Good afternoon, everyone, and welcome to the NGL Energy Partners Second Quarter 2022 Earnings Call. It is now my pleasure to hand the call over to your host, Linda Bridges, CFO at NGL Energy Partners. Please go ahead.

Thank you. Good afternoon, and again, welcome to NGL's second quarter fiscal 2022 earnings call. To start, I'd like to call your attention to our safe harbor language, which can be found towards the end of our Partnership's earnings release, which was filed after market close 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 Disclosure and Analysis section and the risk factors discussed in the Partnership's annual report on Form 10-K for the year ending 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. I'm going to start the call with a few brief comments on the Partnership's financial results for the quarter, and then I'm going to turn it over to Mike Krimbill for additional remarks focused on the operations and the future of the business. Overall, NGL had another very strong quarter in our Water Solutions segment as it reported adjusted EBITDA of $87.4 million. Processed barrels totaled approximately 1.8 million barrels per day and grew approximately 94,000 barrels per day over the preceding quarter. The majority of this growth was the result of continued demand for our services in the Delaware Basin. However, we've also seen growth in volumes in each of the other basins in which we operate as well. Skim oil sales benefited from higher commodity prices and those higher commodity prices have encouraged additional drilling and completion activity in our core operating areas, resulting in continued demand for water—whether that be fresh, brackish, recycled or produced. For the remainder of the fiscal year, we expect to see water volumes increase ratably by 100,000 to 125,000 barrels per day per quarter and anticipate exiting the fiscal year with approximately 2 million barrels per day of processed water volumes. Our Crude Oil Logistics segment reported adjusted EBITDA of $48.8 million, which includes an estimated $15 million of realized gains associated with deferred profits that were embedded in our inventory and hedge book at June 30. Grand Mesa volumes came in at 80,000 barrels per day or approximately 3,000 barrels per day higher than the 77,000 barrels per day reported in our first quarter. And margins in the segment were helped by higher crude oil prices as certain contracted rates with producers increased as NYMEX prices increased. DJ's basin production from our core producer customers as well as crude oil prices will drive operating results for the remainder of fiscal 2022. Our Liquids segment reported adjusted EBITDA of $18.5 million, which was primarily driven by results in our butane business as increases in demand for exports and tighter supply markets have benefited product margins. Our propane business had a slower start to the year as a result of backwardation in the propane market and decreased demand. However, this segment should see financial gains coming back in the third fiscal quarter as the business is well hedged, and we're beginning to see product liftings increase. It's important to remember this is a seasonal business that generates most of its cash flow during the butane blending and propane heating seasons, which run from the fall through the winter, and assuming normal heating degree days, this business should be in line with expectations for the year. Putting it all together, total adjusted EBITDA for the quarter totaled $146.3 million, and year-to-date adjusted EBITDA is $237.4 million. Funded capital expenditures for the quarter totaled $31 million and $79 million year-to-date. As previously mentioned, our capital expenditures were weighted towards the first half of the fiscal year, and we expect CapEx for the full fiscal year to be approximately $115 million. Total debt increased by approximately $45 million as working capital continued to increase through the quarter due to seasonal inventory builds and increasing commodity prices. The increase in working capital was partially offset by free cash flow generated during the period. We've been consistent in our message that we expect to generate significant excess cash flow during the second half of the fiscal year as we've completed the majority of our capital projects, begun to liquidate inventories, and continue to perform operationally. And that the excess cash flow generated will be used to decrease absolute debt and improve leverage. This plan has not changed and remains our top priority. With that, I'm going to turn it over to Mike who has some remarks he'd like to share.

Thank you, Linda. Good afternoon, and thanks for joining us today. Sit back and relax as we tell you the NGL story. As you know, we have our three business segments, and our leaders of each segment are with us today to comment and answer questions as we go along. We're going to provide new information covering fiscal 2022 expectations, fiscal 2023 and 2024 projections, and then our debt and distribution strategy. Of course, all my comments assume the current energy environment. So let's begin with fiscal 2022. The big story is our Water Solutions segment. Volumes are increasing about 100,000 barrels per day per quarter as previously projected. Q1 volumes, obviously, 1.67 million barrels a day, Q2, 1.76 million. We expect Q3 to approximate 1.9 million barrels a day and Q4 to approach 2 million barrels per day. Margins and expenses per barrel are expected to remain flat, which is positive and makes modeling this segment simply a function of volumes. The EBITDA for Q1 was $81.5 million for Q2 was $87.4 million. Q3 and 4 are expected to average $90 million each. Thus, the entire fiscal year should come in at about $350 million EBITDA. We have significant excess injection capacity in our largest shale play positions, so water volume increases should be more profitable incrementally. And importantly, capital expenditures going forward will be below the current fiscal year, $115 million. We have Doug White, who leads our water solutions team. I'd like him to discuss recent developments in Reeves and Culbertson counties, dedications and recycle reuse. Doug, are you there?

Yes. Thank you, Mike. Let's start with the update on seismicity. As many of you may know, the seismicity induced by injection wells in Texas, West Texas, Permian area have been in the news lately. In the NGL footprint in the Southern Delaware, the Railroad Commission of Texas has proposed a recent reduction and about 2 million barrels of permitted injection capacity in our operational area. There are no NGL assets negatively impacted by this. Our assets sit just outside of the risk area. But what this has resulted in is increased interest in NGL's available capacity. So it's a very good positive for the organization. Dedications, we previously mentioned 2 large dedications in the Delaware that really are left on a large-scale basis. One of those dedications, we expect to be closed by calendar year-end this year. Recycle volumes. We've been really focused on recycle volumes and NGL's approach to that business. A large portion of our approach to that business is simply reselling produced water off of our pipeline system. We have the magnitude of water it takes for the producers to complete at scale with multiple frac crews, which is different from what has been previously done. So we take our resale, reuse volumes along with our recycle volumes to put those together. Q1, we did just over 100,000 barrels per day. Q2, we had other projects going on. Those slipped into this quarter, Q3. We expect that to be evenly spread across Q3 and Q4, but those demands are continuing to increase as producers continue to move toward a more sustainable approach to completions. One other thing to note, on our dedicated contracted acreage in the Delaware, we have 34 rigs running on it, 438 drilled uncompleted wells (DUCs) and 16 frac crews. So there's quite a bit of operation going on our contracted acreage. That's what's continued to lead to the increased 100,000 barrel per day volume quarter-over-quarter.

Right. Thanks, Doug. On to Crude Oil Logistics. Our Grand Mesa volumes have averaged 77,000 to 80,000 barrels per day, which is only about 50% of capacity through the first 6 months. We're expecting these volumes to remain flat for the remainder of the year as Civitas consolidates its acquisitions and achieves their synergies. On a positive note, the margin on the Grand Mesa barrels is increasing due to the higher crude oil prices. Our 6-month EBITDA is about $62 million. So if you double that for the full year, you're looking at $124 million; you add the impact of these increased margins, and it will result in a full year EBITDA, we believe, of about $140 million. As volumes on Grand Mesa increase, this is an area that could have some upside. Don Robinson leads this segment. I'd like him to comment on the recent open season as there's been some discussion. We want to make sure everyone is clear on what happened. Go ahead, Don. Don, you're on mute?

No, sorry, Mike. Thanks. Yes, NGL logistics, because of the bankruptcy with extraction, basically they no longer have a contract with Grand Mesa, and NGL Logistics entered into a contract with Extraction to provide service for them for volumes in the DJ Basin. We needed to rightsize our commitment to Grand Mesa. So we approached Grand Mesa as part of the FERC rules to ensure that we could sign up for volume that would commit us to take care of the producers that we have commitments from in the DJ. This is the primary reason for the Grand Mesa open season; you have to go out to all parties and offer them the same type of service that you offer to NGL Logistics or any other third party. So that was the reason behind it and basically have a successful open season.

Great. Thanks, Don. So Liquids Logistics. Our Q1 EBITDA was $5.6 million, Q2 $18.5 million for a total of $24.1 million. These are our 2 lowest EBITDA quarters due to the seasonality of propane use and the butane gasoline blending. Our butane segment is ahead of plan due to improved margins, while wholesale is off to a slow start due to a backwardated price curve in the spring, higher prices since then and warm weather. We expect this business to make up the shortfall in the second half of the fiscal year. Full year 2022 EBITDA is projected to come in around $113 million. The 220-mile 8-inch ambassador pipeline in Michigan is a great example of a smaller, highly accretive asset purchase that continues to move liquids into more of an asset-based business. The northern half of the pipeline is operational with the new midpoint wheeler terminal scheduled for completion by early December. This is the only propane pipeline servicing Northern Michigan. It's bidirectional, so it can move propane south in the summer and north in the winter. The ambassador is kind of exciting because it could become a critical source of supply to ensure energy security for Michigan citizens if the Federal and state governments shut down line 5. Jeff Pinter runs his group. And Jeff, I don't know if you're there, but if so, do you have anything to add?

Thank you, Mike. Good afternoon. A couple more comments to add. We do see the pipeline as a strategic asset for not just NGL, but customers throughout the state of Michigan; it is one of the highest propane demand states in the country. And it's strategically connected to storage on the southeastern part of the pipeline and then does traverse all the way to the northwestern part of the state. So we're hearing a lot of excitement from our customers, and we look forward to having it in service this winter.

Great. Thank you. So for NGL, in total, we're confirming our fiscal 2022 EBITDA range of $570 million to $600 million. We're trying to be conservative and focus on the low end of that range. The individual segment numbers that we've talked about here, less corporate expenses of about $32 million to $33 million, add up to the low end of that range. So next, we want to focus on free cash flow because that's what we are going to use to reduce our debt. So starting with fiscal 2022, the calculation using the numbers we talked about, EBITDA of $570 million, minus interest expense of $250 million, less maintenance and growth CapEx combined of $115 million, adding back $50 million for some asset sales, net of some margin requirements, provides about $250 million of free cash flow for fiscal 2022. So let's jump to the next couple of years. So you get the full picture of how quickly this balance sheet delevers. For fiscal '23, we'll start with some EBITDA relationships here so you can model these things, if you'd like. For fiscal 2023, we expect water EBITDA to be up 10%, so on the $350 million, obviously, that's $35 million. Crude oil, we're assuming flat until we see more drilling and more production in the DJ, and then liquids up about 5% as a result of the ambassador pipeline. For fiscal '24, we expect water to grow another 10%; crude we've just been assuming flat EBITDA there and then we'll assume liquids is flat as well. Again, just to be conservative. So both these years will have EBITDA between $600 million and $650 million. Interest expense, which obviously, we deduct from EBITDA, is $250 million, as we said, in '22, and it drops about $25 million a year in '23 and '24. Maintenance and growth CapEx are decreasing significantly due to our prior year spend and excess capacity in the segments. So the $115 million this year would drop in 2023 to $75 million and in 2024, $90 million. So this results in free cash flow, to summarize, of $250 million in fiscal 2022, over $300 million in '23, and almost $400 million in 2024. Now all of this is prior to reinstatement of the preferred dividends, which are accruing at the pace of about $100 million annually. When the preferred dividends are reinstated, that year's free cash flow will be reduced accordingly. So if you're trying to figure the leverage figure sometime in there, there could be a reinstatement of the preferred dividends. So modeling our business should be fairly simple now with crude and liquids fairly flat, water margins and expenses per barrel constant. So it's really a volume increase story with declining interest expense and CapEx. So now let's pull this all together to articulate our debt and distribution strategy. So it happens if you have an Apple watch, and someone calls you. Okay. So we're going to pull this all together. First, three important points to mention. One, our new ABL and secured notes do not have a leverage or interest coverage covenant. So any speculation about bankruptcy under current market conditions is rubbish. Two, our secured debt due 2026 has a 2-year non-call provision. So we cannot begin repaying it until after February of 2023. And thirdly, under these debt documents, we must reduce leverage to less than 4.75x EBITDA in order to reinstate the preferred dividends and subsequently declare a common unit distribution. This is our number one financial goal. We will generate sufficient free cash flow to repay the 2023 unsecured notes prior to their maturity. Once repaid, we will begin reducing the senior secured notes due in 2026 with the additional free cash flow. Once our leverage is below 4.75x EBITDA, we will address the Class B, C, and D preferred dividend arrearages, reinstate the preferred dividend going forward and continue to delever. We do not anticipate any M&A activity, no accessing the public equity markets nor converting preferred shares into common units. We believe we do have strong assets and a good business model, but we are focused solely on significantly improving the balance sheet. So with that, thank you, and let's open the line for questions.

Your first question is coming from Tarek Hamid from JPMorgan.

So just one question on the water business. You talked about some of the potential dedications as well as some of the potential ongoing changes in rules with seismology issues potentially being a beneficiary. How much of that have you baked into some of the numbers that you've talked to in the last half hour, both in '22 and beyond?

Doug?

Tarek, none of the forecasts that Mike presented include the benefit of these recent developments regarding seismicity.

So that would all be upside, obviously, from here?

Yes, that's correct. It's all incremental. And to give a little more color to it. We are actually moving towards some dedications related to the recent events, which are certainly beneficial, but our incremental, like I said, incremental to the forecast Mike provided.

And then a follow-up for me. Just on the free cash flow guidance. Obviously, working capital, as you talked about, has been a bit of a hit here, some of that makes sense, obviously, just given what's happened to commodity, and so that's seasonal. But can you just talk about sort of as you think about the use of working capital so far this year, how much of that do you sort of view as sort of more permanent and just a function of what's happened to commodity prices versus how much of that just is seasonal, and you expect that to come back in the second half of the year?

Yes. I'll take that question. So when you look at working capital, most of our working capital is going to be seasonal. If you take a look at our balance at $3.31 million of 2021, I think we had a $4 million balance remaining on the ABL facility at that time. As we move through the year, we'll build liquids inventory; we will have some crude inventory, but we would expect that to decrease down to the same level at March 31. So it truly is kind of a seasonal working capital need that you'll see on the ABL facility.

Got it. And then last one for me, just—and I apologize for the nit question, but on adjusted EBITDA, that's a $13 million adjustment for CMA role differentials. Just kind of any color on what that actually is, it's just a little confusing.

Yes. So there is more disclosure in the disclosures around adjusted EBITDA. That can give you more detail. But essentially, we have hedged. We have locked in a $0.20 CMA roll differential. So when you look at our Crude Logistics business, we buy at NYMEX minus the differential in the basin, and we sell at NYMEX plus the CMA, the Argus CMA roll differential, which in a backwardated market is normally—sorry, generally speaking, historically, we have not hedged that. We've just taken the risk within the contract because it generally runs, call it, $0.10 to $0.20 positive or negative at any given time. Last year at this time, we saw that CMA role—last year, first quarter, we saw that CMA role blow out and saw that we probably needed to hedge that difference in the contract. So we did. What that EBITDA—adjusted EBITDA entry is the position on the front end of that hedge. So what we've done is we've hedged 50,000 barrels per day through December of 2023, and we've locked in a CMA role of about $0.20 per barrel, which will result in about $9.2 million to $9.3 million of CMA role that we will generate between May of this past year—and this year, sorry, and December of 2023. That hedge is a long-dated hedge. We have short positions in the near-term and a long position out in December of 2023. Management views that entire, both the short and the long as part of the same hedge strategy. And so while you'll have an unrealized gain out in December of 2023, you'll have realized losses on the short positions between now and then depending on what the market does. So what we've done is in order to eliminate that noise, we've adjusted that out of EBITDA. And again, there's more disclosure around that in EBITDA disclosure.

Assume that you would have an add-back for the next couple of quarters. Then as you approach that period in 2023, there will be a loss associated with that. Overall, this will net out to approximately zero over time.

Correct. Everything will—those hedge gains and losses will net to 0, and you should see about $9.2 million flow through the income statement associated with the CMA role over that time.

Our next question is coming from Patrick Fitzgerald with Baird.

So that CMA roll add back is all in Crude Logistics this quarter? Essentially, that's right, right?

Yes, it's all in Crude Logistics.

Okay. So in terms of like a normalized margin per barrel, how should we think about that, the difference between the first quarter and the second quarter?

Don, do you have a thought on that one? Don, you're on mute.

Yes, Mike. Sorry, again. That—yes, that would be basically additional—as far as the earnings in each quarter as far as—as Linda spoke to the $9.3 million, that basically $300,000 per month over the next 3 years that we'll be collecting. We've taken the loss, as Linda spoke to about CMA. And I'll just add, the reason we did that is because of the Extraction bankruptcy and NGL Logistics, taking that contract. It was just a risk that we did not feel real comfortable about being there for the duration, and that's the reason we put the CMA hedge on.

But Patrick, if you look at the 10-Q, so the margin per barrel that we quote in the 10-Q, that's all excluding the impacts of derivatives. So the effect of whether it's inventory hedging or the CMA role should be excluded from the margin analysis, that's in the 10-Q.

Could you—did you put this out like 10 minutes before the call, what are those numbers? Because it was going like $2.45 per barrel, $2.72 per barrel, $1.64 and then at $6.5 this quarter. I mean, just the—kind of understand like how we should think about that going forward?

Yes. So if you look at the—actually, Patrick, I'm just going to direct you to the 10-Q. Go ahead and take a look at it. And then if you have additional questions, just let us know you can contact us.

Okay. What are your price assumptions in terms of your water volume growth up 10% next year and the year after, is there any price assumption within that? Or are just going to happen regardless of what prices are just going to keep increasing production?

Yes. I think what Mike mentioned is that he's assuming consistent commodity price environment, consistent commodity market environment, and he's assuming flat margin per barrel.

Yes. So Patrick, we're—we don't know what the producers are thinking. They're going through their budgeting cycle right now. So would they drill the same amount at a $75 price, as $85, as $65 don't know. But no, it doesn't assume the same volumes if the prices are $30. Doug, do you have anything to add?

Yes, Patrick. So one thing to consider in these volumetric numbers that we've used to forecast. Keep in mind, we have that large dedication from the Hillstone acquisition that increases annually. We also have this second—this large dedication I mentioned, which is the largest acreage dedication that we have or will have in the Delaware Basin. That certainly adds volumes to it as well. And then our other existing dedications based on what we know today. And keep in mind it isn't centric to the Delaware. And I think everyone has a good idea of what that crude oil range in the Delaware is where activity stays fairly busy or constant. I don't think it's going to take $80 oil to achieve our volume forecast; $60 to $80 range is a great price for Delaware Basin.

Your next question is coming from Philipp Duffner with Aurelius.

For the— in the Crude Logistics business side, you had obviously a significant hedge loss last quarter. And I think you mentioned on the call, but would you mind just repeating how much of that unwound this quarter, what the gain was and what the normalized Crude Oil Logistics EBITDA would have been this quarter?

Sure. So we got back about $15 million related to that embedded hedge gain at 6/30. So normalized, they did $48.8 million this quarter. You take $15 million off of that, you're at about $33 million to $34 million for this quarter, and the first quarter would have been around $28 million to $29 million.

Got it. And the $15 million, is that the full amount? Or is there more to be gained back next quarter or this quarter?

I think we received back everything we had expected.

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.

Yes. So thank you, guys, for joining the conference call and for the interest in NGL. I think hopefully, you can tell we're excited about the remainder of the year and coming into our fiscal 2023, and we will plan on talking to everybody next quarter. Thank you.

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.