Good afternoon, ladies and gentlemen, and welcome to the NGL Energy Partners LP Third Quarter 2022 Earnings Call. At this time, all participants are in a listen-only mode, and the floor will be open for your question and comments following the presentation. It is now my pleasure to turn the floor over to your host, Linda Bridges. Ma'am the floor is yours.

Hi. And again welcome to NGL's third quarter fiscal 2022 earnings call. I'd like to start by calling your attention to our safe harbor language, which can be found towards the end of the partnership's earnings release, which was filed after market closed this afternoon. Today's remarks may contain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. In accordance with the act, I would also like to direct your attention to the Management's Discussion and Analysis section and the risk factors discussed in the partnership's annual report on Form 10-K for the year ended March 31, 2021 and in other SEC filings made by the partnership, which are available on our website and on the SEC's website. These together with the safe harbor statement in the earnings release set forth important factors that could cause actual results to differ materially from those contained in any such forward-looking statements. With that, I'll turn the mic over to Mike for opening remarks.

Thank you Linda. We have our business segment leaders on the phone with us today to answer questions and provide an update on certain topics. But first I'd like to provide context on the quarter and how that transition to the next couple of fiscals we spoke of on the last call. We were slightly disappointed in this quarter. We expected Water Solutions to come in around $90 million EBITDA. But due to lower water disposal volumes in October, November we achieved about an $83 million EBITDA. Crude Logistics EBITDA was expected to average about $35 million per quarter or $140 million annually and we achieved a $30 million EBITDA this quarter. Liquids Logistics is also below expectations but due to the much warmer than normal temperatures during the quarter October, November, December. Based on the fourth fiscal quarter thus far, we anticipate recouping a portion of the third quarter shortfall. We can all see the colder-than-normal temperatures in January and February that could benefit our liquids logistics. Crude Logistics is seeing some benefits from differentials but the DJ Basin seems to be going sideways, not adding to the rig count. But in our Water Solutions business, December EBITDA exceeded $30 million for the first time. For the last two weeks we have averaged over two million barrels a day of produced water. This is 9% greater than the 1.84 million barrels a day received in the third quarter. As you may remember, we projected a 10% increase in our fiscal 2023 Water Solutions EBITDA, which is approximately $32 million EBITDA per month. We're almost there already in this quarter. So we expect to enter fiscal 2023 at that $32 million level. So any growth in fiscal 2023 will provide upside to the Water segment. With respect to skim oil,…

Yes. Doug maybe just a little bit about connectivity, how our wells -- even if we lose some capacity and maybe we're going to lose, pick a number, 50,000 barrels out of 3.7 million. We don't lose any water, we are basically gaining so --

Correct. Yes. So our strategy over the last five years as we grew the Delaware business. We have -- I guess we always mentioned 24 and 30-inch pipelines or large transportation lines. We have lines of 24-inch system Lea County Express going off east into Andrews County, which I believe we are the only ones to have that ability. Out of Lea County and to Andrews County Texas. And then of course we have our Western Express 24-inch pipeline and our oil express 24-inch pipelines, along with our exclusive arrangement with Z&T Cattle in Loving County. Many of our injection wells are in Loving County, Texas and one very big positive for our position there is that, there are no deep injection wells permitted or drilled in Loving County, Texas and we do not see the Rail Commission letting any of them be permitted or drilled due to the fact that that closely to seismicity on deep well. So we have the ability to move water throughout our system, both east to west north to south throughout New Mexico, throughout Texas, both Loving, Reeves and Andrews County Texas. So we have very good ability and very reliable system, because of the redundancy and the large diameter of our pipelines and our ability to move water throughout the system away from seismic impacted areas there, but we can still pick up, like I mentioned, we're picking up quite a bit of new interruptible contracts and water from those others affected within the seismic of SRAs.

Great. And then XRI.

XRI. And as we've mentioned previously in previous quarters, on the last call we talked about our recycling business and how we are ramping that business up. We felt like it was time. As we assess the market and then we assess the returns related to recycling and reuse, we determined that with our best-in-class abilities on the produced wire transfer -- transport and disposal business, we decided that XRI was a very good partner to collaborate with on utilizing their recycling services. So the synergies of XRI enable us to utilize our expanse pipeline system, and deliver those high rates of produced water that are required for these large simul fracs and dual simul fracs that we see today. And then XRI has the equipment, has the head count and the people and expertise to process that water at those high rates and at very high specifications, which we're seeing become more and more important from the producer demand. And rather than reinvent the wheel and go spend the capital hire the people manage another business line that's not our core business. We realized the collaboration with XRI is the right way to go. They get to focus on their core business, enables us to sell large amounts of our produced water and we still capture sizable margins out of that value chain. And the most important part side-by-side with those large margins also we don't spend any additional capital to achieve this. It fits our model bringing as much free cash flow to the bottom line as possible. High margins moving lots of -- selling lots of water off our system and without any additional capital expense.

All right. Thanks Doug. Let's jump over to our liquids and our EVP of that segment Jeff Pinter has some comments and update on the ambassador pipeline.

Thanks Mike. So let's jump from the Texas and Mexico area up to the Wolverine state, where NGL is excited to share some of our investments in the state of Michigan and what it's going to do for propane customers up there. As many of you may know, Michigan is one of the top propane states in the country, but the state only has a modest amount of its own production. As a result Michigan has developed a dependence on importing huge volumes of propane via truck and railcar from neighboring states as well as from Canada. Much of the demand in Michigan is located in Central and Northern Michigan, which consequently have folder weather and more HDDs. So with that a bit of background, I wanted to share a little bit about our investments. First we entered into a multi-year agreement with a sizable NGL producer in Kalkaska, Michigan, which sources its production for Michigan's own oil and gas wells. We partner with the operator of the facility to upgrade a number of things, including the truck rack, which went from loading anywhere from one hour and 15 minutes to one hour and 45 minutes per truck. So now they can do approximately three to four trucks per hour. We also made some upgrades to the inbound rail rack, which accommodates additional supply and backup for flow certainty when needed. And the customers the feedback has been very positive so far. We've had a number of customers that love the convenience of buying product closer to their end destinations, and the fact that they're getting their domestic supply from in the state. Secondly, we just finished the construction of the Wheeler facility near Merrill, Michigan this month. The Wheeler facility a brand-new pipe and truck out facility with 480,000…

Great. Thanks Jeff. And hand it back to you Linda.

Okay. So diving into the financial results for the quarter. Our Water Solutions segment reported adjusted EBITDA of $82.7 million. Processed barrels totaled approximately 1.84 million barrels per day growing approximately 79,000 barrels per day over the preceding quarter and approximately 425,000 barrels per day or 30% and when compared to the third quarter of last year. We continue to see growth in all of our -- all of the primary basins in which we operate However as expected the Delaware Basin is driving the majority of the growth and we still expect to exit the fiscal year with approximately two million barrels a day of processed water volume which is a number as Mike pointed out we've already seen this quarter. Revenue per barrel processed averaged $0.58 compared to $0.60 per barrel for the prior quarter driven by more volumes received from customers with lower contracted rates. OpEx per barrel remained constant at $0.26. Skim oil barrels per day were slightly lower than the prior quarter due to the timing of completions and the receipt of related flowback water. Additionally sales of water were impacted by the timing of producer completions. It is important to note that these water sales can be uneven through the year should be looked at on an annualized basis and are subject to producers' completion schedules. Our Crude Oil Logistics segment reported adjusted EBITDA of $29.8 million for the quarter. The underlying business performed well as we saw positive results in our Transportation and Marine businesses and reported 83000 barrels per day on Grand Mesa pipeline compared to 80000 barrels per day during our second fiscal quarter. That said results in the segment were negatively impacted by approximately $9 million due to the backwardation in the crude curve and its impact on our hedging…

Ladies and gentlemen, the floor is open for questions. [Operator Instructions] Your first question is coming from Tarek Hamid. Your line is live.

Good afternoon. Thanks for addressing the induced seismicity issues head on. I guess from your comments it reads like you view it as more of an opportunity than a threat at this point. I guess any sort of way you can kind of give us context to sort of how much incremental water you can potentially process, if sort of rules stay the same as the current kind of temporary rules that are in place?

Doug?

I think if you estimated the temporary rules stayed in place somewhere between -- in the Delaware where we're handling anywhere from 1.7 million to 1.8 million per day. I would say that incremental increase is somewhere around 5% to 7%. And if I can if I may I'll expand. That additional producer contract, the medium term when I mentioned that is as very firm obligations for delivery of water, which really led to some strength that we didn't expect prior to the seismic activity.

Got it. And then I guess sticking on the water business. One thing I noticed and thank you guys for disclosing the recycled water volumes, but I did notice that recycled water appears to have dropped pretty substantially in the December quarter. Any explanation on that, or is that just more just a function of completion schedules?

Yeah. And I think -- yeah, I think you can see that in the actual water volumes in October, November. The producers were surprisingly disciplined in that last quarter, certainly in October, November and we really saw things slow down, which we were a little surprised at. But then we got into the November period -- or I'm sorry the December period and it was an unusually busy month. So accordingly the recycle reuse volumes went down, but we really saw that increasing late December during the holidays, which is very unusual. And then certainly in this quarter -- this fiscal fourth quarter we've seen it really outpaced our expectations.

Got it. And I guess as you look through that revenue per barrel of water touch appears to have kind of dropped a little bit sequentially. Is that a combination of kind of skim oil being a bit lower and the recycled volume being a bit lower? Is that a decent way to think about it for someone who's put you on public edge?

Yeah. I think more accurately, we do have some of the larger contracts. We have incremental annual increases of obligation volumetrically in those disposal takeaway contracts. Those are at the lower end of our disposal fee rates. So as those agreements and those contracts grow volumetrically, it tends to pull down the revenue per barrel somewhat. But as we do -- actually as we engage more recycle reuse those margins or those fees tend to be lower than our disposal fees. So you will see the revenue per barrel come down. But I hope you noticed also our OpEx is coming down and that is helping us sustain our EBITDA per barrel targets.

That's helpful. I appreciate it. Just last one for me. You touched on expectations for inventory to reverse seasonally. Any kind of context you can give in terms of what that release should look like? Obviously it's important as you look at your objectives of paying down the 23s?

Sure. I can take that one. So the way I typically look at it is year-to-year if you look at our working capital balances on our facility last March 31, 2021. That balance was $4 million. If you forward that to this March, I think what you'll see is similar inventory levels but at higher prices. So you may see a little more outstanding on our ABL facility at March 31 of this year compared to March 31 of last year. But relatively speaking from a volume perspective we should be in the same place.

Okay. It's a helpful context. I'll jump back in a queue. Thank you very much.

Thank you.

Your next question is coming from TJ Schultz. Your line is live.

Great. Doug, just to clarify some of the numbers on the wells, I think you said you had 22 total deep wells. Are those within State Line SRA, or is that expected to grow? I'm just trying to understand if you all may need to voluntarily reduce more than that, 50,000 barrels a day from the six impacted wells even if you do have offsets from some of the advantages of the connectivity in our system.

The interesting thing is TJ is New Mexico has taken a different approach a more aggressive approach than Texas has from the regulatory side. The OCD stepped in noticed those operators of deep wells within the SRA up to 10 miles from the center of the -- epicenter of the 4.0 earthquake which was very near our Paduca 6 well. And they send us all nice letters, asking very nicely to totally reduce or if things don't get better they would then create orders to reduce. Of course all the stakeholders in that area multiple producers, multiple commercial, disposal operators, we have had ongoing numerous stakeholder working meetings. NGL put a bottomhole pressure gauge and temperature gauge in our Paduca 6 well. On July 28 we shut that well in, because it was so near the deep earthquake. And that has remained shut in. The positive of that is we are able to minute-by-minute it's a reported data every minute track the bottom hole pressures of the reservoir in the deep slurry and Devonian depths. And the groups -- the working group has been working together to raise and lower injected volumes in that area certainly within the six-mile area which is we would expect to be most impactful. And we are seeing correlation of the amount of injection. And we're really nailing down some very strong technical basis and correlations of what has led to the seismicity. That said, there have been no 2.5 or greater earthquakes in almost six months. And most of the rumblings that are going out there in that area now are sub 2.0 which are very small in the scheme of things. So we feel very comfortable that the seismicity has been managed. And managed -- it was already being managed by the stakeholders…

Okay. No, that's helpful. And then if we think about potential new water agreements with producers for you all. Is there anything similar in size or scale to Poker Lake that's on the horizon as we think about the next year or so?

As I mentioned on the last call last quarter, there was a very large dedication that is -- that has been a perspective, that is in process. And I would say stay tuned for an update on that very soon. It is the largest dedication that we have done, not only in the Delaware, but anywhere in our NGL water history.

Okay, great. Thank you.

Your next question is coming from Jim Cypher [ph]. Your line is live.

Yes. Hi. Thanks for taking the question. I'm just trying to understand the magnitude of the XRI agreement, when that rolls out and is underway, what percentage of Permian Basin water -- recycled water is that going to comprise? Is that going to be the majority of it, or how should we think about the size relative to what you're doing in total?

That's a tough question to answer from what is the actual amount of water recycled on a daily basis in Northern Delaware. That's a tough one to nail down. I will say previously we have been in reuse, recycle, where we've seen volumes south -- on average south of 100,000 barrels a day. Our goal this year is to be in excess of 100,000 barrels a day and we feel pretty good about maybe even 150,000 barrels a day, but we have a goal that is double of that. And we believe the XRI collaboration will get us there. And as a percentage, it's tough to -- like I said, it's tough to say because you have the producers some of the producers that have their own systems and on and those numbers aren't reported. We have estimates of maybe what others in our line of midstream water business do. Of course, then we know what ours are. So I can just say that, as a percentage basis for NGL, we more than double in this next fiscal year. And with expectations to continue to grow and what we think to be most likely multiples.

Okay. Great. That's helpful. It gives me an idea. And then a separate topic, on those 2023 notes, I know you bought buyback $20 million during the quarter, what are the governors on your ability to buyback more notes and continue to chip away at that balance? Is it simply just a function of free cash flow and price, or are there some other drivers out there that we should be thinking about?

Yeah. Really just free cash flow and price at this point. We are not limited on how much of the 2023 tranche we can repurchase. And so, obviously we would look to repurchase or pay off that entire tranche by maturity. We are limited on the 25 and 26. I believe the original basket was $200 million. I think we've used about $50 million of that to date.

Okay. Great. And then just one more back on the XRI. I was going to ask. Is there any cost to you guys for using XRI's recycling assets?

There is no cost -- it is definitely a collaborative and synergistic arrangement. And I think we -- if you may have seen in our press release, the press release, we still maintain our ability to separately recycle or sell produce water for reuse and they have the same ability to continue to do things on their own. But the collaboration does not come at a cost to either party when we are doing those projects.

Okay. Great. Thanks very much.

Your next question is coming from Patrick Fitzgerald. Your line is live.

Hi. Thanks for taking all the questions. Wondering on the Water segment, the margins were a little weaker and you kind of -- I wasn't quite sure on the explanation for that. But if you could -- are your customers doing anything different like maybe recycling more water themselves or any behaviors that have changed? And going forward, when you gave your guidance, last quarter you kind of said that the margins would be flat and just volume would grow. So going forward, do you expect the margins kind of at fiscal second quarter level, or is this kind of the new run rate?

Yeah. So the customers have not changed. So there's no material change in that aspect. If you dig into the to the Q I think you'll see that our oil cut was down a bit. That certainly has effect on revenue per barrel from an oil-cut basis. And our austerity of turning the corner out of the oil price collapse, we dialed back to a degree on a little bit of our chemical spend also our third-party spend even internally -- internal spend on really clean-outs of our systems. We took the opportunity to go back to normal with that. I will say, one of the hangovers is as, when you cut back on chemicals, and then thereby you start buildup of different things in your tanks tank bottoms, et cetera, our oil recovery systems become less efficient. And I really do believe that the reduction of oil cut in that previous quarter really did impact our revenue per barrel, and it was affected by a little bit of a hangover from the prior 6 months to 12 months. We've since engaged and spent a lot of time getting of our systems cleaned-out. We process that waste, and we actually recover oil from it in our process. So we're actually seeing higher oil cuts throughout our standard processing of water, but we're also selling additional oil at these high prices in this quarter, with those process materials. We – so to answer the – probably the most important question you're asking is does the Q2 revenue per barrel is that the norm, or is the Q3 due to the – really due to the increase of – it's a pretty large increase of our large contracts that are at the lower fees as I mentioned – that has some impact on our average. And so I – the answer to answer you Patrick is somewhere between Q2 and Q3 is where we land. And the volumes continue to grow. And then you also, then have to add back and say we're at $88, $90 oil that will have a positive impact on that average. What we look at and work very hard to maintain is that EBITDA per barrel number. And as I mentioned, OpEx coming down, we were able to achieve our tank clean-outs and increased chemicals, while still dropping our OpEx per barrel by $0.01. So that's a long-winded answer about it, but there are many variables that go into it. I think with the tailwind, we have here with oil price is going to continue to be the positive on revenue per barrel. Meanwhile, our growth of our long-term very large contracts that come with the volumetric growth, those lower disposal fees on those tend to bring it down not by pennies, but by fractions of the cent.

Awesome. No that's – I really appreciate all the detail there. Now in the Liquid Logistics business, typically the third quarter is the best, but then you highlighted it was not very – or warmer than normal in the fourth – in the fiscal third quarter. And that the cold weather that we've seen in the fiscal fourth quarter is helping you guys. I mean, is it a situation where you could see EBITDA kind of being closer to flat, or is it going to have that typical seasonal drop in the fourth quarter?

I think you'll – Patrick, I think you'll see a similar trend to what you've seen before. I would again now, I think, if you look at last year's third fiscal quarter compared to this year's third fiscal quarter we actually – I think last year EBITDA for this segment was a bit lower than what we've reported this quarter. The weakness in propane has been made up for by strength in our propane and refined products margins. So going into the fourth quarter again we typically forecast on normal winter weather. So, we would expect to see similar results to what we've seen in the past. I would say, yes just that we typically forecast normal weather and I would look to historical averages for your volumes going forward.

Okay. And then I think somebody already asked about working capital, but it's been a massive headwind obviously. And if you get back to kind of flat volumes, inventory volumes and prices stay here? I mean any sense of how big of an unwind that would be in the fourth quarter?

Yes it would be north -- it should be north of $100 million.

Okay. At current price levels?

At current price levels yes.

Okay. And then I mean that's still...

I'm talking about from the ABL facility. So the total unwind I guess is going to be closer to $150 million you should see about a $100 million reduction on the ABL facility. The remainder would be a cause of just the increase in commodity prices between last fiscal year and this fiscal year.

Got you. Okay. Thank you very much.

Sure.

Your next question is coming from Philipp Duffner. Your line is live.

Hey guys. Just on a topic of working capital. So your accounts receivables also increased significantly this quarter. Could you provide some context on that? And whether we expect a reversal in that next quarter?

Yes. Yes. You will see -- you should see -- you should see a reversal of that. Some of that increase is going to be as we come into the winter season, you're going to have higher receivables in the propane segment. You're also going to see higher receivables most likely in the butane segment as they're kind of ending their blending season. Commodity prices being higher is also going to cause an increase in AR. You should see a corresponding increase in AP offset by basically your margin on your commodities. But it would be typical to see an increase in AR this quarter.

Got it. Thank you. And could you provide some more context on what caused the increase in the CapEx guidance for this year? And is this like a one-off or could this be a repeat event next year?

Yes. I don't think we've guided softly the CapEx for next year on our last earnings call. We haven't provided an update. We'll update the market on our next earnings call once we get through fiscal 2023 budget and have a chance to detail out all of that information. But I would say the increase to CapEx this quarter or to our guidance was primarily related to some unexpected repairs we had that we would expect to be reimbursed in part from insurance proceeds which is why we've provided that guidance this quarter. Other than that, I'm not sure Mike if there's anything else impacting that.

No, the go-forward is, CapEx is going to drop each year for the next several years. The majority of the vast majority of the systems built out. And we've built I think nearly everything required under our contracts.

Got it. Thank you. And one last question. Grand Mesa, we saw the volumes increase quarter-over-quarter, I think the number of securities we've been reporting pointed to actually like slightly weaker production during the quarter. So, is it the case that other producers are sending you more volumes and that caused the increase, or are you just not impacted by the Civitas or were you not impacted by the Civitas declined this quarter because of your exposure within their larger footprint?

Yes. No, you're correct. We moved more spot barrels on Grand Mesa this quarter than we did last quarter.

Got it. Thank you. That’s it.

Your next question is coming from Fernando [indiscernible]. Your line is live.

Good afternoon. Thank you for taking my question. One quick question because one was already answered. I know that the partnership had the saltwater deposit inventory permits, if volumes were to increase, are those permits still viable, or are they no longer good? And second on the basis points for the skim oil. Is that still the same as the 13 basis points as in the past?

Doug do you want to talk about your permits?

Yes. We have -- and our folks on the Delaware Basin because that's the material basin. We have approximately 60 additional inventory permits. We continue to ladder our applications and permits. Some of those are extendable they typically have a three-year life. And we continue to ladder that inventory to keep a constant inventory. We have quite a bit of laddering that we began this month of the 23 explorations. And we typically ladder them out within a period a little over a year of exploration. And the very important thing is our permits are -- those are anywhere from 30,000 to 40,000 barrel per day capacity approved permits with a half psi per foot injection pressure maximum. The new ones being issued of the newer vintages for other brand new -- completely new applications, a lot of them are receiving 10,000 barrel per day maximum and a quarter psi per foot maximum pressure. Hours are not impacted by that as we ladder those out and that's very important to note. So, someone else getting 10,000 barrel per day, it's costing them per barrel to drill and complete that well with the amount of capacity related to it three to four times what our inventory will take. So we have them always hot and ready to go and ready to drill wells when we need to. And keep in mind those are also spread out across the basin and that's very important as well as we see SRAs pop up and things happen.

And just to…

Yes. Linda if you could answer that skim question you may be better to answer that than I.

Sure. I was going to say Fernando the basis points for skim oil this quarter was 14.5 basis points relative to the 13 you referenced.

Okay. And just I guess the main question that everybody is heading back of their mind. I know that lately for the past two years creditors have pretty much financed the business versus internal cash flow. And I know cash flow is the main driver. But what other levers can be used to improve the balance sheet going forward? Because with the debt being generating interest and with the preferred accumulating dividends. Is there any other immediate lever that can be used to improve the balance sheet going forward in the next three, four quarters?

Yes. So I think you're referencing asset sales. I think Mike had mentioned on the last call, we've been scrubbing the asset portfolio for what we would consider to be idle or underutilized assets and are forecasting $20 million this year and $20 million in sales next year which isn't a ton admittedly but it's very low to no EBITDA impact in every dollar. Quite frankly that comes in a dollar-to-dollar we can pay down debt with. So we've been working pretty hard to those numbers. As Mike mentioned we've got a little way to go this year but those assets have been identified and are currently in process of being sold next year. We've actually identified a bit more than the $20 million. We're handicapping it though and plan to bring in about $20 million in additional asset sales. Something larger, which is probably what you're actually asking about we have historically said, we look at our assets all the time to see if there's value that can be derived from them. There's nothing that's been identified at this point, nothing that we have a formal process running on. If something does pop up we obviously would alert the market as needed but nothing that we've identified at this point.

Very well. No more questions. Thank you.

Your next question is coming from Craig Stein [ph]. Your line is live.

All my questions have been answered. Thanks.

Okay. Your last question is coming from John Horton [ph]. Your line is live.

Thank you. Good afternoon and thank you for the opportunity. Earlier you mentioned the investor pipeline and the pending connection at Marysville. Could you provide a little bit more color to the timing on that and the potential for impact?

Yes. We are currently working through the permitting process with the state of Michigan for that connection. We expect the permits to come in 2Q or possibly 3Q depending on any delays in that state process.

And then following the permitting the time for -- is it a matter of just a simple connect or having to lay an additional infrastructure capital investment?

It's a very modest investment. The line itself is existing line is 225 miles. We have roughly a mile of additional pipe to lay, to make that final connection. And then we have to install a couple of pumps. So, it's a pretty simple process once we get the permit I think we achieved quickly.

No right-of-way considerations for that last mile?

We have that in hand.

Very good. And as far as the Line 5 controversy within the State of Michigan, you alluded to the potential last quarter, is there anything further that has become a clarification? I guess I was surprised when you said it may be Q2 or Q3 upcoming fiscal year I believe for getting permitting done. So given that the government was so hot and heavy to move off Line 5, I would have thought perhaps maybe a little more aggressive time table on the permitting.

Sure. We're I'm really not in a position to comment on Line 5 but I will say that we are working our permitting process as fast as we possibly can.

I think what you're saying is very logical and we'd like you to run for office in Michigan.

I read between the lines and what you're saying because I hear what they say and they sell them to do with anything they say. But yes, so it was a very modest investment. I believe it was about $18.2 million and I don't want to make a bigger deal out of it than it is but it's – it seems like it has a great opportunity. Given the $18.2 million investment, has it met your expectations in this past year?

Yes. We're very happy with the execution and the performance so far. The last mile connection that we've talked about is the key piece to get everything running in and the earlier we get that done this year the better.

Yes the sales volume out of that asset which would be at both Wheeler and at up at Kalkaska exceeded our expectations.

Okay. And given the timing of the permitting, will you miss this upcoming season as far as the opportunities that would come with that line being in place?

No.

Okay.

We have – as you know the Michigan market has a very high winter to summer ratio market. And we do have additional sources of supply that we'll use to augment until the pipeline is fully operational.

Okay. That's it for that line. I have a second one if I may. This is for Mike. Mike, thank you. Nobody knows the struggles of a business like this like you do. But just noting the tone of the call last quarter, it almost seemed giddy and this quarter seems a little somber. And after hours activity would say somber minus. Is there anything you can share that might reflect the change in that tonality of the presentation?

Well, I could start dancing for you that would help but you can't see me.

I can only imagine.

I mean if the somber is we're just disappointed that we didn't do $160 million and we did $147 million. But in the fixed scheme of things it doesn't change the outcome of what we expected last quarter for the next 2.5 years. So no it's just a little frustrating. You get three extremely warm months in a row. We're not seeing perhaps in the DJ any real pickup in activity even though we're at $90 crude. But those are – again, those are smaller EBITDA impacts. The water is doing fantastic. We're 2 million barrels a day now for two weeks, 100,000 barrels of oil a month. Over $30 million a month in EBITDA is as good or better than what we expected.

I was excited to see the announcement about your partnership. It makes total sense with your capital structure and needs for operating and it will enhance your overall margin even that may reduce the total revenue per barrel. But as an analyst recommendation and as an investor myself it's – what should we be excited about still? And what should we make recommendations on here? I mean it's still the same solid path. Did that path shift? Did it shift out further with these results, or do you feel it's just going to be a matter of coming back online this next quarter?

I haven't shifted at all. It's $500 million of free cash flow for fiscal 2022 and 2023 and we still expect it will get -- pay off the 2023 out of our free cash flow from operations plus some of these asset sales. So no nothing's changed and we're -- it's really just the patience game. And we all get whipsawed with these crude prices. But in the big picture where they're at 75 or 90 it's -- I'm not sure that how much that really affects the producers activity it's all very positive. And we are watching all these upstream customers of ours and others that are kind of starting to announce their CapEx and their growth et cetera. And I think we're positive. It's been more positive than we had anticipated. I think we all went into this season thinking okay are they going to go sideways or 5% growth. But I think that these prices are -- we're going to see something with a double-digit growth, which we're not -- we haven't factored that into our numbers but...

Yes. Thank for clarifying that. Because that's one thing that I think is the gap that was missing today that that's not had effect to be factored in yet. So that was very good. That's all that I had.

Okay. Thank you.

We have no further questions from the lines at this time. I would now like to turn the floor back to Linda Bridges for closing remarks.

All right. Well we just want to thank you again for joining our third quarter earnings call and we will see you again with the fourth quarter call in the spring. Thank you.

Thank you, ladies and gentlemen. This concludes today's event. You may disconnect at this time and have a wonderful day. Thank you for your participation.