Good day, and welcome to the Second Quarter 2022 ONEOK Earnings Call. This conference is being recorded. At this time, I would like to turn the conference over to Mr. Andrew Ziola, Vice President, Investor Relations. Please go ahead, sir.

Thank you, Nash. And welcome to ONEOK second quarter 2022 earnings call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. After our prepared remarks, management will be available to take your questions. 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. Just a reminder for Q&A, we ask that you limit yourself to one question and one follow up in order to fit in as many of you as we can. With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer. Pierce?

Thanks Andrew. Good morning, everyone. And thank you for joining us today. We appreciate your interest in investment in our company. On today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Investor Relations and Corporate Development; and Kevin Burdick, Executive Vice President and Chief Commercial Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President of Natural Gas Liquids and Natural Gas Gathering and Processing; and Chuck Kelley, our Senior Vice President of Natural Gas Pipelines. Yesterday, we announced strong second quarter 2022 earnings, provided an update on the Medford incident and affirmed our 2022 financial guidance expectations. As we sit today, we still expect to achieve the midpoints of our 2022 net income and adjusted EBITDA guidance, which Walt will provide additional details shortly. Our second quarter financials were achieved despite unseasonable weather in the Rocky Mountain region during the quarter. Two separate April weather events cause widespread outages and power, disrupting midstream and producer operations across the region. Our employees were well prepared and quickly responded to the challenge. They remained focused on the safe operation of our assets and the safety of the communities where we operate. And they worked with local agencies, customers, utility providers to resume normal operations as quickly as possible. Across our operations, we continue to see strength in producer activity, with commodity prices and demand supporting a strong second half of the year. While it is still too early to provide our outlook for 2023, we are well positioned across our integrated footprint to help transport and process essential natural gas and natural gas liquids. Before I turn the call over, I'd like to make and provide an update on the Medford, Oklahoma fractionation facility. On Saturday, July 9, mid-afternoon, there was a fire at the…

Thank you, Pierce. ONEOK second quarter 2022 net income totaled $414 million or $0.92 per share, a 21% increase compared with the second quarter of 2021 and a 6% increase compared with the prior quarter. Second quarter adjusted EBITDA was $886 million and an 11% increase year-over-year. Compared with the first quarter of 2022, higher second quarter results were driven by increased NGL volumes across our operations and higher realized commodity prices primarily benefiting our Natural Gas Gathering and Processing segment. Operating costs increased in each of our business segments, which is typical for the second quarter as improved weather allows for more routine maintenance projects to take place. As of June 30, our net debt-to-EBITDA on an annualized run rate basis was 3.8 times. And we continue to view 3.5 times or lower as our long-term aspirational leverage goal. In June, we redeemed nearly $900 million of senior notes due in October 22 with cash and short-term borrowings. We currently have no long-term debt maturities due until September of 2023. Yesterday, we reaffirmed our 2022 financial guidance expectations. And to expand on Pierce's comments earlier as we sit today, we still expect to achieve the midpoints of our guidance range ranges, which remain at $1.69 billion for net income and $3.62 billion for adjusted EBITDA. We expect total 2022 capital expenditures to trend towards the upper end of the range of our guidance range of $900 million to $1.05 billion, driven by higher producer activity levels and expansion opportunities in our natural gas pipeline business. Positive drilling activity across our operations and expectations for higher natural gas and NGL volumes in the second half of 2022, support our financial guidance and continue to point to a strong volume exit rate this year. I'll now turn the call over to Kevin for a commercial update.

Thank you, Walt. During the second quarter, we saw NGL volume growth across all our operating regions compared with the first quarter 2022. NGL volume expectations remain strong through the remainder of the year, providing confidence in achieving the midpoint of our raw feed throughput guidance for 2022. Natural gas processed volumes and well completions during the quarter were significantly impacted by the April weather events. And we now expect process volumes to be toward the lower end of our 2022 volume guidance range. Let's take a closer look at our Natural Gas Liquids segment. Total NGL raw feed throughput volumes increased 5% year-over-year and 4% compared with the first quarter 2022. Rocky Mountain region NGL volumes increased 10% year-over-year and 5% compared with the first quarter 2022. Activity in the region has rebounded following the April storms, as July volumes averaged more than 360,000 barrels per day, 9% higher than the second quarter average. Mid-Continent NGL volumes increased 4% compared with the first quarter 2022, driven by increased C3+ volumes as producers continued to add rigs in the basin, with a large majority of the region's NGLs dedicated to ONEOK system. In the Permian Basin, NGL volumes increased 10% year-over-year and 4% compared with the first quarter 2022. We recently completed a 25,000 barrel per day expansion on a portion of our West Texas NGL pipeline in the basin to support continued expected volume growth. We saw increased ethane volumes on our system in the second quarter 2022, and expect continued opportunities for ethane to be recovered through the remainder of the year. We anticipate high levels of recovery in the Permian Basin, periodic recovery in the Mid-Continent and continued opportunities to incentivize ethane recovery in the Rocky Mountain region as in basin natural gas prices fluctuate. Our fractionation…

Thank you, Walt and Kevin. As we enter the second half of 2022, we see producer activity and attractive commodity prices providing tailwinds to our business. We’ve affirmed our financial guidance for the year underscoring the resiliency of our operations, earnings and employees, who are always ready and willing to respond to changing market and operational dynamics. Challenges happen in our business and weather is unpredictable, but how we respond to the – is the real difference maker. Operating safely, sustainably and environmentally responsibly remains an important focus and is key to our success as a midstream operator. How we operate is important, but also how we engage with our employees, communities and other stakeholders is also important. To learn more about our commitments in these areas, I encourage you to review our most recent corporate sustainability report, which was just published to our website last week. The report details are most recent environmental, social and governments related performance and programs and highlights key initiatives underway across the company. Our ESG efforts are a source of pride for ONEOK, and we are committed to continuing to make progress in these important areas. With that, operator, we’re now ready for questions.

Thank you, sir. [Operator Instructions] We will take the first question from Jeremy Tonet from JP Morgan. Your line is open. Please go ahead.

Hi, good morning.

Hey, good morning, Jeremy.

Just want to dig into Medford a little bit more if possible, and as we think about everything there talked about not being material, but maybe it could help us to understand better what the threshold is for financial materiality there. And then just as far as kind of the parameters of what’s happened with regards to volume offloads, where are those volumes going now? Can you tell us? And you said about the timeline being extended, if this slips deeper into 2023 with this impact – might it impact your ability to offload volumes if volumes continue to grow?

So Jeremy, I think I’ll let Walt take the materiality question for us and then we’ll flip it over to Kevin and Sheridan on the offloads.

Well, Jeremy, I think that we’re very comfortable with that, that comment. I’m not going to give you our level of materiality, but I will say that remember that our insurance coverage provides for a 45-day period, which we have as a standalone and then we have business interruption insurance from that point forward. So we’re very, very comfortable with the view of where we’ve come out from a materiality standpoint.

Yes, Jeremy, it’s Kevin. On the volumes and where they’re going right now, I mean, clearly a lot of them are going down to Belvieu. We talked in our remarks about our industry peers that have been very helpful in securing spots for those barrels. We feel good about being able to move the volume. Especially as we get to MB-5 and keep in mind, that’s going to be another 125,000 barrels a day of new capacity that will come online early in the second quarter. So that’s the things we’ve got lined up there. And again, we feel good about being able to move the volumes.

One thing I’d add is, we’ve been able to talking with our peers, we have very much comfortable with our growth plans through 2023, depending on how long this lasts, it will be able to handle all of the volume income in our system.

Got it. That’s helpful. Thank you for that. And just want to pivot over towards IROF if we could and realize it’s hot off the press, and it seems like the shape keeps changing a bit here and what the bill looks like. But just wondering thoughts you could provide as far as how as it currently stands this might impact your tax profile in 2023 or going forward. And as the bill is written right now, separately, would this increase or change your appetite to pursue CCS, renewables or other items like that?

Well, I’ll handle the tax portion of that. Jeremy, that the – you’re right, it’s still off the presses and we’re getting a lot of the details, but I do think the late in the game addition of using tax depreciation versus book depreciation was a positive development for us. And we don’t see a real meaningful increase in our tax over the long-term. We may have a little bit higher tax in the earlier years, but if we get into that alternative minimum tax at that 15% that would be for an extended period of time where we would’ve otherwise gone to a statutory rate. So while we expect some are higher level of taxes that addition to the tax depreciation was a big positive.

And so I’ll take the question about CCUS. I’d like to remind everybody on the call that 36% of the natural gas demand in this country is devoted to electricity. You add to that 33% in the industrial sector. So that’s a total of almost 70% of the natural gas demand goes to those two forms of consumption. Anything that is done that would enhance the ability to capture carbon from natural gas being consumed is a good thing for our industry. And so these incentives, it’s left to be seen exactly how effective they’re going to be, because we need to know the details, but it does encourage us as an industry and as a producer of natural gas and actually, the liquids that are coming off the oil production and the natural gas production in these rich basins that this will help to curb the CO2 emissions in the future. And we do think that will open up some opportunities that we will look both at CCUS and hydrogen. So I think it’s a positive for the industry what’s happening.

Got it. That’s helpful. I’ll leave it there. Thanks.

We will take the next question from Brian Reynolds from UBS. Your line is open. Please go ahead.

Hi, good morning. Maybe to touch a little bit on the 2022 reaffirming guide as it relates to the base business ONEOK appears to expect a complete roughly 60% of its wells for the year in the back half of 2022. And Mid-Con volumes looked to be on track to surpassed 4Q 2019 levels by year end. So I was just kind of curious if you could just talk about given the year-to-date impacts from weather in the Medford frac fire. Was curious if you could talk about how the base business is performing relative to initial year expectations in terms of activity. Thanks.

I mean, I’ll start Brian. This is Kevin. I think the base business is performing very well. If you think about where we were going into the storms, we were right on track with everything that we had kind of outlined and laid out. The storms up in the Bakken did kind of set the basins back a couple months, not just with the volumes flowing, but also it was kind of a couple months pause on lower completions that we saw. So it kind of delayed things, and that’s the reason that we’re going to be at the lower end of the guidance from a volumetric perspective there. But on the flip side, when you look at the NGL business and what they’ve done both from a earnings perspective, as well as a volumes perspective, and then the outperformance of the gas pipeline business, I think those two segments are performing at or better than we anticipated coming into the years. So I think it sets us up nice going into to 2023.

Great. Appreciate that color. And follow-up on the Medford frac. I know while it’s probably a little bit too early, has there been any initial thoughts on potential replacement of the Medford frac and whether we could see it be built in Mont Belvieu or Conway at the time.

Brian, you hit it on the head. We’re still really early in that process. And, and again, not ready to talk about timing or anything like that. We’ve got capacity secured, we believe to move our volumes and we’ll keep working that until we get more information.

Fair enough. Enjoy the rest of your day, everyone. Thank you.

Thank you.

Next question from Michael Blum, Wells Fargo. Your line is open. Please go ahead.

Thanks. Good morning, everyone. So apologies for maybe a technical question. But just so I understand, are you going to be accruing insurance proceeds in your EBITDA results in Q3 and Q4? So that’s how guidance is basically unchanged or is that not the case and you’re just able to make it up in other areas.

Michael, we expect to get timely recovery of our business interruption insurance. We will actually book that as we receive those proceeds. But that’s why we said that we may have from time to time a – little bit of a timing difference if we hit right at quarter end. But we expect timely ongoing payments that would flow through our income statement in a normal way.

Okay, great. Thanks for that clarification. Also just wanted to ask about AECO gas prices, which are big trading at a pretty big discount to Henry Hub. Can you just remind us how your ethane recovery economics in the Bakken work? Will you benefit any way from the decline in AECO gas prices? Thanks.

Michael, this is Sheridan. The way we buy gas at the alternative at the gas plant. So we go and look at what we could sell gas at the gas plant versus what we could sell ethane in Mont Belvieu. And so whatever the gas plant is receiving, that’s what we can get. So an AECO price is a factor in what the gas price we’re receiving at the gas plant.

Got it. Thank you.

Next question from Colton Bean, Tudor, Pickering, Holt & Co. Your line is open. Please go ahead.

Good morning. So the NGL segment had a fairly significant step up in costs. Of the three drivers you mentioned, I think fuel power and then third party services. Do you expect an improvement in the back half of the year for any of those or is Q2 level of pretty good run rate moving forward?

Well, I think there are a couple dynamics going on Colton, the 30 million you referenced really got power costs were just higher, but we also had a more volume. So you had more power just moving it there. And then we also had a turnaround in the second quarter, which caused us to go get some outside frac capacity during the quarter, and that’s in there as well. So some of those costs will just be – will float as power costs moves around. But some of the other costs were more one time. So that’s as we think going forward, we typically do more work like turnarounds and integrity work and other expense project type work. We’ll do more of that in the summer when the weather is better. So historically, you might see a little stronger in the summer from a cost perspective on those types of activities.

Understood. And then just following up on the Bakken ethane discussion, I mean, it sounds like, with the wider gap between AECO and Mont Belvieu pricing this quarter. Would you expect any upside to that bundled rate? Just if you – if the incentive rate that you have to offer is now less of a discount than it would’ve been previously.

Colton, there’s a lot of factors that go into that. Sometimes it impacted, sometimes it doesn’t. I think we’re – we think we have a good opportunity to incentivize more ethane in the second half of the year. So we’re very bullish on that, but due to the regional gas prices, but how it affects the overall average rate kind of depends on where it’s come volume and the escalators that we have on our base business.

Got it. Appreciate the time.

Next question from Theresa Chen from Barclays. Your line is open. Please go ahead.

Hi. I just wanted to ask first on the $16.4 million increase in the NGL segment related to higher average fee rates. Can you tell us what that was related to precisely and is that expected to carry forward?

Yes. That was mainly related to inflationary escalators for both fuel and power and inflation, and we do have those inflationary escalators coming on throughout the year. So we do anticipate it will increase.

Okay. Thank you. And in your GMP segment, the $5.3 million increase due to the contract settlement during the quarter. Should we expect some sort of offset and base earnings going forward as a result?

No, I don’t believe you’ll see any offset. It’s just normal course of business on our large portfolio mix. So I don’t – you won’t see any offset.

Thank you.

Next question from Michael Lapides, your line is open. Please go ahead – from Goldman Sachs.

Hey guys. Thank you for taking my question and congrats on a really good quarter. Just curious as you think about infrastructure needs going forward, given kind of some of the volume commentary about July volumes, how are you thinking over the next year or so about the need for either new processing or even a sixth frac at Belvieu?

Michael, this is Kevin. I mean, I think we’re in really good shape as we’ve talked for the last several months. And when you think about Demicks Lake III coming up, that gets us a nice headroom of capacity in the Bakken. We’ve talked about the available capacity that’s currently exists on Elk Creek and then we’ve got low cost expansion opportunities if we need to expand that pipe. We just demonstrated, we’ve got some expansion opportunities on West Texas as our volumes continue to grow out there that we can expand that pipe in tranches. Plenty of capacity in the Mid-Continent, obviously with what’s going on at Medford frac capacity is tight and is going to remain that way until we get clarity on what’s going on with Medford. But other than that, we’re in excellent shape as we think about our capacities and where we’re at.

So then, if there’s not really a need potentially, I mean, volumes could always surprise to the upside. But if there’s not really any need for any material new asset development in 2023, that implies that the capital budget kind of declines a ton, which not a surprise. How are you and how are the Board – how’s the Board kind of thinking about capital allocation and uses of some of that significant free cash flow that you might be generating next year?

So this is Pierce. The way we look at that is that we look at all the levers that’s available to us. So we’re going to be looking at as we get closer and closer to what Walt had mentioned about the 3.5x on the debt to EBITDA ratio as we continue to go below 100% on our payout ratio, then that’s going to actually open up some of those other elements to us that we’ve had in the past. Of course, our first focus is going to be on these organic opportunities because they give us the best chance to deploy capital that gives us really, really good rates of return. We are proud of our ROFC that we’ve been able to achieve, and we are predicting that is going to continue to go up. So I think what it’s going to do is just give us more flexibility to use whatever levers that we feel like, bring the most value to our shareholders.

Got it. Thanks guys. Much appreciate it.

Next question from Chase Mulvehill from Bank of America. Your line is open. Please go ahead.

Good morning. I wanted to come back to the GMP side of the business, and I guess a few questions. I guess just correct me if I’m wrong and I think your commodity or POP exposure is 15% to 20% this year. And then maybe just remind us again, the gas versus NGL exposure on those POPs and how much you have hedge versus open today? And then just maybe tie into there, kind of what you’re thinking about realized GMP rates in the back half of the year?

Chase, this is Kevin. You’re right. We provide the hedging information that’ll come out in our Q and we’ve provided that in the past. So we are pretty well hedged, but prices have run up significantly and we’ve been able to benefit for that – for the part of those that those contracts that aren’t hedged. So that’s what you’re seeing. And also the other thing that’s driving the price improvement is just what volumes are on what contracts. So we’ve been fortunate to have some volumes come in on higher in this case, higher POP type contracts and been able to benefit from that.

Is it fair to assume in 3Q that a lot of your open volumes were natural gas as opposed to NGLs?

Typically from an open perspective, we’ve got – we hedge most of our commodities in a similar way. So you’re not going to have a higher percentage hedge necessarily of natural gas versus crude versus NGLs.

Okay. All right. If we go up to the NGL section and look at volumes and kind of where they are today, I think you said, 360,000 barrels a day. If we go back and look back in April, you were doing 385,000 a day. So we’re not back to kind of April peak-ish levels, but yet GMP volumes in the Rockies are actually back to peak levels. So kind of help me connect the dots there. Is that Medford related or is there something else, and should we kind pretty quickly back to that 385,000?

I think the first quarter announced – this is Sheridan. We came out and said, we had reached 385,000, but we had an average 385,000. Actually July at 360,000 will be our highest monthly average that we’ve had off the Bakken pipeline. And we continue to trend higher in – as we get into August, we are trending even higher than that. So from an NGL perspective on the Elk Creek pipeline, we are back further than we were in the first quarter, or even in the fourth quarter of 2021.

Okay. All right. Last one, just going to squeeze one more and I apologize. Just want to confirm this. It sounds like, obviously you’re seeing – looking at Medford and trying to figure out when you can bring it back online. But I just want to confirm that it is not a total loss. You do not see it as a total loss at this point. Correct?

Well, I mean, the way I would say that right now is we are looking at all the pieces and parts to that facility right now. So we’ll be assessing that over the coming weeks as to exactly what pieces of equipment are still usable or are not. So we can’t say emphatically right now that it’s either a total loss or not a total loss. We’re doing the assessments of that.

Okay. Got it. Makes sense. I’ll turn it back.

Next question from Craig Shere from Tuohy Brothers. Your line is open. Please go ahead.

Good morning. Congrats on the quarter. One clarification on Medford. So as far as new expense for third-party fractionation or things that were contracted, you ultimately get insurance recoveries, but doesn’t this kind of at least limit optimization margin opportunities until something’s resolved?

Yes. Craig, I think that we are – we believe that we’ve got business interruption insurance for our entire business under that coverage. And really don’t see a meaningful difference from how our earnings would be sorted out in our normal guidance.

Okay. And maybe this is expressing my own ignorance and I apologize. Given the increased gas storage and storage pricing, I’m kind of assuming storage is more of a steady year round product versus gas pipes that have more seasonality since the storage has to fill. So if that’s the case, does the improving storage position in terms of capacity and pricing, reduce your gas height seasonality?

Craig, this is Chuck. No, see the way we contract with our customers, frankly these are firm fee-based contracts. What the customer tends to do is play seasonal spreads and utilize their transport and combined storage for optionality. So from a pipe standpoint, we’ve got levelized fee earnings throughout the year. So the optionality actually comes from the customer, but not the pipeline, so variability from the customer, not the pipeline.

Got you. So the increasing contribution of storage really doesn’t impact seasonality.

Could you repeat that?

So the fact that you’re increasing the amount of storage and the pricing is looking more attractive that doesn’t have any impact on the seasonality question?

Correct. We’re seeing a step up in our storage revenues based on higher rates and the expansion that came online in April. And we’ll have an additional expansion come online in April of 2023 where you’ll see another step up in our storage revenues.

So, Craig, the only thing I’d add to that, this is Pierce, is post Winter Storm Uri, the value of storage has increased. And so we do have customers that lay that seasonal spread and that benefit goes to them. But we also have utilities that are putting gas into storage every single month during the summers getting ready for that winter pull that they have during their peak demand from basically December through March.

Got you. Thank you.

Next question from Jean Ann from Salisbury, sorry, Jean Ann Salisbury from Bernstein. Your line is open. Please go ahead.

Hi. good morning. It looks like there has been some movement on the open season for gas takeaway options out of the back end, but it seems like they’re targeting 2026, which is kind of a long time from now. Do you think that will be soon enough to not constrain gas growth out of the Bakken?

Jean Ann, this is Kevin. Yes, I think we feel good about the timing of that. There’s some other smaller scale things that have gone on up there that have created a little more capacity. So we think that timing lines up pretty well with the kind of our outlook of where gas volumes go. I would remind you, there’s still, we believe 300 million, 400 million a day of Canadian gas that can be displaced coming out of the Bakken. And so that’s there’s capacity there that just may not on the surface look like it’s there. In addition, we can always, if you get tight and we’re I say, we’re wrong or we’re a little bit late, you can always recover ethane to reduce the MMBtus that go into the pipe. So we – all in all, we feel good about where we’re at.

That makes sense. Thank you. And there has been a trend of NGL integrated midstream companies, buying GMP companies, which ONEOK has not really participated in. If this trend continues, do you see it potentially impacting your rates or your close on the Gulf Coast negatively?

Well, I think I’ll let Kevin get into the details of this, but we believe that the positions that we have in the other basins are the right thing for us to pursue based on our positions with our assets and the things that we see in the future. I mean, it’s – could it have a downward pressure on some of the volumes? Yes. But I’d remind everybody that the rates that we get as far as margins in the Permian, in the mid-continent are some of our lowest ones. So as far as having a really material impact, we don’t see that in the future. Kevin, you got anything to add to that?

No, I’d just say that with some of those transactions, obviously, we take a look a lot of things, but they just haven’t been a fit for us. One of the things I would put out there is that me that we could have continued to grow volumes on our West Texas LPG system. Many of those contracts have quite a bit of term left, and many of them are with producers who have taken kind rights. So regardless who the processor is we believe those volumes will stay with us. So that’s some of the other dynamics at play.

Great. That’s very helpful. That’s all for me. Thank you.

The next question from Sunil Sibal from Seaport Global Securities. Your line is open. Please go ahead.

Yes. Hi, good morning, folks. And thanks for all the clarity on the volume trend. So one question for me on the CapEx side of things, could you talk a little bit about what kind of inflation trends you’re seeing in terms of building costs versus what you had budgeted at the start of the year?

Yes. From a cost perspective, we’ve probably seen more pressure on outside services more than anything as we think about our projects. In many cases for the projects, we were working on, especially MB-5 and Demicks III that equipment had been purchased years ago before the projects were paused. So we had a lot of that taken care of. On the new equipment that we’re ordering and the new materials we’re ordering probably as much impact from a supply chain perspective just on a timeliness or schedule perspective than cost. So those are some of the things we’re obviously watching closely and staying on top of hadn’t impacted any of our scheduled dates or our dollar amounts that we’ve got these projects approved for. So we still feel very good that we’re right on top of on budget and on schedule.

Okay. Thanks for that. And then one housekeeping question for me, it seems like, your reconciliation, you had called out a 10 million sequential decrease in the NGL segments from commodity price differentials. I thought the commodity price differentials kind of widened out a little bit in Q2 versus Q1. Am I just looking at that correctly? And I was curious about that line item?

Sunil, this is Kevin. Yes, that’s just with our assets and with – we’ve got assets in Conway and Belvieu and storage, that’s just the delta between sometimes we have an opportunity to make money than as different prices per by commodity. So how different prices compare of the different commodities in how we move barrels around and how we sell barrels. And so that 10 million was just lower than the – sequentially lower in the first – than the first quarter in that part of our business. But it’s all in is part of that kind of how we’re optimizing our system.

Okay. And anything to read into that from for the second half of this year?

No, that bounces – that’ll bounce around quarter-to-quarter just in the sequential comparison.

Got it. Thanks. Thanks for all the color.

Next question from James Carreker from U.S. Capital Advisors. Your is open. Please go ahead.

Hey, thanks for the question. Just thinking about the Medford outage some more, were those NGLs fractionated there largely sold into Conway, or they sold down in Mount Belvieu and just making sure that there’s with that outage there’s sufficient pipe capacity to move incremental barrels down to Mont Belvieu to get fracked?

James, this is Sheridan. We don’t designate by frac where we sell barrels. We can – with our integrated system, we can deliver barrels from any of our frac into the Mont Belvieu complex. And with that frac being down, we can get these barrels into the Mont Belvieu complex, mainly because of our Arbuckle II asset that we had just brought online that we know had significant extra capacity on it for upside. So we’re able to deliver through the raw feed system down to Mont Belvieu. And if we need to, we can use the purity system to do that as well. Since we don’t have as much purities coming off the – we don’t have any purities coming off the Medford frac. We have a little bit extra capacity on that. So from a pipeline perspective, we feel very good about getting the product into Mont Belvieu.

Thanks for that. And I guess maybe one follow-up, maybe it’s minor, but just noticed on this earnings presentation, you’re now saying greater than $0.06 bundled rate on your Gulf Coast, Permian volumes versus prior approximately $0.06, is that maybe a trend that continues or any other color on what’s going on there?

Yes, a lot of it, I think we’ll see our rates tick up a little bit, and you’re seeing that because of the inflationary escalators that we have on our system.

Okay. Thank you.

Thank you.

It appears that there is no further question at this time. Mr. Andrew, I’d like to turn the conference back to you for any additional or closing remark.

Our quiet period for the third quarter starts when we close our books in October and we’ll extend until we release earnings in early November. We'll provide details for that conference call at a later date. Thank you all for joining us, and have a good day.

This concludes today's call. Thank you for your participation. You may now disconnect.