Good day and welcome to the Second Quarter 2021 ONEOK Earnings Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Andrew Ziola. Please go ahead, sir.

All right. Thank you, Casey, and welcome to ONEOK’s second quarter 2021 earnings call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. After our prepared remarks, we’ll be available to take your questions. 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, before we turn it over to the conference coordinator for Q&A, we ask you 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, and good morning, everyone. Thank you for joining us today. We appreciate your interest and investment in our company. For 32 of my almost 40 year career, I had the good fortune to work with the assets in the people through various companies that are now a part of ONEOK. I’m excited and honored to be back. This company has a strong experienced management team and a talented workforce, and we are all looking forward to the future. On today’s call we’ll be discussing ONEOK’s strong performance in the second quarter. And I’ll provide a few of my initial thoughts as to how the management team and I will continue to build on the accomplishments of those that preceded me in this role. I’m also looking forward to reacquainting or meeting many of you in the near future. Joining me on today’s call is, Walt Hulse, the Chief Financial Officer and Executive Vice President Strategy 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 Kelly, Senior Vice President, Natural Gas. I’d like to first start off this call by recognizing and congratulating Terry on his retirement and thanking him for his availability to advise me in my new role. ONEOK has seen tremendous growth and success under Terry’s leadership the last seven years as he’s navigated the company through several growth cycles and industry challenges, including delivering strong results during a pandemic. Terry championed many companies’ successes. The transition to higher fee based business model with less commodity price exposure, significant improvements in company-wide safety and environmental performance. The successful ONEOK partners merger transaction and the completion of more than $10 billion in capital growth projects, to name just a few of his many accomplishments. The company has grown in many ways since I was here last, and I’m looking forward to building on what Terry the Board, the leadership team and ONEOK’s 3000 employees have achieved. It’s been extraordinary. During this first month on the job, I’ve been re-familiarizing myself with our business, holding strategy and planning meetings with the team, and most importantly, listening. I’ve met with my leadership team and many employees to hear more about their focus areas. These introductions and conversations are very important and we’ll continue. What you can expect from me as a CEO is that we will be disciplined and intentional in all that we do and continue to encourage a culture that promotes safety, reliability, employee engagement, value creation, and environmental responsibility. These principles have served ONEOK well for decades and will continue to be a key element of our daily operations and business decisions going forward. The energy systems today were designed to operate on the consumers’ requirements for affordability, reliability, and resiliency. We will continue to focus on meeting our customers’ needs while also transforming these energy systems to drive the overall lowering of greenhouse gas emissions. Yesterday we reported a strong second quarter financial result, supported by increasing volumes across our systems. The energy and economic backdrop continues to improve, with producer activity accelerating in demand for NGLs and natural gas strengthening. Kevin will talk more in detail about how we’re addressing those needs, but first, I’ll turn the call over to Walt to discuss our financial performance.

Thank you, Pierce. With yesterday’s earnings announcement, we updated our 2021 financial guidance expectations. Our view of 2021 continues to improve as we now expect 2021 adjusted EBITDA to be above the midpoint of our guidance range of $3.05 billion to $3.35 billion that we provided back in April. Our outlook for growth in 2022 has continued to strengthen. Higher commodity prices, accelerating producer activity, and the rising gas-to-oil ratio in the Williston Basin, provide a tailwind into next year. With available capacity across our operations and the completion of our Bear Creek plant expansion later this year, significant earnings power remains across our assets without the need for significant capital investment. The strengthening momentum going into 2022 makes us confident that we will achieve or exceed the 2022 outlook we have discussed on previous calls. Now for a brief overview of our second quarter financial performance. ONEOK’s second quarter 2021 net income totaled $342 million or $0.77 per share. Second quarter adjusted EBITDA totaled $802 million, a 50% increase year-over-year, and a 3% increase compared with the first quarter 2021 after backing out the benefit from Winter Storm Uri. We ended the second quarter with a higher inventory of unfractionated NGLs, due to planned and unplanned outages at some of our fractionation facilities. We expect to recognize $12.5 million of earnings in the second half of 2021 as our current inventory is fractionated, and so the majority of which will be recognized in the third quarter. Distributable cash flow was $570 million in the second quarter, and dividend coverage was nearly 1.4 times. We generated more than $150 million of distributable cash flow in excess of dividends paid during the quarter. Our June 30 net debt to EBITDA on an annualized run rate basis was 4.3 times, and we continue to work towards our goal of sub four times. We ended the second quarter with no borrowings outstanding on our $2.5 billion credit facility, and nearly $375 million in cash. In July, the Board of Directors declared a dividend of $0.935 or $3.74 per share on an annualized basis, unchanged from the previous quarter. Our strong balance sheet, ample liquidity, and increasing EBITDA from volume growth in our system providing solid financial backdrop and flexibility as we enter the second half of the year. I’ll now turn the call over to Kevin for an operational update.

Thank you, Walt. Our second quarter NGL raw feed throughput and natural gas processing volumes increased compared with the first quarter 2021 driven by increasing producer activity, ethane recovery and gas-to-oil ratios that continue to rise in the Williston Basin. We expect these tailwinds to carry into the second half of the year and into 2022. In our Natural Gas Liquids segment, total NGO raw feed throughput volumes increased 17% compared with the first quarter 2021. Second quarter raw feed throughput from the Rocky Mountain region increased 18% compared with the first quarter 2021 and more than 85% compared with the second quarter 2020, which included significant production curtailments resulting from the pandemic. As a reference point volumes reached approximately 330,000 barrels per day in this region early this month. At this volume level, we still have more than 100,000 barrels per day of NGL pipeline capacity from the region, allowing us to capture increasing volumes on our system, including volume from a new 250 million cubic feet per day third party plant that came online in early July, and expansion of another third party plant that is underway and our Bear Creek plant expansion, which is expected to be complete in the first half of the fourth quarter this year. Total Mid-Continent region raw feed throughput volumes increased 16% compared with the first quarter 2021 and 10% compared with the second quarter 2020. The Arbuckle II expansion was completed in the second quarter, increasing its capacity up to 500,000 barrels per day, adding additional transportation capacity between the Mid-Continent region and the Gulf Coast. In the Permian Basin, NGL volumes increased 16% compared with the first quarter 2021, primarily as a result of increased ethane recovery and producer activity. Petrochemical demand continues to strengthen and is seen support from a continuing global pandemic recovery. This led to increased ethane recovery across our system in the second quarter. Ethane volumes on our system in the Rocky Mountain region increased compared with the first quarter 2021 as we continue to incent some ethane recovery on a short term basis. Continued ethane recovery in the Rockies in the second half of 2021 will depend on regional natural gas and ethane pricing. We have not included ethane recovery from the Rockies for the remainder of the year in our updated financial guidance. Ethane volumes on our Mid-Continent system increased compared with the first quarter 2021 due to both favorable recovery economics and some incentivized recovery. We continue to forecast partial ethane recovery in our guidance for the second half of the year in this region. Ethane volumes in the Permian Basin increased in the second quarter compared with the first quarter 2021. We continue to expect the basin to be in near full recovery in the second half of the year. Discretionary ethane on our system or said differently, the amount of ethane that we estimate could be operationally recovered at any given time, but is not economic to recover at current prices without incentives is approximately 225,000 barrels per day. Of that total opportunity, 125,000 barrels per day are available in the Rocky Mountain region and 100,000 barrels per day in the Mid-Continent. Full recovery in the Rockies region would provide an opportunity for $500 million in annual adjusted EBITDA at full rates. Moving on to the Natural Gas Gathering and Processing segment; in the Rocky Mountain region second quarter processed volumes averaged more than 1.25 billion cubic feet per day, an increase of 6% compared with the first quarter 2021 and more than 50% year-over-year. An outage at one of our plants, which has since come back online decreased second quarter volumes by approximately 15 million cubic feet per day. Toward the end of June volumes reached 1.3 billion cubic feet per day and we have line of sight to even higher processed volumes later in the year given the recent increase in completion crews and rigs in the basin. Conversations with our producers in the region continue to point to higher activity levels in the second half of 2021 and 2022 particularly in Dunn County, where construction on our Bear Creek processing plant is on track for completion in the first half of the fourth quarter of this year. Once in service, we will have approximately 1.7 billion cubic feet per day of processing capacity in the basin, and we’ll be able to grow our volumes with minimal capital. In the second quarter, we connected 84 wells in the Rocky Mountain region and still expect to connect more than 300 this year. Based on the most recent producer completion schedules, we expect a significant increase in well connects in the second half of the year, with some producers aligning the timing of well completions closer to the completion of Bear Creek. There are currently 23 rigs operating in the basin with nine on our dedicated acreage and there continues to be a large inventory drilled, but uncompleted wells with more than 650 basin wide and approximately 325 on our dedicated acreage. We expect the current DUC inventory to get worked down before we see producers bring back more rigs to the basin to replenish inventory levels. As we said last quarter, the eight completion crews currently operating in the basin is enough to reach our well connect guidance for the year. Any additional completion crews would present upside to our guidance. Rising gas-to-oil ratios and natural gas flaring in the basin continue to present opportunities for volume growth without the need for additional producer activity. Since 2016, GORs have increased more than 75%. Recent projections from the North Dakota Pipeline Authority show that even in a flat crude oil production environment, GORs could increase an additional 45% in the next seven years. This could add 1.3 billion cubic feet per day of gas production and approximately 150,000 barrels per day of C3+ NGL volume to the basin during that same time period. Again, this growth in natural gas is only based on increasing GORs and assumes flat crude oil production. Any growth in crude oil would be upside to those projections. We’ve added a new slide in our earnings materials to show these latest North Dakota projections, which include various production scenarios. During the second quarter, the gathering and processing segment average fee rates increased to $1.06 per MMBtu driven by higher Rocky Mountain region volumes. We now expect the fee rate for 2021 to average between $1 and $1.05 per MMBtu. Mid-Continent region average process volumes increased 4% compared with the first quarter 2021 as volumes returned following freeze-offs in the first quarter. While the region has received some attention as commodity prices strengthen, producer activity has been more moderate than other areas. In the natural gas pipeline segment, the segment reported a solid quarter of stable fee based earnings. The decrease in earnings year-over-year was driven by a onetime contract settlement that provided a $13.5 million benefit to earnings in the second quarter of 2020. We continue to see increased interest from our customers for additional long-term transportation and storage capacity on our system, following the extreme winter weather events earlier this year. Since the first quarter, we have renewed or recontracted additional long-term storage capacity in both Texas and Oklahoma, including a successful open season for more than 1 billion cubic feet of incremental firm storage capacity at our West Texas storage assets. We’ll continue to work with customers to contract additional long-term capacity as we head into the winter heating season. Pierce, that concludes my remarks.

Thank you, Kevin. The results achieved so far this year, only 12 months removed from the unprecedented conditions in the second quarter of 2020 are nothing short of amazing. Resiliency of our assets and our employees and the caliber of our customers, we’re able to work with and provide a long-term runway of many opportunities. But key to our success will continue to be operating safely, sustainably and responsibly with the health and safety of our communities and employees at the forefront of all that we do. To learn more about our commitment to responsible operations, I encourage you to review our most recent corporate sustainability report, which was just published to our website last week. The report details our most recent environmental, social and governance related to performance and programs and highlights key initiatives under way across the company. Its ONEOK employees, who carry out these initiatives every day, and who prioritize the safety and well being of their fellow employees, customers and the public. Thank you for your continued hard work and your dedication to safety to this company. Again, I’m excited to be back at ONEOK, and I’m looking forward to the opportunities and the challenges ahead. Operator we’re now ready for questions.

Thank you. [Operator Instructions] We’ll take our first question from Shneur Gershuni with UBS.

Hi, good morning everyone. Pierce, nice to hear your voice on a different conference call and I’d like to send a congratulations to Terry on a very successful career and congrats on starting a new chapter. Maybe to position and so Pierce to put you on the hot spot, hot seat right off the back here. But I was wondering if we can talk about your thoughts around buybacks in CapEx for 2022. I imagine there’s not much on the CapEx front, just sort of given where you are at this point right now. Maybe a completion of the frozen frac is two inches with the higher ethane recovery that in Kevin’s comments about C3+, with respect to GORs, but outside of that doesn’t appear to be much on the CapEx side, when it’s different take the soft outlooks that have been presented in the past $3.5 billion to $4 billion has kind of been thrown around into potential 2022 run rate. It sort of suggests it’s the leverage for what I was going to be some four times leverage ratio target. This is set up for buybacks in 2022? If so, how should we think about execution around buybacks? Or if I got the thought process online on CapEx? Just curious on your thoughts.

So, Shneur, first of all, thank you for the welcome back. And we will certainly pass on your comments to Terry. And I think we all echo those as well. And we’ll make some kind of a broad comment, and then I’m going to let Walt kind of answer kind of more specifically. But we’re in the process of looking at our strategic plan and our earnings projection, not only for 2022, but also for the next five years. As a part of that, we’ll be assessing what I would consider, our capital allocation opportunities. So, I don’t have a specific answer to, exactly for the buybacks for next year. But I would say that’s all a part of our capital allocation plan and the strategy that we’re actually currently talking about now. So, I’d like Walt to kind of weigh in on any more particulars that any insights that he might have.

Sure. Thanks Pierce. Well, Shneur basically, I would agree with your assessment of the tailwinds that are behind our business today. And we’re excited about the opportunities that are forward and the cash flows that will generate from that we’ll continue to enhance our de-leveraging strategy that’s been in place for quite some time. And we’re starting to see some of our end goals in the near term coming forward. And as we get closer to our goals of sub four times leverage, then obviously, we will expand the horizon of things that we’ll look at from a capital allocation. And I think we spent time with Pierce, we’ll look at all of our options. As we go forward. You’re right that there isn’t any major CapEx project on the horizon here are we really doubled the capacity of our long-haul pipes and the NGL business over the last several years. And that gives us a lot of running room going forward, you highlighted that we have a couple of projects that we pause back with a pandemic. And over the course of, next year or two is, as producer activity picks up, I would assume that we’ll likely clean some of those up and finish them up to meet our customers’ needs. But it’s really going to be routine growth than some smaller growth projects that are very attractive going forward. So, we’ll have plenty of free cash flow to continue to de-leverage and then look at all of those capital allocation opportunities over the next couple of years.

Really appreciate the detail color there. And maybe as a follow up question here, just given the fact that that Terry’s been at the company for so long, and so effective [ph] strategy and so forth Pierce you’re coming in now, how are things going to change? How are they going to stay the same with respect to strategy? Would there any specific marching orders that were given to you from the board upon your arrival? Just kind of curious if you can sort of talk to that kind of holistically?

Sure, I’ll be glad to answer that. I think it’s not so much about, what’s going to change immediately in the company. I think it’s more about what’s changing in the energy industry, I think we can probably all agree that the energy systems across the United States, it’s going to be very important that we continue to transition into a lower carbon energy system across United States. So really, it’s about how we at ONEOK and the assets, and the people in the skill sets that we have, are actually going to transform with that energy system. I view that as a three step process, first of all, you got to understand, what the transformation of the energy systems look like then you prepare for that, for what you’ve learned and what you understand. And then you innovate. And I think that’s the three focus areas that I would say that we have going forward is understanding, where we are preparing and innovating for the future, while at the same time continuing to grow the base business that we have in the use of natural gas and natural gas liquids, because I think the global poll, most countries are not where we are in the United States as far as the maturity of our systems and the transparency that we have in the energy systems here in the United States. So think that’s going to continue to pull for natural gas demand as well as natural gas liquids growth, while at the same time we’re going to be able to use the skill sets and the talents that we have in our company to transform. I do think transformation is a better word than transition. Transition, to me indicates that you’re going to leave one thing and go to another transformation. In my opinion, it means that you’re going to use something that you have, and maybe use it a little bit slightly different, in the future to meet some of the problems that we have, I do think it’s important for the United States to lead in the effort of lower carbon, because I think the other parts of the world can learn from what we do, although there’s only 6.6 gigatons of CO2 emissions in the United States versus 51 gigatons over the globe. So we’re a small percentage, but I think it’s important for the U.S. to lead in these efforts. And, and I do feel like that, ONEOK is positioned. Over a long period of time, a lot of these things, as you look at CNG and hydrogen and LNG for long-haul and carbon sequestration and capturing methane, those are all going to be opportunities that we experienced over the next several decades.

Great. Really appreciate the color and congratulations on the new role.

Well, thank thanks again.

Our next question comes from Christine Cho with Barclays.

Thank you, Pierce. Welcome back to this side of ONEOK. I thought I would maybe start with an ethane question. This quarter, you guys took out more ethane in the back end. And you talk about 25,000 barrels a day of ethane extraction being an incremental $100 million. But that’s predicated on you collecting the full $0.28 TNF. You haven’t been collecting that when you’re doing it more opportunistically and when you do provide more ethane to the market this way, it sort of puts a lid on what prices can be so curious, how do you balance this and make sure you don’t provide too much supply that it negatively impacts a frac spread economics and other basins that you’re in? And what really has to happen in order for producers to sign up for long-term contracts for ethane TNF out of the back end? Is it really only a firm Btu resolution on northern border?

Christine, thanks for the Welcome back. And I think Kevin and Sheridan can probably add more pillar to your question.

Sure. Christine this is Sheridan. I think in your first question on how do we determine how much ethane to bring out of the Bakken and what’s the right amount before putting a lid on ethane prices, really, when we try to understand is, where the next incremental ethane will come out and is that coming off our system or somebody else’s system. And so if we don’t bring it out of our system that somebody else can bring ethane out of their side of the system when we will lose the whole uplift that we’ll have from buying it at gas and selling it at ethane value. So it’s an ongoing process that we look at every month and we try to make that determination that’s why we don’t bring all the ethane now at the Bakken that we could. We could incentivize more. But we just bring what we feel is the right amount of ethane to come out. And really on your question of what would it take for producers sign up for ethane they have already signed up for ethane. They have the option today whether or not to bring ethane on the system or not to bring ethane on the system, we have the capacity for them. And they signed up for a certain amount of capacity. What it really comes down to now is what is going to drive the price high enough that we get a full TNF rate or the full $0.28 to bring that the ethane would come out. And what’s going to need to happen for that as you’re going to need to continue to have a strong ethane to ethylene spread like we have today very, very widespread. So that ethane can continue to rise, prices continue to rise. And the petchems can continue to make money off of that. The second thing is you need to have more demand. And then we need to see more exports coming out there is more export capacity out there and we need to see more crackers and in the second quarter of next year, the ExxonMobil, SABIC crackers going to come online as well. So that’s going to bring on more demand. And I think the third thing you need to look at is you need to look at regional gas prices between the Bakken and other areas. So, if we would see the Bakken gas prices dip down like we typically see in the summer, I think all those things together if they work that you have the possibility of an opportunity to see ethane come out that Bakken at full prices.

Got it. That was really helpful. And then I guess just moving over to I guess guidance. On a prior quarter call you guys kind of gave us off 2022 guidance of about $3.4 billion. Are you guys still feeling good about this? And what sort of ethane extraction assumptions or are you including in that?

So Christine, I’ll start by saying, we haven’t issued our 2022 guidance yet. We’re in the process of looking at that. But I will let Walt or Kevin chime in on that past comment.

Yes, Christine. I mean, I think, when we were still that number still out there that we talked about it as far as where we’d be in 2022. And since the last quarter, nothing, we’ve –everything strengthened since that time. I mean, prices have strengthened, the comments and the feedback we get from our producers have strengthened so that’s the way I would frame 2022 up is, it is definitely more constructive today than it was three months ago.

Got it. Thank you.

Our next question will come from Tristan Richardson with Truist Securities.

Hey, good morning, guys. Really appreciate the comments and kind of what you’re seeing in the second half. And particularly the comment on July, I think you noted, maybe at one point in time the system touched 330 a day is that including some recovery or at least incentivized recovery. So, are you seeing some recovery in the Rockies starting in the second half?

Yes, Tristan, this is Kevin. Yes, that would include some incentivized recovery, which we talked about in the remarks.

Okay. I appreciate Kevin. And then lastly, Walt I think you in the past have talked about the earnings engine at ONEOK and the potential for this business to produce EBITDA, the four handle? I mean, without asking you about a timeframe or anything, can you talk about some of the conditions necessary to hit that type of potential? And are you seeing some of that, as you look out over the near and medium term?

Well, I think that the way we’d frame that up in the past was that we have the assets in place, especially in the Bakken to achieve those types of earnings levels without any meaningful need for CapEx. As you continue to see gas volumes there, maybe at some point in the future, a need for another plant up there, but that’s not in the near term, we’ve got plenty of capacity and McKenzie County and now we’re going to have capacity down in Dunn County. So, we’ve got room to run, and we’ve got room to run on the NGL side. As we get closer to those numbers that would start with a four, we’re probably going to have to have some downstream additions that, like MB-5, and things like that, that would need to be completed. But none of those are major dollars in the scheme of the earnings power of the company. So, we’re pretty excited about, kind of the operating leverage that we have in the company, and the ability to continue to grow significantly with modest capital needs.

Appreciate it. Thank you guys very much.

Welcome.

Thank you.

Our next question will come from Jeremy Tonet with JPMorgan.

Hi, good morning.

Good morning Jeremy.

Hi, Jeremy.

I also want to send Terry our best going forward into retirement their best of luck. Maybe picking up on energy transformation, as you laid out there, RNG Biofuels, Hydrogen CCUS. Just wondering if there’s any specific initiatives that ONEOK is working on right now seems like there’s some things done the RNG side, but just wondering specifically right now, if there’s anything, near medium term opportunities that ONEOK is focused on.

Thank you. I picked up on probably the one that is probably the most likely the quickest. And that is the renewable gas opportunities primarily coming from; these are kind of listed in order of agriculture, wastewater and landfills. I’m going to kick it over to Chuck there just a second, because he can give you some updates on what we’re doing, as it relates to some of the RNG efforts, but the CNG and LNG for the long-haul, I think is another thing that could be a possibility. Hydrogen is probably out into the future because primarily in right now, you can’t take a certain amount of hydrogen based on the tariffs on the interstate and intrastate assets across the United States. But I do think that’s a developing opportunity left to be seen, economically, how that stuff plays off. And then you got carbon sequestration, because 24% of all the carbon emitted of the 6.6 gigatons actually comes from electric generation from coal, oil and natural gas, primarily, coal and natural gas. So, I think that’s going to be important to solve that equation. And of course, transportation has about 28% of that 6.6 gigatons. So, if you converted all the cars today to EVs, then you just switch the problem from transportation over to electric generation and then so you didn’t really solve the problem. So Chuck, I’m going to let you kind of talk a little bit about our RNG opportunities and what we’ve already done and are doing.

Sure, Pierce. So, it’s a little color, Jeremy on our interstate pipes, particularly if you think about where they’re located Upper Midwest, we’ve got, as you know, quite a few dairy farms up in that area. So, you have agricultural waste, we’ve connected three RNG facilities that are originated from dairy farms already up there, looking at another one. And then here on our intrastate business, particularly in Oklahoma, we’ve already connected a large landfill waste site recycling facility, looking at another and then of course, there’s some large feedlots in our Texas intrastate markets. So, we’ve been involved in connecting RNG and bringing that gas into our stream, delivering it to customers downstream. So this has been ongoing over the past three years, and we’re seeing that accelerate, so excited by the RNG aspects that we see out there.

So and I just kind of summarize that by saying that, as part of our strategic plan, we look to develop, business plans around all these different aspects of these opportunities. But I think, more importantly, as far as it what these opportunities do? Is they make the existing natural gas pipelines in the United States, relevant. Instead of just moving methane that you traditionally get from the wellheads, you’re actually capturing methane that is emitted to the air, which is 25 times more potent than the CO2, so you get to see, uplift in the CO2 equivalents. And so you get the extra benefit of removing that. And you’re using existing assets to help other industries reduce their environmental footprint. So the relevancy of it is the important part as opposed to some great business opportunity, to boost your EBITDA. It’s really designed around the relevancy of making essentially 2.6 million miles of pipelines in the United States are very important to the energy transformation future.

That’s very helpful. Thanks and just want to follow up a little bit as it relates to CCUS because it seems like North Dakota is kind of separate themselves, from what all the states given the multiple initiatives there for CCUS with power generation, for actually having primacy on the classics wells, and really kind of solving that problem, streamlining it, and then kind of really proving up quite a sizable sequesteration resource within the state. And just given your positioning in North Dakota was wondering if you see an opportunity for ONEOK to play a role in all these development teams, like, since it seems like things are moving more real time in North Dakota, than other parts of the country.

Definitely. Interesting. This is Kevin, we absolutely see that as an opportunity. And our – and it started and it’s been in with our presence up there. We’ve got strong relationships with state university systems, et cetera and are involved in projects and analysis to understand the Class 6 permits, that that much of the storage has up there, the ability that that puts you further ahead for those opportunities. So, we are definitely involved in those conversations and have a long history and track record of partnering with the state and would expect that to continue as it relates to CCUS.

Got it. Great this Jeremy, thank you so much for taking the questions.

Thank you.

Our next question will come from Michael Blum with Wells Fargo.

Thanks. I just want to add welcome back, Pierce as well.

Thank you, Michael.

I wanted to go back to the Bakken for a minute. And you kind of touched on some of this, but just ask them more directly. How much ethane are you voluntarily recovering in the Bakken today? And it looks to us at least like the Btu limits are either closed or have been returned northern border. So, do you envision at some point here in voluntarily recovering ethane out of the Bakken.

Michael, this is Kevin, we’re not going to, we said last quarter, we’re not going to get into and talk about the actual volume of ethane we’re recovering. Other than to say we have incented some methane to come out. That’s been economic driven, with that ethane recovery, that’s actually pulling down the Btu level on Northern border. So it’s maybe pushing that out a little bit. But if you just go back to the gross kind of production growth, that rather it’s GORs or activity levels that are both increasing. At some point, we continue to believe it’s just math that blended Btu rate is going to go up and become a problem. Northern border or TransCanada continues to have discussions with the various partners and counterparties up there, both on the supply side and the demand side, to understand what a Btu spec might look like. And we expect those conversations with the counterparties and FERC to continue and hopefully we’ll have something, resolution here in the next several months.

Got it. Thanks for that. The other question I wanted to ask was about the Mid-Continent NGL volumes, it looks like they were up sequentially. Just want to make sure I understand is that being driven by just the Arbuckle II expansion because the G&P segment there in the Mid-Con. You cited production decline. So, I just wonder [ph] understanding the dynamics there. Thanks.

Michael, this is Sheridan. Obviously the Arbuckle II expansion helps us move those volumes. We’re really what we’re seeing is we did incentivize the methane in the Mid-Continent more in the second quarter than we did in the first quarter, but we’re also seeing some increased producer activity. So, we’ve seen our C3+ volumes increase as well, and we’re probably back to a level that on the C3+ volumes that is equivalent to pretty close to where we were in the fourth quarter of 2019. So, we’ve seen some pretty good recovery from the pandemic, recovery from the ice storm and some growth. We’re seeing a little bit of activity there. Now, we’re predicting that the Mid-Continent will stay relatively flat this year going forward, that we have seen a little uptick in volume.

Great, thank you very much.

We’ll take our next question from Becca Followill with U.S. Capital Advisors.

Hi, Guys, and welcome back, Pierce.

Thank you, Becca.

Thank you. First question is on the fee rate on GMP, it’s up to $1.06 keeps ticking higher. It looks like the mix continues to be where and I realize its mixed dependent. But it looks like the mix continues to be where the Bakken’s going to grow faster than the Mid-Continent. So should we expect that to continue to take higher or is $1.06 kind of a cap here?

Becca, this is Chuck. I think in Kevin’s remarks, we talked about $1 to $1.05 range, we still believe that somewhere in that $1.05 ranges is a probably a good number for the balance of the year. The $1.06 was a little stronger than we thought it would be frankly, and it was driven really by the contract mix on the Bakken.

Okay. Thank you. And then the second one’s on LPG export facilities. You’ve talked, I think pre-COVID it was you talked about it. But we’ve got NGL that hit record levels in May in the U.S. Any current thoughts on an NGL export facility for you guys?

Becca it’s Kevin. We continue to look at it, it remains a priority for us it is continued there. Clearly the pandemic and the pullback in production, slowed down, some of those discussions, but like you mentioned with exports continuing to be very strong through this and production picking back up. So have the conversation. And so we will continue to look at that. And once as we said before, rather we’re talking LPG or ethane. If we get the right counterparties, the right project and then we’ll announce something, but still looking at it. And it’s still a priority for us.

Thank you.

Our next question will be taken from Spiro Dounis with Credit Suisse.

Good morning team. First one well, sorry, if I missed that [Technical Difficulty].

Spiro you breaking up a little, if you could say whatever you’re saying over again, please.

[Technical Difficulty] CapEx range curious that’s trending in a direction either. But imagine a lot of the higher activity levels are pushing that higher, but maybe not the case.

Okay, I think I got it that you’re looking at CapEx in 2021. We continue to stay within our range. Obviously, as producer activity picks up, we’re going to spend a little bit more on well connect. So that might move us towards the higher end of the range. But we’re very comfortable with the 2021 range that we have out there at this point.

Just M&A will be helpful here. I know in the past, you’ve expressed interest on some of the gas assets that were being marketed by some of the utilities out there. We’ve seen some of those change hands at this point. So, curious if there’s still assets out there that could enter [Technical Difficulty]

So screw up, just make a broad comment about M&A, it’s been about 30 years in the midstream business, and there’s always been some level of M&A activity. It did slow down during the years where most of the assets were into the MLPs. But I guess, what I would say about that is, I’ve only been back for 30 days. And I’d point you back to the comments that that I made on the – in the original opening that whatever we do its going to be intentional. It’s going to be disciplined. So, whether or not we do or don’t participate in the M&A market that’s going to be our guiding principles.

Understood. So Pierce, congrats and good luck to Terry.

Thanks.

Our next question will come from Jean Ann Salisbury with Bernstein.

Is there still any ethane being rejected and the Mid-Con? Or is this number for the volume kind of all potential ethane from the Mid-Con, but as you know that 100,000 of it is sort of discretionarily being recovered?

This is Sheridan. There still is some ethane being rejected in the Mid-Continent. But here’s we get into August, that number is quite low. We think we’re at are getting close to full ethane recovery in the Mid-Continent right now. But for the second quarter, we did still have quite a bit of ethane off in the Mid-Continent. And so we did incentivize some in the Mid-Continent. In the second quarter in August, we have very little that we are incentivizing out.

That’s really helpful. Thank you. And then that new Slide 9 with the gas production at flat Bakken create, is really interesting. This would suggest an ad of like a Bcfd, from here over the next five years, even if oil production is just flat. But there’s obviously not anywhere near a Bcfd of gas takeaway left out of the Bakken. How do you see this has been resolved? And would you participate in this solution for that, if that’s what it took?

Yes, Jean Ann this is Kevin. Yes, that’s something we’ll absolutely keep an eye on. I mean, the good thing there is, we’ve got time. You still got some capacity on northern border that can be you can displace Canadian gas. Going back pre-pandemic, we had talked about looking at other avenues out whether that was expansions on northern border, or moving gas to the west and taking advantage of existing assets that are in the ground, to go to the west and south. So, my guess is those things would come back up, we’ll have those conversations as we see volumes materialize. But the good thing is, we do have some time. And we’ve got some available capacity to get us to that point.

Great. That’s all for me. Thank you.

Our next question comes from Craig Shere with Tuohy Brothers.

Morning team. Pierce, welcome back, and congrats to Terry on retirement in job well done. Historically, there was some interest in getting into the crude gathering and transportation. Are you just so gangbusters on the wet gas and NGLs that this is kind of off the table at the moment? Or how does this look going forward?

So Craig, I think our core business is pretty well defined with natural gas and natural gas liquids. And that’s the direction I would see in the future.

Very good. And just what kind of running room do we have for increased Mid-Con firm capacity demand to avoid further winter market dislocations, in terms of maybe ongoing steady state EBITDA with that could reduce volatility in the Mid-Con.

Let me kind of rewind this back to Winter Storm Uri, because I saw that up close and personal. And the Mid-Continent area, which is defined as Southwest Kansas and the Texas Panhandle and Oklahoma, is a net exporter of natural gas, even during the month of February during the middle of winter to the tune of about three Bcf a day. That turned back between the demand that we saw in the Mid-Continent and the lack of production for various reasons to basically only 5% exports. So, the real issue is to talk about resiliency of the supply chain and how we can potentially get gas in those kind of situations back from maybe the South East, up into the Mid-Continent if it ever happens again. So those are things that that we would be looking at, but it really is looking at not necessarily the capacity that’s there today or the contracting of that capacity. We are addressing a little bit of that which is some uptick in storage and some additional volumes there. But that’s not going to get you through a second Winter Storm Uri. So it’s going to have to be a holistic approach between the exploration and production folks, the midstream folks and the utilities to really get us to a point where we can take on another Winter Storm Uri. We’ll say volumetrically, there were very, very few customers lost in the state of Oklahoma. And so that volumetrically was a very positive force. The issue was where the price went to, not necessarily the stability and the reliability of being able to perform. So, I think the focus needs to be on resiliency and there’s going to be a lot of people that’s going to be involved in that process.

Can this process de-risk some of the Mid-Con EBITDA?

Craig, this is Kevin, I think, those assets are highly contracted and have been highly contracted for a long time. And we would expect that to continue. So, I think what this does is maybe provide opportunities for expansion. This team has done a really good job of whether it’s connecting new power plants or doing smaller projects to bring gas from other areas, to Pierce’s comments, we’ve done some of that. We just think there may be more opportunities for that in the future.

Right, thank you.

Our next question will come from Michael Cusimano with Pickering Energy Partners.

Good morning, everyone and congrats on the new roles. I have more of a strategic question. Hypothetically, using Elk Creek 540,000 barrels a day of expandable capacity is kind of a ceiling being filled by even like the 330 touched on earlier this month and the 125,000 barrels a day of available esteem that you mentioned. It still leaves is that 85,000 of capacity available for the GOR and volume growth opportunities that you mentioned. So with that in mind, I’m trying to understand the strategic rationale for overland pass today. Is that just there capacity available for potential growth beyond Elk Creek? If you can mention – just talk about just how that fits into the portfolio today?

Yes, this is Sheridan. I think when you think about the strategic rationale OPPL you need to think about Elk Creek as one system. And the Bakken pipeline delivered into OPPL as a second system. So to reach the total 540,000 barrels a day of capacity that we could achieve by expanding Elk Creek, Elk Creek will run 400,000 of that the other 140 will be on the Bakken pipeline and delivering that into OPPL and delivering all that into business so that’s where OPPL fits into our strategic plan for volumes out of the Bakken.

Okay. So okay, so it was more of thinking of Elk Creek from Rockies, before it touches into were open to well connect that’s more of like a 400,000 barrels a day capacity?

It is, if we would put the additional pumps on. Right now, we stated that that’s 300,000.

Okay, perfect. Yes, that’s really helpful. Thank you.

Our next question comes from Michael Lapides with Goldman Sachs.

Hey, guys want to wish Terry a congrats, and Pierce, congrats to you as well look forward to getting together at some point. Have a volume question, you made the comment – someone made the comment on the call about 330,000 barrels a day is kind of what you’re seeing right now out of the Bakken. Can you give same data points for what you’re seeing right now in the Mid-Con and in the Permian relative to kind of what the second quarter run rate, I think on Slide 4 was?

We – I haven’t looked specifically at what we’re running right now. I will say that we are running higher on both those systems than we did in the second quarter. But I have a specific look at what we have reached on each one of these systems. But we are running – we are turning higher on both of those systems.

Got it. And when I look at your guidance, your volumetric guidance across G&P in NGL throughput? Do you think there’s material upside to this little surprise given today’s numbers and then the comment on the 330,000 that you didn’t kind of do a volumetric guidance raise here?

Well, Michael, we’re still within – this is Kevin. We’re still within the range in both segments. I mean, clearly, as we see strengthening activity that you’d see some – there would definitely be some upside to those numbers. But the other dynamic that’s going on is, when you look at an annual average, you had a pretty tough first quarter with the winter storm as it related to volumes. So, I do think you’re going to see a much stronger volume in the second half of the year than you did in the first half, but still tracking inside the guidance at this point.

Got it. Super helpful. And then last question just on frac capacity, can you talk about and I know you had the outage this period. So it may be a little hard? What the utilization of your fracs are and when you actually think the earliest you might need new capacity would be?

Well, right now, the utilization of our fracs is as much as we can get through them, because we’re trying to frac off that backlog of inventory that we had carryover from the second quarter as we go forward. In terms of adding new frac capacity, we’re continuing to evaluate that we’re seeing good strong volume growth in our in our area, we’re trying to understand when the right time is to kick that project off. And we’re hoping that volumes continue to grow. And we can see that come up pretty quick.

But Michael, I would just add that add that capacity, all we would be doing is completing MB-5, and you’re just talking a couple $100 million to finish up that project.

Got it. But is that something you think could be needed next year? Or do you think it’s more longer term down the road?

Well, it possibly could be needed next year, I think when we get it up, it’ll take a little bit longer than that to get it up and going. So, that’s why we kind of need to look at longer than a year ago probably take a little bit longer than that to get it up to complete what we need to have done there. But there’s a possibility it could be needed next year. But still, I still steal there’s quite a bit of capacity in the industry right now that outside frac deals could be done in the short-term.

Got it? Thank you guys. Much appreciate it.

We’ll take our final question from Sunil Sibal with Seaport Global Securities.

Yes, hi. Good afternoon, everybody, and welcome back to Pierce and then also congrats to Terry on his retirement. A couple of quick questions for me, seems like there has been a fair bit of debate between the activity levels, public versus private. Could you remind us, how much of your volumes come from private producers versus public producers in Bakken?

We’ve got – obviously, we’ve got the big, there’s a lot of publics out there when you think about ConocoPhillips, and Continental and ExxonMobil, and so forth. So the majority of those are coming from the public’s up in the Bakken. But we do have some of our smaller customers are the privates, but we really haven’t seen a distinguishing factor between who’s bringing rigs back, it’s really more an independent company, just depending on what their financial situation is, and how they’re viewing their balance sheet, et cetera. But pretty much across the board, we have seen all those customers talk about increasing activity as we move through the rest of this year into 2022.

Got it, thanks for that. And then seems like, when I look at Q2 versus Q1, you had a fairly decent uptick in volumes, but your OpEx were flattish to lower sequentially. I was curious, is there any specific thing which is driving that? And how should we be thinking about your OpEx going forward?

No, I think, we’ve had a couple quarters of a pretty close run rate here. We grow from sequential quarter-to-quarter. It was really just some timing, coming out of the winter, being able to – starting to execute on some expense projects that that will typically do and as the weather gets better, and that some of that was occurring in the NGL segment. But as we think going forward, other than maybe a little uptick with Bear Creek when it becomes operational later this year, other than that, kind of the current run rate would probably be a decent number to use.

Go got it. Thanks.

Thank you.

This concludes today’s question-and-answer session. I will now turn it back to Andrew Ziola for closing remarks.

All right. Well thank you all our quiet period for the second quarter – for the third quarter, excuse me starts when we close our books in October, and extends until we release earnings in early November. We’ll provide details for the conference call at a later date. Thank you for joining us and the IR team will be available throughout day. Thank you.

Ladies and gentlemen this concludes today’s call. Thank you for your participation. You may now disconnect your phone lines.