Good morning, and welcome to today's Conference Call to discuss Crestwood Equity Partners' Q1 2023 financial and operating results. Before we begin the call, listeners are reminded that the company may make certain forward-looking statements as defined in the Securities Exchange Act of 1934 that are based on assumptions and information currently available at the time of today's call. Please refer to the company's latest filings with the SEC for a list of risk factors that may cause actual results to differ. Additionally, certain non-GAAP financial measures such as EBITDA and adjusted EBITDA, distributable cash flow, and free cash flow will be discussed. Reconciliations to the most comparable GAAP financial measures are included in the news release issued this morning. Joining us on today's call with prepared remarks are Founder, Chairman, and Chief Executive Officer, Bob Phillips, President, Robert Halpin, and Executive Vice President and Chief Financial Officer, Johnny Black. Additionally, additional members of the management team are available for the question and answer session with Crestwood's current analysts following the prepared remarks. Today's call is being recorded. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. At this time, I will turn the call over to Bob Phillips. Thank you, operator, and good morning, everyone. Thank you for joining us today to discuss our Q1 2023 results and a little discussion on how we're positioned for the rest of the year. I'll begin by a few opening remarks and then turn it over to Robert for an operational review of the quarter, and then finally to Johnny to review the Q1 financial results in more detail. As I start, as a reminder, when we went into a lot of detail last quarter about our strategic M&A, let me just give you a reminder that we have repositioned the Crestwood portfolio in the last couple of years through strategic M&A, specifically to bulk up our G&P assets in the areas that we operate and extend our long-term producer dedicated inventory in those core oil-weighted resource plays, which are the Williston, Delaware, and Powder River basins. Our producer customer portfolio continues to improve year-over-year through upstream consolidation. We believe oil fundamentals will remain strong throughout the decade and natural gas prices, while lower today due to oversupply, will start to improve beginning in the second half of this year and on into 2024. We expect that to occur due to a pullback in gas-directed rig activity in the short term and LNG demand growth over the long term. We're bullish on gas prices going forward. As producers are becoming more disciplined in their development programs across the industry, we think our G&P portfolio is strategically located on or near some of the best undeveloped acreage in these oil-weighted basins with the lowest break-even cost and the highest potential for production growth. We think this is indicated by the 70 new wells that we connected to Crestwood assets in the Q1. Let me give you a high-level update on our core areas. First, in the Williston. We're seeing the Arrow system slowly catch up to last year's volumes as we expect to connect more than double the new wells in 2023 than we connected last year. Our key producers, Devon, Exxon, Enerplus, are maintaining active new drilling or DUC completion programs, and they have a number of workover rigs coming back in the field, bringing weather-related shut-in production back online. A lot of activity around Arrow. On the Rough Rider system, Chord is spot on on their 2023 development schedule, and we just placed the very important City of Williston three product gathering project in service last week. This is critical infrastructure to support Chord's 2023 and 2024 drilling program in the Western acreage dedicated to us. Let me finally say that our Williston operations team continues to do a great job in reducing operating costs, continuing to find integration synergies, and mitigating winter weather disruptions that we've experienced in the Q4 and the Q1 of this year. On to the Delaware. Now that our Sendero CPJV, Willow Lake, and Orla assets are fully integrated, we continue to see solid performance in producer drilling activity, new well connects, IP rates, system volumes, and third-party processing opportunities. The efficient integration of our Delaware assets has allowed us to maximize available gathering, compression, and processing capacity while minimizing or delaying growth capital to capture new supplies. We have years of great Delaware inventory dedicated to our systems there with access to multiple competitive downstream markets. We're very well positioned for future growth in the Delaware. With in-basin gas production continuing to hit record levels, the market for gas processing capacity has become very tight, which places a significant premium on unutilized processing capacity. Based on our current schedules, we expect to see a significant amount of organic production growth over the next 12-18 months that we think will drive near full utilization of our processing capacity. Good timing on the Sendero and CPJV acquisition last year. Great integration effort by our operations team. Extremely well done build out by our EPM team with new gathering compression, and we're beginning to utilize all of that processing capacity that we bought last year. Now to the Powder River Basin, the future continues to look bright. We've recently had meetings with Continental, and they continue to ramp up their long-term development across all 3 dedicated acreage blocks. We expect to see that continue to grow over the next few years. With excess gathering, compression, and processing capacity on the legacy system that we built for Chesapeake pre-bankruptcy, Crestwood's very well positioned to compete for not only the growth of Continental volumes, but significant new producer supplies that are being developed in the PRB in and around our gathering systems. Quickly to the finance side. Despite all the changes in our portfolio, Crestwood continues to maintain strong distribution coverage and conservative financial metrics compared to our peer group. To keep our balance sheet in check, we divested legacy low growth and non-core G&P assets in the Barnett Marcellus. We sold JV interest in our gas storage assets at Stagecoach and Tres Palacios. We got better than expected prices for those assets and were able to reduce our debt back to 4 times leverage on a pro forma basis. We continue to believe that was a really good trade for Crestwood as we scaled up our G&P portfolio with visible long-term growth in top-tier oil-weighted basins. We expect that to drive continued declines in leverage in 2023 and 2024. We're also continuing to streamline the Crestwood organization through the efficient integration of these new assets, resulting in lower per unit operating costs and, importantly, reduced emissions on the newly acquired assets using Crestwood's leading carbon management plan. Our operations plan this year is now to focus on execution, optimization, and value creation while our capital allocation strategy for 2023 remains focused on utilizing free cash flow after distributions to pay down debt and enhance Crestwood's financial flexibility. A couple of final notes before I hand the call over to Robert. I want to reiterate that Crestwood's off to a great start in 2023. Got volumetric growth on key systems. Our quarterly performance was very much in line with market expectations, and we continued to enhance our financial flexibility, closing the Tres Palacios transaction and getting our leverage ratio back to 4.0 pro forma. After a busy 2022, we're excited to focus on this year's priorities to execute on our 2023 guidance, grow EBITDA and free cash flow by optimizing our asset base and creating long-term value for our unit holders through deleveraging of the balance sheet and paying out our well covered distribution of $276 million a year to common unit holders. We think the combination of all these strengths across the Crestwood organization will continue to represent a compelling total return opportunity for Crestwood investors. We're really pleased with how we're well-positioned for the next several years to grow in all these areas. With that overview, happy to turn the call over to Robert and Johnny to cover the quarter's operational and financial results. Robert? Thank you, Bob. Good morning, everyone. As Bob mentioned, I am very pleased with Crestwood's great start to the year and believe that the outlook for the remainder of the 2023 timeframe looks very strong across all of our assets. Starting in the Williston Basin, we connected 29 wells across the Arrow and Rough Rider systems during the Q1, which was in line with our expectations as producers turned in line wells on schedule and on time. This was a fantastic accomplishment for our operations teams up in North Dakota as well as for our producer customers as this past winter proved to be exceptionally challenging as record snowfall and cold temperatures hit North Dakota and surrounding states. While we did experience some lingering volumetric impacts associated with the weather in the Q1 of this year, we are seeing positive trends across the assets as warmer weather has arrived. Also important, it appears as though our customers have successfully mitigated some of the supply chain and labor challenges that we faced in North Dakota over the past year as D and C schedules year to date have been right in line and planned wells for Q1 and the early part of Q2 have turned in line on or even ahead of schedule. To that end, we continue to anticipate strong producer activity across the rest of the year and remain on track to connect between 115 to 125 new wells by year-end. The majority of these new well connections are coming from key Bakken operators, Devon Energy and Chord Energy. Our growth capital spend in the basin, approximately half of our 2023 budget, is progressing as planned and is focused on the western expansion of the Rough Rider system as well as incremental expansions on the Arrow system. We are excited to bring our Rough Rider expansion into service as we are optimistic about the growth potential of the dedicated acreage and the third-party opportunity set in the western Williston Basin. In the Delaware Basin, we connected 35 wells across our New Mexico and Texas gathering assets during the quarter, which drove natural gas gathering volumes of 495 million cubic feet per day or over a 100% year-over-year growth. This is in part due to our acquisition of Sendero Midstream, but also as a result of substantial volume growth on our legacy Willow Lake system by both public and private operators. With gathering and processing volumes growing by 60% and 50% year-over-year, respectively. For the balance of the year, the development activity for our assets remains strong, and we continue to expect 120 to 130 new well connections through the end of 2023. Finally, our capital spend in the Delaware, approximately 40% of our 2023 budget remains on track and is focused primarily on well connects, system expansions, and compression additions in New Mexico to accommodate continued development from our dedicated customers. Now moving to the Powder River Basin, we connected 6 wells during the Q1, and Crestwood remains on track to connect between 10-20 new wells throughout 2023. Additionally, we are actively pursuing commercial opportunities with large operators in the basin to bring new volumes onto the Jackalope system and capitalize on our unutilized processing capacity at the Bucking Horse facility. Finally, in the storage and logistics segment, our NGL Logistics business, which constitutes about 90% of segment earnings following the Tres Palacios divestiture, had a successful quarter optimizing our NGL storage and transportation assets in response to increased demand from winter weather in the Midwest and East Coast. The 10 million barrels of NGL storage and 13 terminals, the NGL Logistics business is well positioned this year to capitalize on continued commodity price volatility and deliver a solid year of results. Now I'll turn the call over to Johnny to cover our financial results. Thank you, Robert. For the Q1 of 2023, Crestwood generated adjusted EBITDA of $193 million, a year-over-year increase of 11%, driven by our expanded operations in the Williston and Delaware Basins. Additionally, Crestwood delivered approximately $104 million of distributable cash flow. For the Q1 of 2023, Crestwood announced a $0.655 distribution payable on May 15th to unitholders of record as of May 8th, resulting in a quarterly coverage ratio of approximately 1.5 times. Looking at the segment results, in the Gathering and Processing North segment, Q1 2023 EBITDA totaled $133 million, roughly flat to the Q1 of 2022 due to incremental cash flow from a full quarter contribution of the Oasis Midstream assets, offset by lower gas gathering and processing volumes and reduced commodity prices impacting areas percent-of-proceeds revenue contracts. In the Gathering and Processing South segment, Q1 2023 segment EBITDA totaled $41 million, an increase of 50% year-over-year. Segment growth was driven by a combination of the Sendero Midstream and CPJV acquisitions, coupled with volume growth from the legacy Permian assets, offset by the divestitures of the Barnett and Marcellus G&P assets. In the Storage & Logistics segment, EBITDA totaled $33 million for the Q1, a year-over-year increase of 55%, driven by increased product demand from winter weather in the Q1. From a capital investment standpoint, during the Q1, we invested a total of $37 million in growth capital projects, which was primarily related to the continued build-out of the three-product gathering system for Chord Energy and other third parties on the western side of the Rough Rider system. We also invested capital in the Delaware for well connects and to expand our compression capacity to support the substantial volume growth over the next 12 months from our dedicated producers in New Mexico. On a full year basis, Crestwood continues to expect 2023 growth capital investments to be between $135 million and $155 million. Turning to the balance sheet, Crestwood ended the Q1 with $3.3 billion of total debt outstanding, including $474 million drawn on our $1.75 billion revolving credit facility, resulting in a consolidated leverage ratio of 4.2 times. As Bob mentioned, pro forma for the sale of Tres Palacios, which closed a few weeks ago in early April, Crestwood now has a leverage ratio of 4.0 times and available borrowing capacity of approximately $1.2 billion as of the end of the Q1. Lastly, from a strategy standpoint, Crestwood's number one financial focus going forward is maximizing free cash flow generation from our assets and minimizing costs and capital needs across the portfolio. We are forecasting free cash flow to ramp in the second half of this year, and we remain committed to allocating all free cash flow after distributions to debt paydown in 2023, as we are squarely focused on the balance sheet and reducing our debt outstanding. We believe this strategy will create financial flexibility for the company to deliver incremental returns to our unitholders over the long term. With that, operator, we are ready to open the lineup for questions. Thank you. We will now be conducting a question- and- answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for questions. Our first question comes from the line of Tristan Richardson with Scotiabank. Please proceed with your question. Hey, good morning, guys. just curious about maybe the mix of well connects this year in the Bakken, the 115-120? Maybe at a high level, just share kind of where you're seeing most of the activity with East versus West, you know, Rough Rider versus Arrow, et cetera. Yeah. No. Hey, Tristan, this is Johnny. It's a great question. you know, it's a, it's a pretty even split, I would say, of the midpoint, you know, call it 120. It's roughly 60 from Arrow and 60 from Rough Rider. on the Arrow system, really across both of the systems, I'd say roughly 75% of those well connects are three product well connects at both Arrow and Rough Rider, and then roughly 25% are kind of water only well connects on both of those systems. And again, as Robert said on the Arrow system, you know, the activity is underpinned by Devon, and then nice contributions from XTO as well as Enerplus. On the Rough Rider system, that's underpinned by Chord Energy, and then we also have some nice third-party producers connecting wells up there as well. Appreciate it, Johnny. Bob, you talked about the potential to see your existing capacity in the Delaware full over the next 12-18 months. Could you talk a little bit about, you know, lead times you're seeing for early procurement for additional processing infrastructure, you know, maybe where geographically a future plant might go in the Delaware? Or even, you know, just to the extent you're thinking about offloads as we see new third-party capacity in the Delaware coming online in 2023 and 2024. Tristan, let me maybe answer a question that you didn't ask, and then turn it over to Diaco, who runs that business for us. He's got much better handle on who's building new plants, what their time schedule is, and how we're gonna fill the void there and make a good deal of what we think incremental profit by utilizing the available capacity. If you remember when we announced the Sendero deal last year, one of the big attractions to us of that deal was a whole lot of excess processing capacity. We felt like our Orla plant was largely full or was going to be full fairly soon, and we properly evaluated that. That was a good buy and a good strategy for us. The drilling has been better than we thought in the area that we operate. There have been a couple of maybe short-term delays or pushbacks just due to gas price, maybe a little rejiggering about target completions in a lot of these multi-zone wells out there. I'll let Diaco talk about that. On balance, we have been as one of the very few guys that has excess capacity in the area with all this new gas production coming online. We have been targeted by not only producers who ask us before they drill, "Can we get in your plant?" Many of our competitors who we have good relationships with and interconnects with are coming to us and asking for onload or offload opportunities as the case may be. We have not only an active Well Connect Program going on the acreage that's dedicated to us, and we're more than serving all of our current contract producers' needs for processing capacity. We are also actively pursuing onload opportunities with these other operators out there, and we think that'll last a year and a half. As our producers continue to execute on their drilling plans in 2023 and 2024, we'll largely be filling up that capacity with long-term dedicated production, and that's more profitable for us than onload is. Diaco, maybe give us a sense for who's building plants out there, what the timing is, and how we see the overall lay of the land from a processing standpoint. Yeah. Without going into the details of specific counterparties, what we are doing, Bob's right on the strategy. We're working with others for onloads and those onloads could be future offloads for us to mitigate capital and push capital out. That's the structure that we're contemplating with others helping each other out. The production activity, as Bob highlighted, is spot on. We'll fill the void in the interim as people build their plants, those are all public. You can see those. We'll help them out in the interim as our producers ramp up, as they ramp up, the onloads will come off and we may or may not use offloads. We still have a very cheap low capital option at Orla to expand the processing capacity there. We'll probably trigger that first, and then explore a new plant addition down the road when we can underwrite it properly, and that will most likely be in New Mexico. Yeah. The good thing, Tristan, is it gives us a chance to not only fill up the available capacity but push capital out as well. That's really important to us right now as we're trying to be very disciplined in all three basins about capital utilization. Great. Bob, Diaco, thank you, guys. Thank you. Our next question comes from the line of Spiro Dounis with Citi. Please proceed with your question. Hi, this is Chad on for Spiro. I believe you mentioned EBITDA, DCF, and coverage metrics met or exceeded your expectations within the Q1, and the guidance range for the full year appears to factor in, you know, a fairly wide range of scenarios. Just curious, when could you be in a better position to refine the EBITDA guidance range, and what variables go into that? Yeah. Hey, good morning. This is Johnny speaking. You know, it's a good question. I'd say to the extent we would revise or tighten our range, I would say that probably would be done in the August call after our Q2 earnings, where we've got two quarters of actuals and more visibility into the second half of the year. You know, as we think about the outlook for the remainder of this year. By far the biggest factor for us will be the timing and the performance of the well connects to be brought online between Q2 and Q4. As we stated in our press release, in our initial comments, we connected 70 wells in the Q1, which exceeded our expectations. From Q2 to Q4 this year, we're expecting to connect another 190 wells collectively across the Williston, Delaware, and Powder River Basin. That's a lot of wells, and that's a lot of IP volumes coming onto the system. The timing and volume performance of the wells will have a large impact for us this year. A lot of that activity occurs through the summer months, you know, once it gets warmer, especially in the Bakken. You know, from a timing standpoint, as Robert mentioned in his remarks, our producers generally connected wells ahead of our internal estimates through the Q1. Based on feedback and activity from our producers, we're expecting that trend to hold for the remainder of 2023, especially since we're now past the extreme winter weather in the Bakken for the most part. You know, I'd say the other factor impacting our performance this year will just be around commodity prices. As we have said, we have roughly 15% of our company cash flow exposed to commodity prices via our POP contracts in the Williston and Delaware. Realized gas and crude prices will have an impact on the financial performance either to the high end or the low end of the range. With that, I think, you know, those are the key factors for this year. Okay, thanks. That's helpful. Just 2nd question, a small one. Looking through the slide deck, I noticed phrasing on the quarterly EBITDA ramp chart in the slides changed to significant cash flow generation from, I believe, in the Q4 call. It was $35 million EBITDA growth from Q1 to Q4. Anything to read in there, or is the $35 million growth still a good way to think about the EBITDA ramp through the year? Just thinking about exit rates into 2024 there. No, it's a great question and good attention to detail there on the presentation. You know, I'd say it's really just because we outperformed in the Q1. The $35 million was attributable to our internal projections, you know, from the Q1 to the Q4 back from the February guidance. Because we, you know, we outperformed in the Q1, you know, we, you know, the $35 million, you know, comes down a little bit. I'd say the, you know, Q4 number is still the same. Okay. Thanks. Makes sense. Thanks for the time today. Thank you. Our next question comes from the line of Ned Baramov with Wells Fargo. Please proceed with your question. Thanks. Good morning. Just wanted to go back to the Williston. Well connects were in line in the Q1, yet gas gathering and processing volumes declined 7% or 8% year-over-year. You mentioned the impact of weather. You also reaffirmed well connect targets for the year in the Williston. Could you maybe review your expectations for volume growth in the Williston exiting 2023 for crude and gas? I'll take a shot at that, Ned. You know, you know, the Q1, volumes were still impacted, as Robert said, from the extreme winter weather, we saw through the Q4, and we continue to see a bit of that through the Q1. Wells, you know, continue to be shut in the Q1. You know, producers have been, you know, unable to get workover rigs out to the wells due to the weather. We're beginning to see volumes lift right now through the Q2, as weather has improved in the Bakken and our producers are able to get workover rigs out to their pads. That the weather in the Q1, as you mentioned, did not impact their completion timing and their turn in line timing of the wells. you know, I'd say cadence of growth between Q1 to Q4, you know, it differs by product again because there's three product wells and there's water only wells. I'd say generally we're expecting about 10%-15% growth from Q1 levels to Q4 levels this year. Again, pretty strong exit rates for 2023, setting up a pretty good 2024. Diaco, give some color on our producers' activity in the field right now and what they're doing. We're just now coming out of the wintertime really. I mean, the roads aren't even clear. We still got a lot of mud and so we're supply chain's improving, but give us some color around our producer activity. Ned, I'd point you to two things. It's a good question you have. I mean, you think about this level of D&C activity, there's a lot of shut in for offset track that goes on with that level of activity. On top of that, I think we've got somewhere around 25 workover rigs working on Arrow right now. That's a large number of workover rigs. It's cleaning out wells, putting down ESPs, and getting that production online. We should see those volumes come right back up as the quarter, as it warms up, as it has already warmed up, and our customers are reaffirming their activity levels. Thanks for that. Very thorough. My second question is on leverage and your thoughts on longer term targets. Specifically, are you looking to get to your stated long-term target of 3.5 times at some point next year and then maybe stay there? Would you consider further deleveraging below the 3.5? Yeah. A great question, Ned. This is Johnny again. you know, we've stated, you know, our long-term leverage target has moved, I'd say from 3.5x to under 3.5x. You know, as we mentioned, we are very focused on the balance sheet this year and allocating all excess free cash flow to debt pay down. We want to get our leverage target closer to that 3.5x before we start thinking about incremental returns across the board. you know, as we get into 2023-2024, I'd say allocation of capital will really be a function of the outlook of the business at that point in time and opportunities to reduce our cost of capital and continue to drive, you know, value for our investors. I'd say over time, you know, we see the free cash flow generation of the business ramping significantly in 2024 and onwards, which should provide a lot of opportunity with that excess cash flow to, you know, either drive into the balance sheet or incremental returns to our unit holders. Thank you. Thank you. Our next question comes from the line of Neal Dingmann with Truist Securities. Please proceed with your question. Morning, gentlemen. My first question is on your S&L segment. Specifically, could you discuss expectations for the future earnings given what you're seeing down today's forward curve? You know, I know you had decreased the hedge position, so I'm just wondering how you're thinking about that today. Yeah. Neal, this is Robert. I mean, I think our outlook, you know, this year is pretty constructive. As we mentioned, we had a good Q1. You know, we kind of think about that business as about a $100 million a year business in aggregate. I, and I think the curve is set up to perform to that. I think it'll be a solid year after a couple years of some challenging market environments with, you know, pretty steep backwardation. I think now as we look out into the future, and we eliminate some of the hedge losses we experienced last year, we should be back in line with kind of normal operating. Okay. That's good to hear. My second is just maybe on the Powder River asset specifically. Certainly not the size of your Williston or Delaware, I'm just wondering if you could give some color on kind of what you're seeing in year-to-date activity there in the play and, you know, its impact on your Jackalope system. Yeah. Hey, Neal, one thing I'd highlight with our Jackalope WellConnect results, those actually underrepresent. What we don't report is the WellConnects that are behind Continental's gathering system to the north of the Heritage Chesapeake asset. They're quite active over there. They're running 2 rigs right now. The well results we're seeing are fantastic. Really as producers ramp up in that area, which they have been doing, the supply chain costs start to become more and more attractive. The well results of going to 3-mile laterals and even testing 4 are gonna drive what's needed to break that basin four stair soon. We're very, very pleased with having Continental as a partner there. They're no longer a public, they're a private, which is fantastic for us and we're really excited about what's in store for that basin. I appreciate it. Thank you all. Thank you. As a reminder, ladies and gentlemen, if you would like to ask a question, please press star one on your telephone keypad. Our next question comes from the line of Elvira Scotto with RBC Capital Markets. Please proceed with your question. Hey, good morning, everyone. Just a couple of questions from me. Can you just remind us of what your commodity price sensitivity is, specifically around the POP contract? Hey, Elvira, this is Johnny. you know, we've got, you know, roughly 15% of our company cash flow correlated to commodity prices. you know, as we show in the investor presentation, all that's in the Williston and the Delaware, roughly 75% of that in the Williston and 25% in the Delaware. you know, from a sensitivity standpoint, I'd say every $ per MMBtu move in gas prices has about a $10 million annual impact on the plan. About a $1 million a month for a $ per MMBtu move in gas. On the crude side, every $10 per barrel move in oil prices has about a $12 million or $13 million annual impact on the plan. again, you know, a little bit about $1 million a month for $10 per barrel is the way to think about it. Thank you. That's helpful. Can you talk a little bit about, I know you give a lot of producer commentary, but are you hearing any differences between your public versus private producers or maybe some of your larger versus, you know, smaller midcap type producers? Yeah, thank you, Elvira. This is Diaco. Appreciate the question. First, I want to point back to what Bob highlighted in his opening remarks. Our strategic M&A has created a portfolio of assets with significant undeveloped inventory in the core of oil-weighted resource plays. Oil fundamentals remain strong and will remain strong. We do see a lot of discussion on private versus public operators. Our two largest privates are Continental and Newbern. If you think about those two, they're bigger than most publics. We're not seeing any material deviation versus what they told us to shape our 2023 forecast. I mean, we put 70 wells in the books for Q1, a winter quarter, and we're reaffirming our 260 for the year in 2023, which should set us up for a solid 2024. Again, going back, we're in the core of the core of the oil-weighted basins, and our privates are not typical privates. Great. Thank you very much. Elvira, this is Bob. I might add that in almost all of our basins, we've seen larger companies buying the small privates almost in the way of an internal consolidation or a field consolidation. I'll give you a couple of examples. Of course, Continental bought out Chesapeake out of bankruptcy, and so that was great. That was probably one of the most important things that happened to us over a couple of years ago. In on the Arrow system, I mean, we've had Devon buy out RimRock. We've had Enerplus buy out Bruin. We had Chord before they merged with Whiting buy out Diamondback. You know, so we're consolidating acreage in the hands of extremely strong basin players. They're financially strong. They know how to drill and complete wells. Typically, they drill and complete better wells than the small privates did. Maybe not as aggressive on the drill schedule. That's understandable. Privates try to drill it up to get it sold. These guys are longer term players, but we love the impact that consolidation has had on the customer quality of our producers around our assets. Same thing in the Delaware. We're going through that process now. You know, we've got some really impressive small privates that are drilling great wells, and eventually they're gonna attract the attention of the bigger players in the play. That's a good thing for us because we're a long-term player, as Diaco said. You know, by our calculation, and I think we've put that information out from time to time, I mean, we have several thousand long-term drilling locations dedicated to these three systems, and the ability to grow and reach out and capture additional inventory. The financial strength, the long-term quality of our producers is really important to us. We look at our portfolio overall right now, it has improved dramatically over the last couple of years. We've got great producers under contract. We have great relationships with them. We provide good customer service. We talk to them in multiple basins, we're in a really good spot with respect to our producer customers. Not sure that helps you with, you know, a broad brush across the industry or not, but, we do see, the privates starting to pull back a little bit on gas price, whereas the publics probably weren't pushing it too hard to begin with. We don't see any big change in the areas we operate on drilling and development programs over the next, 18 to 24 months. In fact, we think we've got great visibility, probably the best visibility that we've ever had with our customers in terms of collaborating, to make sure that capacity's there, the well connects are there, processing capacity's there, so that we're not flaring gas in these basins, 'cause that's critically important to everybody right now, no flare across the industry. Hope that helps. That does. Thank you very much. Thank you. There are no further questions at this time. I'd like to turn the floor back over to Bob for closing comments. Thanks, operator. Just a point in time with the Trace transaction, which we closed in early April, we're largely completed with our strategic repositioning. I think we've done a great job to restructure this company portfolio. We're a top 3 gatherer and processor in the Williston, the Delaware, and the PRB. Long-term inventory positions dedicated under long-term contracts, good terms, good margins, a good access to additional supplies, as technology improves, and we go from 2-mile to 3-mile laterals. Diaco didn't really talk about that, but that's gonna have a big impact on pro-productability in the areas that we operate. Almost all of our operators are either doing it or thinking about it or coring up acreage and swapping acreage to get ready for 3-mile laterals. We're gonna see improved IP rates from some of these wells. We think that the new G&P position in these basins gives us a competitive advantage. It's still a very competitive business out there, and there's still a cat fight for undedicated acreage. We're in a good spot in all three basins to continue to drive growth of our systems. We're gonna do it with very disciplined capital spending, and Robert highlighted that, and Johnny did too. Capital discipline this year and next is incredibly important to us. Our capital spend should be going down year-over-year, and that should generate increased free cash flow and reduce debt. That is our simple business plan, and it's pretty darn simple. We've got great visibility, as I said, to the 2023, and we think 2024 drilling and development programs with our customers. A lot of our capital spend today will make new acreage available to be drilled next year, particularly some of the new projects in the Williston Basin, the city of Williston and the Painted Woods. Great visibility there. Now it's about execution quarter- to- quarter. I think the team is excited to be really focused on the drill bit and the wellhead and the connects and maximizing available capacity at minimal capital expense. I wanna thank all of our investors for supporting us through that restructuring period. I know that wasn't easy, and it probably didn't look like we knew what we were doing, but when you look back on it's almost like a triple bank shot to have been able to bought good assets, integrated them, cored up our position in 3 oil-weighted basins, and then selling the rest of our assets, which didn't have any growth potential, to keep our balance sheet back in line. Now we're on track to do what we do best, which is gather and process gas, and market natural gas liquids. I think the team's in good position, and the Q1 was a good start to the year. Thanks to everybody for joining us. Thanks to all the analysts for the questions. I know you guys have a lot of work to do today with a number of companies coming out, but we're really pleased with our Q1 performance, and thank everybody for their time this morning. Thank you, operator. This concludes today's teleconference. You may disconnect your lines now. Thank you for your participation, and have a wonderful day.