Welcome to the MPLX Fourth Quarter 2021 Earnings Call. My name is Kristen and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] Please note, that this conference is being recorded. I will now turn the call over to Kristina Kazarian. Kristina, you may begin.

Good morning and welcome to the MPLX fourth quarter 2021 earnings conference call. The slides that accompany this call may be found on our website at mplx.com under the Investor tab. Joining me on the call today are Mike Hennigan, Chairman and CEO; John Quaid, CFO; and other members of the executive team. We invite you to read the safe harbor statements and non-GAAP disclaimer on Slide 2. It's a reminder that we will be making forward-looking statements during the call and during the question-and-answer session that follows. Actual results may differ materially from what we expect today. Factors that could cause actual results to differ are included there as well as in our filings with the SEC. Now with that, I'll turn the call over to Mike.

Thanks, Kristina. Good morning and thank you for joining our call. Earlier today, we reported adjusted EBITDA of $1.4 billion for the fourth quarter of 2021 and $5.6 billion for the full year. Over the past year, we've executed on each of our three priorities. We exceeded our initial cost reduction target, reducing our annual operating expenses by approximately $400 million as compared to 2019 levels. We've made significant progress in this area over the last two years. And so what began as a cost reduction initiative is being embraced by the organization now a low-cost culture is being embedded in how we conduct our business. We brought multiple projects into service over the last year while maintaining strict capital discipline. Within the L&S segment, our three Permian takeaway projects, Whistler for natural gas, Wink-to-Webster for crude oil and our NGL project, were all placed into service and we expect volumes across these systems to ramp over time. Within the G&P segment, both the Smithburg one processing plant in the Marcellus and the Preakness processing plant in the Permian have started operation. We also continued our portfolio optimization efforts and completed the sale of the Javelina processing plant in Texas and some minor gathering assets in Southern Wyoming for proceeds of approximately $110 million. In addition to our cost reduction and portfolio optimization efforts, 2021 also benefited from the tailwinds of strong NGL prices and the recovery in U.S. refined product demand. All these items resulted in exceptionally strong cash flow and enabled us to return over $4.2 billion to unitholders through distributions and unit repurchases. On our Alaskan logistics and storage assets, we've been working sales process since we last communicated. We'll be back to you when we have more details that we can share. Turning to Slide 4…

Thanks, Mike. Slide 7 outlines the fourth quarter operational and financial performance highlights for our Logistics and Storage segment. L&S segment adjusted EBITDA increased $50 million when comparing fourth quarter 2021 to 2020. Pipeline volumes were up 18% and terminal volumes were up 11% year-over-year as the industry rebounded from the pandemic. The benefits of these higher throughputs and higher distributions from our pipeline joint ventures were partially offset by lower contracted marine transportation rates with MPC. Turning to our capital outlook. More than half of our planned 2022 growth capital is directed to the L&S segment, including a number of smaller expansions and debottlenecking projects such as expanding our Permian natural gas and NGL takeaway systems. Moving on to our Gathering and Processing segment. Slide 8 provides the segment's fourth quarter operational and financial performance highlights. G&P segment adjusted EBITDA increased $40 million compared to the fourth quarter of 2020, largely due to higher NGL prices. For the quarter, NGL prices averaged $1.05 per gallon, more than double the $0.52 per gallon average in the fourth quarter of 2020. These higher NGL prices and this quarter's asset sale gain of $19 million more than offset the effects of lower volumes. Overall, gathered volumes were up 3%, while processing and fractionation volumes were down 2% and 6%, respectively, compared to the fourth quarter of 2020. Our lower processing and fractionation volumes were partially due to the divestiture of our Javelina processing plant in early 2021. Focusing on our largest region, in the Marcellus, gathered volumes were up 7%, while processing volumes decreased 2% and fractionation volumes decreased 1% as compared to the fourth quarter of 2020. During the fourth quarter, as Mike mentioned, we completed commissioning of the 200 million cubic feet per day Preakness processing plant in the Delaware…

Thanks, John. [Operator Instructions] With that, operator, can you open the call for questions? Operator?

Thank you. [Operator Instructions] Our first question comes from John Mackay. Your line is now open. Goldman Sachs.

Hey, good morning, everyone. Thanks for the time. Appreciated the context and some of the color on growth CapEx looking into '22. Just wondering if you could give us a little bit more in terms of - we saw '21 way below where you'd initially guided, so maybe if any of that is kind of '21 spending shifting into '22. And then also just on the energy transition side, is there anything in that bucket related to Martinez? Would that be incremental to this number? Just any context on that, too.

John, on your first point, yes, there is a little bit of '21 spending that makes its way into '22. So there's a little bit of that. So that was a good observation. In general, I would tell you - I'm going to let Tim and Greg give some comments here, too. But in general, I would tell you, we don't have any big headline projects this year that we would talk about as large capital. But at the same time, we're pretty excited about we have a lot of smaller bolt-on debottlenecking expansion projects which tend to be a little better in return. Obviously, you don't have the headline, so it's a little tougher for you guys to think about it in general. But I actually like to set that we have now. And let me - Tim, Greg, why don't you guys give some examples of what we're talking about.

Okay. Well, this is Tim Aydt. I'll just give maybe a couple and then turn it over to Greg. You are right, we are spending money at Martinez. And really, that's spending capital to modify the assets in support of MPC's conversion of the refinery to renewable fuels. So that's a chunk of money there. And then, I think maybe another example I'll point to is, recently, we announced the expansion of the Whistler Midland Basin, 36-inch up further into the Midland Basin. I think that basically - those volumes will essentially fill the capacity on Whistler. And given the tightening gas takeaway situation it's being faced, we're starting to see a lot of producer customer input. And as a result, we're starting to consider the potential expansion of Whistler to 2.5 Bcf. So those are just a couple of examples. But as Mike said, there's a lot of other opportunities for bolt-ons and so forth and that's a focus.

Yes, this is Greg Floerke. With regard to Gathering and Processing capital, the two largest projects that we have underway now are Smithburg de-ethanizer and that project scheduled to come online midyear. And then the other large plant capital is for our Tornado 2 plant which will increase our West Texas processing capacity to one Bcf per day when it comes online late next year. The other capital is around growth on gathering lines in the Bakken and some in the Utica dry and Marcellus area.

So John, I think it's a really good question and I know people are going to try to understand that. So what Greg was saying is, hey, we're adding to our Smithburg Complex. What Tim was saying is we're adding to the Whistler project, as an example. So we have a long list of those. That's what really is in our program for this year, a lot of assets that are already existing that we're going to tweak and debottleneck and expand a little bit. And they're really nice projects because it's relatively small on the capital side but it can enhance the revenue side pretty good.

John, this is John Quaid. One other - just while we're talking about capital, one other item just to be thinking about, maybe a little bit abnormal from prior years, I would say, as we look at the plan right now, it's probably more front-end loaded towards the beginning of the year than what you might have seen from us in prior years. And again, we've got this nuance as well where there's some maturing debt at the JV. We've got to fund our equity partner there to make that payment and we know that's going to happen in the first quarter just based on when the debt matures. So another little context, too. It's probably a little bit more front-end loaded this year than what you've seen in the past.

That was great. Super thorough and clear across the board. Definitely appreciate that. Maybe just my follow-up here. Overall quarter looked pretty good. Some kind of puts and takes, products. Volumes look good. G&P looks good. Utica was processing a little weak again. Just curious if you could give us some context on - you're looking out into 2022, just some of the general upside, downside drivers for EBITDA that we should be watching.

Yes. John, maybe one way to think about that is to think about the tailwinds or, as Mike has called them in the past, the red bars that may be affected 2021. I mean, certainly, while we're largely a fee-based business on the G&P side, we do have some sensitivity to NGL prices which moved up significantly throughout the year, right? And we roughly say $0.05 on NGLs is roughly $20 million a year of an annual impact. So we start to see that when, for the year, we go from $0.43 to $0.87. The fourth quarter was $1.05. What's it going to be for all of '22? That's something we don't know. So that's certainly something we'll be watching. That, I think, drove '21 results but it's early in '22 to understand how that might drive '22. We also would have had some asset sales, as Mike referred to, over $110 million of proceeds. So we're going to have those again. Again, we continue to review our portfolio and look for opportunities but those may come, those may not. We also had reduced capital spending. Again, some of that was certainly our kind of continuing focus on strict capital discipline but some of that maybe to just producer activity and their uncertainty around COVID that maybe we're seeing, knock on wood, maybe start to look a little less concerning as the cases come down on Omicron. And we had some favorable working capital last year, too, that we wouldn't necessarily count on that repeating as well. So Mike, I don't know if there's something you want to add to that.

Yes, John, I just want to add - John used one of the terms that I use internally and it's one that I used in my prior life. I should probably explain a little bit more is I call our code cash flows and I use the term blue bar to refer to cash flows that I think are there in all markets, very stable that they are in all markets. And then I put red on cash flows. They could be onetime or not necessarily going to repeat themselves, etcetera, things that we don't count on as much. And as John just referred to that, I thought I would explain that a little bit. So, I think about blue bar and red bars, our cash flows. And as we think about the year, we're hopeful there are going to be some other red bar cash flows but we try not to count on that. John mentioned NGL prices. Maybe it'll stay strong through the full year, or who knows, right? That's the way the market goes on commodity pricing. So that's got a little bit of red element to it. Like John said, sales are clearly red. We'll evaluate those as those come along. So it's kind of the way we think about our capital allocation in general as we get to the back part of the capital allocation which are blue which are red and helps us make determinations on distributions versus buybacks, etcetera. So hopefully, that helps.

No, that's great. Appreciate the time. Thank you.

You're welcome.

Thank you. Our next question comes from Michael Blum, Wells Fargo. Your line is now open.

Thanks. Good morning, everybody.

Good morning, Michael.

I just wanted to follow up on the Whistler comment about expansion to 2.5 Bcf a day. I just want to clarify, is that something that's actually in the budget and plan for 2022? Or is that still something that you're considering? And if it is in the budget, any details on timing or cost would be really helpful.

So this is Tim. I'll take that one. Currently, that expansion is being contemplated by the JV partners and so forth. It is not a budget item that is currently in there. What I was trying to draw attention to is that as we continue to extend up into the Midland Basin and so forth, we've essentially tapped out some of the existing capacity and we'll be looking to grow that capacity on Whistler overall. So as far as timing, that remains to be seen. So more to come later.

And Michael, it's Mike. I'll just add to Tim's. What he was referring to is at the end of January, the partners made this announcement of this extension lateral. That - we have a little bit of capacity beyond the MVC commitments. So that extension kind of gives us another little geographic area to us to put into the project. And then the next step as the Permian continues to grow is can we add some more additional assets to take the capacity up some more. So what Tim was describing, kind of a two-pronged thing with - what we just announced in January is near in, committed. We're doing that. The second part of it is we expect this to happen. We have a good asset and it'll be tough to beat the expansion economics that we'll be able to provide, if that makes sense.

Yes. Absolutely. Appreciate that. The second question I had was really, I guess, a capital allocation question. In light of all the inflationary pressures we're seeing in the market, just wanted to know if that impacts your thinking on the mix of distribution growth versus buybacks and all the other options in 2022, meaning do you see the need to raise the distribution faster to offset inflation for investors? Or do you just sort of continue your ratable distribution increases you've been doing year after year?

Michael, it's John Quaid. I think as we think about where we are and go back to Mike's comments, right, we look at the balance sheet. We want to be around 4x. We're very comfortable at around 3.7x now, right? We'll focus on maintaining our assets, securing the distribution, looking at growth opportunities and then looking at kind of where we're left. And that growth capital opportunity is that buybacks or is that more distributions. Again, we've got a pretty strong payout ratio and distribution, as you know. So it's certainly one of the avenues we look at as we think about return of capital.

Great. Thank you.

Thank you. Our next question comes from Jeremy Tonet, JPMorgan Chase. Your line is now open.

Hi, good morning.

Good morning, Jeremy.

Just wanted to pick up with some of your comments at the beginning of the call there with regard to the asset sales. I just wanted to catch that, that was a bit over $100 million of sales there in Wyoming. And just wondering if this was a process that you're continuing to evaluate your assets and check out kind of what the value is on the market there, or did someone else approach you? And just in general, I guess, how are you seeing the appetite for G&P assets out there? Are they starting to close in on the valuation that you see that maybe there could be more rotation?

Jeremy, it's John Quaid. I'll start with the first part of that. So just to clarify, the $110 million is the proceeds for the year from two sales. So that includes the about $70 million from the sale of Javelina earlier in 2021 and then $40 million from the sale of those gathering assets in Southern Wyoming. So there's actually two pieces to that. Again, in the quarter, it was just the sale of the gathering assets in Wyoming for proceeds of about $40 million and a gain of about $19 million, just to kind of rack those numbers. And I'd say both of those just resulted from our continuing kind of portfolio review to look at our assets and optimize them what makes sense in our portfolio versus what might make sense in someone else's. I think - and maybe I'll start on kind of our - the basin question we talk about every quarter. I'll let some others chime in as well. Again, I think we're still in the same spot where, while in some of these basins, we're continuing to generate cash flow. So we're not in the rush to sell those. And we'll see as the market moves, if that bid ask starts to compress a little bit but - and certainly, something we'll actively review but I don't think we have any significant updates here on that right now.

Got it, that's helpful there. And unless anyone else is going to jump in there.

I'm getting thumbs up around the room. So I think that was the - I think everybody is good with that, Jeremy, if you got another question.

Yes, great. I just wanted to touch on the Northeast a bit more in producer activity there. You have Mariner East looking like it's getting completed here which would add needed NGL egress. And then you have the Shell cracker in the middle of this year and this could really help NGL price realizations in the basin and incentivized drilling. At the same time, the basin has been challenged for takeaway over time, although there's been incremental capacity additions coming in here. Just wondering how you think the basin production progresses at this point. Do you see shifting activity, dry to wet, that benefits you? How are producer activity conversations going at this point?

Jeremy, this is Greg Floerke again. I think as we've talked before and most of our producers in the Northeast are - they're focused on free cash flow generation and on making sure that even with good NGL prices and gas that they match the takeaway capacity, as you mentioned, both residue and natural gas liquids. Mariner East capacity has incrementally expanded over the last few years as Mariner East two and 2X have worked towards completion And so I think that's more of an incremental gain and it does free up room for more ethane production, along with the Monaca plant coming online midyear. We mentioned our Smithburg two de-ethanizer plant down in West Virginia, along with our existing fleet of de-ethanizers. This is going to open up even more capacity to help fill that Monaca plant. We expect upwards of 80% of the supply could come off our system. And otherwise, some producers will continue to kind of slowly bring on new pads, some are in decline and some have maybe single-digit growth. So overall, we're looking at continued flat - I think flat production in the Northeast that's going to be a series of some producers up, some down but overall in balance.

Got it. That's very helpful. Thank you.

You're welcome, Jeremy.

Thank you. Our next question comes from Spiro Dounis, Credit Suisse. Your line is now open.

Thanks, operator. Good morning, team. I wanted to go back to growth CapEx quickly. Just given that a lot of these projects are smaller in scale and brownfield in nature, just curious if it's fair to assume that the majority of that $700 million in CapEx could actually be cash flowing by year-end, or is that a little too aggressive?

Yes. It's - Spiro, it's John here. I think maybe a little aggressive. I mean, some of these - as Greg talked about, some of those plants coming up midyear, some of those will be ramping throughout the year. Timing-wise, we're spending some capital on the Martinez renewables project, right? But MPC is not finishing that project this year. So that's not going to cash flow. So I think that might be a little bit strong. Some of them - and some of them, right, kind of come on in pieces, too, throughout the year. So I think I'd be a little hesitant to say they're all going to be cash flow at the end of the year.

Spiro, it's Mike. I'll just add, in general, the capital you spend in one year has a lag for the cash flow, especially if it's going to be ramping volumes as well. So yes, it's kind of aggressive to think of this capital to hit the cash flow. It's really capital that we spent the year before and the year before that. That really starts to play itself into this year's cash flows.

Understood. That makes sense. I just like setting a high bar for you, Mike. So apologies on that one. Next one is just on processing capacity.

No worries. Thanks for the help, Spiro.

You got it. Next one just on processing capacity. I noticed that some of the capacity, I guess, in three of your basins fell quarter-over-quarter from 3Q. And just curious, what exactly drove that? Sorry if I missed it in the prepared remarks.

Yes. So if you look year-over-year, there's some slight decreases there. I think I'll let Greg chime in as well. I think some of that is just going to be timing in the basin as producers move through activity. The other thing, don't forget, because the volumes year-over-year on the quarters, they're slightly down. Remember, we had the Javelina facility that we sold. So like fourth quarter year-over-year, if we're down 2%, like it's a small decrease and half of that is probably the fact that we had Javelina in one period and not the other. So I think it's both the sale of Javelina and then maybe just timing on the producer side. But Greg, I don't know if you wanted to...

And sorry to cut you off. It was more around - not so much the volumes that went through but just the capacity specifically at...

I'm sorry. I'm sorry, Spiro. My apologies. My apologies. So as we look at our regions, we do kind of an annual review of our capacities. And as you noted, in Southern Appalachia and the Rockies, in those particular regions, we, frankly - and really, it's part of our cost reduction efforts to some degree. We had some units that really were not needed based on demand in the region and we don't see them to be needed. So we've kind of permanently idled or disconnected those units from our capacities in those regions, save some cost for us. So those are adjustments we made, again, primarily in those two regions to the processing numbers, just an annual process we do. Instead of changing that every quarter, we kind of flow those through here at the end of the year. My apologies for answering the wrong question.

No, no worries. That was really helpful. So that's all I had today, guys. Thank you very much.

You're welcome.

Thank you. Our next question comes from Theresa Chen, Barclays. Your line is now open.

Good morning. I'd love to ask a little bit more about MPLX's overall decarbonization plans and potential participation in MPC's decarbonization efforts. So first, in addition to the logistics assets serving Martinez, is there any appetite to take up some bigger capital projects maybe with the processing units?

So this is Tim. I'll take that one. I think maybe it'd be helpful to kind of give you a little bit of an overview of our strategy. It really involves a two-pronged approach. First, MPLX is going to support MPC and its renewable fuels build out. Now that's primarily through the associated logistics opportunities. We talked a lot about Martinez already this morning. So that's the prompt example. I think second is just as important, though and that's we're going to look to be part of developing and executing industry solutions for decarbonization. As we've announced previously, we're participating in the Houston area CCS consortium and - or discuss another similar efforts as well. But I think beyond that, we continue to evaluate really a wide array of low-carbon opportunities. Unfortunately, there's none that I can publicly discuss at this time but stay tuned. I think as a general rule, when you look at the time line that we're working off of, we see RD and SAF as being really the prompt and shorter-term opportunities. CCS and maybe RNG would come in the midterm. And then certainly, hydrogen and distributed power is something we're looking at. That's probably more capital deployed in the longer term. And of course, as we've noted before, we're bullish natural gas. And so we really see natural gas as an important transitional energy source and that's going to play a key role in the energy mix well into the future. So we have a lot of opportunities in that regard as well that's tied to energy evolution. So hopefully, that answers your question.

That does very comprehensively. Speaking of natural gas, maybe pivoting towards some of the earlier comments related to the Whistler potential expansion. Granted that you're still going through the process and imagine having discussions with the partners and producers and such but in terms of getting to that 2.5 Bcf per day, how do you view the economics with the expansion relative to other possibilities for expanding different assets within the basin of competitors? Like how does your project stack up versus competitors? Certainly, imagining it's more competitive than any sort of greenfield project. And what are the gating factors in getting producers to sign on? And are there any initial thoughts about how much this would cost?

So I'll answer a few parts of that. I think when you look at the forecast, they contend to indicate a need for increased takeaway out of the Permian Basin. Some of this could be served by Whistler expansion. But I think even beyond that, another pipeline is viewed as being necessary in the next two to three years. But certainly, I think the goal of the industry and certainly the goal of our JV would be to fill up existing assets first. Obviously, that's the most capital-efficient path forward. We like our project as it exists today with Whistler and we see that as a very capital-efficient way to move forward. But again, that would get you about half of the basin is looking to grow, we think, a lot more than that. So as far as project capital and so forth, I'm not able to get into any of that. So I would just tell you that as is customary for gas, we would require MVCs to expand existing systems or to participate in any new pipeline as is customary.

Thank you.

Thank you.

Our next question comes from Keith Stanley, Wolfe Research. Your line is now open.

Hi, good morning. I wanted to ask first on your pipeline volumes, oil and products. They continue to run solidly ahead of where they even were before COVID in 2019. So are you still - is it still the dynamics of just lower exports and higher volumes through MPLX pipes? And do you expect this to be sustained into the future?

Keith, it's John. That's a great question and maybe another tailwind that benefited us last year that we've got to watch this year that I maybe failed to mention before because, certainly, there's a portion of that as we saw less exports. But recovering U.S. demand, we were able to utilize those assets more. Certainly, we're looking to go after market share, etcetera. But if exports kind of pick back up, that might be a headwind then on those volumes. As you know, they're pretty strong.

Great. And one on operating costs. So I think last quarter, you talked to a $40 million increase for Q4. Did that materialize in the quarter? And I guess more importantly, how should we think about operating costs in 2022 relative to fourth quarter levels?

Yes. Thanks, Keith. Great question. And yes, I think I talked about perhaps up to $40 million. I think I might have to stop losing my bet with Tim and Greg because they continue to find other ways and their teams to offset those increases. So while we did see it in certain areas, the team was able to find other areas to reduce costs and offset a good bit of what we were maybe seeing in our forecast. So great job by the team and we'll be fighting to maintain that as we go through next year. But certainly, no major swings, pluses or minuses to kind of say going into next year on project expense.

Okay. So we should - for now, we should assume 2022 is pretty similar to kind of where you were in Q4 on cost?

Yes. Yes. I mean we're - again, the teams - as Mike talked about, going back to 2019, we've - we feel we've taken about $400 million of cost out of our cost structure. And the teams are really focused on maintaining that, looking for other opportunities, managing costs with some of our growth capital as we bring new operations on. So we're going to be fighting to embed that and look for more opportunities as we continue to work to really move from this low-cost initiative into a low-cost culture.

Great. Thank you.

Thank you. Next up, we have Brian Reynolds, UBS. Your line is now open.

Hi, good morning, everyone. I'll follow-up on some of the earlier return of capital questions. When we look ahead into '22, we appear to be seeing some similar trends as '21 in terms of sub-4 leverage and free cash flow in addition to some growth. Just given that there's roughly $300 million left on the buyback authorization, I was curious if you could talk about interest expanding and extending the buyback program and how we should ultimately think about an additional special distribution in '22?

Yes. Thanks. I think on the buyback, obviously, that's a discussion with the Board that we'll take up with them at the appropriate time. So I wouldn't want to get ahead of that discussion. And then the overall return of capital, again, we've kind of walked through a number of times kind of how we think about the framework and the priorities there and that's something we're going to evaluate each quarter end, looking at where we are and thinking about our avenues for return of capital, whether it be distribution increase, unit repurchases or special, again, driven by where we are and what we're seeing. So I think that's an ongoing, maybe somewhat more dynamic kind of assessment than maybe, to some degree, what was dynamic but looked a little programmatic last year.

Brian, it's Mike. I'm going to add to John's point there. The way we think about it is we want to put the portfolio in a position that we're generating this excess cash beyond distribution, beyond capital. Now to what level that turns out to be, some of these other factors that we talked about blue and red bar cash flows kind of come into play. So his point about being dynamic is the way we think about it. We look at the year. We try and assess things. We're committed to returning capital. It's something I feel strongly about. And at the end of the day, whether it comes in the form of distribution, whether it comes in the form of buybacks, we discuss that throughout the year. And I've said this on many calls, we also ask the owners, the unitholders. And there is a bifurcation. There are those who really support buybacks and there are those who really support distributions. So part of what you saw last year was some balancing in our view of people that want buybacks. We think we did a good portion of that with the capital that we had for people that want distributions. We were a little cautious because of some red bar. So we put it in the form of special as opposed to permanent. But we also did a little bump up on permanent as we continue to feel good about our blue bar cash flows. So dynamic is a good word. John said it well. I think people think of it more programmatic because it's been around the same level but that's mainly because as we sat down and looked at it, we were forecasting about the same level for a while. And then things came our way a little bit and we ended up with a little bit more and then we made an adjustment. So we'll proceed into '22 very similarly. We have a base plan that obviously we're going to execute on and we'll see how the market plays itself out. We'll see where the equity trades. We'll see how the capital projects kind of progress throughout the year and we'll just continue to evaluate it and then each quarter, try and give you guys an update on how things have played out.

Great. Really appreciate all that color. Maybe to pivot, I know - appreciate all the color on the gas takeaway from the Permian. But maybe to talk about the NGL side of things and new BANGL solution and bringing in the new JV partner. Just curious if you could provide some color about how you see that project in JV evolving over time. While the gas pipes needs - appear to be first, how do you see the NGL takeaway in the future? And how do you see BANGL being a part of that solution over the long term?

Okay. This is Tim. I'll take a stab at that. You're right, we did recently announce the addition of another partner. That was Rattler Midstream to the BANGL JV. So that program or that project rather kicked off operations early fourth quarter last year with deliveries to Sweeny. So that project continues. As the basin continues to recover, we're seeing increases in NGL demand for takeaway. And so as a result, I see that platform, much like the Whistler on the natural gas side being a good platform for growth for the JV. I think there's certainly an appetite for more volumes to head towards Sweeny. And we have capital-efficient expansions that we can do on a just-in-time basis and that's what we're looking to accomplish.

Great. And as a quick follow-up, is there any CapEx related to BANGL in this year's budget in terms of expansions? Or would that be more a '23 event?

There is - there is some. I can't speak to the quantity on individual projects but yes.

Yes. Brian, let me just add a little bit to what Tim just said. And I was hoping that we were clear but maybe we haven't been. So if you look at our asset base across all of our portfolio, as Greg mentioned and Tim mentioned in the beginning, think about - we're doing little projects across our whole asset portfolio. That's kind of the way this is shaping up this year. So there's not that - I use the term, there's not a headline project but there's a little bit of opportunity throughout our asset base. I hope that's a little bit clearer, maybe not but trying to give you guys as much color on that as I can.

Thank you. Next up is Chase Mulvehill, Bank of America. Your line is now open.

Hey, good morning, everybody. So I guess I want to come back to Whistler. A lot of questions around Whistler. You kind of talked about the potential for half of B a day of additions. But if demand was actually there, could you do more than half of B? Or is it half of B to be kind of the limit of what your brownfield expansion could be on that pipeline?

Okay. This is Tim Aydt. Relative to Whistler expansion, half of B would be the max. You could get through the 42-inch pipe with the compression. So what I was pointing out earlier is that the basin is expected to continue to grow obviously beyond that. And most projections again suggest two to three years, another pipe would be necessary. So as is the case, the industry is looking to potentially solve that problem. We're also looking to solve that problem as well but that's kind of the outlook. A Whistler expansion in and of itself would not be deemed enough to meet the basin's needs.

Right. And what would be the timing if you sanction that today, the incremental half of B? What would be the timing to kind of bring that incremental capacity online?

It's really going to come down to the lead times on compression. With the supply chain issues, I would say, a good time line is probably a minimum 18 but probably closer to 24 months.

Okay, right. And a quick follow-up here on kind of Permian takeaway capacity. The issue is probably getting contracts for - 10-year contracts for some of these, whether it be brownfield expansion or greenfield expansion. Obviously, the demographics of the Permian production growth are changing. More profits. Profits have less drilling inventory. They certainly don't - most of them don't have 10 years of drilling inventory to sign a 10-year take-or-pay contract. So somebody is going to have to absorb more risk to get more pipe built. So how do you think this ultimately plays out?

Well, I think the LNG market is continuing to grow and is forecasted to grow in a pretty big way over the course of time. So I think the producers are looking to make sure that they have adequate takeaway capacity. And as a result, I think it's going to come down to making those commitments. I do believe that several producer customers have north of 10 years of drilling capacity. There's also a reduced amount of flaring and so forth. So I believe the gas is out there and will continue to be with the outlook on LNG exports being what it is.

Yes, makes sense. If you allow me to kind of squeeze one more in. Obviously, MVP is very topical these days, having kind of continued permitting issues and just political issues there. How would - can you kind of just walk through the puts and takes of MVP delays and how this will impact your Marcellus business?

Greg Floerke. In terms of the delays, there have been a number of hurdles there but the pipe is, as we understand it, is over 90% complete. So it's down to - the distance is probably less important remaining than what kind of crossings and permits are required. I can't speculate not being involved in that project on what the delays mean or what the timing would be. I can say that in terms of takeaway capacity for our producer customers, most of them were early players that took out capacity and have firm capacity on the existing lines. And with the flat to very limited amount of growth near term to medium term, they've got sufficient capacity and we're depending on - I think most were not depending on that expansion. Obviously, longer term, the basin needs more takeaway to experience more growth and we're hopeful that eventually the pipeline is completed.

Okay, perfect. I'll turn it back over. Thanks.

Thanks.

Next up, we have Tristan Richardson, Truist Securities. Your line is now open.

Hey, good morning guys. I love all the red bar, blue bar references. It's a great throwback. You've covered a lot of ground already, so just one for me. But can you talk about just capital and activity levels you're seeing in the Bakken? Obviously, small asset but you noted some debottlenecking spend there. And just curious on the capital that's going in and then also activity levels and if, over time, you see any need for additional potential processing on your footprint there.

I'll start off and I'll let Greg. First of all, thanks for the throwback. Sometimes it can't change my strides from the past. But yes, like I was saying earlier, I'll let Greg comment a little bit more. But yes, all of our areas is - what I was trying to say is we're doing a little bit in each of these areas. So we're doing some Marcellus. We're doing some Permian. We're doing some Bakken, etcetera. As the market is recovering and as the commodity cycle is what it is, we have assets that can participate. And we're putting little bolt-ons and little expansions to incrementally increase our asset base. Do you want to add, Greg, or...

Yes. Thanks, Mike. I'll add. Obviously, crude - high crude prices and crude rig activities driving not only expansion opportunities for us on the crude gathering side for MPLX but also the associated gas. There is a large amount of gas even with the existing production that was being flared. Obviously, the flaring is not something that's sustainable, whether it's in the Permian or the Bakken. So there's opportunity to pick up more rich associated gas. There's gathering opportunities and processing opportunities. In terms of future expansion, yes, I would say there's definitely opportunities for - there's going to be opportunities in the current pricing regime for additional processing. We have high utilization there. We don't have the amount of processing capacity buildout that we do in some other areas but we do have some capacity we continue to fill and also look at other potential joint venture opportunities as well if there's existing capacity that can be utilized and that we can gather and work with.

Yes. And Tristan, it's John. Just to be clear, as Greg was saying, we - so I think a lot of the capital now in the Bakken is probably more on the gathering side and filling up systems we have. We're looking at opportunities to fill up another system that's there. So while we look at processing, there's no processing in the Bakken in our plans right now.

That's great, super helpful. Thank you guys very much.

You're welcome.

Our next question comes from James Carreker, U.S. Capital Advisors. Your line is now open.

Hi, thanks for the question. I was just wondering if you could talk a little bit more about Q4 results. A pretty nice step-up in adjusted EBITDA relative to the prior three quarters in 2021. And then just thinking about - is there anything that happened in Q4 that maybe shouldn't carryover into 2022 as we look to what EBITDA could be then and kind of thinking about what a run rate EBITDA could be? I'll just leave it there, I guess.

James, it's John. Thanks for the question. I think I might circle back to our tailwinds and talk a little bit about some of those that were in the fourth quarter, right? So we talked about nearly a $20 million asset sale gain in the quarter, right? That's not going to repeat every quarter. We talked about NGL prices which were the highest quarter of last year. It was the fourth quarter at $1.05. Again, would we love to see $1.05 all this year? Yes. But is that going to happen? That's an open question. I think we, too, we probably - you would have noticed on the L&S side of the business, we had some higher distributions from our pipeline joint ventures. Some of that would have been with - remember, Hurricane Ida in Q3. So some of the Q3 distributions might have pushed into Q4. And again, too, I think there's some timing there on when distributions are made from those ventures that may be kind of piled into Q4 that's not going to maybe be a normal run rate looking into next year. So there are certainly some things I'd be careful just taking Q4 and times it by four given kind of the drivers of those results.

Yes, that's helpful. That's exactly what I was looking for. But then I guess that should be offset. I assume you're going to continue to have growth on a number of your JV pipes. DAPL, Wink-to-Webster, Whistler, BANGL, those should all contribute meaningfully more in '22 than '21?

Yes. I mean as we look at the volumes on those, again, Whistler will keep ramping up, as Tim has commented. Certainly, I'd say this year was probably less about the Permian joint ventures and more about our other kind of crude line joint ventures. So we'll - it was probably more on that side, right, where we're not really changing those pipes. And Whistler will come on. Again, we've financed some of that as well. So that will affect how that comes through cash flow.

Got you. And then I guess maybe a final question. Can you talk how much maybe impacts the FERC tariff adder could have on your business? I know it's not until July 1. But potentially, a 9%. Can you remind us how much that impacts your L&S segment?

So this is Tim. I'll take that one. I guess as kind of a reminder, the escalators are meant to cover the cost increases that come with inflationary pressures. So while we do expect to see an increase in the FERC index rate and, therefore, the revenue, we don't really expect to see a material change to our EBITDA. Again, those are meant to offset. We do plan to manage any inflationary pressures that might come up through either increased efficiencies or these index adjustments. I guess relative to the amount, I can't give you specifics on that but I'll just kind of remind you that less than 1/3 of the L&S revenue comes from FERC-regulated assets. So most but not all revenue streams do have some form of inflation escalator attached to them. One exception to that is the storage revenues. They're generally not indexed. But all the other revenue sources would have either a fixed inflation adjustment or maybe a PPI or CPI adjustment or some other formulaic path. So hopefully, you find that helpful.

I do. Thank you.

You're welcome.

Next up, we have Timm Schneider for our last question with Citi. Your line is now open.

Hey, thanks and good morning. Actually, here your deck [ph] colors actually matched the red bar, blue bar as well. So there you go. First question real quick on Whistler and apologies if I missed it. So the - on the potential expansion, has that already - is there already interest from shippers on that? Or are you just talking hypothetically about that?

If I heard the question right, you were asking about the expansion and whether there's interest already. Yes, I would say we're in constant communication with producer customers and there is interest. So I can't get into specifics on shippers and potential shippers, etcetera but it's not really hypothetical. It's - there's interest out there.

Okay, got it. And as a follow-up to this and this is maybe a little bit more longer-dated impact here. But let's assume Permian gas egress gets jammed again like we saw a couple of quarters ago, do you think there's a big kind of marketing opportunity on Whistler to realize some of those basis differentials between Waha and Agua Dulce? And then how much of that capacity - or potential capacity is actually available for kind of marketing activities versus what's committed?

Yes. Timm, it's Mike. It's a great question. It's a good hypothetical. I don't want to speculate on it. But I think what Tim was trying to say and it kind of got a little bit of runaway here, was he was trying to say, look, we have some good bolt-on projects. We announced one just last week and that's why we were trying to explain this lateral into Midland. And then it sets up an expansion at Whistler and he said conversations are occurring. But I think he said it also very well earlier is this is going to continue to evolve. This is in this week or this month issue. Over time, we expect producers to continue to spend money in the Permian to increase their production there. So you have a fair point. Could it eventually bottle up the way it was before? It's possible. I - personally, I think the market is aware of that and probably going to look to avoid that and talk to us and other players to make sure that it doesn't happen the way it happened in the past. That's just my own personal guess. So as I said, it's speculation. It's not a bad thought. But my own personal view is people are going to be conscious of that and get out in front of it and talk to midstream players like ourselves and see if they can put a plan together.

All right, great. My last question is just on the debt. I mean, look, you're at, call it, 3.7x now. You said you're comfortable with 4x. You don't have a ton of debt maturities due in 2022, a couple of things in '23. Last time I checked, I think your 10 years where yield to worst was sub-3%. How do you think about retiring that debt versus just rolling it and just using that cash flow for other things?

Tim, it's John. I mean, certainly, it's something we take a look at all the time, right, looking at optimizing that debt portfolio. And frankly, when you look at where rates are both short and long term, the cost of trying to go after that debt really doesn't work for us to do that. So I think if the numbers change, we'll take a look at it. But right now, looking over that portfolio, it's just - it's not cost-effective to go after that longer-term debt.

All right, that's it for me. And go BANGLs [ph]. There we go.

Love the Ohio connection, Tim. Thanks.

All right. Operator, with that, thanks, everyone, for joining us today and thank you for your interest in MPLX. Should you have additional questions or would like clarification on any of the topics discussed this morning, members of the IR team are here to help you. Please just reach out. Thank you, everybody.