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 questions 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, 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 31st, 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 and 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. First, I'd like to provide context on the quarter and how that transitions to the next couple of fiscal years 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 $83 million EBITDA. Crude Logistics EBITDA was expected to average about $35 million per quarter or $140 million annually. We achieved $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. In our Water Solutions business, December EBITDA exceeded $30 million for the first time. For the last two weeks, we have averaged over 2 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 this quarter. We expect to enter fiscal 2023 at that $32 million level. Any growth in fiscal 2023 will provide upside to the water segment. With respect to skim oil, we recovered about 82,000 barrels per month in the third quarter at an average realized price of $72.50, which is about $78 before transportation costs. In January, we recovered 100,000 barrels, which we do expect to continue each month going forward. The current crude oil price is about $90 or approximately $12 a barrel above the third quarter pre-transportation price. The current water volumes, monthly EBITDA, and skim oil recovered are all at new highs. We have slightly reduced our fiscal 2023 EBITDA range to 550-560, which is in line with the average analyst expectations. We are augmenting our free cash flow with asset sales of excess real estate and unused assets. We have closed on $12 million of sales thus far in fiscal 2022, and we have another $8 million in process to close before year-end. We've identified another $20 million to sell in fiscal 2023. Our focus continues to be on repaying all of the 2023 unsecured notes prior to maturity, which we expect to achieve. With that, I'd like to introduce our EVP of Water Solutions, Doug White, and ask him to discuss the current status of seismicity in the Delaware and Midland basins, which there's been a lot of, I think, discussion about, as well as the thinking behind the collaboration with XRI. With that, I'll turn it over to you, Doug. Thanks, Mike. Seismicity, I'm sure everyone's heard quite a few different aspects of this, or induced seismicity related to injection, from different parties. Some of them are accurate, some are not. I would like to educate you a little bit on the facts of NGL's assets in regard to seismicity. Seismic review area, SRA, that's an acronym that's out there. Both the Railroad Commission of Texas and the OCD in New Mexico, they have utilized that term to identify areas of which there's increased or, concerning seismicity, in different areas. There are three main areas, the Midland Basin, around the city of Midland, Odessa, and then also at Stanton. There's the Delaware in Texas, which is the Culberson Reeves SRA, sometimes called the NCR, North Culberson Reeves. We have two of them, one small, very small in Lea County, and then one at the state line in Eddy and Lea County, New Mexico. In the Midland Basin, the SRA there has a neutral effect on our water business. We have one deep well there that has not taken water for about four years. It's an idled asset. We will P&A that well, plug and abandon it, this quarter that we're in today in this fiscal year for very low cost to us. It's just normal course of business. That will take us completely out of the Midland Odessa SRA and won't have any effect on our business. There's not a lot of pickup at this time of additional business in that area on our shallow wells, due to the fact that reductions have been voluntary in that area to date, many of them, and there's still decent amount of disposal capacity available, a lot of producer capacity. We go to the Delaware, Texas, Northern Delaware, Culberson Reeves. No NGL wells are within the Culberson Reeves SRA. As many of you know, that there were hundreds of thousands of barrels of potential injection capacity being limited there. Once again, no NGL wells with any capacity limitations there. We've executed a new medium-term contract with an affected deep well injector, which is a producer. We are thereby being outside of the issues in that area, picking positive amounts of business there. We're glad to help our customers, of course. We get to the New Mexico, Delaware. We have six wells affected by the state line SRA. We've taken voluntary reductions of about approximately 50,000 barrels per day, temporarily across all six wells. That's a total of 50,000 across the wells. We are seeing greatly increased demand for our services because we have the ability, through our large pipeline network, to take water where others are limited. I think there are 12-14 other total wells in the area that have been limited, all voluntarily, due to the state line SRA in New Mexico. I think it's important to point out, you know, NGL has 22 deep wells in the northern Delaware, and we have 90 shallow, active shallow wells in the Northern Delaware. The deep wells have been most likely tied to the seismicity, and we think that will continue to be the case. You know, over 83% of our wells are shallow wells. I think that bodes well for our future on the side. Anything else you'd like me to mention, Mike? Yeah. Doug, maybe just a little bit about connectivity, how, you know, our wells, even if we lose some capacity, and maybe we're gonna lose, you know, pick a number, 50,000 barrels out of 3.7 million, we don't lose any water. You're basically gaining. Correct. Yeah. You know, our strategy over the last five years as we grew the Delaware business, we have, I guess we always mention, 24 and 30-inch pipelines are large transportation lines. We have lines at 24-inch, the LEX 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 into Andrews County, Texas. 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. We do not see the Railroad Commission of Texas letting any of them be permitted or drilled due to the fact that that closeness to seismicity on deep wells. We have the ability to move water throughout our system, both east to west, north to south, you know, throughout New Mexico, throughout Texas, you know, both Loving, Reeves and Andrews County, Texas. We have a 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. 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 SRAs. Great. XRI. XRI. As we've mentioned, you know, 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 determine that, with our best-in-class abilities on the produced water transport and disposal business, we decided that XRI was a very good partner to collaborate with on utilizing their recycling services. The synergies with XRI enable us to utilize our expansive 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. Then XRI has the equipment, the headcount 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. Rather than reinvent the wheel and, you know, go spend the capital, hire the people, manage another business line that's not our core business, you know, we realized, you know, the collaboration with XRI is the right way to go. They get to focus on their core business. It enables us to sell large amounts of our produced water, and we still capture sizable margins out of that value chain. 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, selling lots of water off our system, and without any additional capital expense. Great. 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. Let's jump from the Texas to New Mexico area to the Wolverine State, where NGL is excited to share some of our investments in the state of Michigan and what it's gonna 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 rail car from neighboring states, as well as from Canada. Much of the demand in Michigan is located in Central and Northern Michigan, which consequently have colder weather and more HDDs. With that 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 from Michigan's own oil and gas wells. We partnered 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 to 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. The customers, the feedback's been very positive so far. We've had a number of customers that love the convenience of buying product closer to their end destinations. You know, 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 is a brand new pipe-in truck-out facility with 480,000 gallons of storage and two state-of-the-art truck bays capable of loading trucks at 3,600 gallons per minute, which means that each truck bay can load a truck in 20 minutes-30 minutes. The Wheeler facility started loading trucks on February 1st, and the early feedback is fantastic from some of Michigan's top propane retailers, who love the lack of lines and efficient turns out of the brand new facility. Third, and certainly not least, NGL purchased an existing 225-mi pipeline that traverses the Wolverine state from southeast to northwest, connecting Kalkaska, Michigan, the northwestern part of the state, to the existing propane supply and large storage infrastructure in Marysville, Michigan. This pipeline, which we have named the Ambassador Pipeline, provides Central and Northern Michigan propane customers with a very safe, efficient, and reliable source of propane. The Ambassador line is an 8-inch line and has been repurposed for bi-directional propane service. Once the final connections are made to the Marysville underground storage caverns, Michigan propane customers will have access to the region's over 8 million barrels of underground storage, various pipeline connections, and a faster, cheaper method of transportation to distant parts of the state. Importantly, the Ambassador Pipeline will help reduce emissions from trucks and rail cars and will help improve the condition and safety of Michigan's roads by eliminating the needs for hundreds of thousands of long-distance truck miles. Overall, we could not be more excited about the newest terminal and the opportunity to grow our business in the state of Michigan. We look forward to providing additional details later this year. Great. Thanks, Jeff. Hand it back to you, Linda. Okay. 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% when compared to the third quarter of last year. We continue to see growth in 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 2 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 flow back 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 83,000 barrels per day on Grand Mesa Pipeline, compared to 80,000 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 positions and inventory valuations. Similar to the effect we saw in our first and second quarter, we expect to recoup approximately $5 million of this negative impact in the fourth quarter through gains associated with deferred profits that were embedded in our inventory on December 31st. As mentioned on previous calls, results for the remainder of the fiscal year and into fiscal 2023 will be dependent on crude oil production in the DJ Basin. Our Liquids segment reported adjusted EBITDA of $48 million, which was primarily driven by positive results in our butane business as tighter supply markets driven by increases in demand for exports have benefited product margins, as well as our refined products and biodiesel businesses where extended refinery downtimes in certain markets and favorable location differentials have increased anticipated margins as well. Our propane business battled some headwinds in the third quarter as most of the U.S. experienced warmer than normal weather during the start of the winter season. However, recent cold weather has been positive for demand and as always, fourth quarter results will be driven by volume. In total, adjusted EBITDA for the quarter was $147.7 million, which is a bit shy, as Mike mentioned, of where we would have hoped to have been for the quarter. As such, we're adjusting our adjusted EBITDA guidance to a range of $550 million-$560 million. Capital expenditures for the quarter totaled $26.5 million and totaled $96 million year to date. Due to certain unexpected repairs, we are updating our capital spend guidance for fiscal 2022 from $115 million to $125 million-$130 million, which is net of certain anticipated insurance reimbursements. Quickly turning to the balance sheet, working capital balances have remained high due to elevated commodity prices and inventory builds. As is typical for our seasonal businesses, we expect to see inventory liquidated over the next couple of months, leading to lower working capital balances going into the spring. The partnership repurchased $20 million of its senior notes due 2023 during the quarter, bringing the total tranche size down to under $500 million. As previously stated, it remains our priority to decrease the outstanding balance of these notes, which we will continue to do so going forward. Lastly, on our last call, Mike provided some thoughts regarding next year's guidance. We're currently working through our budgeting process and will update the market on our next earnings call. However, at this time our view of next year remains unchanged. Flat performance in the Crude Oil Logistics segment, a small increase in Liquids Logistics related to Ambassador Pipeline, and a 10% increase in our Water Solutions segment. With that, we're happy to open the line up for questions. Certainly. Ladies and gentlemen, the floor is open for questions. If you have any questions or comments, please press star one on your phone now. We ask that while posing your question, you please pick up your handset and listen to your speakerphone to provide optimal sound quality. Once again, if you have any questions, please press star one on your phone now. Please hold while we poll for questions. Your first question is coming from Derrick Whitfield. Your line is live. Good afternoon. Thanks for addressing the induced seismicity issues head on. I guess, you know, 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 context to sort of how much, you know, incremental water you could 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-1.8 million per day, I would say that incremental increase is somewhere around $0.05-$0.07. Got it. If I may, I'll expand. That additional producer contract, the medium-term one I mentioned, that is, has very firm obligations for delivery of water, which really lend to some strength, that we didn't expect. You know, prior to the seismic activity. Got it. I guess sticking on the water business. You know, one thing I noticed and thank you guys for disclosing the recycled water volumes, but it, you know, I did notice that recycled water appears to have dropped pretty substantially in the December quarter. Sort of any explanation on that? Or is that just more just a function of completion schedules? 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. We really saw things slow down, which we were a little surprised at. Then we got into the November period, I'm sorry, the December period, and it was an unusually busy month. You know, accordingly, the recycle reuse volumes went down. We really saw that increase in late December during the holidays, which is very unusual. Then certainly in this quarter, this physical fourth quarter, we've seen it really outpace our expectations. Got it. I guess as you look through kind of the revenue per barrel of water touched appears to kind of drop 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 kind of decent way to think about it for someone who's looking at it on a public sub? Yeah, I think more accurately, you know, we do have 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. As those agreements and those contracts grow volumetrically, you know, it tends to pull down the revenue per barrel somewhat. Actually, as we engage more recycled reuse, those margins or those fees tend to be lower than our disposal fees. You will see the revenue per barrel come down. I hope you noticed also our OpEx is coming down and that is helping us sustain our EBITDA per barrel targets. Oh, that's helpful. I appreciate it. Just last one for me. You know, you touched on kind of expectations for inventory to reverse seasonally. Any kind of context you can give, in terms of sort of what that release should look like? Obviously that's kind of important as you sort of look at your objectives of paying down the 2023s. Sure, I can take that one. The way I typically look at it is, you know, year to year, if you look at our working capital balances on our facilities, last March 31, so March 31 of 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. 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. Yeah, that's helpful context. I'll jump back in the 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 Dateline SRA or is that SRA 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 your system. The interesting thing is, TJ, is New Mexico has taken a different approach, a more aggressive approach than Texas has, from a regulatory side. The OCD stepped in, noticed those operators of deep wells within the SRA out to 10 mi from the center of the epicenter of the 4.0 earthquake, which was very near our Paducah six well. They send us all nice letters asking very nicely to potentially reduce, or, you know, 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 bottom hole pressure gauge and temperature gauge in our Paducah six well. July 28th, 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 reported data every minute, track the bottom hole pressures of the reservoir in the deep Silurian-Devonian depths and the working group has been working together to raise and lower injection volumes in that area, certainly within the six-mile area, which we would expect to be most impactful. 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. 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. We feel very comfortable that the seismicity has been managed for. It was already being managed by the stakeholders, and then OCD sent the letters out once they ascertained how they wanted to manage SRAs. Everyone now has voluntarily reduced, but it is in regard to the OCD's wishes. We feel really good about that. We feel very confident that that will continue to reduce magnitude and frequency of events in the state line area, and it sure seems corralled at this point. Of course, it's the subsurface of the earth and 16,000 ft-19,000 ft deep and, you know, more things could happen, but we feel good about that. On the other side of the state line in the Culberson-Reeves area, we have a little bit of concern about that area. From your standpoint of your question, will that SRA potentially grow? We think there's possibility of that because Texas has taken a much more metered approach than they have in Midland. I would say it's mostly because really the populace is not in existence in Culberson-Reeves. Nonetheless, we are working directly with the Railroad Commission on the Culberson-Reeves area, along with the other stakeholders out there as well. To specifically talk about the state line area, we feel very good about how it has been handled, both by the stakeholders in industry and also by the regulators. Okay. No, that's helpful. If we think about potential new water agreements with producers, for you all, is there anything similar in size or scope 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 has been prospective. 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 James Spicer. Your line is live. Yeah. Hi. Thanks for taking the question. I'm just trying to understand the magnitude of the XRI agreement, when that, you know, rolls out and is underway. What percentage of Permian Basin water, recycled water, is that gonna 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. 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, you know, we have been in reuse recycle where we've seen volumes, you know, south of 100,000 barrels a day on average. Our goal this year is to be in excess of 100,000 barrels a day. We feel pretty good about, you know, maybe even 150,000 barrels a day. We have a goal that is double of that. We believe the XRI collaboration will get us there. 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 those numbers aren't reported. We have estimates of maybe what others in our line of midstream water business do. Of course, we know what ours are. I can just say that as a percentage basis for NGL, we're more than doubled in this next fiscal year and with expectations to continue to grow in what we think to be most likely multiples. Okay, great. That's helpful. Gives me an idea. In a separate topic, on those 2023 notes, I know you bought back $20 million during the quarter. What are the governors on your ability to buy back 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 a 2023 tranche we can repurchase. You know, obviously we would look to repurchase or pay off that entire tranche by maturity. We are limited on the 2025s and 2026s. I believe the original basket was $200 million. I think we've used about $50 million of that to date. Okay, great. Just one more back on the XRI. I was gonna ask you, is there any cost to you guys for using XRI's recycling assets? There is no cost. It is a definitely collaborative and synergistic arrangement. I think if you may have seen in our press release, the joint press release, we still maintain our ability to separately recycle or sell produced water for reuse, and they have the same ability to continue to do things on their own. The collaboration does not come at a cost to either party when we are married up doing those projects. Okay, great. Thanks very much. Your next question is coming from Patrick Fitzgerald. Your line is live. All right. Thanks for taking all the questions. Wondering on the water segment, you know, the margins were a little weaker, and I wasn't quite sure on the explanation for that. If you could, you know, are your customers doing anything different, like maybe recycling more water themselves or any behaviors that have changed? Going forward, you know, when you gave your guidance last quarter, you kind of said that the margins would be flat and just volume would grow. Going forward, do you expect the margins kind of at fiscal second quarter level, or is this kind of the new run rate? The customers have not changed. There's no material change in that aspect. If you dig into 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. We, you know, in 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 internal spend on really clean outs of our systems. We took the opportunity to, you know, go back to normal with that. I will say one of the hangovers is when you cut back on chemicals and then thereby you start buildup of different things in your tanks, tank bottoms, et cetera. Due to the increase of, you know, 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. The answer to you, Patrick, is somewhere between Q2 and Q3 where we land. The volumes continue to grow. You also have to add back and say we're at, you know, $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. As I mentioned, OpEx coming down, we were able to achieve our tank clean outs and increase chemicals, while still dropping our OpEx per barrel by $0.01. 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 gonna 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 a cent. Awesome. No, that's. I really appreciate all the detail there. Now, in the Liquids Logistics business, typically the third quarter is the best. But then you highlighted it was warmer than normal 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, you know, EBITDA kind of being closer to flat, or is it gonna have that typical seasonal drop in the fourth quarter? I think you'll see a similar trend to what you've seen before, Patrick. I would again note, I think, you know, if you look at last year's third fiscal quarter compared to this year's third fiscal quarter, 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. Going into the fourth quarter, you know, again, we typically forecast on normal winter weather. We would expect to see similar results to what we've seen in the past. I would say, yeah, just that we typically forecast normal weather, and I would look to historical averages for your volumes going forward. Okay. You know, I think somebody already asked about working capital, but it's been a massive headwind, obviously. 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? It should be north of $100 million. Okay. At current price levels? At current price levels, yep. I mean, that's. I'm talking about from the ABL facility. The total unwind, my guess, is gonna be closer to $150 million. You should see about a $100 million reduction on the ABL facility. The remainder would be because of just the increase in commodity prices between last fiscal year and this fiscal year. Gotcha. Okay. Thank you very much. Sure. Your next question is coming from Philip Jessner. Your line is live. Hey, guys. Just while we're on the topic of working capital. Your accounts receivables also increased significantly this quarter. Could you provide some context on that and, you know, whether we expect a reversal in that next quarter? You will see a reversal of that. Some of that increase is gonna be as we come into the winter season. You're gonna have higher receivables in the propane segment. You're also gonna see higher receivables, most likely in the butane segment as they're kind of ending their blending season. Commodity prices being higher is also gonna cause an increase in AR. You should see a corresponding increase in the AP, you know, offset by your basically your margin on your commodities. It would be typical to see an increase in AR this quarter. Got it. Thank you. Could you provide some more context on what caused the increase in the CapEx guidance for this year? Is this like a one-off or could this be a repeat event next year? I don't think we—you know, we've guided softly to 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 budgets and have a chance to detail out all of that information. 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, I think the go-forward is CapEx is going to drop each year for the next several years. The majority, the vast majority of the system's built out. We've built, I think nearly everything required under our contracts. Got it. Thank you. One last question on Grand Mesa. You saw, we saw the volumes increase quarter-over-quarter. I think the numbers that Civitas have been reporting pointed to actually like slightly weaker production during the quarter. Is it the case that, you know, other producers are sending you more volumes and, that caused the increase? Or are you just not impacted by the Civitas decline this quarter because of your exposure within their larger footprint? Yeah. 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. Yep. Your next question is coming from Fernando Anzures. Your line is live. Good afternoon. Thank you for taking my question. One quick question, 'cause 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? Yes. Doug, do you wanna talk about your permits? Yes. I'll focus on the Delaware Basin because that's the material basin. We have approximately 60 a dditional inventory permits. We continue to ladder our applications and permits. Some of those are, you know, extendable. They typically have a three-year life, and we continue to ladder those that inventory to keep a constant inventory. We have quite a bit of laddering that we began this month of the 23 expirations. We typically ladder them out within a period a little over a year of expiration. The very important thing is our permits are, those are anywhere from 30,000-40,000 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 0.25 psi per ft maximum pressure. Ours are not impacted by that as we ladder those out. That's very important to note. If you know, someone else gaining 10,000 barrels per day, it's costing them, you know, per barrel, you know, to drill and complete that well with the amount of capacity related to it, you know, 3x-4x what our inventory will take. We have them always hot and ready to go and ready to drill wells when we need to. Keep in mind, those are also spread out across the basin. That's very important as well as we see SRAs pop up and things happen. Just Fernando. Yeah. Linda, if you could answer that skim oil question, you may be better to answer that than I. Sure. I was gonna say, Fernando, the basis points for skim oil this quarter was 14.5 basis points relative to the 13 you referenced. Okay. Just I guess the main question that everybody's had in back of their mind. I know that lately, for the past two years, creditors have pretty much financed the business versus internal cash flow. I know cash flow is the main driver. What other levers can be used to improve the balance sheet going forward? Because, you know, 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? Yeah. I think, you know, 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. Every dollar, quite frankly, that comes in the door is a dollar we can pay down debt with. 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. You know, we have historically said, you know, 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. Nothing that we've identified at this point. Very well. No more questions. Thank you. Uh-huh. Your next question is coming from Craig Stein. Your line is live. All my questions have been answered. Thanks. Thanks, Craig. Your last question is coming from Jon Horvath. Your line is live. Thank you. Good afternoon, and thank you for the opportunity. Earlier you mentioned, Ambassador 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 in Q2 or possibly Q3, depending on any delays in that state process. Following the permitting, the time for it, is it a matter of just a simple connect or having to lay in additional infrastructure capital investment? It is a very modest. Alluded to the potential last quarter. Is there anything further that has become clarification? I guess I was surprised when you said it may be Q2 or Q3 upcoming fiscal year, I believe, for getting permitting done. Given that the governor was so hot and heavy to move off Line 5, I would have thought perhaps maybe a little more aggressive timetable on the permitting. Sure. 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. Okay. 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 in what you're saying because I hear what they say, and they seldom do with anything they say, but yes. 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 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. You know, the last mile connection that we've talked about is the key piece to get everything running, and the earlier we get that done this year, the better. Can't get it into the system. Yeah. The sales volume out of that asset, which would be both Wheeler and then up at Kalkaska, have exceeded our expectations. Okay. 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. No. We have. As you know, the Michigan market is 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. 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. Just noting the tone of the call last quarter, it almost seemed giddy, and this quarter seems a little somber. 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 if that would help, but you can't see me. Yeah, I can only imagine. I mean, if the number is, we're just disappointed that we didn't, you know, do $160 million, and we did $147 million. Yeah. In the big scheme of things, it doesn't change the outcome of what we expected last quarter for the next 2.5 years. No, it's just a little frustrating. Yeah. You know, 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, you know, smaller EBITDA impacts. The water is doing fantastic. We're, you know, 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. Yeah. I was excited to see the announcement about your partnership. It makes total sense with your capital structure and needs for operating, and it'll enhance your overall margin, even if it may reduce the total revenue per barrel. 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 gonna be a matter of coming back online this next quarter? You know, it hasn't shifted at all. It's Yeah. You know, $500 million of free cash flow for fiscal 2022 and 2023, and we still expect it. We'll get, you know, pay off the 2023s out of our free cash flow from operations plus some of these asset sales. No, nothing's changed, and it's really just a patience game. You know, 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 how much that really affects the producers. Yeah. Activity is all very positive. You know, we're 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 gonna go sideways or 5% growth? I think that, you know, these prices are. We're gonna see something with that double-digit growth, which, you know, we haven't factored that into our numbers. Yeah. We're just- Thank you for clarifying that because that's one thing that I think is the gap that was missing today, that that's not yet had effect to be factored in yet. That was very good. Thank you. Yeah. That's all that I have. Okay. Thank you. We have no further questions from the line at this time. I would now like to turn the floor back to Linda Bridges for closing remarks. All right. Well, we just wanna 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.