Oneok Inc (OKE) — Q4 2020 Earnings Call Transcript

Thanks, Andrew. Good morning and thank you all for joining us today. As always, we appreciate your continued trust and investment in ONEOK. Joining me on today’s call is Walt Hulse, 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 Kelley, Senior Vice President, Natural Gas. Before we discuss our 2020 results and 2021 guidance, I want to first express my deep appreciation for our employees who have been working tirelessly through recent extreme winter weather in the U.S. from North Dakota to the Gulf Coast. They have continued to meet the needs of our customers, while faced with personal challenges of their own homes, losing power without water, freezing pipes, you name it. I continue to be amazed by all that they do to provide exceptional customer service under very challenging circumstances. After a year like 2020, and so far in 2021, it’s understandable to want to focus on what’s ahead. But first, I’d like to highlight several operating financial and ESG related accomplishments achieved during the challenging 2020. ONEOK’s adjusted EBITDA grew 6% year-over-year, despite a global pandemic reduced worldwide energy demand and depressed financial markets. Our resilient business, the advantages of our integrated assets and the dedication of our employees has never been more evident. The credit goes to those employees who have continued to prioritize the health and safety of their communities, families and fellow employees. Whether continuing to report on site in order to monitor assets and systems or juggling the complexities of working from home, all of our employees are critical in keeping natural gas and natural gas liquids flowing on our systems. And these energy products are critical for the economy to quickly recover from this pandemic. From an ESG perspective, we received numerous recognitions this year, including recently being named an industry mover in the S&P Global Sustainability awards and the only North American energy company included in the Dow Jones Sustainability World Index. ONEOK also was the only Oklahoma-based company to receive a perfect score of 100 in the 2021 Human Rights Campaign Corporate Equality Index. We formed a standalone environmental sustainability team back in mid-2017 that accelerated our ongoing environmental stewardship efforts. In collaboration with those efforts, we recently created a group charged with the commercial development of renewable energy and low carbon projects. The team is actively researching opportunities that will complement our extensive midstream assets and expertise, and not only lower our greenhouse gas emissions, but also help enhance the vital role we expect to play in a future transition to a low carbon economy. Opportunities under evaluation include the further electrification of compression assets, potential carbon capture and storage opportunities, sourcing renewable energy for operations and other longer-term opportunities such as hydrogen transportation and storage. As we develop these opportunities, we’ll remain disciplined in our capital approach, applying similar project criteria in terms of return threshold, contractual commitments and operational fit, just as we do on other projects. We accomplished a great deal in 2020 and financially, we ended the year stronger than we started it, with improved leverage and a more solid balance sheet. Strategic financial decisions and strong operating performance has positioned the company for another year of earnings growth in 2021. Yesterday, we announced our 2021 adjusted EBITDA guidance range of $2.9 billion to $3.2 billion, which is a 12% year-over-year increase compared with the midpoint. As the fundamentals of our business continue to improve, we’re more likely to end the year at the higher end of our earnings guidance range, and we’ll likely adjust guidance upward accordingly. Earnings growth in 2021 isn’t dependent on significant increases in producer activity or on sustained higher commodity prices, although we have seen both in recent months. The earnings power of our assets and available capacity from completed projects enables growth, even in an environment continuing to rebound from 2020. Kevin will talk more about the key operational drivers of our guidance shortly. Let me touch briefly on the Dakota Access Pipeline. Since we provided our original outlook in July, we believe that the potential impact to ONEOK, if DAPL were shut down has significantly decreased. Producers have had time to secure alternative crew transportation and we’ve seen crude oil prices increase making rail transportation, even more feasible. We believe that even if DAPL is shut down quickly after a ruling in April, the earnings impact to ONEOK in 2021 would be less than $50 million of EBITDA, assuming the pipeline was shut down for the remainder of the year. We remain confident in the long-term resiliency of our business and are well-positioned in integrated assets and especially our employees in these challenging times. While world events have resulted in volatile times, ONEOK’s businesses remain resilient and will continue to provide essential services for decades to come delivering much needed natural gas liquids and natural gas to our customers. With that, I will turn the call over to Walt.

Thank you, Terry. ONEOK’s fourth quarter and full year 2020 adjusted EBITDA totaled $742 million and $2.72 billion respectively, representing year-over-year increases of 12% for the fourth quarter and 6% for the full year. Distributable cash flow was nearly $520 million in the fourth quarter, a 6% increase compared with 2019. We also generated more than $100 million of distributable cash flow in excess of dividends paid during the quarter. Our December 31 net debt to EBITDA on an annualized run rate basis was 4.6 times compared with 4.8 times at the end of 2019. Proactive financial steps taken through 2020 and earnings contributions from completed projects enabled us to improve our leverage metrics, despite challenging market conditions. We continue to manage our leverage toward 4 times or less and maintain 3.5 times as a longer term aspirational goal. We ended 2020 with no borrowings outstanding on our $2.5 billion credit facility and approximately $525 million of cash. ONEOK is now rated investment grade by three major credit rating agencies. As Fitch issued a first time rating of BBB with a stable outlook in November, additionally, Moody’s and S&P both reaffirmed ONEOK’s investment grade ratings in 2020. We proactively paid off upcoming debt maturities and we’re opportunistic in repurchasing nearly $225 million of debt through open market repurchases in 2020. We currently have no debt maturities due before 2022. We ended up achieving cost savings of more than $150 million last year, compared with our original plan and would expect a good portion of that to carry over into 2021. Last month, the Board of Directors declared a dividend of $0.935 or $3.74 on an annualized basis, unchanged from the previous quarter. As Terry mentioned, with yesterday’s earnings announcement, we provided 2021 financial guidance, including a net income midpoint of more than $1.2 billion and an adjusted EBITDA midpoint of $3.05 billion, a 12% increase compared with 2020. Earnings expectations are supported by increasing producer activity, ample capacity and efficiency gains from recently completed projects and the continued opportunity for flared gas capture and strong gas to oil ratios in the Williston Basin. Additionally, due to a higher natural gas and propane prices driven by extreme weather across our operating areas over the past two weeks, our Natural Gas Pipelines and Natural Gas Liquid segments benefited from our ability to supply increased demand to meet critical needs during this time. We expect benefits from these short-term opportunities to be partially offset by decreased natural gas and natural gas liquid volumes from well freeze offs, that will still represent upside to our guidance midpoints. Our 2021 guidance assumes first quarter WTI crude prices at the current strip and assumes a range of $45 to $50 for the remainder of the year. From a producer activity standpoint, we are also assuming volume levels that correspond with a $45 to $50 WTI range. Sustained higher prices could lead to a higher volume ramp and drive earnings towards the higher end of our guidance range. Total capital expenditures for 2021, including growth and maintenance capital are expected to range between $525 million and $675 million, a more than 70% decrease compared with 2020. This range reflects improved crude producer activity levels and volume expectations, including capital to complete the Bear Creek plant expansion and associated field infrastructure later this year, which we referenced on our third quarter call. Conversations with producers in the Dunn County area of the Williston Basin remain extremely positive. And the likelihood of needing this additional capital this year is high. The original adjusted EBITDA multiple of four to six times still holds for this project with the multiple and incremental remaining capital being much lower. In terms of 2020 capital expenditures, we completed an expansion of our Elk Creek pipeline in December. Another example of low capital operating leverage on our system, a $100 million expansion increased capacity by 60,000 barrels per day, and provides added transportation capacity on our most efficient pipeline out of the Williston Basin. As we like to remind people every 25,000 barrels per day of NGLs from the region contributes approximately $100 million of annual EBITDA to ONEOK. Financially, our priorities in 2021 remain largely unchanged with our primary focus on debt reduction and investing alongside our customers. I’ll now turn the call over to Kevin for a closer look at our operations.

Thank you, Walt. I’ll start with a quick recap of fourth quarter operations and then discuss 2021 growth drivers. In our Natural Gas Liquids segment, fourth quarter raw feed throughput from the Rockies region increased 13% from the third quarter of 2020 and 24% year-over-year. In January, propane plus volume from the region exceeded our fourth quarter average, despite typical winter weather challenges. In the Mid-Continent region, ethane on our system decreased nearly 40,000 barrels per day in the fourth quarter, compared with the third quarter, primarily due to high ethane inventories from hurricane-related petrochemical outages in the third quarter. In the Permian Gulf Coast region, raw feed throughput volumes were lower in the fourth quarter compared with the third quarter due to a short-term fractionation-only contract that rolled off as well as a third-party plant outage and reduced ethane on our system. Moving on to the natural gas gathering and processing segments. In the Rocky Mountain region, fourth quarter processed volumes increased 16% compared with the third quarter and 11% year-over-year as nearly all curtailed volume came back online. The return of volume with a high fee percentage in the Rockies combined with lower volumes in the Mid-Continent drove the segments average fee rate to $1.04 per MMBtu compared with $0.94 per MMBtu in the third quarter. In the natural gas pipeline segment, we reported another strong quarter of stable fee-based earnings with strong capacity 95% contracted. The segment continues to provide ONEOK with fee-based earnings driven by end-use demand. You can find more detailed information on our fourth quarter and full year 2020 results in our earnings materials. Now moving on to 2021, as we sit today, the operating environment is much improved from even a few months ago. Conversations with our customers remain positive and we’re seeing increasing producer activity across our operations. Our 2021 volume guidance at the midpoint would result in a 7% increase in total NGL volume and a 5% increase in total natural gas processing volumes compared with 2020. In the natural gas liquids segment, we expect the volume growth to be driven by projects completed in 2019 and 2020, continued growth from well completions and the ramp of new plant connections and expansions completed in 2020 and 2021. In the Williston Basin, the recent low-cost expansion of our Elk Creek pipeline increased its capacity to 300,000 barrels per day and increased our total NGL capacity from the region to 440,000 barrels per day. With this expansion, we had ample capacity to transport our Williston and Powder River Basin volumes exclusively on the Elk Creek pipeline at the beginning of this year, which reduces transportation costs paid to Overland Pass Pipeline and is expected to result in $40 million to $50 million in additional earnings in 2021. The Elk Creek expansion provides added capacity, which is also available for potential ethane recovery if needed. Our current NGL volume guidance does not assume Williston Basin ethane recovery but does assume partial Mid-Continent ethane recovery. We currently have approximately 100,000 barrels per day of incremental ethane opportunity in both the Mid-Continent and Williston Basin. As we look forward domestic and international petrochemical demand and export dynamics look strong, but we continue to expect ethane volumes on our system to fluctuate throughout 2021. With available pipeline capacity between Conway and Mont Belvieu, the differential between the two market centers is expected to be near the historical average of $0.02 to $0.03 per gallon for ethane. However, so far in 2021, we’ve seen prices for several of the NGL products fluctuate outside of this range, recent extreme winter weather, and the resulting increase in propane prices in the Mid-Continent created opportunities for both our optimization and marketing business, as we utilized our pipeline and storage assets to meet market needs. In the Permian Gulf Coast region, our firm contract to offload 25,000 barrels per day on third-party NGL pipelines expired at the end of 2020. And these volumes are now flowing on our system, eliminating the additional transportation costs. From the federal lands perspective, we estimate that less than 10% of our NGL volume is from acreage on federal lands, primarily in the Permian Basin. Moving on to the natural gas gathering and processing segments. Higher 2021 volumes are expected to come from the Williston Basin. There are currently 16 rigs operating in the basin with eight on our dedicated acreage. Our conversations with producers indicate that in the current price environment, they expect to bring more rigs back to the region once weather improves in the spring. There also remains a large inventory of drilled but uncompleted wells in the basin with more than 650 basin wide and more than 375 on our dedicated acreage. The capture of additional flared natural gas in the region remains an opportunity. The latest North Dakota data, which is for the month of December showed the state achieving a record of 94% gas capture. This leaves approximately 185 million cubic feet per day still flaring in the basin with approximately half of that on ONEOK’s dedicated acreage. Increasing rig activity, flared gas capture, DUCs and continually increasing gas to oil ratios provide solid tailwinds for volume growth in the region. At the midpoint of our guidance, we expect a 17% increase in 2021 processed volumes compared with 2020, which would result in an average volume greater than 1.2 billion cubic feet per day. We expect to connect between 275 and 325 wells in the region this year, which would be 25 completions per month at the midpoint, the segments average fee rate is expected to range between $0.95 and $1 in 2021 based on our volume mix assumptions for the year. As we said previously, nearly 80% of our dedicated acreage in the Williston Basin is on private lands. The smaller portion on federal land is primarily outside of the cooled basin acreage, where little to no activity was expected. In the Mid-Continent region, we expect to connect 30 wells in 2021. The same amounts connected in 2020. Flat rig activity and natural production declines in the region are factored into our volume guidance for the year. However, producers have indicated that was strengthening commodity prices, particularly natural gas and NGL, they are evaluating adding rigs in the stack and scoop areas. In the natural gas pipeline segment, we expect transportation capacity to be approximately 95% contracted in 2021. As we’ve experienced recent extreme cold temperatures across our operating areas, we’ve continued to transport natural gas on our extensive natural gas pipeline systems to the markets that need it most. Our well-positioned assets and connectivity within these customers have enabled us to provide services on our pipelines to meet higher demand during this critical time. When both the Permian and Mid-Continent areas were experiencing a significant reduction of supply due to well freeze-offs, ONEOK's more than 52 billion cubic feet of natural gas storage assets, which are primarily located in the Mid-Continent were able to bridge the supply shortfall by providing natural gas to meet critical needs. Some of the gas provided from storage is owned by ONEOK, which we retain through our transportation contracts and sell as part of our normal course of operations. While these were short-term weather events, our preparedness and our ability to quickly react and adjust services for customers highlights operational flexibility and financial upside in an already financially stable segment. Terry, that concludes my remarks.

Thank you, Kevin. We’re in a good position, both financially and operationally as we’ve begun 2021. And the current market environment is showing positive signs of increased producer activity and increasing demand for our products. As we said many times before, we will remain focused on delivering value to our shareholders in a profitable, safe, and environmentally responsible way. Thank you again to all of our employees for the work you did in 2020 to prepare us for growth in 2021. Operator, we’re now ready for questions.

Great. Good morning, everybody. Just wanted to go back to just the comment you made earlier about the guidance that you thought, you perhaps trend towards the high end of the guidance range. I just want to make sure I understood that correctly. Is that just based on year-to-date pricing versus what’s baked into your guidance? Are there other factors that are leading maybe to that conclusion?

Yes. I think – well, I think your primary – what you’re looking for right now is what are producers going to do in 2021? And they’re providing us pretty good indications and given the stronger backdrop in the commodity prices that we’re seeing, they’re giving us good signals, but it’s going to take a little bit of time for them to commit the rigs and do the things that they’d like to do in response to those prices. So let’s take a little bit of time. Right now, the body language is very good and as Kevin indicated in his comments, it looks really positive. But as we see these prices, now we’ve got crude with a six handle on it. Are our producers even further going to increase their activity? And we think that they will. But it’s going to take a little bit of time to sort through that. Kevin, you got anything?

No. I think that, that’s what we’re hearing. The feedback from producers continues to be positive about strengthening activity, given these prices. So we’ll just watch that play out.

So Michael, I’ll just make a comment. You remember where we were last year at this time. We issued guidance in February and two weeks later, we got hit with a global pandemic. So you might understand a bit of conservatism here in the guidance that we put forward. But we’re certainly giving you a pretty good body language and what we think is going to happen in 2021. And we’ll adjust it accordingly. We won’t wait till the end of the year to adjust the guidance. We’ll jump on it pretty quick, if we continue to see the strength that we’re seeing today.

Great. I appreciate that. And then probably a little greedy with this question, but I think historically at this point of the year, you have given kind of like a soft directional guidance for the following year. So in this year would be 2022, you obviously haven’t done that this year. But just some – based on some of the data that you provide in your own slides, I think you’ve said you can kind of back into that. I think you need kind of low-20s rig count to keep production flat in 2022. So I think we’re right now, we were about 15 rigs in the back end. So if that’s still the right math, and it sounds like based on your prior comments that you think you’re heading in that direction, but you’re just not sure yet?

I’ll let Kevin take that question.

Michael, I think that – I guess I think that the 20 counts probably a little high based on – now that may hold crude flat, but again, with the rising gas to oil ratios and our ability to continue to capture more and more of the gas that number, is to me, is probably somewhere a little bit less than 20 to hold production flat.

Great. Thank you very much.

Good morning guys. Just wanted to get a follow-up on the 2022 kind of impacts, kind of a two-part hypothetical question here. So given the plan to finish building the Bear Creek 2 plant, all else equal, then I realize in a hypothetical situation or scenario. Is it fair to assume that there will be incremental EBITDA going into 2022 versus kind of where you’re standing with respect to 2021? And then, in terms of how it goes through the plant, but then also when we think about Elk Creek and we think about the heat rate at Northern Border, does the possibility exists that you get incremental recovery of ethane that ends up on to Elk Creek as a result of hitting limits on the Northern Border?

Yes. So in general, like a Bear Creek first, and yes, you’re thinking about that, right. I mean, I think when we paused it originally we were probably thinking more of the 2022 timeframe, but now that we’re looking at it by the end of this year, that would absolutely add incremental EBITDA into 2022 if we go forward and finish it by the end of the year. So that is absolutely an upside to how we were thinking about 2022 previously. As it relates to Northern Border and potential for ethane, yes, that potential still exists as you see volumes continue to increase in the basin. On the gas side that high BTU gas is going to go into the Northern Border. And so the map just continues to work that the blended content of that, heat content is going to go up, which over time is going to drive the need to pull that back down a little bit.

Okay. And maybe it’s a follow-up to the first questions that were asked. I was just wondering if you can give us a little bit around sensitivities and just clarify one of your responses to Michael’s question. Is there like an EBITDA percent of NGL that we should be thinking about that you can share with us in terms of how we think about modeling? And then just in answering the question about the rigs, you said it was below 20. If I do my math, you needed 25 wells to stay flat per month, when I divide that by two, as I think about two wells per rig that should bring you more to around 13 or 14 rigs. I’m just wondering if you can clarify those points.

Okay. What was your first question again? Sorry.

Just wondering when I think about changes in NGL prices and impact to changes, and EBITDA unless they’re like a 5, 10 changes at NGL would equal X amount of dollars in EBITDA, as we sort of think about your guidance range. And then the second part was about how many rigs you need specifically to keep yourself flat versus growing. You said it was below 20, but it sort of sounds like it would be the low teens if I do my math correctly.

Okay. So on the first – and on the just commodity pricing, given how heavy fee-based we are and how much hedged we are, there’s really not as massive or a significant move in pricing just with our – we’re so fee-based at this point. Yes, with an improving commodity backdrop, you are going to get a pick up a little bit, but it’s not – we’re not talking about hundreds of millions of dollars there. On the second question, I do believe, I do agree that it’s – the number of rigs we believe we’ve made is in more of that mid-teens-ish, is what we’re thinking there as we look at that in our own material, we have kind of a different – it shows different completion rates and what that would do to our gas production over time. And I think that’s the key. So much is written about what the basin needs to hold production flat. All that is typically crude oil-based and again, with the strengthening gas to oil ratio is the number of rigs we need to hold gas production flat is quite a bit less than that. But we’ve put that number in the mid-teens.

Great. That makes perfect sense. If I can slip the one last one in. The timeline on the green investments that were mentioned in the prepared remarks, is that something that can happen relatively soon, or do you need some sort of tax incentives to be passed? Is it kind of like a three-year view or is this something that can happen in the next 18 months?

Yes. It’d be more near term. I mean, we’ve got that is worth thinking about that some of the smaller investments in these projects that Terry mentioned. But as opportunities present themselves on a larger scale, we’ll consider them and with the appropriate return thresholds.

Perfect. Thank you very much. I really appreciate the color today.

Thanks for taking my question. Maybe if I could start with the fee-based rate for G&P assumed in guidance is $0.95 to $1. You came in above that in 4Q and I would think Bakken production only increases while Mid-Con decreases this year. So shouldn’t that support fee-based rates similar to what we saw in 4Q if not better. So is that just conservatism, and is there a cap on this fee-based rate at some point?

Christine, this is Chuck. I’d say when we put our forecast together, we go ahead and we break down what’s the mix of our producer volumes by contract. So as we did that, these different contracts have varying levels of fee as a component of total value. So based on this projected mix of volumes, we feel comfortable in the $0.95 to $1 range. We may have quarters where in fact, it exceeds that because the mix may be a little bit different than what we originally assumed. And we’ve seen some of that obviously here in Q4. So you could see some upside above the dollar, but we feel pretty confident in the $0.95 to $1 range.

Okay. And then if I could also move on to some of the prepared remarks talk about some tailwinds, which sounds like it’s going to materialize first quarter, or at least first half, you talked about the NGL spreads, providing opportunity for the NGL segment, but then you also talked about 52 Bcf of storage that you have in the Mid-Con. And you talk about retaining some of that and selling it as part of your normal course of operations. Just to clarify, does that mean you are selling gas into the grid? And if you could also give us some color on what’s the max deliverability rate on the storage? Like how much gas can you take out of the storage each day?

Christine, I let Chuck handle that question.

So, Christine, the storage is we’re referring to are located in Kansas, Texas, and Oklahoma with the largest of that 52 Bcf, call it, 46 Bcf in Oklahoma, remaining fields in Texas are about another four or five in the balance up in Kansas. So yes, as we transport gas, we do retain some fuel that becomes equity for us. And we have an ongoing normal course of business. We go ahead and we’ll store that gas. We have a sales program portfolio where we look in the forward strip relative to weight cogs as anyone would. And choose how we want to monetize that equity gas. We also keep some gas available, obviously for unexpected situations, market movements, and what have you. And we set up each year this way. So it happened this year, we set up and this event occurred. So we were able to participate in these market prices that you may have seen here in Oklahoma and Texas. And I’m sure we’ll talk more about that in the Q1 earnings call.

And any color on max withdrawal rates?

I don’t know if we publicly have provided that in the past, but just generally in Oklahoma, when we’re fully pressurized you could see us withdrawing as high as 1.4 Bcf, 1.5 Bcf a day. Our Texas numbers obviously the caverns are smaller, so you’re more in that $350 million to $400 million a day again, when they’re pressurized.

Good morning. I appreciate all the commentary around the assumptions for 2021. Just wanted to follow-up on a previous question with respect to rigs in the Rockies, I think just on the range of completions you guys have talked about for the year. Do we need to directionally see any improvement in rigs from your customers to achieve the range? Or should we think about ranges, that’s a range of outcomes or just the current state of race today?

I think the way we look at it again, back to the original remarks, as we’ve talked to our customers and in a lot of these conversations were taking place with crude in the $45 to $50 environment. That’s the activity levels that we kind of have baked in. Very recent conversations with the strengthening of the commodity strip, those conversations are starting to get stronger as far as the amount of activity. So that’s the way, I guess we would think about this in our remarks around the range and Terry’s comments about us trending towards that upper end, if we see the current commodity environment hold because we do believe customers will bring more activity at the current price environment, if it holds.

Sure. Thank you. And then just on the CapEx. I think in previous quarters, you guys have talked about $300 million to $400 million a year as a potential kind of new run rate. And can you talk about the current guide and what’s embedded in that? Should we think of that maybe that incremental spend is purely the Bear Creek expansion? Or just at least you bridge that gap between the previous range you guys have talked about hypothetically?

Sure. So if we just kind of put the $300 million to $400 million discussion in context, that was initially made back when crude was in the $30s. So even at a $45 to $50 level assumption, you expect a lot more activity, which is built in. So that’s one part. Bear Creek 2, you’re right, yet that’s probably little over $100 million of that number. And then the rest, if you think there’s another $100 million where we’ve found opportunities, for example a compression replacement and expansion project on one of our interstate pipes. That’s not only going to provide additional capacity, more reliability, and reduce our emissions footprint. We’re doing some work down on Mont Belvieu to expand our storage position. That’s a good project. We’re also doing some work in Belvieu to expand our distribution network and get more direct connect to a few customers. So those are things, again, none of them by themselves, each one is $20 million, $30 million, $40 million, but you have three or four of them together and there’s another $100 million. So they’re all good projects, they’re strong return projects, and we found those opportunities. So we’re going to go execute on it.

Good morning. Just wanted to dig into the guide a little bit, is some of the buildup there. When you talked about kind of the potential for increased activity, if current commodity prices hold or these producers more on the public side or the private side? Just trying to get a feeling for who might be increasing activity here? And just curious if the GOR ratio is that continues to improve over time, kind of – how – do you have any thoughts quantify as far as how you think that ratio kind of improves over time, that’s at least in your forecast?

I will let Chuck handle it for both those questions. Yes, Jeremy. So to your first question, I’m sorry, I was thinking about the GOR question. Give me your first question one more time, if you don’t mind.

Yes. Just as far as a commodity price is holding, there’s the activity tick up. Is it more from the public or private, larger or smaller, just trying to get a feel for who could be increasing activity here?

Sure. No, it’s a combination. I mean, obviously, you’ve seen a couple of the public say that the CapEx position that they said, they’re going to hold that for 2021 pending some of its DAPL, some of it at the time, but they said that we run a $45 to $50 crude environment. So they’re rethinking that a little bit, obviously. But it’s a combination of the large capitalized publics plus some of the privates up there. And then as far as the GOR question, GOR has increased in the past just in the past year, a 15% year-over-year. And I think we pointed out in our slide, 63% since 2016. So pretty significant increases, particularly this last year, seeing that 15%. So when you think about it, they’re rising over time as pressures decline. So more of that trap gas is released relative to crude and producers have confirmed this for us as well. But they think the implied GOR will continue to rise. And I can’t say it’s at 15% year-over-year, but it’s definitely rising. Pretty significant tailwind for us.

Hi, guys. Can you hear me?

Yes.

Got it. Yes, just on the levered one. Just wanted to – what’s your confidence in kind of hitting the 4 times versus the 3.5 times, I was going to kind of get into that 3.5 number. Is it more growth – incremental growth projects? Is it just the operating leverage you have in your existing systems? Just any color you can provide there would be helpful.

Well, I think that what’s going to take us to 3.5 and 4 is definitely going to be the continued growth that we see on our system that obviously is going to produce cash flow and help us from a debt reduction standpoint. So we’ll try to do it from both sides of the coin. But it’s the continued growth that we see on our system over time. And the fact that we have so much headroom within our asset base, these pipes have lots of capacity, so that we’ve got great operating leverage going forward.

Got it. And then maybe just one on the mid-continent talks about, I think pretty well connected this year with potential, I think you talked about some customers actually adding activity. Do you see that kind of plateauing into 2022 or how do you kind of think about the mid-continent kind of coming out of 2021?

From a well connect and activity perspective and I think as we move through 2021, we’ve had a lot of conversation about that. As you move into 2022, it’s going to be a function of commodity price. I mean, if we’re still sitting in this, if you’re still sitting in a $55 million to $60 million type environment then you’re going to see an increase in activity. And I believe that activity will sustain. There’s a lot of drilling locations up there left, a lot of inventory debt and I think you’ll see that sustained through 2022.

Kevin, it’s not all just about crude price. I mean, obviously, NGLs and natural gas are a big driver for the activity up there. And you’ve seen stronger natural gas prices, particularly as we come through the polar vortex as we come out the other side of this thing, I think fundamentally – the fundamental backdrop is we’re going to see a higher values for nat gas and certainly for liquid. So those will also be important drivers for producers, particularly in Oklahoma.

Great. I appreciate it, guys. Thanks for the time.