ONEOK, Inc.

Good day, everyone, and welcome to today's fourth quarter 2020 One Oak earnings call. 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 One Oak'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 One Oaks 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 One Oak. 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 Chef Kelly, 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 a challenging 2020. One Oak suggested 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. One Oak 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 have positioned the company for another year of earnings growth in 2021. Yesterday we announced our 2021 adjusted EBITDA guidance range of 2.9 to 3.2 billion dollars 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 will 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 One Oak if DAPL were shut down has significantly decreased. Producers have had time to secure alternative crude 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 One Oak 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, our well positioned and integrated assets, and especially our employees in these challenging times. While world events have resulted in volatile times, One Oaks 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. One Oaks' 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 four times or less and maintained 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. One Oak 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 one of its investment grade ratings in 2020. We proactively paid off upcoming debt maturities and were 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 93.5 cents 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 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, but to 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 quicker 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 and $675 million, a more than 70% decrease compared with 2020. This range reflects improved 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 meeting 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 on the 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. The $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 an annual EBITDA to One Oak. 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 liquid segment, Fourth quarter raw feed throughput from the Rockies region increased 13% from the third quarter 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 segment's average fee rate to $1.04 per MMBTU compared with 94 cents per MMBTU in the third quarter. In the natural gas pipeline segment, we reported another strong quarter of stable fee-based earnings with firm capacity 95% contracted. The segment continues to provide One Oak with firm 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 MGL volume, and a 5% increase in total natural gas processing volume compared with 2020. In the natural gas liquid segment, we expect 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 MGL 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 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 Bellevue, the differential between the two market centers is expected to be near the historical average of two to three cents 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 MGL 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 NGO volume is from acreage on federal lands, primarily in the Permian Basin. Moving on to the natural gas gathering and processing segment. 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 One Oaks dedicated acreage. Increasing rig activity, flared gas capture, ducts, 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 segment's average fee rate is expected to range between 95 cents and a dollar 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 land. The smaller portion on federal land is primarily outside of the Coord Basin acreage where little to no activity was expected. In the mid-continent region, We expect to connect 30 wells in 2021, the same amount 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 with strengthening commodity prices, particularly natural gas and NGLs, 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 with end-use 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, One Oak'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 One Oak, 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'll 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.

Wonderful. Thank you, sir. And ladies and gentlemen, if you do have any questions, please signal by pressing star 1 on your telephone keypad. If you just make sure you have your mute function turned off, we can receive that signal. Again, at this time, star one for any questions. And first from Wells Fargo, we have Michael Bloom.

Great. Good morning, everybody. Good morning. I just wanted to go back to just a comment you made earlier about the guidance that you thought, you know, you could 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, or are there other factors that's leading you to that conclusion?

Yeah, I think, Will, 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 giving us the stronger backdrop in the commodity prices that we're seeing. They're giving us good signals, but they're 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. It's going to 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. 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 add? No, I think 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 know, 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 uh you know a bit of conservatism here uh in the guidance that we put forward but we're we're certainly giving you a pretty good body lean and what we think is going to happen in 2021 and we'll adjust it accordingly uh we'll you know we'll we won't we won't wait until the end of the year to adjust the guidance we'll jump on it jump on it pretty quick if we continue to see 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 this year would be 2022. You obviously haven't done that this year. But just 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're about 15 rigs in the Bakken. So is that 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 the 20 count's probably a little high. 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, you know, that number, to me, is probably somewhere a little bit less than 20 of every age you meet.

Great. Thank you very much.

On to Schneur Gashani with UBS.

Hi. Good morning, guys. You know, just wanted to follow up on the 22 kind of impact, kind of a two-part hypothetical question here. So given the plan to finish building the Bear Creek Q plant, you know, all else equal, when I realize this is a hypothetical situation or scenario, is it fair to assume that there will be incremental EBITDA going into 22 versus kind of where you're standing with respect to 21? And then, you know, 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, you know, does the possibility exist that you get incremental recovery of ethane that ends up onto Elk Creek as a result of hitting limits on northern border?

Yeah. So, Shannara, take Bear Creek first. Yes, you're thinking about that right. I mean, I think when we paused it, Originally, we were probably thinking more of a 22 timeframe, but now that we're looking at it by the end of this year, that would absolutely add incremental EBITDA into 22 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 22 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 northern border. And so the math just continues to work that the blended content of the 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, you know, proposed the tariff. FERC asked them to go back and work with shippers and producers and other stakeholders in the region. Most folks are understanding those conversations are underway at this point. So we'll watch that for an official tariff that might get filed. But I would expect that process to continue over the coming months.

Okay, and maybe as 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. You know, 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. Um, just wondering if you can clarify those points. Okay. What was your first question again? When I think about changes in NGL prices and impact to changes in EBITDA, is there like a five cent change in 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, you know, specifically to keep yourself flat versus growing. You know, you said below 20, but it sort of sounds like it would be low teens if I do my math correctly.

Okay, so on the first one, on just the commodity pricing, given how heavy fee-based we are and how much hedged we are, there's really not a massive or 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 And we're not talking about hundreds of millions of dollars there. On the second question, I do believe you're, I do agree that it's, the number of rigs we believe we'd need is in more of that mid-teens-ish, is what we're thinking there as we look at that. And in our earnings material, we have kind of a different, you know, 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, that all that is typically crude oil based. And again, with the strengthening gas to oil ratios, the number of rigs we need to hold gas production flat is quite a bit less than that. But we'd put that number in the mid-teens.

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

Yeah, it'd be more near term. I mean, we've got that, as we're thinking about that, some of the smaller investments in these projects that Terry mentioned. But as opportunities present themselves, you know, on a larger scale, we'll consider them with the appropriate return threshold.

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

Sure. All right, we'll move on to the next question. It's Christine Cho with Barclays.

Good morning. Thanks for taking my question. Maybe if I could start with the fee-based rate for GMP, assumed in guidance is $0.95 to $1. It came in above that in 4Q, and I would think BAC in production only increases while mid-cont decreases this year. So shouldn't that support a fee-based rate 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 95% to $1 range. We may have quarters where it, 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 move on to some of the prepared remarks, talk about some tailwinds. which sounds like it's going to materialize, you know, first quarter or at least first half. You know, you talk about the NGL spreads, you know, providing opportunity for the NGL segment. But then you also talked about, you know, 52 BCS of storage that you have in the MECON. And, you know, 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're selling gas into the grid And if you could also give us some color on, you know, what's the max deliverability rate on the storage? Like how much gas can you take out of the storage each day?

Christine, we'll let Shep handle that question.

So, Christine, the storages 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. As we transport gas, we do retain some fuel that becomes equity for us. We have an ongoing normal course 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 WACOG 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, what have you. And we set up each year this way. So what happens 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, you know, 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, 1.5 BCF a day. Our Texas numbers, obviously the caverns are smaller, so you're more in that 350 to 400 million a day, again, when they're pressurized.

Great. Thank you so much.

Sure.

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

Hey, good morning, guys. Appreciate all the commentary around the assumptions for 21. 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 an improvement improvement in rigs from your customers to achieve the range, or should we think of that range as that's a range of outcomes with just the current state of rigs today?

I think the way we look at it, again, back to the original remarks, is we talk to our customers, and 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.

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. Can you talk about the current guide and what's embedded in that? Should we think of maybe that incremental spend as purely the Bear Creek expansion or just – we bridge that gap between the previous range you guys have talked about hypothetically.

Sure. So if we just kind of put the $300 to $400 million discussion in context, that was initially made back in the summer when Creed 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, too, you're right. That's probably a little over $100 million of that number. And then the rest, if you think there's another $100 million, well, we've found opportunities. For example, a compression replacement 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 in Mont Bellevue to expand our storage position that's a good project. We're also doing some work in Bellevue to expand our distribution network and get more direct connected to a few customers. Those are things, again, none of them by themselves. Each one is $20, $30, $40 million, but you add three or four of them together and there's another $100 million. They're all good projects. They're strong return projects. And we found those opportunities. So we're going to go execute on them.

I appreciate it. Thank you, guys.

Thank you.

And moving on, we have Jeremy Tanay with J.P. Morgan.

Hi, good morning.

Hey, good morning, Jeremy.

Good morning. Just wanted to dig into the guide a little bit, some of the buildup there. When you talk about kind of the potential for increased activity if current commodity prices hold, are 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, as that continues to improve over time, kind of – Do you have any thoughts that quantify as far as how you think that ratio kind of improves over time that's at least in your forecast?

We'll let Jeff handle both those questions.

Yeah, 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.

Yeah, just as far as if commodity prices hold and there's the activity tick up, is it more from – the, uh, public or private, larger or smaller, just trying to get a feel for who, who could be, uh, 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 set, they're going to hold that for 2021 pending, you know, some of it's dappled, some of it at the time that they said that we were in a 45 to $50 crude environment. So, uh, They're rethinking that a little bit, obviously, but it's a combination of the large capitalized public plus some of the privates up there. And then as far as the GOR question, you know, GOR has increased just in the past year at 15% year over year, and I think we point out in our slide it's 63% since 2016. So pretty significant increases, particularly this last year seeing that 15%. So, you know, when you think about it, they're rising over time as pressures decline and So more of that trapped gas is released relative to crude. And producers have confirmed this for us as well, that they think the implied GORs will continue to rise. Now, I can't say if 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 it 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 CapEx to fall out if these things come to fruition as you outlined here?

No, Bear Creek is included in that CapEx number of the midpoint of $600 million. Jeremy, this is Terry. The only comment I'll make about Bear Creek is the way you have to think of it. The two-thirds of the capital to complete Bear Creek II is sunk. It's equipment, it's materials, it's a lot of labor that we incurred. That's sunk cost. And so this small amount that Kevin is referring to, the returns on that incremental investment are huge. And so it makes a lot of sense given the specifically in Dunn County where we're seeing this 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 budget 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 just a little bit because you're only talking about WellConnect capital at that point, which is the most efficient capital we spend in the portfolio.

Understood. That's helpful. Okay, great. Thank you.

All right, next from Tudor Pickering Colton Company, we have Colton Bean.

Morning. So just circling back to some of the comments on throughput, it looks like for the midpoint of the gathering guide, it falls just below Q420 levels. Can you frame the expected trajectory over the course of the year or ask differently? Does that assume exit-to-exit declines or that we're entering the year a bit softer and then rebounding thereafter?

Well, up in the Bakken, you know, we exited 2020 at a very good level, right in that 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, Qs 2 and 3 have always been very strong for us. The beginning of Q4, equally strong. December's kind of dicey again for weather.

Got it. And then just sticking on the GNP side, there's a little bit wider gap between gathered and processed volumes than ROCUs in Q4. Based on the guide, it looks like that should close in 2021. Were 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.

Yeah, just interested if you were potentially offloading some volumes, the 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 and fluctuation of the gathered versus process.

Okay, now that makes sense. It did have some practical tech going on. It could have impacted it.

Understood, yeah. It was just a little bit wider than historical, so I wanted to follow up. Appreciate it.

All right, next question will come from Mizuho. We have Gabe Marine.

Hey, good morning, everyone. I just kind of want to follow up on the events of the last week or two, and just wondering from your perspective, I know it's early days here, you'll think there'll be conversations with customers in terms of, I guess, winterizing assets. You know, clearly there's only so much you can do about well freeze-offs, but just wondering in terms of, you know, processing plant reliability, 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, would you think there'll be some upper pressure maybe on some of the rates you can charge for those services?

Well, Gabe, this is Chuck. In the Williston, obviously, we purchase winterized packages for everything. I mean, we've got heat tracing equipment in our plants. We've purchased Arctic packages for our compression equipment. So this is normal course of business in the BAC and we've seen it as 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 it's just a value proposition for producers and frankly processors and pipelines do you. 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 we lost power, which really there wasn't anything that we could do about that But I do think, you know, 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. You know, 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 and 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?

Yeah, I think you're referring – Gabe, this is Sheridan. I think you're referring to a 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, the 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 conditions. levels at this time. So I think right now we don't see a case where we're going to convert Elk Creek to a crude oil system. And in talking with the producers up there, a lot of them are securing space on other pipelines in anticipation of the DAPL going down and on rail terminals. And as we talk 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 another crude line or just this crude conversion. So, I mean, I think that's a factor as well.

Yeah, 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 Jeanne 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?

Jeanne Ann, this is Kevin. We've gotten that question a lot. Clearly, we think we can capture more gas than, 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, you know, would require some kind of changes in the way we work together and 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. You know, in total, does it go to zero? Probably not. You know, with operational disruptions, et cetera. But we've got many customers now working with us, 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 between Bluestem starting up and energy transfer, suggesting they may try to connect some of Enable's NGL production to their own systems. It seems like there may be some challenges to one of the dominant mid-continent NGL systems. 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, the volumes on our system are tied up under long-term contracts, which have many years left on them. We don't specifically talk about contract terminations or volumes on the system. but we think our contracts right now for the immediate future are very well secured.

Okay, thank you.

All right, next we have Sunil Sabal with Seaport Global Securities.

Hi, good morning, guys, and thanks for all the clarity on the call today. I just had a clarification. Yeah, can you hear me? So my question was on the sensitivity you provided in case DAPL was shut down sometime in April, $50 million for 2021. I was curious, you know, how would you characterize that impact say in 2022 if DAPL were to remain shut down and we were in a $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 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 22. But, but again, that's going to be dependent on if you're in a, 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, um, at these commodity prices. Got it.

And then on the second question was on the Elk Creek expansion. that you completed in fourth quarter. I was curious, were there any MVC commitments tied to that decision? Or is it just the original MVCs kind of hold for the expanded capacity also?

I think the answer is expanding Elk Creek to 300,000 did a couple things for us and one we mentioned on our calls is that ensures that we can move all our volume off of OPPL onto Elk Creek and still have ample capacity to be able to bring ethane out of the balkan if that is needed as well. That was the preemptive step why we did the expansion of Elk Creek.

Okay, got it.

Thanks.

All right. And then moving on, we have Michael Lapidus with Goldman Sachs.

Hey, guys. Thank you for taking my question. Just real quick, high level, how are you thinking about the path to deleveraging 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 dividend, it seems? how you're thinking about allocating cash flow between dividend growth, between new growth projects, or between paying down debt?

Well, Michael, what I would say about that is that we always want to make sure that if we have a good project that is going to serve our customers' 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 here 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 deleveraging plan is right on track. And if these commodity prices hold at this level, it should do nothing but accelerate.

Got it. Thank you, guys. Much appreciated.

Yeah, 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. Yeah, just on the levered one, just wanted to see, you know, what's your confidence in kind of hitting the four times versus the three and a half times? And what's going to kind of get you to that three and a half number? Is it more growth? I don't know. 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 three and a half and four 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, you know, 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 continent you talked about, I think, pretty well connects this year with potential, I think you talked about some customers actually adding potential activity Do you see that kind of plateauing into 2022, or how do you kind of think about the big continent kind of coming out of 2021? Thanks.

From a well-connected activity perspective, and I think as we move through 21, we've had a lot of conversation about that. As you move into 22, 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 to 60 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 depth, and I think you'll see that sustain through 22. Kevin, it's It's not all just about crude price. Obviously, NGLs and natural gas are a big driver for the activity up there. We'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 higher values for net gas and certainly for liquid. Those will also be important drivers for producers, particularly in Oklahoma.

Got it. And then maybe one last one from me. Yeah, definitely, I think recovery, I think in your guide, as you said, you're not factoring any in the Wilson, I think some in the mid-continent. But you kind of mentioned there could be some volatility. So how do you think about the FAA recovery throughout the year?

Well, what we see for the FAA recovery in the mid-continent, we do feel we'll see some FAA recovery this year, probably maybe a little bit more in the second half of the year. Obviously, what we've seen 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 in 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 them back on, they're going to run at very high rates. So we think we'll see more ethylene 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 late 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. Right.

I appreciate it, guys. Thanks for your time today. Thanks, Jeff.

All right, everyone. That looks like that will 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.