Andrew Ziola - IR Terry Spencer - President and CEO Walt Hulse - EVP and CFO Kevin Burdick - EVP and COO Sheridan Swords - SVP, Natural Gas Liquids Chuck Kelley - SVP, Natural Gas

Shneur Gershuni - UBS Christine Cho - Barclays Michael Blum - Wells Fargo Elvira Scotto - RBC Capital Markets Danilo Juvane - BMO Capital Markets Jeremy Tonet - JP Morgan Dennis Coleman - Bank of America Craig Shere - Tuohy Brothers

Good day and welcome to the Second Quarter 2018 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, Brad, and good morning. And welcome to ONEOK’s second quarter 2018 earnings conference call. This call is being webcast live and a replay will be made available. 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 CEO of ONEOK. Terry?

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. On today's call, we'll discuss ONEOK’s second quarter financial and operational performance, our updated financial guidance included in yesterday's earnings announcement and share our progress on our more than $4 billion of capital growth projects. As we noted in our release yesterday, the high level of productivity continues in the basins where we operate. Our consistent volume growth underscores the strong performance of our supply customers across our asset footprint. And while NGL pricing spreads and optimization are noteworthy, the fact is our core business, the fee based services we provide for both natural gas and natural gas liquids customers continues to expand with incremental volume growth across our system and is the largest contributor to our earnings growth this year. And we are well positioned for additional volume growth through incremental investments at attractive returns. Our long term strategy remains focused on expanding our integrated assets through capital growth projects and strategic acquisitions that fit within our footprint and provides sustainable long-term fee based earnings. Yesterday, we completed the acquisition of Martin Midstream’s 20% interest in the West Texas LPG pipeline. With that acquisition, ONEOK became the sole owner of West Texas LPG, a strategic step in our broader Permian Basin strategy and further positioning us for expansion opportunities, some of which are in the late stages of negotiations. Construction on our organic growth projects is progressing as planned and Kevin will provide more detail on those projects in a moment. With that, I will now turn the call over to Walt.

Thank you, Terry. ONEOK’s second quarter operating income totaled nearly $450 million, a 40% increase year-over-year and a 7% increase compared with the first quarter 2018. Second quarter adjusted EBITDA was $602 million, a 30% increase year-over-year and a 6% increase compared with the first quarter 2018. During the second quarter, we paid a dividend of $0.795 and last week, we announced another 4% increase to $0.825 per share or $3.30 per share on an annualized basis, in line with our previous guidance. The dividend is payable on August 14. At June 30, our debt to EBITDA on an annualized run rate basis was 3.4 times and 3.66 times on a GAAP trailing 12-month basis. We generated more than $160 million [Later changed by the Company to $126 million] of distributable cash flow in excess of our dividends paid in the second quarter, a 9% increase compared with the first quarter 2018. Total distributable cash flow in the quarter was more than $450 million, with healthy dividend coverage of nearly 1.4 times. We have proactively managed our future debt maturities and liquidity with our $1.25 billion senior notes offering completed in July. Proceeds from the offering were used to repay short-term borrowings and together with excess distributable cash flow will fund our upcoming debt maturity and help fund our capital growth expenditures. As of today, we have approximately $900 million in cash and $2.5 billion available on our credit facility. We continue to maintain a strong balance sheet and significant liquidity as we construct our capital growth projects. With yesterday's earnings announcement, we increased our net income and adjusted EBITDA financial guidance midpoint expectations and narrowed our financial guidance ranges. The midpoint of our net income guidance increased $30 million to 1.09 billion and our adjusted EBITDA midpoint increased $35 million to 2.35 billion. These guidance increases are primarily driven by expected continued volume growth and our NGL optimization and marketing results. If the optimization spreads maintain at these levels and no severe weather occurs in the fourth quarter, we could easily be at the high end of our guidance range. I’ll now turn the call over to Kevin for a closer look at each of our businesses.

Thank you, Walt. Starting with the performance of our natural gas liquids segment, NGL volumes gathered in the second quarter averaged 903,000 barrels per day, a 12% increase compared with the second quarter 2017 and a 6% increase compared with the first quarter 2018. Volume growth remained strong, as we have averaged more than 930,000 barrels per day in July. Two new third-party natural gas processing plants were connected in the STACK and SCOOP areas in the second quarter where strong producer results and increased ethane recovery continue to drive higher volumes. Mid-Continent gathered volumes averaged 569,000 barrels per day during the quarter, an 8% increase compared with the first quarter 2018. Our Bakken NGL Pipeline remains full and we began railing NGLs out of the region during the quarter. We expect to be able to rail up to 30,000 barrels per day to provide interim takeaway capacity until the Elk Creek pipeline is in service. NGL volumes fractionated averaged 696,000 barrels per day during the second quarter, a 12% increase compared with the same period last year. We expect to be toward the high end of our guidance range of 650,000 to 725,000 barrels per day fractionated in 2018. As total NGL volumes increased across our system, ethane volumes are also increasing. We had approximately 60,000 barrels per day of additional ethane on our system in the second quarter compared with the same period in 2017. The increase has continued in July with more than 70,000 barrels per day of additional ethane on our system compared with the same month last year. With a strong volume growth across our system, pipeline utilization has increased, which has led to a higher than anticipated location price differential for ethane priced in Conway. This price differential is causing Conway priced ethane to remain in rejection. Even without the Conway priced ethane being recovered, we are well on our way to achieving our volume targets. We continue to expect ethane production across our system to increase during the second half of this year, as petrochemical companies complete expansion projects and exports increase. Last week, the startup of another Gulf Coast ethane cracker was announced, which is approximately 90,000 barrels per day of additional demand and we expect several additional petrochemical facilities to come online by the second quarter 2019, totaling more than 200,000 barrels per day of new ethane demand. Optimization and marketing activities in the second quarter also contributed to the segment’s higher adjusted EBITDA, with increases of $23 million compared with the first quarter 2018 and nearly $50 million compared with the second quarter 2017. Wider location price differentials between Conway and Mont Belvieu and the sale of NGL inventory previously held contributed to the increases. We continue to expect transportation capacity from Conway to Mont Belvieu will remain highly utilized due to growing NGL volumes, which we expect will sustain current spreads until Arbuckle II is placed in service. Moving on to the natural gas gathering and processing segment. Adjusted EBITDA for the segment increased 30% compared with the second quarter 2017 and increased 28% compared with the first quarter 2018, driven by volume growth in the Williston Basin and the STACK and SCOOP areas. Producer activity across our dedicated acreage remains strong. Second quarter natural gas volumes processed averaged nearly 1.8 billion cubic feet per day, a 17% increase compared with the second quarter 2017 and a 3% increase compared with the first quarter 2018. During the second quarter, ONEOK’s natural gas volumes processed in the Rocky Mountain region averaged 932 million cubic feet per day, more than 100 million cubic feet per day higher than the same period in 2017 and a 5% increase compared with the first quarter 2018. We connected 210 wells in the Williston Basin and 26 wells in the Mid-Continent during the second quarter. We now expect well connects to total approximately 680 for the year, with 550 well connections expected in the Williston Basin and the remainder in the Mid-Continent. We have approximately 60 million cubic feet per day of available processing capacity and we’ll add an additional 200 million cubic feet per day of capacity in Oklahoma in the fourth quarter of this year, with the expected completion of our Canadian Valley plant expansion, which remains on schedule. In the Williston Basin, we have approximately 125 million cubic feet per day of available processing capacity, including the recently completed expansion of our Bear Creek plant, which increased its capacity to 130 million cubic feet per day from 80 million. We continue to look at additional plant and compression and expansion opportunities in the basin in addition to our 200 million cubic feet per day Demicks Lake plant that is under construction and expect it to be complete in the fourth quarter 2019. The segment’s average fee rate increased to $0.89 per MMBtu in the second quarter 2018, above our original guidance of $0.80. Higher fees have been driven by greater than expected volume growth in the Williston Basin and higher volumes on contracts that have higher fees. We now expect our average fee rate to be in the range of $0.85 to $0.90 for 2018. In the natural gas pipeline segment, second quarter adjusted EBITDA increased 6% year-over-year, benefiting from higher interruptible transportation volumes and decreased 9% compared with the first quarter 2018, primarily due to normal seasonality. In June, we announced four expansion projects to provide additional takeaway capacity in the Permian Basin and STACK and SCOOP areas by up to a total of 1.7 billion cubic feet per day. The projects include an expansion of ONEOK’s WesTex Transmission system from the Permian Basin to the Texas Panhandle; a project to make Roadrunner Gas Transmission bidirectional to transport natural gas from the Delaware Basin to additional markets at Waha, and both westbound and eastbound expansions of ONEOK’s gas transportation system in Oklahoma to accommodate growing volumes from the STACK and SCOOP areas. These capital efficient expansions will quickly create critical takeaway capacity and offer additional optionality for natural gas producers and processors in these areas. The open seasons have concluded on the WesTex, Roadrunner and ONEOK gas transportation westbound projects. We've received strong interest on the projects and we’ll provide the results once all bids have been analyzed and contracts finalized. Now, a quick update on our growth projects, starting with Elk Creek. We have begun construction on the southern portion from the Powder River Basin area to the Mid-Continent and we continue to expect this section to be completed as early as the third quarter 2019, which should help alleviate some capacity constraints in the Williston Basin before the entire line is in service. We expect the entire project will be complete by the end of 2019. We've also contracted an additional 20,000 barrels per day on Elk Creek since our last call, bringing the total contracted volume to approximately 140,000 barrels per day. We are currently buying right away [ph] for Arbuckle II and remain on schedule for that project, which is expected to be complete in the first quarter of 2020. We've contracted an additional 30,000 barrels per day on Arbuckle II, bringing our total contracted volume to approximately 290,000 barrels per day. Site work has begun on our 125,000 barrel per day MB-4 fractionator and we remain on schedule for this facility to be complete in the first quarter of 2020. We remain on schedule to complete our 110,000 barrel per day extension of our now wholly-owned West Texas LPG pipeline in the third quarter and we are in late stage negotiations with several producers and processors in the region for additional expansions. As those deals are finalized, we will announce them. Lastly, the 60,000 barrel per day expansion of our Sterling III pipeline is also on schedule and is expected to be completed in the fourth quarter 2018, which will provide additional capacity for growing Mid-Continent volumes. Terry, that concludes my remarks.

Thank you, Kevin. These calls are a great way to discuss operational performance and earnings results, but they don't always allow time to discuss the many other valuable and business enhancing initiatives happening at ONEOK. Whether it's implementing new technology to help our employees stay safe, volunteering time in our communities, improving pipeline safety monitoring or protecting the environment, our employees are doing great things for our business and for the communities where we live and work. So thank you to our employees for all of your efforts. Within the next month, we'll be publishing our 10th Annual Sustainability and ESG Report, which will highlight these initiatives and many others. I encourage everyone to review the report. To all of our investors, thank you for your continued support of ONEOK, our operations and our strategy for growth. So with that, we’re now ready for questions operator.

[Operator Instructions] And our first question comes from Shneur Gershuni with UBS.

My first question, I was wondering if we can talk about kind of the drivers related to guidance. You tightened up the low end of the guidance range and so forth, but I was wondering if you can talk about the higher end of the guidance range? What we would need to see to be able to hit the higher end? Is there some specific drivers that you think that are likely to happen? Are there some macro events that we should be thinking about? Any color around hitting the higher end would be appreciated. Thank you.

Sure. Shneur, as Walt indicated in his comments, he mentioned that optimization margins, going forward, if they stay about where they are, we could see hitting the high end of the guidance pretty easily, particularly also if we see some -- a little bit less severe weather than we've typically planned in our G&P segment. So, certainly optimization spreads, as we've proven, are very difficult to forecast with any degree of certainty. We really don't see anything fundamentally that could -- that will change or compress these spread, but certainly we’ve factored in some cushion in our current guidance. But again, let me reiterate, if we see these optimization spreads kind of stay in this $0.20 a gallon range throughout the end of the year, we can see some upside, particularly in this NGL business. Certainly, the high end of guidance is very achievable, if that happens.

So to clarify, kind of the midpoint of your guidance does not assume that the spreads that we're seeing maintain themselves, but if they do and you're not forecasting one way or another, then you would definitely be able to hit the high end. Is that a fair paraphrase?

That's right on.

All right. Perfect. And a follow-up question, just wanted to dig in on Mid-Con volumes a little bit and I think you guys kind of touched on it in pieces in your prepared remarks, but is it a scenario where ethane is backing up the gas pipelines, the Permian with what it's doing is sort of backing up the entire system, are there de-bottlenecking issues that just sort of need to be taken care of and we can see an upside opportunity for Mid-Con volumes, as [indiscernible] are worked out. I was just wondering if you can sort of talk about kind of the steps and where we are with that.

Hey, Shneur. This is Kevin. No, we don't see bottlenecks from a standpoint of the ethane that's being left in, creating residue issues. Our producers, from what we hear, both are, on our G&P side and overall producers from an NGL standpoint, continue to have great results. We haven't seen them back off at all and we definitely expect those volumes to increase as we move through the rest of this year and into ‘19.

So is it fair to say the Mid-Con is kind of a timing issue right now?

For our G&P business, yeah, a lot of timing and then the slight reduction in the well count in well connects that we put out there is just really, maybe slightly less than one rig and some timing is all that drives that, but no, still feel good about where we're at from a volume perspective.

[Operator Instructions] Our next question comes from Christine Cho with Barclays.

I was wondering if we can get an update on the utilization levels on Sterling and Arbuckle and if you could provide some insight into which products you're optimizing the most at the moment?

So, we'll turn that question over to Sheridan.

Christine, this is Sheridan. Right now, in the Sterling pipeline, we're still in that 80% to 90% utilized range, even though we had a bit more volume in the second quarter than we did in the first quarter. And then on the Arbuckle pipeline, we're in the 85% to 90% range and we were moving all of the Y grade [ph] we can out of the Mid-Continent on Arbuckle at this time.

Okay. And which NGL product are you optimizing the most at the moment?

Ethane and propane are the ones we’re optimizing the most and that's just really driven by the fact that those are the two products that we have the most on our system. So, we're still optimizing butane as well, because it has a very nice spread, but we just don't have as much butane as we have ethane and propane.

Okay. And then I noticed that you guys took out the language that ethane rejection is expected to decrease to 70,000 barrels per day by year end. With Conway ethane frac spreads expected to be negative and the producers that are priced off Conway expected to continue to reject ethane, what do you expect your ethane rejection exit rate to be now?

I think, Christine, this is Kevin. I mean, we – clearly, we're not going to -- we won't be at the 70,000 barrels per day but – of rejection at the end of the year, with Conway still being rejected, but I think the key there is that ethane that's not coming on is giving us the space for the optimization and will more than make up the value, if you will, that wouldn't come from the Conway barrels that would be recovered, will more than make up for that with optimization. So that's kind of where we sit today with these widespreads, no, we don't expect that to come out by the end of the year, but we're going to more than make it up with the optimization.

Okay. And then one more if I could. Can you give us an idea of how much your Mid-Con contracts are priced off Conway versus Belvieu? And then if -- and then are all the Bakken contracts priced off of Belvieu?

We won't give that much breakdown, but at the macro level, all the contracts, you're probably 60-40 Belvieu to Conway.

60-40 Belvieu-Conway. Perfect. Thank you so much.

Thank you. And our next question comes from Michael Blum with Wells Fargo.

Hey, good morning, everybody. Just wanted to clarify or get confirmation. The incremental contracting you did on Elk Creek. That’s coming from Bakken, producers of Bakken volumes. And sort of the follow-up question to that is, do you have any update on the potential to add either DJ volumes or even potentially Western Canadian volumes to Elk Creek?

Yeah. Michael, it’s Kevin. The 20,000 barrels a day is coming out of the Bakken. I mean, that's I think primarily coming out of the Bakken, maybe a little bit out of the Powder. But in -- and discussions continue to go well up there. I mean, you're seeing a lot of growth across all the G&P companies in the Williston, as producers continue to have great success in the Williston and we've seen a lot of activity in the Powder as well and the DJ. So, a lot of conversations going on with producers about additional volume. Sheridan?

The one thing I would add is, we talk to the contract that we’ve already – the people we've already contracted with, their ramp-up schedules have been moving forward, so we think that we will ramp up to our contracted volume quicker than we originally thought.

And then kind of a minor issue I guess, but just more curious on the dynamics. The North System, is there anything out of the ordinary going on there, given the delays with Mariner East II getting into service and who they’re servicing [Technical Difficulty] over there? Thanks.

Shifting on the North System that's been affected by Mariner East or what's going on there, I mean, the North system was down in the second quarter versus the first [ph] quarter, but that's more seasonality that we see every year. We still do receive volume into the Conway off of rail out of the Marcellus and that's probably driven by the Mariner East issues, but we’ve been receiving those for quite some time. But I don't think it's enough to really affect the North-South spread or affect anything on the North System.

Thank you. And our next question comes from Elvira Scotto with RBC Capital Markets.

Hey, good morning. So what are some of the benefits that you guys see with the full ownership of West Texas LPG versus only owning 80%? Is it just the ability to deploy more capital?

Well, so, Elvira, one of the key things to make note of with -- when you have a partner and particularly if that partner is trying to monetize and create liquidity, you could wind up with a partner that doesn't necessarily fit with us. So, you have some risk there. So we've taken that risk off the table, but I think probably the most important thing is the ability to freely integrate that pipeline system in with our existing NGL business. When you've got a partner that's got a 50-50 vote, which is basically how it the JV was structured, long ago when Chevron owned it, you've got -- you want to be on the same page obviously and so the thing that -- the risk that you – the risk that you run is that you can't -- you don't -- you're not perfectly aligned, if you've got somebody else involved and as a result, you may not be able to do all the things you want to do with that pipeline asset. So by taking out Martin, we clean that up and now we own it 100% and now we can more effectively, without risk, integrate that business and take advantage of all these synergies that that asset has with our existing business and existing assets. Did that help you?

Yes, very helpful. Thanks. And then in your -- you mentioned in your prepared remarks that you were looking at expanding your integrated footprint through organic growth projects and strategic M&A. So, can you maybe talk about your appetite for larger scale M&A and what sorts of assets you’d consider to expand your integrated footprint, is it more downstream sort of export type capacity?

Well, first of all, from an M&A perspective, certainly, we're very -- we remain very interested in M&A, but I think what you saw with the West Texas pipeline acquisition, I mean, that's a perfect example of what we're really interested in. Certainly, as we think about acquisitions and acquisitions from a more strategic standpoint, if they simply don't fit very well or have a real compelling strategic logic, we're not going to be very interested in it. So that's how we think about it. I think broadly speaking, in terms of the types of assets again that we -- that we're interested in, certainly, downstream assets, particularly as it relates to terminal and storage, transportation of liquid products that don't have to be NGL, it could be crude oil, could be refined products, could be petrochemical products. That infrastructure as well as long haul crude oil transportation up -- further upstream could certainly make a lot of sense and we've been very vocal about that over the past couple of years, but then just candidly what I'll tell you is those assets, people don't want to let go of very often, so the opportunity from an acquisition perspective sometimes is limited as well as -- there’s certainly quality fee based assets that everybody wants, including us.

Great. All right. Thanks a lot.

You bet. Thank you.

Thank you. And our next question comes from Danilo Juvane with BMO Capital Markets.

Thank you and good morning. Guys, [indiscernible] gathering fee being as strong as it has been for the first six months of the year, is it fair to say that the new guidance number that you provided, I think it was $0.85 to $0.90. Should that be something that we should carry over into 2019 as well?

Yeah. This is Chuck. I would say that in ’19, you'd probably see similar range on our fees as we move forward with the mix of volumes coming out of the Bakken, primarily driving that.

Got you. And I guess switching gears, I noticed that you're still stating, no equity needs well into 2019. Does that change at all, just given how strong you’ve performed so far this year and of course you do speak about having additional opportunities next year, do you see a need of potentially issuing equity at some point in ’19.

This is Walt. We obviously have experienced strong cash flows, which is helpful, because we get to reinvest that back into the business and that helps us from a debt capacity standpoint as well. So we don't see anything today with what we have on the table that would change our view that we want to issue equity in 2018 or well into 2019, if at all in 2019. Now that said, we are seeing opportunities for growth projects that are on the horizon and if they come sooner as opposed to later, we have to leave that door open, if we need to manage the balance sheet. We think the investment grade credit rating is incredibly important and we're going to do what we need to do to protect that, but as those move out further on the timeline and these pipelines start cash flowing the way they will, we continue to expect to de-lever very quickly 2020 and beyond.

Thanks, Walt. Last question from me, you mentioned in the press release some impact to NGL segment earnings from the timing of unfracked NGL volumes, should we be expecting a positive impact over the next couple of quarters from that dynamic?

I mean, when we think about the frac volume, yeah, we did put some raw feed and inventory in the second quarter. We expect that will get fracked off over the rest of the year, so we should be -- you should see that come over the next couple of quarters.

Any estimates as to what the EBITDA impact would be from that?

Probably in that -- it would be in the $10 million to $20 million range.

That's it from me. Thank you so much.

Thank you. And our next question comes from Jeremy Tonet with JP Morgan.

Good morning. Thanks. I think you guys kind of touched on a couple of different times here with regards to guidance, but just kind of bringing it all back together as far as what kind of the main drivers were to the guidance increase, raising it here, was it just kind of strong first half is in the books at this point or now you kind of assume spread duration is going to remain at higher and better levels for longer duration in the back half of the year. And just want to confirm West Texas LPG acquisition is not in the -- not factoring in here as you guys already consolidated that, are there any other items that you'd say, if you kind of rank order, what was the biggest components to the increase in guidance here?

Well, Jeremy, I think you're right on in the comments you made, but the biggest mover certainly is optimization. Now, we do very typically, as I mentioned and Walt mentioned in his remarks, as we do factor in some weather degradation later in the year, if that and you know that weather can be severe, if it's not as severe as we've got factored in, we could certainly see some pretty significant benefits to our G&P segment, as we move through the fourth quarter. But the biggest mover is the optimization. And again as I said earlier, it's difficult to predict these spreads with any degree of certainty, but what I will tell you is everything that we're looking at today is leaning toward pretty consistent scenario where we see wide spreads for an extended period of time.

That's helpful. Thanks. And then just going back to the 30 less well connects in Mid-Con you were talking about, it seems like it's kind of timing related I think. But just wondering if you could share kind of what areas this is, if this is a STACK, SCOOP or kind of legacy areas?

No. It's pretty much just in general. And again, that's back to, rigs move around a little bit on our acreage and it's not that we're seeing any degradation overall in the STACK and SCOOP. It's just, maybe less than one rig that's been on our acreage versus somebody else and a little bit of timing, that's all that’s driven there. There is no structural or fundamental change in our outlook of how we’re viewing the STACK and SCOOP.

That’s very helpful. Thanks for taking my question.

Thank you. And our next question comes from Dennis Coleman with Bank of America.

Yes. Hi. Good morning. A lot has been asked, so just a couple of detailed ones from me if you would please. There's a footnote that says you may bring Elk Creek on the Southern in the third quarter and the whole thing on in the fourth quarter. Any meaningful earnings impact from that that we might expect to model in?

The earnings impact would be, like we've said, we're using rail as a bridge to provide our customers those -- that service as it relates to their growing volumes in advance of the pipeline capacity. So -- one way to think about it is, as we move barrels, if we get that Southern section done, we're able to move barrels from the Powder River Basin over to that pipe and start collecting the full pipeline fee rather than the rail -- and not have to pay the rail cost, so that would be the uplift we would get. That's the way we're thinking about it and we haven't really talked about ’19 guidance yet, but clearly, as we get closer and we do that, that will be considered as we provide that guidance.

Perfect. Okay. And then obviously strong results here and potential for higher guidance, does that change anything about when you think you will become a cash tax payer?

No. We still have a -- as we've guided in the past, we won’t be paying taxes through at least 2021 or beyond. It will be some point further out than that and that hasn't changed.

Okay. That’s it from me. Thanks.

Thank you. Our next question comes from Craig Shere with Tuohy Brothers.

[indiscernible] but just a little confused on the last answer to Jeremy’s question on guidance. You’re assuming some discount to recent spreads from Conway to Mont Belvieu on the optimization into the second half, right? A –Terry Spencer: That's correct. Some degradation in the spreads going forward through the third and fourth quarter.

Okay. And so -- and to your point, if we just stay flat from where we've recently been, you’ll hit the upside of guidance? A –Terry Spencer: You got it.

Okay. And then Kevin, on the additional 20,000 a day for Elk Creek and 30,000 for Arbuckle, any thoughts about how quickly that will ramp? I know Sheridan kind of mentioned that up in the Bakken, producer activity plan seem to suggest a quicker ramp than you guys had shared on the last call for your legacy contracts.

I don't -- I mean, yeah, we continue to get good information or positive information from our producers about the volumes being stronger. That has translated into additional contracts and a little bit steeper ramp, but we would still expect it, the volumes are going to ramp over a year or two, as we move through these projects and once they come online.

Okay. And any thoughts about what next in the Permian besides the West Texas LPG expansion.

As we think, we've got a lot of visibility to volume growth. And when you look at what's going on out there, I mean, clearly, the Permian with the number of rigs and the growth expectations on the liquids side, we have a lot of targets out there and again are in late stage negotiations with several of them. So, we would look to continue to expand and loop West Texas all the way from the Permian to where it connects with Arbuckle II and now that we wholly own it, we’ll be able to integrate eventually that pipe into Arbuckle II and achieve some significant capital savings by leveraging the Arbuckle II pipeline and the capacity there versus laying another line that's part of West Texas LPG.

Okay. So it's just maximizing what you’ve got, nothing on the crude side or any other ideas there?

So Craig, we're always thinking about the crude business, we're always thinking about the potential to take existing assets and repurpose them to crude and vice versa. So, we're always thinking about those things. I would never rule out the opportunity, particularly in a basin where crude is being produced as prolifically as it is. We're certainly always thinking about it and in particular in the Permian.

Okay. And last question, a bit of a follow-up to Elvira’s M&A question. She referenced export possibilities. I know that Terry, you've kind of commented in the past, you wouldn’t mind moving into LPG exports. Any kind of update on the market there, your thoughts?

Well, we continue to aggressively pursue export terminalling opportunities, that has never stopped. We like the prospects that are in front of us today. Our commercial teams are working very hard and looking at a lot of options. We're talking to a lot of international markets that we’re spending a lot of time hopping across the pond, speaking with potential customers and potential partners in the project such as an export terminal. So very high on our list and certainly a business or an activity that makes a lot of sense for us.

Thank you. We have no further questions at this time. I would now like to turn the conference over back to Mr. Andrew Ziola.

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'll provide details on the conference call at a later date. Thank you for joining us and have a good day.

Thank you. This concludes today's teleconference. You may now disconnect.