NGL Energy Partners LP (NGL) 2021 Q4 法說會逐字稿

Good day, and thank you for standing by. Welcome to the Fourth Quarter Fiscal Year 2021 NGL Energy Partners LP Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I will now hand the conference over to your speaker today, Trey Karlovich, Chief Financial Officer. Please go ahead.

Thanks, Carmen. As a reminder, this conference call includes forward-looking statements and information. Words such as anticipate, project, expect, estimate, plan, goal, forecast, intend, could, believe, may, will and similar expressions and statements are intended to identify forward-looking statements. While NGL Energy Partners LP believes that its expectations are based on reasonable assumptions, there can be no assurance that such expectations will prove to be correct. A number of factors and risks could cause actual results to differ materially from the projections, anticipated results or other expectations included in the forward-looking statements.

Certain of these factors include changes in general economic conditions, including market and macroeconomic disruptions and related governmental responses, the prices of crude oil, natural gas liquids, gasoline, diesel, biodiesel and energy prices generally, the general level of demand and the availability of supply for crude oil, natural gas liquids, gasoline, diesel and biodiesel, the level of crude oil and natural gas drilling and production in areas where we have operations and facilities, the effect of weather conditions on supply and demand for crude oil, natural gas liquids, gasoline, diesel and biodiesel, the availability and cost of capital and our ability to access certain capital sources and political pressure and influence of environmental groups upon policies and decisions related to the production, gathering, refining, processing, fractionation, transportation and sale of crude oil, natural gas, natural gas liquids, gasoline, diesel or biodiesel and other refined products. Other factors that could impact these forward-looking statements are described in the risk factors in the partnership's annual report on Form 10-K, quarterly reports on Form 10-Q and other public filings and press releases. You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date hereof, and except as may be required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise.

This conference call also includes certain non-GAAP measures, namely EBITDA, adjusted EBITDA and distributable cash flow, which management believes are useful in evaluating our financial results. Please see the partnership's earnings releases, investor presentations, annual report on Form 10-K and quarterly reports on Form 10-Q for more information on our use of non-GAAP measures as well as reconciliations of differences between any non-GAAP measure discussed on this conference call to the most directly comparable GAAP financial measure. This information is also available on our website at www.nglenergypartners.com under the Investor Relations tab.

Thank you for joining us for our fourth quarter and fiscal year-end 2021 earnings call. I will cover our financial results for the year and some of the drivers of those results and then turn the call over to Mike to discuss our initial sustainability report and give our closing remarks. We will then open it up for your questions.

We reported a net loss in fiscal 2021 of $637 million, which included the following onetime items: crude segment goodwill impairment of $238 million and an intangible asset impairment of $146 million, both of which were driven by the Extraction bankruptcy and ultimate settlement and were recognized in the fiscal third quarter; additional long-lived asset impairments in the water segment totaling $84 million recorded in the fiscal fourth quarter related to obsolete and underutilized assets, none of which were in the Delaware Basin; and transaction costs of $103 million related to our refinancing that were required to be expensed and also were recognized in our fiscal fourth quarter.

Our adjusted EBITDA from continuing operations for the 2021 fiscal year totaled $448 million compared to $589 million in fiscal 2020. The most significant variances include the Grand Mesa volume decline driven by Extraction's bankruptcy and a decline in DJ Basin production, resulting in a $75 million decline in adjusted EBITDA from our Crude Logistics segment last year. Water volumes declined significantly in the Eagle Ford and DJ Basin and also declined slightly in the Delaware Basin compared to fiscal 2020. We were able to reduce operating cost per barrel to offset this decline in volumes and actually grew Water Solutions EBITDA by $9 million year-over-year, with full year contribution from Mesquite and Hillstone acquisitions. Demand for natural gas liquids, primarily butane and refined fuels, were severely impacted by the pandemic and drove a decrease of $80 million in adjusted EBITDA on our Liquids segment compared to last year, which I'll remind everyone was a record year for this segment.

We also saved almost $5 million this year in corporate and other costs compared to the prior year, and that is after incurring approximately $6 million in cost to defend the Extraction contract throughout the year. Our fiscal fourth quarter results were impacted by the following: Crude Logistics continued to be impacted by lower volumes on Grand Mesa as we settled the Extraction bankruptcy in January and did not see volumes return to the pipeline until February. This segment also incurred some financial derivative losses on its inventory position that we expect to benefit from in fiscal 2022. Winter Storm Uri resulted in a pretty significant shut in of volumes in the Delaware Basin for about 2 weeks, which negatively impacted our water disposal volumes during the period. Additionally, the storm impacted producers' drilling programs and ultimately, the increase in volumes we were expecting in the second half of the quarter.

We also incurred some incremental operating costs to run generators and keep our system operational through the storm, which increased our operating cost per barrel during the period. The good news is that we are seeing volumes pick back up, including demand for fresh, reuse and recycle water in the basin through April and May. The winter weather pattern also impacted our liquids segment as we saw propane prices spike in February, causing a steep backwardation in the propane price curve through March. This price move had a slight negative impact on our net inventory position when considering our financial hedges that offset any benefit we recognized during the Polar vortex in February.

We managed through the past year and all the challenges it presented and like many of you, we are looking forward to the upcoming year and the opportunities in front of us. We believe there are a handful of important factors that will drive our earnings for next year and beyond that you should pay a specific attention to as you assess NGL and our performance. First, Delaware Basin oil production and completion activity and the associated water will be the largest driver of our performance next year. We are seeing increases in other basins as well, but the Delaware Basin is easily the most significant and important. Disposal volumes will continue to be the largest driver, but we are also selling produced water for use and recently started our first large-scale Delaware Basin recycling project in Lea County.

Next, DJ Basin production growth will also be important, most notably from the combination of extraction of Bonanza Creek as our most significant contracts in the Crude Logistics segment are with those producers, and we will be tied to their production volumes on Grand Mesa. Third, a strong recovery in demand for refined products and blending feedstocks, most notably butane to pre-pandemic levels will be important for our Liquids -- Logistics segment to generate incremental cash flow compared to last year. We will also continue to focus on cost reductions across our segments and at the corporate level and minimize capital expenditures to meet our operational needs. These will be the most important metrics for us to maximize our earnings and cash flow and drive deleveraging of the balance sheet.

We invested significantly in the years leading up to the pandemic and the commodity price collapse, and we'll be working to maximize the earnings potential of our asset base in fiscal 2022 and beyond. Our liquidity position is much improved from last year, and we have a few years to manage our debt balances and maturities. Our current focus will be on repaying our 2023 notes, which mature in November of 2023 as we earn excess cash flow. We will also evaluate noncore asset sales and other options to reduce indebtedness. We do not have a time line set out to reinstate preferred or common distributions, but we understand and appreciate the importance of both, and we'll be working diligently to improve the balance sheet and ultimately, increase stakeholder value.

I'll now turn the call over to Mike to cover our sustainability report and give his thoughts and our closing remarks.

Great. Thanks, Trey. I'd like to provide a few comments on the ESG front. As we mentioned in previous calls, we have been working on gathering data information in order to give you a picture of some of the things we do every day at NGL from a sustainability perspective. We are excited to share this with you in our inaugural report, which should be posted to our website within the next week. In the meantime, let me give you a couple of high-level thoughts. First of all, we look at our sustainability journey as a tremendous opportunity as you will see our assets and capabilities give us a unique position to help improve air and water quality, assist our customers in decreasing the amount of fresh water they use in operations and enhance the extensive natural habitat we have.

When you think of our businesses, particularly our Water Solutions segment, which includes our extensive ranch holdings, where we own or lease over 200,000 acres of ranch land, it is easy to envision the opportunities to enhance the environment, conserve water resources, improve the land holdings, explore opportunities to sequester carbon and protect wildlife. What is also important to keep in mind is, in many cases, our efforts and initiatives are done in collaboration with others. We collaborate and partner with communities, not for profits, industry partners and government agencies. We think these partnerships are critical for our success and lead to the most sustainable solutions. You will see a number of examples of this type of outreach in our report.

A few specifics included in the report include the following: now through the build-out of our extensive water pipeline system, we have either eliminated or avoided millions of truck miles, positively impacting air quality in roads; in the area of water conservation, we provide recycled and produced water to our customers for use in their operations, thus reducing the need for fresh water. In the last few months, we have provided between 100,000 and 150,000 barrels daily of such water. We are focused on fit-for-purpose water reuse, which is where we -- where produced water is treated to a standard appropriate for specific applications, such as nonconsumable agriculture or growing plants to sequester carbon.

NGL was the first to pledge financial and kind support for the New Mexico-produced water resource consortium committing $1 million to this effort at its outset in 2019. The contribution represents NGL's commitment to science-based decision-making, collaborative industry academic and government partnerships all working towards sustainable and safe wastewater treatment and reuse solutions. The consortium is a collaboration between the Mexico Environmental Department and the New Mexico State University. The consortium is working to advance scientific and technological solutions related to the treatment and reuse of wastewater generated by the industry.

Fourth, the land conservation opportunities with respect to our ranches are expanding. We are collaborating with the state and federal land managers, wildlife agencies and others to improve the habitat for stock grazing, non-game and game wildlife species as well as increased native grass growth and distribution. Finally, one of the things we are most proud of is the implementation of the program earlier this year that instituted a minimum wage of $20 per hour for every one of our full-time employees. We have always believed that our employees are our most important asset and this program is a reflection of that.

So with that, Trey, back to you.

Great. Thanks, Mike. That concludes our prepared remarks. We will now open the call up for any of your questions.

(Operator Instructions) Our first question comes from [Tareq Amin] with JPMorgan.

Could you maybe just talk a little bit more specifically about sort of the dollar impact of some of those Winter Storm Uri impacts? I think it's sort of easier to understand the sort of water solutions impact, but maybe just a little bit of help on the Crude Oil Logistics and thinking about the sort of quantum that we can sort of blame on the weather versus the quantum that sort of relates to the kind of tail end of extraction.

Sure. So from a Crude Oil Logistics perspective, again, a portion of the impact was from Winter Storm Uri as it relates to, again, we do market and buy and sell barrels out of the Permian Basin, which was impacted. But additionally, our transportation assets in the Gulf Coast were impacted by the lack of activity and just the decline in volumes during that period of time as well as the subsequent recovery. That did have an impact on our Crude Logistics segment. We have not -- we're not -- haven't disclosed the quantum of that. It was -- I think the bigger driver for Crude Logistics was still the volume on Grand Mesa and the timing and amount of volume that ultimately has flowed from extraction when they came back online in February.

Okay. That's helpful. And then as you talked about -- you made obviously some pretty positive remarks about sort of the outlook ruling kind of past this quarter. But you did have guidance out for fiscal '22 of $570 million to $600 million. Should we kind of still think of that guidance given some of these impacts in transitory as being valid? Or is it maybe head trending toward the lower end of the guidance at this point?

We have not changed our guidance. That guidance was put out in January. No change at this point in time and no expectation to change at this point in time. Obviously, it's the first of the year. We are seeing the volume increase in the water segment that we anticipated. We're seeing volumes back online on Grand Mesa. Obviously, $60-plus crude price is beneficial. The keys will be the items that I pointed out. We need to continue to see growth in production in the Delaware Basin and the DJ Basin to support those large assets, being the Grand Mesa pipeline and the DJ and the water platform in the Delaware. Those are going to be the biggest drivers. Obviously, our Liquids segment was impacted over the past year from a demand perspective. We're seeing a pickup in that activity as well. That needs to be sustained. And then obviously, our propane business is still impacted by the winter heating season. So those are going to be the drivers to focus on.

Got it. And then just last one for me. You touched on the first big recycled water project in the county. Can you maybe just talk a little bit about sort of your current sort of percentage of recycled water volume and sort of your kind of ultimate goal is on the system over the next couple of years?

So I'll start and Mike, please add in. So this one project is recycling about 120,000 barrels a day initially. So that's the initial project. So it is a significant scale project. I don't know if we have a specific goal, I'll defer to Mike on that on how many barrels or what percentage we would look to recycle, but we are looking to grow that business with the producers. This is expertise that we have had for a long period of time. We have done it, obviously, in some of our other basins to a larger scale. We have been promoting this with producers in the Delaware Basin, and there seems to be an opportunity that we're -- we'll be able to take advantage of.

Mike, I don't know if you want to add to that.

Yes. I would add that the producers seem to be more comfortable using the raw produced with some minor treatment and so we're seeing the -- I'll say the demand in the future is increasing. So as we said we're at 100,000, 150,000 a day right now as a percentage of produced water -- I mean, of our total water, that would be about -- on the 150,000 side, that will be 10% of what we disposed of in the fourth quarter. But that water will have to keep going -- that kind of had to keep going up to maintain 10% or better. But I think that's certainly the trend. We wouldn't expect it to decrease.

Our next question comes from Philipp Duffner with Aurelius.

One question on the Crude Logistics segment. It seems like you missed -- like part of the guidance that's related to that segment. And you said that some of that was due to storm Uri, but was there any -- like did the Extraction volumes come back later than what you were expecting and that impacted the guidance? Or were you saying that just impacted the year-over-year comparison?

Primarily, the year-over-year comparison, Philipp. Again, their volumes have come back online. They were not at the level that they were when they went off-line last winter. They have brought on incremental production. They have announced that their -- what their drilling plans are and their production plans are for this year. Again, we do know -- we no longer have an MVC with Extraction. So we are strictly tied to their volume of production. We do have a dedication in the DJ Basin. So all of their production essentially comes to us. But the key will be based off of their production now rather than an MVC. Additionally, we mentioned that we did have a financial derivative loss that we realized during the period with the run-up in commodity prices that we took in the fourth quarter that we believe better positions that business going forward.

Got it. And in terms of the impact from storm Uri, like has all the production and the volumes, have they normalized at this point? Or are you still seeing them below what you were expecting pre the storm?

We believe the volumes are back to where we had expected them. Again, that's -- most of that impact is in our water business. There was obviously about a 2-week period where volumes were significantly off-line. We started to see those volumes come back. However, it delayed completion activity and some drilling activity. So it did have an impact into March and, call it, early April time frame, but I believe we're seeing volumes back to where we expected them to be at this point in time.

Are you basically saying that in the water segment, the entire miss was due to storm Uri or are there other factors as well?

I think the water volume impact was pretty much driven by storm Uri. I think there was also some incremental costs that we incurred associated with our system related to the storm. That would be the primary drivers.

Our next question comes from [Jason Steward] with [Steward Holdings].

First question is for Trey. During the last quarter's call, you mentioned that XOG was able to renegotiate for their reduced rates on Grand Mesa, but that our price adder that kicks in around $50 a barrel would begin to offset that and looked like around $60 a barrel, we should expect to get back to a historical rate of $440. Does that price adder have a maximum limit or phase out on the upside? Or should we expect NGL to continue realizing benefits as WTI rates go up?

Yes. So we talked about the price adder kicking into $50 that has been of benefit as prices have gone over $50. Again, as we talked before, at $60-plus we're back closer to where our prior rate was on the contract. What I'll say about that contract in -- we have not disclosed all of the particulars and neither has Extraction but what I will say is it is similar to the Bonanza Creek contract.

Okay. All right. And then in our -- we mentioned last quarter also, Mike started telling us about the produced water sales, and you've mentioned earlier on this call some produced water and some other programs that are ongoing. Are those new revenue sources? And when can we expect to see some more detailed financial results in this water segment that break out those various revenue sources?

Yes. Yes, those are new, and that really started up in our first quarter. So you should see those numbers in the first quarter Q.

Okay. And then also, Trey, for you, last quarter, you mentioned that there were certain contract provisions that allowed producers to retain more of the skim oil from produced water has been a contributing factor to lower skim oil revenues. Can you give me some more detail on how much processing and removal of minerals, substances customers do before transferring that produced water to NGL? And give some insight as to what NGL's ownership rights are to that produced water once it's turned over, like the mineral and substance content?

Sure. Sure, Jason. So it varies somewhat by a producer. Some of the larger, more sophisticated producers that are doing most of their own infield gathering, they will put systems in place to try to get out as much of the oil as possible. And in those cases, we get a very small amount of skim oil. Generally speaking, we will get a little more skim oil from flowback water than we do from produced water, which we saw that last year. We're seeing a bit of an uptick in that as production is ramping back up and drilling activity is ramping back up. But it is producer by producer specific. I think our average skim oil recovery rate was about 13 basis points last year. I would not expect it to deviate significantly from that level.

Again, as we bring on incremental barrels in some of the more trucked basins, you could see that number go quite a bit higher. But again, as you're bringing on larger volumes from the Exxons and the EOGs and the Devons of the world, those producers are much more sophisticated and will strip out as much of the skim oil as they possibly can. Now once that skim oil gets to our system, it is, generally speaking, ours. There are a handful of contracts that allow the producer to recuperate the skim oil that we recover on their behalf. That is a pretty small number, but there have been some contracts that have been set up that way. Most of those have been acquired by NGL, they're not contracts that we've put in place. So -- but generally speaking, we have title to all of the product that we receive at the transfer point.

Okay. And what about the other mineral content? Lithium and -- where I'm kind of going with this is towards this trend toward companies doing direct extraction of lithium and hydrogen and other valuable substances out of the produced water. And I'm trying to kind of gauge what's NGL's direction on those type projects where we might find other ways to monetize the produced water and new revenue sources as well as ESG policy benefits?

Sure. We've historically looked at what other minerals we could extract from the water in an economic way. We have found that there are some that could be extracted, but in such quantities that they would actually depress pricing in those markets to the point where we don't think it would become economic. We have recently looked at lithium, but we -- at the moment, we don't see lithium being extracted economically. So at this point, we don't have any additional minerals, we think, that we can extract economically.

But contractually, and it may vary from producer to producer, but contractually, we should expect that things other than skim oil would remain in that produced water that they're not going to extract it before passing over to NGL?

I mean they could extract anything they wanted to until they give it to us.

Okay. All right.

But once we have the water, yes, the minerals remain in the water. And if we can figure out a way to extract it economically, we would.

Our next question comes from [Fernando Anser] with [APCO, Inc.]

My first question is Intrepid Potash in their earnings call mentioned that they purchased water from third parties to fulfill their contracts. Can we assume that, that came from the partnership?

No, you can't assume that. We do have a water sharing agreement with them between their ranch, which is called Dinwiddie ranch, and our Beckham ranch. But they buy, I think, substantially. They have a lot of water rights, and they -- my guess is they buy substantially more water from others than us.

Okay. Second question. There was a press release that I don't know its false or not. NGL supply wholesale acquired a pipeline up in Michigan for net gas from Lamda Energy. Can we assume that is correct or not?

Well, I think you're correct on both points. There were several articles that said someone else bought it, but that was incorrect. We did buy that pipeline. And yes, we are putting in a propane service by directional so that we will be able to supply Northern Michigan with whatever propane they would like.

Okay. Is there a price tag for that? Or is that confidential?

I'm looking around.

We have not disclosed the price, but what I'll say is it was not material or significant. There is some incremental disclosure in our 10-K around it. But again, it is not a significant trend.

Did we disclose the number anywhere?

We have not.

Okay. No, we're saying we haven't disclosed it, but it's not a big number.

Okay. And finally, I guess for Mike, if you're given the opportunity to eliminate all the partnership's short- and long-time debt, which of the 3 sectors would you sell online?

Which...

Which would you sell in any of the 3 segments? And why?

I wouldn't sell any of the 3. I think we're in exactly the right spot. All 3 businesses are going from our -- I think, well, they are performing well. They're in the right places. And we're just not going to be acquiring. We're not in the M&A game anymore, and we're just going to -- we have capacity not being utilized, we just need to fill that up. But no, we would not sell any of our 3 segments.

Okay. And I guess, finally, I know that all the automakers, they're becoming full electric by 2030 and some are by 2026. The Bay Area announced that (inaudible) issue any more construction permits for gasoline stations. My question is, where do you see the partnership 8 years from now? Do you think it will be a vibrant partnership with the 3 segments?

I mean, really, that's your view of fossil fuels, and our view is not that fossil fuels are going to disappear in 8 years. So I think we will be vibrant. Yes. I'm feeling vibrant right now.

Our next question comes from [Alan Fragen] with [Lonestar Capital].

I'd like to focus on the $40 million consent payment that you made to the holders of the Class D preferred units. Under what contracts did you require that consent?

So as a part of our refinancing, a requirement of the new bondholders as well as the bank group was that we would no longer be able to pay any restricted payments until our leverage was reduced to 4.75x. Restricted payments includes distributions on preferreds. Our partnership agreement did not allow us to reduce the distribution on the Class D preferred units. So that had to be negotiated with the holders of the Class Ds. And so that was a negotiation with the Class D holders to enable us to do the refinancing.

Given that your Class D holders have a representative on your Board, I mean, do you really think that they would have objected your refinancing given that they're junior classes securities?

They were not excluded -- yes, they were not included in those discussions and negotiations with the note holders because of independence purposes.

Are you saying to me that the note holders required you to get the consent of Class D preferred before they would be willing to finance -- to invest in the 2026 secured notes?

Yes. We would have been in violation of our partnership agreement if we had not done so.

And a violation of the partnership agreement would have caused what sort of ramification? It's not like there's a default on a debt indenture, right?

Not technically. That's probably more of a legal question, but our partnership agreement is an agreement with all partners, not just preferred holders. So the partnership agreement includes, at this point, Class B, Class C, Class D and common unitholders. And to enter into an agreement that is contradictory to what our partnership agreement, I would imagine would subject the partnership to share unitholder litigation.

So I'm trying to understand the parse through what you just said. Would you have required the Class Bs and Class C preferred units or also subunits partnership agreement to consent to this financing?

That was not required in the partnership agreement. They did not have a provision that would restrict us from not paying that distribution. That distribution is perpetual, cumulative and so that -- therefore, it would not require an approval of those holders. However, the Class D units are structured differently and did require that approval.

Our next question comes from James Spicer with TD Securities.

I wanted to start just a follow-up on the price adder feature on that Extraction contract. I'm just trying to understand a little bit better how it works and what the potential magnitude of the impact could be, given that we're approaching $70 oil today. I don't know if you can talk about the incremental benefit you received during the quarter or what you expect that to be going forward, but anything along those lines would be helpful.

Sure, James. I can share a little bit. Again, the price went over the $50 threshold in kind of February time frame. So we had 1 month essentially where we had the benefit. That's also when Extraction, in this case, had a lower volume on the pipe. They have since had some completions. They're continuing to ramp up completion activity. They expect to grow volume throughout the year. So that will be a benefit. We have not disclosed what the exact terms of the adder are nor has Extraction. So I'm limited on that from that perspective. But again, I think I can refer you back to the Bonanza Creek contract, and it is similar.

Okay. And then just on the Extraction, Bonanza Creek merger itself, have you guys seen any updated plans from them? Are you expecting the production for the pro forma company to be greater than some of the volumes you would have expected from each company individually?

I'll start and Mike, please chime in. When we announced the settlement with extraction, I think Mike even mentioned that we do see consolidation in the basin. So we're not surprised. We think that -- we think this is a good combination of companies that I think their strengths benefit each other. So we are very supportive of the combination. At this point in time, I don't believe they've guided to any incremental volume in the near term from the combination. So I don't see that being anything we should be looking at here in the next 12 months. But we do believe that having a stronger counterparty that continues to consolidate the basin is a benefit to NGL and Grand Mesa pipeline.

Do you want to add anything, Mike?

I would add that the -- I think we're seeing certainly amongst the majors and some of the non-majors that they all, I'll say, prepared budgets last November, October with $45 crude price and the appropriate number of rigs at that free cash flow level. Clearly, it's much more than that. The majors have stuck to their -- I think their budgets. Some of the independents have added rigs. I think in the DJ, this first year, calendar '21 is a -- I think it's viewed as a great opportunity to repay a significant amount of debt. And then I think we'll just wait and see what happens in calendar '22 and see if these prices are maintained over $60 or $65 million if they are going to add additional rigs or not. But at this point, we see the same information you do on Bonanza and Extraction, and we don't expect Extraction to change from -- I think they have a 1-rig program. I think the model upstream is changing somewhat that a number of these companies view paying a dividend is appropriate. So I don't really see any change this year. So 2022 will be the question.

Yes. Yes. Okay. No, that makes sense. And I appreciate the color. My last question here is, you have EBITDA guidance out there for fiscal 2022. And obviously, Water Solutions is a big driver. Can you tell us what you're assuming in your EBITDA guidance in terms of water volumes in the Delaware?

Well, that's -- can we or will we? That's the question. Go ahead, Trey.

So James, obviously, we're expecting growth, and the Delaware is going to be the driver. In fact, our current forecast does not really have any growth in the other basins. We are seeing some benefits in this commodity price cycle. But the Delaware is going to be the driver. We need to get those volumes over and above where they were historically. I think our expectation for this year is that those volumes will grow ratably throughout the year. We don't see producers really -- especially public producers really ramping up activity in the higher price environment. But our expectation is that if this price environment does sustain as we get into the fall and the budget season for 2022, that we will see a pretty significant ramp beyond this year. So I think stay tuned. Our expectation is a pretty steady ramp quarter-over-quarter and that's where we're headed right now. So I think what we've seen so far, quarter-to-date, it's moving in the right direction. I think we feel good about where we are at this point in time, but it's got to continue to grow throughout the year.

And I will add this to Trey's -- I got to move a little further away from him, I guess. But common sense-wise, with our guidance at the $570 million to $600 million, water would have to exceed $300 million, right, to make -- to get there. $300 million.

Yes. And I'll just add, James, our rates and our OpEx per barrel, they won't change significantly. I would expect our disposal rates to be pretty consistent with what we've had in the past. I think our operating expense, we've worked really hard to get that number down, and we got close to $0.25 a barrel. That's really our target. I think if we can achieve that level, that would be a win for this year. That's really what we're focused on. Obviously, this past quarter, we had some one-offs with the storm. But I think getting to that $0.25 a barrel keeping our disposal rates, you should be able to back into pretty reasonable volume number.

Our next question from Jason Mandel with RBC Capital Markets.

Just wanted to focus for a moment on cash flow in '22 and use of it. So it sounds like the EBITDA guidance is effectively affirmed. CapEx the same, I think, $100 million to $125 million was the last guidance there.

Yes. No change there, Jason.

Okay. Great. So without distributions, we're looking at some pretty significant anticipated free cash flow. I think you made comment in the prepared remarks about use of cash flow being towards debt reduction. I don't know if you can give any further guidance. It looks like in this past quarter, the spending was really on the unsecured 26s versus the front end bonds. So just how to think about discount versus maturity.

Yes. At this point in time, our focus is on maturity. It will -- I think we will be focused on the 23s. That being said, our bonds are not highly traded. So sometimes it's take what you can get. We did -- there was still a pretty significant discount on the 26s right around the time of our transaction. And so that's what we did in the past quarter. We have a very small basket of what we can utilize for 25s and 26s. So at this point in time, the focus will be on the 23s. It is something we have to address, and we have to address it over the next, call it, 18 to 24 months.

So let me add to that is when you look at the recovery in the out -- long-dated bonds into the 85 to 90 range, 85 to 88, there's really not a lot of deleveraging to be had there. So it's -- I think it's -- we're shifting, it's more important to push out the 23s.

Very helpful. And then just one final follow-up on that. In the secured deal that was done, you guys bought some room for second lien capacity. Is that something you just plan on reserving for now or is there any intention to use?

At this point in time, we would reserve that. But again, we want to make sure we have options. And so we'll evaluate all sorts of opportunities here as the market dictates.

Our next question comes from Harold Weber with Aegis Capital.

I was hoping if you could try and maybe just in a nutshell, what do you -- I've been here for years and years, we'll look at it this thing, the whole energy space has gone up like crazy and we're at the bottom. What do you think it's going to take? What type of attitude needs to change from The Street towards us? What do they want to see before they come back to us and give us some credibility that we're improving here?

Trey, you need an hour for that.

Let me start.

Well, if you look at it's been to 30 to 2 and then back to 7 and now we're 2 again.

Sure.

I mean I know you might bought lots of stock at $10 and I did this in (inaudible) and haven't seen any management by any (inaudible) while, but I know you guys are there and we're sure that you want to see the thing improve, but this has been very painful, and I'm trying to get an idea of how to look at this going forward, what do I tell my clients? I just don't know how to respond, frankly.

Sure. That's a fair question. I think there's a couple of phases to it. The first phase is we've got to get leverage under 4.75x. And so there can't be any distribution reinstatement until that time. Once we get down there and when we reinstate, then we've got to get, obviously, the distribution to a level that will make sense. If you're going to be at the 10% yield, you need to pay $1 to be at $10. So really, that's the second phase. And we're all large owners of the units. So we have felt the pain as well. So we are -- I think we've -- we're getting our EBITDA back to where it should be, we're keeping CapEx low, we're going to have substantial free cash flow. We can't say how long it's going to take. We're also looking at, as Trey mentioned, some smaller pieces of really noncore assets to sell. So we'll just delever as fast as we can, and then we'll reinstate -- we have to first reinstate the preferred distribution and then go start again on the common. I can't give you a time frame, but right now, it's just watched leverage. That's the key to when we can raise the distribution or reinstate.

Okay. Well, I certainly understand that. But looking at the picture, I mean, the energy space has gone up a lot. How much -- I don't think my people are expecting a very substantive improvement from here. Let's just, as I hope, it hangs around here, that should have a very material effect for us or is there other things that we need to happen other than that? I mean in the market itself has improved. So hopefully, the demand for our services is ramping up as before. But how does the math translate to where we were before? Are we behind [8 pull]? Even so, can we start to expand our free cash flow based on where the rates are currently?

Yes, I think we can. Again, we didn't -- when we put out our current guidance, we didn't expect $65, $70 crude. I think producers are being very prudent right now with their cash flow. They are focused on deleveraging, returning capital to shareholders. We will be tied to the producer activity. However, higher prices will drive volume. And so we said, I think if we get through this year in this type of price environment, I do think that's beneficial for the company and for the services that we provide. And then additionally, on the demand side, you're seeing an increase in transportation activity, whether that's gasoline, jet fuel, diesel, et cetera. That also is a benefit to us in the long term, but that has to be sustained.

Okay. Are there any -- you mentioned some noncore assets potentially you're looking at. In this environment, probably some is not bad, maybe use some of that to pay down the shorter-term debt. I don't know if you guys are looking at that. I'm sure you are. But clearly, the macro numbers in this space are doing better. And I would like to see that we should be able to capitalize on that after what we've been going through here.

Yes. Absolutely. Last year was not a time to try to sell assets as the market...

Surely, but now things are much better. I mean, now things are much different, and there's activity going on in the space.

Yes. So that's something that we will continue to evaluate. Again, we need to do that at a price level or valuation that's deleveraging.

And I'm not showing any further questions in the queue. I will like to turn it back to management for any final remarks.

Great, Carmen. Thank you for your interest. Thank you for the time. We appreciate it, and we'll talk to you next quarter.

Thank you. And this concludes today's program, and you may now disconnect.