project timing in each of the basins where we operate. Starting with the Rockies region, producer results remain strong in the Williston and Powder River basins. North Dakota natural gas production is more than 2.8 billion cubic feet per day and there continues to be around 60 rigs operating with more than 500 million cubic feet per day of natural gas being flared and nearly 1,000 drilled and uncompleted wells in inventory. All of these factors provide an inventory of growth for our natural gas liquids and natural gas segments. As Terry mentioned, we completed the southern section of the Elk Creek pipeline from the Powder River Basin to the Mid-Continent, and it is currently flowing more than 30,000 barrels per day of NGLs. With the southern section in service, we have moved volumes previously railed onto our pipelines, eliminating higher rail transportation costs. This has also freed up rail capacity, which can be used to address continued NGL growth in the Williston basin until Elk Creek is fully in service in the fourth quarter. As further growth is expected, we will add pumps on Elk Creek as needed to increase capacity. These projects are low cost and can be completed incrementally to address additional volume growth, including the need for potential ethane recovery. Approximately 815 million cubic feet per day of new natural gas processing capacity is coming online basin wide between now and the end of the first quarter 2020, which translates to approximately 110,000 barrels per day of propane plus NGL production when these plants are full. With all of the NGLs from those plants dedicated to ONEOK and more than 30,000 barrels per day already flowing on the pipeline, we remain confident that throughput on Elk Creek will reach approximately 100,000 barrels per day in the first quarter of 2020. ONEOK has now announced a total of 600 million cubic feet per day of additional natural gas processing capacity in the Williston basin, expected to come online between now and early 2021. Our latest announcement was the 200 million cubic feet per day expansion of our Bear Creek plant in Dunn County, an area that has recently experienced some of the highest production increases in North Dakota, and has a decades-long runway of well inventory yet to be drilled. We expect volumes on the Bear Creek expansion to ramp up over a 12 to 24 month period once in service. This expansion also increases our NGL volumes contracted for natural gas processing plants in the Rocky Mountain region from 200,000 barrels per day to 225,000 barrels per day. Our Demicks Lake I plant remains on schedule to open fully in the fourth quarter 2019 in conjunction with the completion of the northern section of Elk Creek. Demicks Lake II is expected to be complete early in the first quarter 2020. Moving on to the Mid-Continent, producer activity in the region remains in line with our expectations for the year. In the second quarter, we saw increases in both NGL raw feed throughput volumes and natural gas volumes processed in the Mid-Continent compared with the first quarter 2019. Large well pad completions early in the quarter drove the increase in natural gas volumes processed and two new third-party plant connections contributed to the increase in NGL volumes. Arbuckle II is on schedule for completion in the first quarter of 2020, and its contracted capacity now totals 375,000 barrels per day compared with 350,000 previously. Last week, we announced NGL fractionation facility expansions, totaling 65,000 barrels per day in the Mid-Continent. These projects will increase our propane plus fractionation capacity to help address the heavier NGL barrels from the Williston basin. 15,000 barrels per day of capacity is expected to be completed in the third quarter of 2020, with the remaining 50,000 barrels per day completed in the first quarter 2021. These types of projects can be efficiently completed at costs substantially lower than new construction. Recently completed expansion projects in our natural gas pipeline segment continue to drive higher firm capacity contracted in the second quarter compared with both the second quarter 2018 and the first quarter 2019. These projects increase the capacities of our Mid-Continent and Permian basin pipeline systems and will continue to provide increased firm transportation earnings going forward. Now, let's take a look at our Permian basin and Gulf Coast operations. NGL raw feed throughput volumes in this region increased 20% compared with the first quarter 2019, primarily driven by volume growth on our West Texas LPG pipeline. We continue to expect our average fee rate in this region to trend higher in future quarters as legacy volumes roll off West Texas LPG and are replaced with market-based transportation and fractionation volumes. The 80,000 barrel per day expansion of West Texas LPG remains on track to be completed in the first quarter 2020, with volumes ramping up quickly after it is placed in service. And last week, we announced a third expansion which will add 40,000 barrels per day of capacity to the system. The expansion is supported by long-term dedicated NGL production from processing plants in the Permian basin and is expected to be completed in the first quarter 2021. Our NGL fractionation capacity, given current product composition, is approximately 820,000 barrels per day and was approximately 90% utilized in the second quarter. We now expect to complete our 125,000 barrel per day MB-4 fractionator in phases. Phase 1 will provide approximately 75,000 barrels per day of capacity and is expected to be available in the fourth quarter of this year, earlier than originally planned. Phase 2 will consist of the remaining 50,000 barrels per day and is expected to be completed in the first quarter of 2020, as originally announced. MB-5 remains on track for completion in the first quarter 2021. Terry, that concludes my remarks.

Thank you, Kevin. The progress on our capital growth projects this year is setting us up well for a significant volume and earnings uplift in 2020. As Walt emphasized, we're even more confident in our 2020 adjusted EBITDA growth outlook of greater than 20% compared with our 2019 guidance midpoint. The impressive production results across our operations highlight the widespread quality of our operating basins and well-capitalized and experienced producers operating there. The volume growth we discussed today has high visibility as both NGL and natural gas volumes are ready and waiting for processing and transportation now. Producers are looking to ONEOK to provide the critical infrastructure they need to connect their products with demand markets and we are well equipped and ready to grow our operations efficiently in order to do so. I'd like to recognize our large project teams and operations personnel located both at our headquarters and at our various field locations for their hard work to keep our growth projects on time and on budget and specifically to those working on our Elk Creek pipeline who were able to place the southern section in service early benefiting many of our customers. Thank you to all our employees for your dedication to our customers and dedication to ONEOK. Your continued focus on safe and responsible operations has led to our continued reliability and operational success. With that, operator, we are now ready for questions.

Thanks and good morning. You mentioned in the press release having significant upside in the second half of the year from the early start of Elk Creek and other projects as well. Where do you see 2019 EBITDA number was added relative to the midpoint? And to the extent it was that high to the midpoint do you still see a 20% growth rate between 2020 and 2019?

No, we haven't changed any of our guidance and don't expect to do that today on this call. Obviously, as we get through the year we will continue to evaluate whether we're going to adjust that. But right now we're giving that outlook on 2020 off of the midpoint to let people have a basis on which to think about it.

Thanks for that, Walt. DCF was pretty strong during the quarter. And it looked like it potentially came from Northern Border, anything going on there?

Nothing really out of the ordinary. Northern Border made an off-cycle distribution, in addition to our normal quarterly distribution in the second quarter, but nothing out of the ordinary course of business.

We shouldn't expect that to continue going forward?

I'm sorry, can you say that again?

We should expect any more off-cycle distributions for the balance of the year?

Now, it's a distribution in excess of earnings for the quarter, and that catches us up. So distributions going forward will track with earnings as they have in the past.

Got you. Last question for me, to the extent that you continue to see strong production out of the Bakken for liquids, any thoughts on a potential residue gas takeaway solution?

I think, I mean, clearly there, you know, it's something we're looking at, we're paying attention to. When you look at the capacity that's getting ready to come online across the basin. And, you know, we do believe we can continue to, in the basin we will continue to displace gas coming from Canada. But absolutely, there are conversations going on, you know, a variety of different outlooks and we're participating in all those conversations.

Thanks, Kevin. Those are my questions.

Thanks.

Hey, guys, good morning. Nice to see you in execution. Thanks for taking my questions. Well, I just want to circle back on that question Danilo had asked about Northern Border. Just for my own edification to understand is, I guess, what's the mechanism for that? This cash build at the JV and then you and your partner make the decision to pay that out on a periodic basis?

Yes, to the extent that, over time, we make a regular quarterly distribution, and to the extent the Management Committee believes that there's a capacity to do more than that. They have the ability to do it on a one-time basis. And that's what happened here.

And as it pertains to DCF guidance and things of that nature, this was anticipated to fall this year. Is that also correct?

I think it's fair to say that as we develop our plans throughout the year, we expect distributions to align more closely with what we've seen on a quarterly basis.

Okay. All right, great. And then if I could switch and just, Kevin, I wanted to touch base, you guys have done a really nice job continuing to contract up Arbuckle to seemingly every quarter we get another 20,000 or 25,000 barrels a day of commitments there. And I just wanted to better understand or just I guess, review and remind myself as to where the volume slate now for that pipeline will be sourced I guess between what said to it from Elk Creek what comes from the Mid-Con plants and then what comes from third parties, is there a rough rule of thumb at this point given all the incremental contracts that you have had?

Well, I mean, it varies as we contract new plants. Obviously, if you're getting a plant in the Mid-Continent and new contracted plant that's going to be tied, you know directly to Arbuckle II as we get a new Bakken plant if those barrels are going to all go all the way to Belvieu then that will be included in both Elk Creek and Arbuckle II. So that's how we break it down.

I think that's right, so definitely you can see that on a very macro sense of the difference between what we've contracted for Arbuckle II and what we've contracted for Elk Creek. That difference is definitely coming out and they call it.

Okay. If I look at the table you provided regarding the bundled rates for your NGL raw feed service, I want to ensure I'm appropriately crediting each of these two assets without counting the volume from Elk Creek that also moves down to Arbuckle II more than once. Is it reasonable to credit the Elk Creek volume with the bundled rate for the Bakken portion and then consider the additional volume above that at the Mid-Continent rate? Is that a sensible approach, or would you suggest a different method?

No, I think that's a fair way to think about it.

Okay. All right. Great. Thanks for taking my question, guys.

Thanks, Chris. Sure.

Good morning, guys. Just on the expansion project for Mid-Con frac capacity. You talked about that in prepared comments just about the heavier barrel. Is this purely really just optionality for you guys in the customer or just kind of curious could you talk about sort of the need for new capacity there relative to what the projects you have going on at Belvieu?

I think it just came down, a lot of it just came down to we had the ability as our teams looked at how we provide more fractionation capacity, but that was a low-cost option for Williston and would drive the best return. With our other pipes, clearly we'll have the ability to move those purity products down to Belvieu once Arbuckle II is up. So we do get that optionality. But it really came down to where we look at where we could provide the lowest cost, most efficient frac capacity.

Great. To follow up on your commentary about the potential range for 2020 CapEx compared to 2019, should we consider this only in relation to the projects you have already approved, or does it also include other potential projects that may not yet be officially approved?

No, I think that our expectation given everything that we see going forward, both what we've been able to announce. And we're thinking we have lower CapEx in 2020 than it will be in 2019.

Appreciate it. Thank you guys very much.

Thanks.

Hi, everyone. Great quarter. What is the financial benefit going to be when rail and third party frac costs roll off? I'm assuming it's all off by the first quarter next year when all your assets are online. But could you provide the cadence of the roll off between now and then as well?

Well, I guess what we talked about previously, the way to think about that is the barrels that have already rolled off rail, I think we said we save about $0.20 per gallon of transportation costs. So as we put more barrels on rail through the rest of this year, then the next step will be when the full pipeline is in place and all those rail barrels move to the pipe then you'll see another uplift at that point, along with other volumes coming from processing plants when the flare start getting put out when the processing capacity comes online. Did that answer your question, Christie?

Yeah, I guess. Okay, but you've moved 30,000 barrels per day off right now with the southern portion coming on. But you're still continuing to rail. So I guess and I'm guessing the rail is still going to increase throughout the end of this year. So at what point does that peak, like how much are you railing today and how much do you expect to rail at the peak between now and year-end?

The rail volume decreased significantly when we started using the southern section, bringing it close to zero. As a result, we temporarily halted most operations. However, we anticipate that rail volume will begin to increase as new plants come online ahead of Elk Creek's service commencement. Once those plants are operational, rail volume will gradually rise, and ultimately, when the complete pipeline is established, all of the volume will be transferred back to the pipeline.

Okay, got it.

Christine, this is Sheridan. We think by the time we bring Elk Creek back off when we get the Northern section of Elk Creek completed, we will be railing upwards of 30,000 barrels a day again.

Okay. Super helpful. And then your contracted bubbles on Elk Creek is approaching capacity. Can you remind us, how long it would take to expand the pipeline, if you decide to do so. And also discuss at what point you would do that just given it's probably low cost and your numbers is too minimal ethane extraction, and I'm not sure at what point that might change?

We look at it continually. Clearly those projects aren't two-year projects like building the pipe. They're measured in terms of months, not years. And we also have the ability to do things like ordering Thompson and a lot of the long lead time of long lead equipment and other engineering things we can go ahead and do to prepare for that. So that it drives the time required to get that done again just a matter of months.

Okay. And then last one for me there was an increase in Bakken processing volume, but your NGL pipeline volumes remained flat. What was the reason for that?

We just drove our ethane rejection just continued to drive deeper and deeper. So to get more throughput through the plants and remain the pipe, the NGL takeaway was at capacity. So we were able to, through our plants drive deeper rejection and run more inlet but not produce as much liquids.

So, you are doing max rails to the quarter to then?

I mean towards the year, yes, but that we were pretty much at max rail.

Hi. Good morning, everyone. I'm curious, if you can just comment a little bit, obviously NGL prices have been pretty volatile. I was curious for your latest views on how you see things trending for the rest of the year and into 2020. And then kind of related to that, if you have any different or updated views on how the Conway to Belvieu spread is going to trend here for the rest of the year?

Michael, this is Sheridan. I think as we look at the overall price, if you keep crude at the level it is today, you'll see a little uptick in prices. Obviously we're seeing more export capacity for propane come online, which should create more demand and you're seeing more crackers come online. That you should see some uptick in absolute price here through the end of the year and into 2020. Not a huge spike but I think you'll see some strength. On the Conway to Belvieu spread right now, we think that where it is today is where it's going to be or in this range through the third quarter and start into the fourth quarter. Then you'll get into some seasonality issues that probably will bring that spread in a little tighter than it is today. Then of course, as we've said before, once we bring Arbuckle II online, that spread will go back to more what we have seen historically, which is much narrower than we have today.

Okay, great. I appreciate that. And then just this recent slate of projects that you just announced. So we just think of their returns on those projects. Would you consider those to be kind of within the normal course of your typical return profile or those would be better, because some of them are kind of bolt-on in nature? How do we think about that? Thanks.

Yeah, Kevin here. I believe the plant projects will fall within our usual range of 4 to 6 times, but several of the expansions and frac expansions we've discussed can be achieved at lower costs, and the new constructions are expected to perform even better than that.

Thank you.

Hi, good morning. I appreciate that you guys are not updating guidance at this point. But just curious within the G&P and the gas pipeline segments. It seems like you guys are trending quite strong versus the ranges that you put out there. Is there anything in the back half of the year that could kind of temper this trajectory or is kind of like the high-end or above the high-end seems like it could be possible for those?

Jeremy, this is Chuck. Let's start with G&P. I believe we have the potential to trend higher. This increase will primarily come from our pipeline infrastructure and some of our facilities becoming operational. Timing will be crucial as we approach the end of the year. Regarding our gas pipeline business, we've experienced strong demand not just for our interoperable volumes, but also for our balancing and short-term storage services, which are contributing some unexpected earnings. Both segments are performing well right now, demand is rising, and we are focused on meeting our customers' needs.

Great. That's helpful. And then, thinking about the balance sheet here, it seems like I think before the leverage is going to peak, I think at the beginning of 2020 with all the projects coming online. You've added some more to the backlog there and or you did more broad into what you're going to do? And just wondering how you see leverage, I guess, moving across 2020? Is that still the same peak or any color that you could provide on how that all comes together?

Well, Jeremy, our heaviest spending is definitely in the third and fourth quarter of '19. So when you enter in that first quarter, we've said that, with Elk Creek coming on in the fourth quarter and the volumetric disclosed, the guidance that we've put out there as it relates to our expectations of how quickly Elk Creek is going to build its volume around that 100,000 barrels, we're going to see a significant uplift in our EBITDA in the first quarter of 2020. And throughout 2020 and that's going to deliver us right from the get-go in 2020. So, as we cross over the year, that'll be our peak. The projects that we've announced to date will be towards the back end of 2020 and into 2021 from a CapEx spend and will already be well down our road to delivering and in my prepared remarks, I gave you some thoughts on where we might end the year. So we're going to see in the same trajectory and still looking for some significant delivering going forward.

That's helpful. That's it for me. Thanks.

Hi, good morning, everyone. I'm interested in understanding how you phase in the fracs. Could you explain how bringing on a frac in stages works?

Yeah, Dennis, it's Kevin. Well, in this case with our complex down there, we had some spare capacity for somewhat I'd call it kind of utilities, some refrigeration, some heaters that are typically long lead equipment, long lead time type equipment items. And so we're able to leverage some existing spare capacity, we have to bring up the frac and kind of in a partial mode. And then as we've installed the rest of that equipment, that's what we'll get it up to full capacity in '20.

Okay, so the vessel is ready, and I guess the follow-up question is, if you're utilizing that capacity, should we anticipate that it will be a model for frac 5 as well?

We'll evaluate it. We may not have the same type of spare utilities, if you will for frac 5. But that's something obviously we'll take a look at a variety of different things to do, but I wouldn't expect that to happen for the MB-5.

Thanks for that. Just to clarify about the Northern Border distribution, Danilo and Chris both mentioned it, but this one-time payment wasn't included in the guidance, correct? So we should refer to the guidance while considering this one-time payment. If we include that, does that mean we should expect to be above the guidance?

It's fair to say that that was not included in the original guidance.

Perfect. That's what I need. Okay, that's it for me. Thanks.

Hey. Good morning everyone. Just maybe going back to the 20% growth expectation for next year. I'm not sure we've seen you guys highlight that in a while here. Maybe not since the original guidance was provided. So getting the sense of that means you're getting pretty confident of that figure. So curious how you are thinking about some of the underlying assumptions to get there maybe just around commodity differentials and some of the base business growth. You made some comments earlier just around the differential outlook. But if you just expand there in the context of that 20% growth next year?

Yeah, this is Kevin. I mean, I think the obviously the huge driver there is the backlog of flared gas and the inventory we talked about up in the Bakken. And when you think about to just kind of put the math to the 100,000 barrels a day that we expect on Elk Creek by the first quarter. And you put that out over the course of the year, and then you've got a full Demicks Lake II plant running full for the entire year, you got Demicks II ramping up and then you've got growth on the Permian and Mid-Continent as well. But when you just go back to the 500 million cubic feet a day that's flaring in the Bakken across the basin, and the processing capacity that's coming online between now and the first quarter that just generates a significant amount of NGLs, which is the primary driver for the '20 number.

Got it. If I'm understanding correctly, it seems that there isn't any significant change being indicated outside of that or any notable commodity or differential movement. Is that accurate?

That's fair. In fact, we've been talking very openly as shared and mentioned, with Arbuckle-II we expect spreads to come back in much narrower than they are today. And that is included in that, that assumption is included in that 20% greater than 20%.

Got it. Got it. Okay, appreciate that. And then maybe just more broadly, and how you're thinking about your Mid-Con footprint longer term? And, clearly the most of your growth is really focused outside that area. And I guess lately, producer commentary, there has been somewhat lukewarm. So just curious, what sort of optionality do you have around that footprint, maybe offset some potential volume headwinds sort of pass-2019 or if you think that's even fair to be cautious on the Mid-Con at this point?

In general, the Mid-Continent volumes have matched our expectations. While a few producers may not have performed as well, others have exceeded our forecasts. We continually remind others that we base our expectations on our system's footprint and size, considering both G&P and NGL segments. As we project future forecasts, we take all of this into account. We are optimistic about growth in the Mid-Continent as we move forward.

We're still planning on hooking up another two more plants in the Mid-Continent second half of this year. So we're still seeing some need for capacity.

And what I would add from model G&P standpoint would be, I think our well connect guidance that we gave, were trending as though we're going to exceed that, and I think we probably well this year.

Got it. I appreciate that. Just one last quick one if I could and sorry if you guys touched on it, just around LPG exports, obviously has been considerable amount of new capacity announcements made recently. I imagine that factors into your market outlook. So just how you thinking about that now?

I think we definitely agree with that. And again, as we discussed earlier, there are a variety of projects being discussed in different avenues to get more residue out, but clearly if we stay on a growth trend, the basin is going to need some additional takeaway capacity over the next two, three, four years.

Okay. That's a good thing. My next…

No, I just said well beyond that.

Okay. Thank you. I was just going to ask, it looks like we might need a new gas export pipe to handle that volume do you agree with that and is that a project you're getting?

Yes. I think we definitely agree with that. And again, as we discussed earlier, there are a variety of projects being discussed in different avenues to get more residue out, but clearly if we stay on a growth trend, you're going to need some additional takeaway capacity over the next two, three, four years.

Okay. Moving down the south. How has the decline in NGL prices impacted, if at all, the rates and negotiations with customers for frac capacity?

It has not impacted them at all. We are going to reprice our services based on alternatives, also what the marketplace is. And remember that NGLs are byproducts, it needs to be taken away in areas where people can't get the capacity, they are flaring with what they say. So the absolute price of the NGL does not have an impact on what we can charge for our services.

And the market's still fairly tight?

Market's fractionation capacity is still pretty tight, there is a lot coming on. And pipeline capacity obviously tight because we're building new ones as we come on, as well. So yeah the market is still fairly tight in all areas.

Okay. And then last question. There are a lot of assets on the market and a few whole partnership, what's your appetite for M&A here?

Ethan, this is Terry. Not very high, candidly, when you look at the gross laid of opportunities that we have going forward. When you think about it from an accretion standpoint, we are talking dollars a share and additional earnings to come to the Company over the next several years. We can really get that from strategic M&A. Now there may be some assets from time to time that we could buy with cash that could make some sense. But right now, we really don't see anything out there that's that compelling or valuations, in particular that makes sense particularly when you think about the alternative we have to invest organically.

Okay. Thanks you all. Much appreciated.

Good morning. Congratulations on another great quarter.

Thanks.

Thanks Craig.

On the G&P unit fee-based margins, that look to be a record in the second quarter. Is that sustainable and what's driving that?

Craig, this is Chuck. We guided to $0.90 to $0.95, we are at $0.93 today. Obviously, with more Bakken gas coming out, it's higher margin relative to our Mid-Con business so that's part of the driver. In addition to that you get in the contract mix, different producers we have different fees. And so is it sustainable? I think we are solid in that range.

Okay, great. I want to understand the system integration aspects related to Arbuckle II and the potential modularity of your system. Currently, you are starting at 400,000 and experiencing an increase of 5,000 daily. You contracted 375, but if you switch to the Sterling III purity product, any excess wide grade that hasn't been fractionated would need to go to Arbuckle II. This could result in directing all the growth from West Texas LPG into the Southern Leg of Arbuckle II. I'm trying to figure out how quickly the entire system can fill up.

That's a great question. We're examining how quickly we can expand capacity, and as we've mentioned, we can add pumps relatively swiftly moving forward. You're correct to highlight that the modularity and optionality of our system provide us with considerable flexibility. Currently, Sterling III operates on a royalty basis, and we plan to direct all of Sterling III's raw feed to Arbuckle to enhance purities, which is why we believe the spread will align soon. We anticipate ramping Arbuckle up to 1 million barrels quickly as capacity comes online, as we project. We also believe we have the ability to exceed the 1 million barrels threshold, as we have some uncontracted capacity available. We expect to be operating at the upper end of Arbuckle II, and a full pipeline is positive for us. If necessary, we are prepared to construct an additional pipeline to accommodate increased volume.

The northern section of Arbuckle II has a different capacity compared to the southern section, correct? So if you take the West Texas volumes and adjust for 1 million barrels, that's related to the northern section, right?

The Northern section has a capacity of 600,000 barrels, while the Southern section can handle 1 million barrels. This configuration allows for 400,000 barrels a day available for West Texas sales without affecting the volume flowing from the north. This was the design and plan from the beginning. We anticipate that we could see up to 400,000 barrels moving from West Texas to Arbuckle II.

And then if I understand it that would free the southern section of West Texas for potential crude service?

That's correct. As we aim for 400,000 barrels a day from West Texas, we will need a new pipeline from the Permian to Arbuckle II. This will release the legacy West Texas system from the Permian to the Gulf Coast for other services, including crude.

I understand. Moving the wide range from Sterling III to Arbuckle II is unrelated to the 375 a day contract. The 375 is additional to your current volume. Transferring capacity to benefit from the purity product is just a bonus.

That is correct. The 375 does not include the volume that's moving on Sterling III today.

Right. Thank you very much.

Yes, good morning everyone, and thank you for the clarity during the call. I have a quick question regarding the G&P segment. The results were quite strong, and I observed that your operational expenses in that segment decreased sequentially compared to last year, despite a reasonable increase in volumes. I'm curious if there's anything specific driving that change, as I know commodity prices, particularly gas prices, can influence those expenses. I would appreciate a bit more clarity on that.

Yes, this is Chuck. We are about $6 million lower sequentially, mainly due to timing between the quarters. If you average those two quarters together, the run rate might be slightly higher as we move towards Demicks I and II, increasing the number of employees and field costs, but those are solid numbers for the year.

Okay. And gas is more like a pass-through cost that natural gas prices don't really impact that number, correct?

No, it does not impact that number.

Thank you for that. I'm looking to gain a clearer understanding of the LPG export situation. I've heard about several dock expansions being implemented, which may be causing some limitations in transporting LPG volumes to end customers. Do you have any insights on this? Additionally, since you are in communication with customers on the LPG side, is there a way for your team to leverage this situation as an opportunity?

I mean, again, as Sheridan kind of alluded to on the dock question. Yeah, there have been announcements out there, there's more capacity that's going to be announced. We do see some of the short-term rates or spot rates have been pushed down. But like Sheridan mentioned, I think the key is, as we talk to customers, we're looking longer term, we're looking for rates are going to economically justify a project. And that's the way we'll approach it.

Okay, got it. Thanks, guys.

Hey, guys. How you guys thinking about what a 2021 step up looks like versus 2020? I mean you've got a lot of projects that come online in ‘20. And trying to think about how much that 20% plus captures that for 2020 versus what drives a ‘21 step up?

Michael, I think that we're definitely not going to give you 2021 guidance, and we're stepping out a little further than we usually do and give you to an outlook on 2020. So you're going to have to do your own work here. But if you just take the capital that we're investing and recognize that we're in the same multiple in some of these incremental projects or even at better multiples, 2021 is looking pretty good too.

Got it. Do you still assume a 4 to 6 times multiple on most of these projects, or do you think some can even be better than that once you get a full run rate?

I believe the frac is an excellent example of adding capacity at approximately half the cost of construction, which is certainly preferable to a 4 to 6 times multiple.

Got it. Okay, guys, thank you. Much appreciated.

Sure.

All right. Well, thank you, everyone. 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 will provide details for that conference call at a later date. Thank you for joining us and the IR team will be available throughout the day for your questions. Have a good week.