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ONEOK Inc
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Good day, everyone and welcome to today’s Fourth Quarter 2020 ONEOK Earnings Call. A quick reminder that today’s program is being recorded. And at this time I’d like to turn the floor to Andrew Ziola. Please go ahead, sir.
Thank you, Greg, and welcome to ONEOK’s fourth quarter year-end 2020 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. A reminder that statements made during this call that might include ONEOK’s expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934.
Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. Our first speaker is Terry Spencer, President and Chief Executive Officer. Terry?
Thanks, Andrew. Good morning and thank you all for joining us today. As always, we appreciate your continued 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 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 rage. Sustained higher prices could lead to a hooker 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 volume – 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 from fee-based earnings driven by end-use demand. You can try and 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 liquid 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 ONEOKs 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.
[Operator Instructions] And first from Wells Fargo, we have Michael Blum.
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’s leading maybe is 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 price, 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. 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 to.
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 lane 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 backend. 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 of rejuvenate.
Great. Thank you very much.
Shneur Gershuni with UBS.
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 exist 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. Northern Border proposed the tariffs, forecast him to go back and work with shippers and producers and other stakeholders in the region. Those kinds are understanding – those conversations are underway at this point. So we’ll watch that for an official tariff that might get filed, that I would expect that process to continue over the coming months.
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 rates. 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 even unless they’re like a 5, 10 change 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 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 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 is we look at that in our owns 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.
We’ll move on to the next question. It’s Christine Cho with Barclays.
Thanks for taking my question. Maybe if I could start with the fee-based rate for G&P assumed in guidance is $0.95 cents 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 a 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 breakdown, 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 word in fact, 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 to the 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 our – 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 setup each way – each year this way. So it happens this year, we setup 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.
Great. Thank you so much.
Next question will come from Tristan Richardson with Truist Securities.
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 seen 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 use, back in the summer, 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 connected 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 had 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.
I appreciate it. Thank you, guys.
And moving on, we have Jeremy Tonet with JPMorgan.
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 question.
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 dapple, 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 point 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.
Got it. That’s helpful. Thanks. And just, if I think about the CapEx as you guys outlined there. Does that include Bear Creek right now, or if the current commodity price holds and there’s these upside opportunities, where would you expect kind of CapEx to fall out? If these things come to fruition, as you outlined here,
Bear Creek is included in that CapEx number, of the midpoint of $600 million.
And Jeremy, this is Terry. The only comment I’ll make about that about Bear Creek is way you have to think it. The two-thirds of the capital to complete Bear Creek 2s it’s stuck, it’s equipment, it’s material, it’s a lot of labor and that we incurred that’s on cost. And so this small amount that Kevin is referring to the returns on an incremental investment are huge. And so it makes a lot of sense, given the specifically in Dunn County where we’re seeing this activity, it makes sense to address it. And so I just can’t stress enough how outstanding the economics are, how compelling the economics are in completing that project.
Got it. And so maybe just to clarify, if the upside opportunity emerges, as you said, the CapEx as you budgeted it now kind of covers that being able to service that production, or would CapEx move up a little bit more from here to kind of cover that higher activity level?
It would just move up. It would just move up just a little bit, because you’re only talking about well connect capital at that point, which is the most efficient capital we spend in the portfolio.
Understood. That’s helpful. Okay, great. Thank you.
You bet.
All right. Next from the Tudor Pickering Holt & Co., we have Colton Bean.
Good morning. So just circling back to some of the comments on throughput. It looks like for the midpoint of the gathering guide at falls, just below Q4 2020 levels. Can you frame the expected trajectory over the course of the year? Or asked differently, does that assume exit to exit declines or that we’re entering the year a bit softer and then rebounding thereafter?
Up in the Bakken, we exited 2020 at a very good level, right, at 1.2% range. Of course, here in Q1, you typically see weather and we’ve seen the effects of weather throughout February and back-half of January, primarily February. So if you think about the shape of the volumes throughout the year, Q2 and 3 have always been very strong for us at the beginning of Q4 equally strong December is kind of dicey again for weather.
Got it. And then just sticking on the GMP side, there’s a little bit wider gap between gathered and process volumes in Rockies in Q4. Based on the guide, it looks like that actually closed in 2021. Where you offloading more volumes during the quarter or anything else to point to?
I’m sorry. I missed the last part. I couldn’t understand that.
Yes. Just interested if you were potentially offloading some volumes to third-party processing or what drove that gap in the Bakken? And then why exactly that would close over the course of 2021?
No. We weren’t offloading. So I’m not – I just can’t answer what gap you’re referencing because frankly I didn’t see it. There was nothing from a business perspective, there was nothing going on. So it would just be kind of normal course in fluctuation of the gathered versus process. I mean, protect going on, it could have impacted it.
Understood. Yes, it was just a little bit wider than historical, so one of the follow-up. Appreciate it.
All right. Next question will come from Mizuho, we have Gabe Moreen.
Good morning, everyone. I just kind of want to follow-up on the events of the last week or two. And I’m just wondering from your perspective, I know it’s early days here, you think there’d be conversations with customers in terms of the guys winterizing assets, clear there’s only so much you can do about well freeze offs, but just wondering in terms of processing plant liability. And then kind of as you look at the portfolio overall, whether it’s gas pipeline capacity coming out of Canada, or whether it’s some of your gas storage assets, where do you think there’ll be some upper pressure, maybe on some of the rates you can charge for those services.
Gabe, this is Chuck. In the Williston, obviously we purchased winterize packages for everything. I mean, we’ve got heat tracing equipment in our plants, we’ve purchased Arctic packages for our compression. So this is a normal course of business in the Bakken. We’ve seen minus 30 and our amazing people are still out there running these assets. It’s incredible. And we don’t have very high utilization, very rarely offline. What freezes is the wellheads come on down to Oklahoma and Texas, and frankly, that’s just a value proposition for producers and frankly processors and pipelines. If you go ahead and winterize and spend whatever that percentage extra might be for a small event, and I’d say going forward, people are going to really look at those costs and see if in fact somebody is willing to pay for that service.
Gabe, this is Kevin. The only thing I would add is when you think about the last several weeks, our pipeline assets performed incredibly well. I mean, they ran and they were up virtually the entire time and our field folks did a fantastic job, keeping those assets available and reliable, whether it was pipeline, compression, dehydration, all the equipment that we needed to run, they ran virtually uninterrupted. Our processing plants ran extremely well too, even in the mid-continent. Really the only disruptions we had was when power – when we lost power, which was really, there was – that we could do about that.
But I do think, obviously with all – there’s been a lot of conversation about how the market should respond and the availability and having storage assets and having pipeline assets. We’re always looking for those opportunities to expand those – expand that footprint. And we’ll be there if some of the customers need some additional services we can with our integrated assets, we can provide them.
Great. Thank you. And then maybe if I could just follow-up sort of on the – I appreciate the initial DAPL comments in the opening remarks. Just as a follow-up to that, I was wondering how warm or not warm conversations on potentially converting Elk Creek would be with producers. And I don’t recall you ever having put out a CapEx figure on that conversion, is that something you’d be willing to kind of take a stab at?
Yes, I think you referred – Gabe this is Sheridan. I think you are referring conversion to Elk Creek to a crude oil system. Right now we continue to see really good volumes on the NGLs on Elk Creek system that I don’t think a conversion is in the cards at this time. In fact, through this whole February, as Chuck said, that Bakken Basin performed the best out of all the regions on the NGL system, their volume dropped the least amount. And it’s already almost back to pre-winter or pre-storm level at this time. So I think right now we don’t see a case where we’re going to convert Elk Creek to crude oil system, and then talking with the producers up there, a lot of them are securing space on other pipelines in anticipation of a DAPL going down and on rail terminals. And as we talked to the customers, they really don’t see an impact to their volumes if DAPL would go down at this time.
And Sheridan, they’re hesitant to sign up for long-term capacity to underwrite and then the crude line or this is crude conversion. So I think that’s a factor as well.
Yes, that’s the main factor. I mean, they don’t want to sign up for a long-term deal to convert this system when they already have viable outs today.
Got it. Thanks, everyone.
Next question will come from Jean Ann Salisbury with Bernstein.
Hi. Good morning. On Slide 10, the wedge that you’re calling the flared gas capture opportunity, what level of flaring would that represent on your acreage if you did capture it all? And is it realistic to capture it all? What do you see as needing to happen for you to get it?
Jean, this Kevin. We’ve gotten that question a lot. Clearly, we think we can capture more gas then – capture some of the gas that’s still flaring. Even with the percentages coming down well into the single digits, we think there’s more room to drive that even lower. A lot of our conversations that we’re having with customers now, especially some of the larger ones, they’d like that number to be zero. Now that ultimately is going to require some – would require some kind of changes in the way we work together and in the way, some of the equipment on the wellhead is structured. But again, it can be done and we’re encountering those conversations with the customers. In total, does it go to zero? Probably, not. With operational disruptions, et cetera, but we’ve got many customers now working with us, wanting – just from a variety of perspective, from a value capture, from an emissions perspective just bringing that number as low as we possibly can.
Great. Thank you. And then Bluestem starting up and energy transfer suggesting they may try to connect some of enables NGL production to their own system. It seems like there may be some challenges to one of the dominant mid-con NGL system. Can you comment on the medium term pressure that you see here and how much it could kind of erode your business?
Well, what I would say about the energy transfer enabled deal is that in the Mid-Continent, our – the volumes on our system are tied up under long-term contracts, which had many years left on them. We don’t specifically talk about contract terminations or volumes on the system that we think our contracts right now for the immediate future are very well secured.
Okay. Thank you.
All right. Next we have Sunil Sibal with Seaport Global Securities.
Yes. Hi. Good morning, guys. And thanks for all the clarity on the call today. I just had a clarification – yes, can you hear me?
Yes.
So my question was on the sensitivity you provided in case the DAPL was shut down sometime in April $50 million for 2021. I was curious, how would you characterize that impact say in 2022, if DAPL were to remain shut down and we were in at $45 to $50 WTI price environment.
Well, we haven’t gotten into trying to speculate what would happen beyond that. They’re well into the EIS process. I mean, I think we believe that they’ll ultimately be successful, even if it gets shut down that they would get the proper easements and permit approvals. But again, you could maybe do a little extrapolation if you wanted to think about 2022. But again, that’s going to be dependent on if you’re in this type of price environment it’s going to be – it’s not going to be a big number because again, rail is continues to be very attractive at these commodity prices.
Got it. And then on the – sorry, go ahead. Then my second question was on the Elk Creek expansion that you completed in fourth quarter. I was curious, was there any MVC commitments tied to the season or it’s just the original MVC is kind of a hole for the expanded capacity also?
I think the answer is expanding Elk Creek to 300,000 did a couple of things for us. And when we mentioned on our calls is that ensures that we can move all our volume off of OBDL on to Elk Creek and still have ample capacity to be able to bring ethane out as the Bakken if that is needed as well, that was the preemptive stuff, why we did the expansion of Elk Creek.
Okay. Got it. Thanks.
All right. And then moving on, we have Michael Lapides with Goldman Sachs.
Hey guys, thank you for taking my question. Just real quick high level. How are you thinking about the path to de-leveraging and kind of the balance between using incremental cash flows and at the high end of your guidance, your free cash flow positive after the after the dividend it seems. How you’re thinking about allocating cash flow between dividend growth between new growth projects or between paying down debt.
Well, Mike, what I would say about that is that we always want to make sure that we have – if we have a good project that is going to serve our customer’s needs, that we’re going to make that investment. As Kevin mentioned, we’ve got smaller projects here that we’re kind of adding to our system around. We don’t have any larger capital plans on the horizon in the near future. It’s really more additive to our existing system. So you’re going to see the bulk of that free cash flow go to debt reduction here in the near-term and our de-leveraging plan is right on track. And these commodity prices hold at this level it’s to do nothing but accelerate.
Got it. Thank you, guys. Much appreciated.
Thanks, Mike.
All right. And everyone looks like our last question is going to come from Derek Walker with Bank of America.
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.
Got it. And then maybe last one for me. Yes, definitely I think recovery, I think in guide [indiscernible] Williston, I think some in mid-con, but kind of mentioned there could be some volatility. So I guess, how do you think about the ethane recovery throughout the year?
Well, what we see for the ethane recovery in the mid-continent we do feel we’ll see some ethane recovery this year probably maybe a little bit more in the second half of the year. Obviously, what we see now is in February, a lot of the petrochemical facilities have gone offline due to loss of power and gas. So in February, we did see a lot of ethane rejection across our system. Ironically, even as we come out the other side and the drop of gas prices today, we are starting to see an increased amount of ethane recovery in the mid-continent. But we do think throughout this year, it will be a little lumpy, which more weighted towards the back half of the year. The fundamentals for the petrochemical industry are very good right now, as we see the price of propylene and ethylene very high. And as these plants come back, get it back on, they’re going to run at very high rates. So we think we’ll see more ethane recovery potentially in the first half of the year, which would drive us more to the upside of our guidance.
So complete recovery from the hurricane impact like last year, we’re through all that.
We’re through all that piece and now just got to get them back up after the storm.
Great. I appreciate it, guys. Thanks for the time.
All right. And everyone that looks like that’ll conclude our Q&A session today. I’d like to turn the floor back to Andrew for any additional or closing remarks.
Okay. Thank you, Greg. Our quiet period for the first quarter of 2021 starts when we close our books in April and extends until we release earnings in later April. We’ll provide details for the conference call at a later date. Thank you for joining us and have a good week.
And once again, folks, that does conclude our call for today. We do appreciate you joining us. You may now disconnect.