Andrew Ziola - Former VP IR and Corporate Affairs Terry Spencer - President, CEO & Director Walter Hulse - CFO & EVP, Strategic Planning & Corporate Affairs Kevin Burdick - EVP & COO Sheridan Swords - SVP, Natural Gas Liquids Charles Kelley - SVP, Natural Gas

Danilo Juvane - BMO Capital Markets Shneur Gershuni - UBS Investment Bank Spiro Dounis - Crédit Suisse Michael Blum - Wells Fargo Securities Christine Cho - Barclays Bank Jeremy Tonet - JPMorgan Chase & Co. Michael Lapides - Goldman Sachs Group Sunil Sibal - Seaport Global Securities Christopher Sighinolfi - Jefferies Craig Shere - Tuohy Brothers

Good day, and welcome to the Third Quarter 2018 ONEOK Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Andrew Ziola. Sir, please go ahead.

Thank you, Katie, and welcome to ONEOK's Third 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 Chief Executive Officer. 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 will discuss, among other topics, ONEOK's third quarter financial and operational performance; our financial guidance increase included with yesterday's earnings announcement; NGL fractionation capacity; and we'll share our progress on our now $6 billion in capital growth program. Our strategy to create value for our stakeholder remains the same with our assets well positioned. In some of the most economic and prolific basins in the United States, we continually find opportunities to serve our customers through long-term fee-based contracts. The NGL and natural gas volume growth we have experienced this year continues to result in high-quality earnings growth attributable to our core business of fee-based services. Our volumes in the Williston Basin and the STACK and SCOOP areas, combined with favorable optimization and marketing activities from our extensive, reliable and integrated NGL network, has resulted in another increase in our 2018 financial guidance. Since our last call, we've announced additional capital growth projects anchored by long-term customer commitments, which include the second expansion of our West Texas LPG pipeline to serve the continued growth in the Permian; another NGL fractionator in the Gulf Coast, MB-5; another processing plant in the Williston Basin, Demicks Lake II; and an expansion of the Arbuckle II pipeline, which has already begun construction. Building off our extensive asset base allows ONEOK to expand at attractive returns, providing clear visibility to strong earnings growth in 2019 and accelerating thereafter. With that, I will now turn the call over to Walt.

Thank you, Terry. ONEOK's third quarter operating income totaled $495 million, a 40% increase year-over-year and an 11% increase compared with the second quarter 2018. Third quarter adjusted EBITDA was $650 million, a 26% increase year-over-year and an 8% increase compared with the second quarter 2018. With yesterday's earnings announcement, we increased our 2018 financial guidance for the second time this year, driven by strong financial and volume performance year-to-date and our confidence in the fourth quarter. We increased guidance for net income by 9%, distributable cash flow by 7% and adjusted EBITDA by 5%, all compared with our previous guidance midpoints. Our new adjusted EBITDA midpoint is now $2.47 billion, an increase of $120 million compared with the guidance we announced last quarter and nearly $500 million above our 2017 adjusted EBITDA. Adjusted EBITDA guidance midpoint for all three business segments also increased with the largest increase of nearly 11% in the natural gas liquids segment. Continued volume growth and strong optimization results drove the $145 million increase in the NGL segment's guidance. And greater-than-expected volume growth and higher average fee rates drove the guidance increase in the gathering and processing segment. With two months left in 2018, we feel confident in our new financial and volume guidance ranges. Kevin will provide additional detail on our revised 2018 volume expectations. During the third quarter, we paid a dividend of $0.825 per share and last week, we announced another 4% increase to $0.855 per share or $3.42 per share on an annualized basis, in line with our previous guidance. The dividend is payable on November 14 to shareholders of record on November 5. At September 30, our debt-to-EBITDA on an annualized run rate basis was 3.4x and 3.78x on a trailing 12-month basis. We generated $133 million of distributable cash flow in excess of dividends paid in the third quarter, a 6% increase compared with the second quarter 2018. For 2018, we expect to generate more than $500 million of distributable cash flow in excess of dividends that we can reinvest in the business to fund our capital growth program. Total distributable cash flow in the quarter was more than $470 million, up 4% from the previous quarter with a healthy dividend coverage of nearly 1.4x. With $1.6 billion of equity issued in 2017 and January 2018, we have satisfied our expected equity needs for our announced capital growth projects through the remainder of 2018. We expect to benefit from increasing cash flows from operations in 2019 and expect any additional equity financing to be considered in the latter part of 2019. This consideration will be based on the timing and amount of capital expenditures. We expect any additional equity financing, if needed, to be limited to issuance under our existing at-the-market equity program. As of now, we have nearly the full capacity of $2.5 billion available on our credit facility. We remain focused on sustaining our strong investment grade balance sheet and having significant liquidity as we construct our capital growth projects. I'll now turn the call over to Kevin for a closer look at each of our business segments.

Thanks, Walt. Starting with our natural gas liquids segment. NGL volumes gathered in the third quarter averaged 956,000 barrels per day, an 18% increase compared with the third quarter 2017 and a 6% increase compared with the second quarter 2018. Mid-Continent gathered volumes averaged 614,000 barrels per day during the quarter, an 8% increase compared with the second quarter 2018. Volumes on our West Texas LPG system averaged 204,000 barrels per day, a 4% increase compared with the second quarter 2018. Our Bakken NGL Pipeline remains full, and we continue to rail NGLs out of the region. We expect rail volumes to continue to increase until the Elk Creek pipeline is in service. NGL volumes fractionated average 732,000 barrels per day during the third quarter, a 21% increase compared with the same period last year and a 5% increase compared with the second quarter 2018. Fractionation capacity across the industry remains tight, and our fractionators have been running near capacity. With recent expansion and debottlenecking projects, we estimate we have more than 800,000 barrels per day of fractionation capacity given our current product composition, which gives us approximately 60,000 barrels per day of available capacity to accommodate growth. We expect that this capacity, along with additional debottlenecking projects at our existing fractionators, our storage assets and a small amount of already contracted third-party offloads, will provide sufficient capacity until our and MB-4 fractionator comes online in the first quarter of 2020. ONEOK's standard practice is to align our NGL transport and fractionation agreements pricing terms with the actual physical redelivery location of either Conway or Mont Belvieu, thus, avoiding the risk of pricing mismatch in our contracts. So the contracts that support Arbuckle II include Conway pricing terms until Arbuckle II is in service and then the terms will switch to Mont Belvieu pricing. The benefit of our integrated system, including our use of storage for unfractionated NGLs in both the Mid-Continent and Mont Belvieu, offers a number of ways to optimize available capacity and provide our customers the NGL services they need. Our Sterling I and II pipelines are currently shipping purity products and running full. And our Sterling III pipeline is transporting unfractionated NGLs into Mont Belvieu. Our Arbuckle Pipeline continues to operate close to its full capacity of 255,000 barrels per day. We continue to expect the transportation capacity from Conway to Mont Belvieu will remain highly utilized due to growing NGL volumes, which we expect will keep spreads wider than normal until Arbuckle II is placed in service. When Arbuckle II comes into service, it will have the ability to move the unfractionated NGLs currently flowing on Sterling III. This will open up capacity for more purity products to get to Mont Belvieu, which we believe will narrow the Conway-to-Mont Belvieu NGL pricing differentials. In conjunction with increasing the segment's adjusted EBITDA guidance, which Walt talked about earlier, we've also updated 2018 volume expectations. Our guidance for NGLs fractionated increased by approximately 5%. And we narrowed the range for NGL gathered volume guidance, keeping the midpoint at approximately 925,000 barrels per day due to better-than-expected C3 plus volume growth in the STACK and the SCOOP, which was offset by the continued rejection of Conway-priced ethane. Total ethane supply on our system continues to increase with approximately 100,000 barrels per day of additional ethane gathered on our system in the third quarter 2018 compared with the same period in 2017. Moving on to the natural gas gathering and processing segment. For the third quarter, adjusted EBITDA for the segment increased 12% compared with the third quarter 2017, driven by volume growth in the Williston Basin and the STACK and SCOOP areas. Contract settlement adjustments in the second and third quarters of 2018, together, resulted in a sequential quarter adjusted EBITDA decrease, but the core business continues to grow. Volumes remained strong across the basins where we operate. Third quarter natural gas volumes processed averaged more than 1.8 billion cubic feet per day, a 15% increase compared with the third quarter 2017 and a 3% increase compared with the second quarter 2018. During the third quarter, ONEOK's natural gas volumes processed in the Rocky Mountain region reached a new milestone averaging more than 1 billion cubic feet per day, a 17% increase compared with the third quarter 2017 and an 8% increase compared with the second quarter 2018. In the Mid-Continent, third quarter natural gas volumes processed averaged 835 million cubic feet per day, a slight decrease compared with the second quarter 2018 due to several large well pad completion delays. In October, we have already seen increased production with processed volume reaching nearly 900 million cubic feet per day on several days. We connected 137 wells in the Williston Basin and 29 wells in the Mid-Continent during the quarter. We've now connected a total of more than 550 wells through the first 9 months of the year, well on our way to meeting our increased guidance of 680 well connections. Rig activity remained strong with nearly 35 rigs on our Rockies-dedicated acreage, including two in the Powder River Basin and 15 in the Mid-Continent. The strong producer activity we've seen around our assets year-to-date is expected to continue for the foreseeable future. We updated our 2018 volume guidance for the segment with the main change being the expected volume mix by basin. Our Rocky Mountain processed volume midpoint increased and our Mid-Continent processed volume midpoint slightly decreased due to the timing of completions in the STACK and the SCOOP areas. The segment's average fee rate increased to $0.92 per MMBtu in the third quarter 2018 from $0.89 in the second quarter 2018. Higher fees continue to be driven by greater-than-expected volume growth in the Williston Basin compared with the volume growth in the Mid-Continent. We expect our average fee rate for the fourth quarter to be similar to the third quarter. In the natural gas pipelines segment, third quarter adjusted EBITDA increased 6% compared with the second quarter 2018 and increased 3% year-over-year, benefiting from increased interruptible transportation volumes and firm transportation capacity contracted. We had successful open seasons on three of the expansion projects announced in June, which will provide additional takeaway capacity in the Permian Basin and STACK and SCOOP areas. Open seasons resulted in more than 900 million cubic feet per day of capacity secured on our project to make Roadrunner Gas Transmission bidirectional, 300 million cubic feet per day of capacity secured on the expansion of our WesTex transmission system in the Permian Basin and 100 million cubic feet per day secured on the westbound expansion of ONEOK's gas transportation system in Oklahoma, which is on track to be completed before the end of the year. The eastbound expansion of the ONEOK gas transmit - gas transportation system did not have an associated open season, but was anchored by 115 million cubic feet per day of firm commitment. Now a quick update on our growth projects. Since our last earnings call, we've completed the extension of our West Texas LPG pipeline into the Delaware Basin. We also completed the expansion of our Canadian Valley natural gas processing plant in the STACK, which brings our total Oklahoma processing capacity to approximately 1.1 billion cubic feet per day. Volumes on both projects are expected to ramp up over the next 12 to 18 months. Additionally, we recently completed some meaningful fractionation expansions in the Mid-Continent, including an approximately 20,000 barrel per day expansion of our propane plus capacity or heavy-in capacity at our Bushton, Kansas fractionator. This expansion was part of the related infrastructure upgrades included in our Elk Creek pipeline project to help accommodate the heavier NGL barrel coming from the Williston Basin. We remain on schedule to complete the 60,000 barrel per day expansion of our Sterling III NGL pipeline this quarter. Construction remains on track for Elk Creek, and we continue to expect - to complete the southern section as early as the third quarter 2019 and the entire pipeline by the end of 2019. We've also contracted an additional 30,000 barrels per day on Elk Creek since our last call, bringing total contracted volume to approximately 170,000 barrels per day. Arbuckle II is under construction and on schedule for an expected completion in the first quarter of 2020. The expansion of Arbuckle II, which was announced in July and will increase capacity - total capacity from 400,000 to 500,000 barrels per day is expected to be complete in the first quarter of 2021. We've contracted an additional 20,000 barrels per day on the system, bringing our total contracted volume to approximately 320,000 barrels per day. Also, our MB-4 fractionator is on schedule to be complete in the first quarter of 2020. Finally, we are currently constructing an additional 400 million cubic feet per day of processing capacity in the Williston Basin with our Demicks Lake I and II plants with Demicks Lake I on track to be complete in the fourth quarter 2019. Given our current volume outlook, we expect Demicks Lake I to open nearly full. As a reminder, all these projects are backed by long-term commitments and/or acreage dedications addressing the needs of our customers and are aligned with the expected volume growth we see across our operating basins. Terry, that concludes my remarks.

Thanks, Kevin. This has clearly been a quarter of operational milestones and impressive financial results that underscore the reliability of our employees and our assets and the success of our customers in the basins where we operate. I'm not one who typically focuses on statistical records because we've achieved more than I can count over the years. Our goal, after all, is to create value for our stakeholders and let our track record of capital discipline and performance speak for itself, including doing what we say we're going to do and working hard to improve each and every day. But the milestone Kevin mentioned earlier about reaching 1 billion cubic feet per day of processing in the Williston Basin is one that, I think, speaks volumes about the growth of our operations and the ambition of our employees. Just 8 years ago, we had only one processing plant in the basin. Now we're processing 1 billion cubic feet per day of natural gas and are the primary NGL takeaway provider from the region. The growth between then and now isn't just the story of the Williston Basin, which has been an incredible basin for us, but it's also a reflection of our bigger company story and our continued growth in all the basins where we operate. Our employees have taken a great base of assets across our system and built a fully integrated midstream operation with unique competitive advantages in each basin where we operate. This kind of ingenuity and drive while doing it safely is what our employees thrive on and what has enabled us to announce our long list of growth projects at attractive returns. This couldn't have been accomplished without the hard work and dedication of each and every employee or without the continued support of our long-time investors. To follow up on my closing remarks last quarter, we recently published our 10th corporate sustainability and ESG report, which is available on our website. Stakeholder expectations have continued to increase for the energy industry to operate safely and environmentally responsibly. At ONEOK, our long history of good corporate citizenship is clearly reflected in this report and I'm proud of our progress. Operator, we're now ready for questions.

[Operator Instructions]. Our first question will come from Danilo Juvane from BMO Capital.

I wanted to start with the Mid-Con and how the volumes were sort of light this quarter. Can you sort of explain what drove that decline?

Yes, Danilo, this is Kevin. Again, as I stated in my remarks, it was really just a timing of some of the well completions that we had kind of scheduled out with the producers. We had a little maintenance activity. But I think, as it relates to the STACK and SCOOP, what I'd do is look at the Mid-Continent volumes of NGL. I mean, we have like a 45,000-barrel per day increase sequential quarter-to-quarter for the NGL group, which I think is a broader indication of we still feel very strong about the SCOOP and STACK as well as we've seen the volumes pick up significantly in October in our G&P segment.

Got it, got it. I know you don't provide guidance until February at least. But should we expect the volumes in Mid-Continent to remain as strong, if not stronger, in 2019?

Yes, I think we expect - if you see this rig count remain, which we expect and I think you will see volume growth. I mean, getting the Canadian Valley II expansion complete and having that capacity now, you've got some of the pipe constraints with our projects and others that have taken care of some of the residue. So I think you're set for growth as we move through '19 and beyond.

Got it. One of your largest customers in the Bakken outlined a pretty bullish long-term view for the basin. By our estimates, you are tapped out on central processing capacity and that's without including the PRB picking up here. How much more Rocky-related growth are you guys seeing going forward here?

Well, let's start, on the G&P side, we still have some available processing capacity that we think we'll see a little more flaring, but we'll get there with our Demicks Lake I plant that's coming up in the fourth quarter. From an NGL perspective, yes, takeaway, the pipeline is full, but we've got the rail capacity that we've got up to 30,000 barrels a day of rail capacity that we will take advantage of as we move through '19 until Elk Creek comes online. And with Elk Creek, again, the southern section being complete in the third quarter, that allows us to accommodate growth that we expect to come out of the Powder early by shifting those volumes over to that pipe. Does that help?

Got it. Last question for me - yes, absolutely. I appreciate that. Last question for me is on the ATM. Obviously, you said that you may need limited equity next year dependent on project timing. As you are sort of developing these organic projects, is it fair to see that you continue to get something in the 4 to 6 times EBITDA range?

Yes, we continue to see very attractive growth opportunities that are in the range of our capital investments.

Our next question comes from Shneur Gershuni with UBS.

Maybe I - just to start off, I was wondering if we can talk about storage a little bit. I guess kind of two-part question here. When we look at the inventory builds on your balance sheet, can we just assume that's effectively unbooked EBITDA and that's due to timing? And then, secondly, when we sort of think about your storage positions and we sort of think about the spreads and the pipes being full and so forth, are you able to synthetically effectively sell volume at Mont Belvieu without actually moving the molecule by using your storage in Belvieu and using your store storage in Conway?

I don't think so. I mean, we can sell volume - I'm sorry, this is Sheridan, we can sell volume forward and store it in Conway until it's ready to be shipped to Belvieu, but eventually, it's going to have to be shipped. We can't synthetically make the transaction without actually physically shifting volume. Does that answer your question?

Yes, that's essentially it. And also the value of EBITDA - of the inventories booked at the end of each quarter on your balance sheet, is that effectively unbooked EBITDA that just didn't happen due to timing?

Yes, this is Kevin. I mean, Shneur, you're really talking about from a raw feed perspective, that would be an inventory, yes, that would be effectively unbooked EBITDA.

Great. And just a couple of follow-up questions here. You sort of addressed some of this in your prepared remarks, but just to try to nail it down for us less technical people. Given the questions in the industry about being short capacity, can you walk us through how you mitigated that risk? When you go to build a new processing plant, for example, do you already line up the transportation and frac capacity that you expected the output of that plant? If you can sort of walk us through that, please.

Yes, this is Sheridan. Yes, that's basically what we do. So most of our bundled services that we provided and how we contract, we go and provide certain amount of capacity to each processing plant, whether it's us or whether it's other people. And we make sure we have the transportation and fractionation capacity available to get that to the pricing point in the contract. And that's when we talked about Arbuckle II. Until Arbuckle II comes up, some of our contracts will stay priced in Conway as we can't physically get that barrel yet to Belvieu. But we look at through our whole system to make sure we're balanced and we don't get out of whack and get into a spot where we are having to buy third-party or buy out of spreads to handle our contracts or commitments.

Perfect, that makes total sense. One final question just in terms of outlook both near term and longer term. Ignoring the optimization spreads just due to the volatility in that, the good results that we've had this quarter, you've raised guidance, which implies a stronger 4Q, how much visibility do you have a of the base business growing into 2019? And then if I recall correctly during your prepared remarks, you'd mentioned that Elk Creek is now 70% contracted. By the time it comes online, could we actually be in a position to be expanding that?

On that last question, yes, this is Kevin. We would love for that to be the case. I mean, we continue with - the growth in the Bakken continues to be strong. I think a lot of people listened to the call yesterday of one of the large producers up there and they were clearly very bullish when you just look at the returns they're getting on the wells. So absolutely, we don't think we're done. And like we've mentioned, we could expand that pipe with minimal capital by just adding pump stations as we continue to grow our contracted volume. And you're also seeing growth in the Powder River as well, which would feed Elk Creek from that standpoint. So yes, we think that, that's something that we're keeping an eye on of when we might need to expand that.

And with respect to 2019 in terms of the trends in your base business, should we expect a similar cadence of growth that we're seeing in 3Q this year and what you're guiding to for 4Q this year?

I mean, without getting into guidance, clearly, when you look at the rates that are in our acreage on the G&P side and you look at the rigs that are ultimately behind our significant positions in the Mid-Con and the Bakken on the NGL side, absolutely, you would expect growth. As we've talked about, some of the pipes are full, but again we definitely believe that core business is going to be in a great position not just in '19 but then as we move through 20 when these assets come in service

Shneur, this is Terry. We'll be coming out with guidance after the first of the year at some point in time in January. So and as Kevin indicated, all the fundamentals look incredibly strong for us as we think about '19. Certainly, you can't forget about 2020 and 2021, we're doing a lot of things in '19 that set us up for 2020 and 2021 in a big way. So you'll see more as we come out with guidance after the first of the year in terms of what our thoughts are as far as volumes, but - and all the indications we're seeing from all the producers and rig count expectations are all just - are outstanding for '19.

Our next question comes from Spiro Dounis from Credit Suisse.

Just wanted to start off on the tightness in the frac market. Obviously, you guy have taken steps there with Mont Belvieu 4 and 5 in 2020, 2021. But I guess, just in the near term here, how do you guys think about some of the short-term solutions to help clear the market? Is it all just going to storage? Are there other creative solutions you guys come up with going forward? And then just around OKE specifically, what are the other benefits we could see you accrue to you guys over the near term here?

This is Sheridan. I think what you're seeing happening in the market is obviously storage plays a big place in that. If you can store barrels, for us it could be in Conway or in Belvieu for unfractionated NGL barrels until your fracs step up in '20 and 2021. Also we continue to look at our fracs in very detail to see is there any minor debottlenecking that we can do to eke out 5,000 barrels a day here, 10,000 barrels a day and then look at the different compositions we have. So we have some plans for that as we get into '19, the first quarter of '19, we'll have a little bit of turnarounds to help - allow us to incrementalize and move some of our fracs up in capacity. So I think you're seeing some of those - by all the industry participants continue to look at each one of those. And also we have seen, it's been pointed out in other calls, that there's actually some petrochemical crackers now that are looking at cracking unfractionated raw feed as well, especially when the spot frack market gets as wide as we have seen it, you always then have those participants coming in. So I think all those things are what's going to be needed to get to 2020 or beyond 2020. I still don't think the frac market will - I think the frac market will still be tight in 2020. We need to get through 2021 to really loosen it up or get it back to more normal levels. But everybody is well incentivized to find every creative solution to get a little more frac capacity to do storage, do cracking through our petrochemical facility or increasing your own frac capacity.

Got it, that's great color. And then just on West Texas LPG and the potential to, I guess, convert to a crude pipeline there. How are you thinking about the timing around that, which I think is kind of a big factor, I'm guessing, in the economics. But what are the other factors you guys are considering as you think about that decision?

I think one of the things we're considering is whether or not, with all the growth we've seen out there and our ability over these last months to be able to contract new volume, which drove our announcement under the expansion out there, that it may be better served to leave it in NGL service. And so that's probably one of the biggest decisions we have is what's the best service and how do we make the most money out of it going forward. Obviously, there's a spread differential in crude out there right now that everybody's trying to get to, but what's the long-term aspect of being able to contract that. So there's lots of different things, but we're talking to people about it, trying to understand how do we make the most money with the assets we have.

Our next question comes from Michael Blum with Wells Fargo.

I apologize in advance, this is probably like a multipart question, but I'm trying to understand a little bit about some of the dynamics with the flows and the bottlenecks. So it sounds like the producers are getting close to flaring limits in the Bakken, which, obviously, one way to alleviate that would be to toggle ethane yet you got downstream constraints on frac capacity to fractionate. So just wondering like how those two factors are sort of playing out those dynamics? And I guess, related to that, what is your utilization of frac capacity currently at Conway? And is there any room there for additional frac? So I know there's a lot in there, so apologies.

Michael, this is Kevin. We'll start with the flaring in North Dakota. Clearly, as you've seen the state report information published the latest one, it's ticked up little bit. I would remind everybody that, that information is the gross production and the gross gas capture levels. So then what happens with each individual producer then is able to, with the updated regulations, they're able to utilize or take credits, if you will, if they have beat the target over the last six months. And they're also able to exclude 60 days of IP gas on their new wells. So we believe many of our producers will be able to stay under and expect to stay under the flaring targets as they move through '19 till some of the capacity comes online. To the question about the ethane and the toggling there, clearly, we're managing that very carefully with all our processing plants to try to maximize throughput while still also managing the downstream impact. So obviously, we are rejecting at this point with the Bakken line being full and then the rail activity, we are rejecting as much ethane as we possibly can to give us as much NGL Takeaway capacity as possible to help them out. So that's the way we think about that. As for the Conway specific, Sheridan, do you have comments about the Conway?

Michael, what I'd say about Conway is we stated in Kevin's remark that we have about 60,000 barrels a day of available fractionation capacity. And with our integrated system, we can make that fractionation capacity show up anywhere on our system that we want to as we move raw feed around. But with wide north-south spread, you would say all that fractionation capacity is in Conway because we're taking everything we can to Belvieu. So right now we'd probably say we have 60,000 barrels a day of fractionation capacity in our Conway market. That is above what we're bringing in on gathering. Today, we're using that 60,000 barrels a day to reduce our raw feed in inventory, and we plan on ending the end of this year, end of 2018, with minimal raw feed in inventory to get ready for the ramp-up in volume in '19 and get us to the 2020 MB-4 fractionator.

Got it. I appreciate the details - the detailed answer. My second question really is more of a balance sheet financing question. Just as we think about modeling going forward, is there a leverage ratio that we should think about where you'd start to then consider tapping the ATM for equity a little bit to keep that within some sort of range?

Well, Michael, what I would say is that with the increased cash flow and the earnings growth that we've had in '18, we've been able to reinvest that money back into the business so it's kept our leverage at a run rate basis right now at 3.4x. So we're sitting pretty good at the end of three quarters and going into '19. We've always said that our longer-term target is to be below 4x and nothing's changed on that. But we've also said that we expected it to creep up in the latter part of '19. The rating agencies have acknowledged that. And so we're going to have to keep an eye on it. But our expectation is that cash flows keep flowing as they are, we'll be in a pretty good spot moving throughout '19. So we're keeping ourselves flexible if we need some equity, but we think there's a good chance that there won't be any equity in '18.

Our next question comes from Christine Cho with Barclays.

I have a follow-up to Shneur's question. If you fractionated the barrels, but put it into storage afterwards as purity product, then it's booked as revenue in your income statement, is that right? So there could be inventory on your balance sheet that already has been recognized as revenue?

That is correct. If you fractionate.

It's when you actually sell the barrel that we get. The thing is that we fractionate and store so many barrels on a constant flow basis that they're constantly flowing through there, Christine, and bringing in as much as we do on a daily basis. But we actually recognize the revenue when it is sold. The Barrels are fungible and they're going in and out of storage every day.

But I guess, when we look at the buildup in your inventory, I mean, should we - if more of that was purity product than y-grade, I'm just trying to get a sense of like whether or not most of that was already recognized versus not, if that makes sense.

It wouldn't be recognized until we got it solved. But obviously, if it's purity product we have ability to sell it into the marketplace at any time.

We sell almost all our barrels every day into the marketplace. We don't take price risk on our barrels, so we're selling our barrels every day into the marketplace.

Okay, but I guess I'm also trying to split to, Sheridan, your comments on earlier questions that you guys are trying to reduce your y-grade inventory in storage, is that right?

That is correct.

Okay, but the number one up, so I can only assume that your purity product storage went up, is that incorrect?

Those aren't necessarily the same. If we fractionate our y-grade in inventory, we'll sell it into the marketplace. If we decide to keep y-grade in storage, we may still sell it in the marketplace and then sell it forward or something as we go with that. But just because we fractionate more barrels, more barrels in y-grade, doesn't necessarily mean that we have to store that barrels of purity product. We still have the ability to place it into the market.

Okay. And then I think you kind of alluded to this in your prepared remarks. But for the last year and change, guys have told us that we should assume that your optimization capacity would decrease throughout the year if customer commitments grew. But it sounds like we should assume that what you have now is what you'll continue to have maybe actually go up when your Sterling III extension comes online. Is that the right way to think about it?

Well, as our Sterling III expansion comes online, we will be moving - we'll have obligations to move more y-grade into the Mont Belvieu market. Not all of that y-grade that we move into the Mont Belvieu market we'll need to frac because some of the - the main contract that supported the Sterling III expansion was a transport-only barrel. So we still have that obligation to get those barrels into the Mont Belvieu market. But to the extent we have excess capacity on Sterling III and have the frac capacity and Mont Belvieu to frac it, we would increase our optimization.

Okay. And then how much debottlenecking can we see out of the fracs? I mean, you guys already mentioned the 20,000 barrels per day of propane plus out of the Bushton frac. Was that included in your 800 number or no?

Yes, it was.

Okay. But how much more could we see beyond that? Do you guys have like a general sense?

I think you can maybe able to see 20,000 to 30,000 possibly. A lot of depends on, when you get these higher levels depends, actually on the composition that you have coming into the system. So as we do different things, composition could change, they'll move around. But you could see 20,000 to 30,000 possibly.

So Sheridan, this is Terry. So that 800,000-barrel a day number could be higher number particularly if the feed composition change to a lighter barrel, more ethane.

Yes. We can frac 840-plus thousand barrels a day as our nameplate if we had the right composition. And especially in the wintertime when you got colder temperatures, we can definitely get above nameplate with the colder temperatures in there. But right now, we still have some ethane being rejected on our systems, so we're still fracking very heavy barrels especially at the Bushton fractionator. So if we get live feed, we will go above that. But we're seeing we're at - at the composition we see today, we can get above 800,000 barrels a day.

And we wouldn't see the 840-plus unless the Conway ethane frac spread went positive, is that right way to think about that?

Yes, you need to get more ethane into the Conway fracs however that happens.

Our next question comes from Jeremy Tonet with JPMorgan.

Just want to pick up with Conway-Belvieu a bit more here, and granted, it's a very, very difficult question to answer and you're not providing guidance at the time, but I was just wondering if you could provide us with your updated thoughts on how you think that spread could kind of trend over next year? Where do you see some of the give and takes there? And as it impacts your optimization, do you see more risk to the upside or downside in 2019 versus 2018 optimization margins there?

Well, 2018 was pretty good. So if 2018 would repeat itself, that would be very good. But we think it will be volatile and - but it won't go back to historical levels or anywhere close to historical levels until we get Arbuckle II up and get more purity capacity in between Conway and Belvieu. But a lot to me depends on what the demand is in Belvieu for our exports on propane and petrochemicals on ethane, overall price, there's a lot of factors that go into that. But what we do know is it that we have volume in Conway that can't get to Belvieu due to pipeline constraints and that won't be allayed to Arbuckle II, which is what leads to a wide north-south spread.

Fair enough. And at the risk of asking about something besides NGL, just want to pivot towards the WesTex expansion there and really just trying to dig in a little bit more and see how much of that - this build-out is getting to destinations that really kind of clear the basin. I mean, does the extension kind of connect into north of Plainview or for NGPL kind of north of Amarillo? Just trying to see how much extra this helps get past choke point.

Yes, Jeremy, this is Chuck. The OGT - I'm sorry, the OWT northbound, it was pretty much designed to move the Waha gas molecules north to the Mid-Continent where the spreads were wider and they could access little different markets. So yes, you're seeing that gas up into the Texas Panhandle and potentially utilizing some of the Oklahoma assets as well.

So it connects in north of those kind of 2 hubs on those pipes?

Yes, you're looking at NGPL, Panhandle, Mid-Continent-based markets.

Our next question comes from Michael Lapides with Goldman Sachs.

We're six days out from election day, how are you guys thinking if the unlikely scenario plays out that Prop. 112 in Colorado passes? And I know you've kind of talked about it, but just how do you think this kind of flows through each of your three segments?

This is Terry. Really no significant impact if Proposition 112 passes. Doesn't look like it's going to pass, it's close. But it doesn't look like it's going to pass. But even if it does, don't expect any significant impact to us, to our business whatsoever.

Got it. And then one other question really, just kind of balance sheet and credit metric perspective, you've got a lot of growth projects that you're going do fourth quarter this year through next year. What is the peak leverage level, the peak debt-to-EBITDA that you're willing to go to knowing that it's going to be temporary? Meaning knowing it may be just for a quarter or 2 or 2 or 3 quarters before the big backlog of projects comes online in second half of '19 through 2020?

Well, I think my answer is going to be the same as I said just before is that our long-range target's 4x and we will edge above that in the latter part of '19. But we're seeing very significant cash flows from the business that we're reinvesting into the business. So we think that if things keep trending that we'll be in a good spot from a balance sheet standpoint. But if we need a little bit of equity, we have the ATM available.

Our next question comes from Sunil Sibal with Seaport Global Securities.

A couple of questions for me. First, the clarification on the max frac capacity that you mentioned previously on the call, the 840,000 barrels a day and then you have 20,000 to 30,000 on top of that in composite, everything?

We would have - the 20,000 to 30,000 would be on top of both the 800,000 barrels a day that we can frac with our current composition. So the extra 20,000 to 30,000 barrels a day would be on top of that.

Okay, got it. And then on the G&P segment contract settlements, which impacted this quarter, how should we kind of think about that going forward? Is that something of a bit of an ongoing issue? Or is that kind of resolved at this stage?

This is Chuck. No, that - we have approximately 2,000 contracts in the G&P segment. And from time to time, you're just going to see settlements and adjustments on some of these contracts. So no, that wouldn't be something we would anticipate going forward.

Okay. And then, lastly, on the Canadian Valley processing plant that you brought online. I was just wondering based on the activity you're seeing behind that, what's the kind of the expectation for that plant ramping up and getting full?

We think - as we said in the remarks, it'll be - probably it'll ramp over the next 12 to 18 months.

Our next question comes from Chris Sighinolfi with Jefferies.

Just a little nitpicky one maybe for me, Terry, if I could. On Slide 7 of the deck, you guys featured as you had in past quarters the anticipated bundled - average bundled rate by region. I just was noticing the Mid-Con, WesTex, I'm sorry if you mentioned this before, but there's now a tilde between those two ranges as opposed to a less-than symbol. So I'm just curious what sort of happened in those regions to maybe bump up modestly your view on the bundled rate?

Well, I think on West Texas pipeline, you're seeing a bump up on that because as we brought these new volumes on, they're at-the-market rate, which is much higher than the legacy rate that some of the old volume was on. And some of that old volume has left and so we fill some of the existing volume with higher-market volume. So our average rate is starting to trend up on the West Texas pipeline as we thought it would as we bring on market-based barrels, market price barrels for T&F service. And the Mid-Continent is the same thing, we've been able to contract it at little bit higher rates. As we continue to go forward, we've had some volume decrease on areas like the Barnett Shale and places like that, but some that are smaller volume - smaller-rate volume and we'll put it in STACK and SCOOP, which is higher-rate volume at the Mid-Continent. We're seeing a shift towards the higher-margin volume from the low-margin volume on our system.

And is there - I guess, as you think about that then on profile forward, is there a meaningful amount of contracted volume that you guys know of that you think is going to be profiling off in the next couple of - next - in whatever period you want to define it that could cause that rate to go higher on just existing capacity? Or is this driven more of over time just by adding these stuff?

I think on the West Texas pipeline over next year and into 2020, you will see a lot of our low-rate volume leave the system in favor of market-based or a more market rate volume. So yes, you could see significant increase in the West Texas LPG system average bundled rate.

Okay, great. Switching gears real quickly, a lot of questions on the Bakken from a gas recoverability and processing perspective. I'm just curious if we get it to crude, you had mentioned and referenced one of the largest producers up there talking positively about the basin. There's two pipelines that have talked about expansion opportunities. I'm just wondering your view on that from a crude perspective as both a major operator and someone who formerly had a crude project in the backlog?

This is Kevin. Yes, we've got a lot of questions when you have a differential blow out a little bit, that was primarily due to an abnormal amount of refinery maintenance that was occurring in the upper Midwest, you've seen that spread come back in. But as you look forward, clearly you've got an open season out there right now on DAPL. You've got some other expansions being discussed. I mean, clearly, the producer yesterday was in conversations about larger expansions that they think may happen over the next couple of years. And you've also got some rail - a significant amount of rail capacity that used to be in service and now is sitting there. So with the combination of those expansions and the rail capacity, I think, as we talk to customers, they're comfortable that, that's going to absolutely bridge them to the point if you did need another greenfield project to provide additional capacity out.

Okay. Yes, I guess, that's what prompted my question was the discussion of significant new capacity, which seemed to be bigger than what those current expansions have discussed. So when I was just dusting off who had at prior points in time talked about projects from there, you guys being one, I was just curious if that - obviously, you have a ton in flight and I'm not saying you should add anything more at this point. I'm just curious if Bakken crude express gets dusted off at any point.

It's not on our radar at this point. I mean, we're absolutely locked and focused on providing the processing and the NGL takeaway. But you know, long term, we are a big player up there. Is it something we would consider, absolutely.

Chris, it's Terry. So what I'll tell you just from our experience the last time the challenge associated with getting the kind of commitments that you need to make these large projects like Bakken Express work very challenging, the things that these producers do are innovative ways - using their ingenuity to find ways to get barrels out of that basin, and Kevin just listed off all those things. An so we've recently talked to some producers in private meetings about this very thing. And they're working on a lot of things, they have a lot of options to get crude out of the basin and we really don't have concerns about crude takeaway, certainly, over the near term and broadly over the long term really.

Our next question comes from Craig Shere with Tuohy Brothers.

One quick follow-up on West Texas LPG repurposing. I was under the impression that the expansion connecting the line and Arbuckle II kind of sets you up for twining the systems so that you don't have to have an either/or proposition, albeit maybe a couple of years out to really bring on an opportunity to enter into crude service. So can you kind of elaborate on that?

I think what we're saying there is when we complete the loops that we're starting on these expansions we've done so far, we'll have a complete system from the Permian to Arbuckle II then we'll use Arbuckle II to get into Mont Belvieu, which will open up the legacy West Texas system for some other service. As we continue to go, we've explored looking at crude and what that looks like. But we're also seeing a lot of opportunity in the NGL services that we may be able to fill, all that we have are capacity we see going forward on this Loop and Arbuckle II and need additional capacity for NGL. So it may be better to leave it in NGL service or it may be better to put it in crude service. But as we go along, we'll make that determination. But it's not a foregone conclusion that we will move it to crude service. We'll move into the right service that makes us the most money.

Understood. I know kind of breaking into services in the crude spaces then, along with LPG exports, has been kind of a focus for longer-term opportunities to add a leg to the stool, so to speak. If West Texas is most optimally used for NGL service for a number of years forward, is there anything else you're looking at to kind of provide additional multiple services to same producers?

Well, I think we still would like to look at the crude side of it for sure, it just may not be through this method. There's - obviously, there's other methods to get into that side from different ways starting from gathering or further down the road, it could be M&A further down the road. You don't know. On the export side, we continue to work very hard on the export side and having a lot of meaningful discussions and growing. But when we're ready to announce that one, we'll announce that one when we get everything lined up. So we still see that as opportunity to where we could grow, it just may not be through the West Texas LPG side.

Craig, the only thing I'd add to what Sheridan said is that we've talked about other products, refined products, in particular, terminalling that could make some sense for us. So crude, refined products, LPGs, potentially logistical opportunities serving petrochemicals and refineries, those type of logistical assets could make some sense for us. Certainly, we don't see a lot of them popping up for sales. People covet those assets. But certainly, we're interested in those types of things and particularly bolt-on opportunities. When Sheridan indicated M&A, that's what he's referring to, just when acquiring assets that could make sense. So we're always prospecting through those opportunities, those types of opportunities. So as we think about the LPGs, we think about Mexico, we think about Canada potentially. We're actively pursuing or actually considering or developing opportunities in those spaces. So that's the kind of thing that we're in. And certainly, the export opportunity is something we've been working for years. We like where we are today and we're making progress. And certainly, when we get further down the road or ready to roll that project out, certainly we'll come out. I'd just tell you personally from the export dock standpoint, if we're not announcing something probably in the first half of '19, I'll be disappointed. But again, a lot of things have to happen in order for that to be successful.

I appreciate all the color. It certainly sounds like a full plate.

Our final question will come from Shneur Gershuni with UBS.

Just one very small follow-up. In your responses to Christine about the inventory levels and sort of the changes in value and so forth, is it fair to conclude that with NGL prices rising something like 20% or 25% from, let' say, June 30 to September 30, that, that's part of the remeasurement upwards as well also you're just booking something at a higher cost that's come in?

Yes. So I think that's the way you look at it.

Okay. So you can have a scenario where the actual volume of inventories goes down, but the value booked on the balance sheet goes up because of the price basically, that's a potential outcome?

Yes. Just as you work through that and work that off, then yes, you could see some changes.

At this time, I'd now like to turn the call back over to Mr. Ziola for closing remarks.

Our quiet period for the fourth quarter starts when we close our books in early January and extends until we release earnings in late February. We'll provide details for the conference call at a later date. Thank you all for joining us, and have a good day.

Thank you, ladies and gentlemen. This concludes today's teleconference. You may now disconnect.