Ladies and gentlemen, thank you for standing by and welcome to the Q3 FY 2021 NGL Energy Partners Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to hand the call over to your speaker today, Mr. Trey Karlovich, our CFO. Please go ahead.

Great. Thank you and good evening everybody. As a reminder, this conference call includes forward-looking statements and information. Words such as anticipate, project, expect, plan, goal, forecast, intend, could, believe, may and similar expressions and statements are intended to identify forward-looking statements. While NGL Energy Partners 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 could cause actual results to differ materially from the projections, anticipated results or other expectations included in the forward-looking statements. These factors include prices and market demand for natural gas, natural gas liquids, refined products and crude oil, level of production of crude oil, natural gas liquids and natural gas, the effect of weather conditions on demand for oil, natural gas and natural gas liquids and the ability to successfully identify and consummate growth opportunities and strategic acquisitions at costs that are accretive to financial results and to successfully integrate and operate assets and businesses that are built or acquired. Other factors that could impact these forward-looking statements are described in 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. NGL Energy Partners undertakes 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 and annual and quarterly reports on Form 10-K and Form 10-Q on our website at www.nglenergypartners.com under the Investor Relations tab for more information on our use of non-GAAP measures as well as reconciliations of differences between any non-GAAP measures discussed on this conference call to the most directly comparable GAAP financial measure. With that, I will turn the call over to our CEO, Mr. Mike Krimbill. Mike?

Great. Thanks, Trey. Welcome. I would like to begin with NGL’s business outlook. First, on our water segment, higher crude prices mean more DUC completions and ultimately drilling in the DJ, Delaware and Eagle Ford, which will translate into higher volumes. The DUC count on acreage dedicated to NGL in the Delaware is in excess of 500 wells currently. The DJ has at least 8 rigs running and 3 completion rigs that we know of. With respect to BLM land, we know about as much as you do. Our customers have multiyear inventory of drilling permits. We do not expect a surge of rigs entering the basin. The upstream companies will spend within their cash flows, which can actually be better for midstream as there will be consistency to drilling activity, not the peaks and valleys we have seen in the past. From a right-of-way perspective, we anticipated the current environment and we have secured all the BLM right-of-way we need to service our customers as well as future dedications we are working on. Importantly, we continue to reduce our cost per barrel through installation of station power, limiting diesel and generators, incremental barrels coming to us on pipe and staff reductions through automation and consolidation. With respect to our Crude Oil Logistics, as you know, we settled the Extraction bankruptcy, retaining their crude oil production with a new term supply agreement. We negotiated what we call a price adder. If crude exceeds $50 a barrel, we get to share in that increase. That will come into play beginning March 1. Obviously, we are very fortunate, because crude is in excess of $58 at the moment. With higher crude oil prices, we anticipate increasing volumes. It was important for us to retain these volumes on pipeline and secure dedication over…

Great. Thanks Mike. I am going to start with the refinancing. Obviously, this was a very significant transaction for the partnership. First, I would like to thank our NGL team for all their efforts in pulling this transaction together. It was a – like I said, it was a significant accomplishment. As we discussed on our last earnings call, the extension of our credit facility has been our top priority due to the significant amount that was outstanding on the facility, about $1.7 billion plus $140 million in letters of credit and the near-term maturity of the debt, which went current in October and matured later in 2021. We were working closely with our relationship banks to effectuate a short-term extension into 2023. However, we were not able to meet certain terms and requirements of some of the lenders. We evaluated several alternatives to complete the extension, including asset sales, minority interest investments in our assets, private capital transactions, among others. Ultimately, we made the determination that a refinancing of the entire credit facility would be the best outcome for all stakeholders as it provided a complete solution to near-term maturities and will allow the business operations to recover and grow following COVID, NOPEC, and our recent Mesquite and Hillstone acquisitions as well as the settlement with Extraction. This refinancing pushed $2 billion of maturities that were coming due between now and June 2023 out to February of 2026. It also provided over $200 million of needed incremental liquidity today as we are managing higher commodity prices and a ramp up in demand and activity associated with the COVID recovery. This refinancing obviously came with a cost. Our interest costs will be higher over the next few years. And as Mike noted, our distributions will be temporarily suspended until our…

And thank you. [Operator Instructions] And our first question comes from TJ Schultz from RBC Capital Markets. Your line is now open.

Hey, guys. Good afternoon. Just first so I am clear, with the debt deal done, are you no longer pursuing a JV of the water business?

That’s correct. We are not.

Okay, understood. And then on the water business, as we think about other potential dedications out there, are there dedications similar in size to Poker Lake out there that you expect in the coming year? And is guidance next year dependent on capturing any of those types of dedications or is it more of the DUC conversions driving some of that growth?

Yes. There are two in particular working on that size. None of those are in our numbers. So, it’s more – we anticipate more of the DUCs getting completed. That’s quite a bit of water. And then hopefully, we just kind of maintain a certain rig count and as I said before, get rid of the peaks and valleys.

Okay, understood. And maybe for Trey, on the distributions, I understand the 4.75x leverage target. But where do you want to manage the business longer term from a debt perspective? Should we assume you keep driving leverage lower before restarting the common unit distributions? And then is there a different timeline kind of thinking along those lines to pay on the preferred versus restarting on the common? Thanks.

Sure. So, the 4.75x is the threshold, TJ. So, we have to be below 4.75x in order to make restricted payments, which would include common and preferred distributions. The preferred distributions will accumulate. So, we will have – and we will have to make preferred distributions before we can make common distributions. Obviously, we want to continue to push leverage lower. Our target is not 4.75x. We would like to get below 4x. That’s been a long-term goal and continues to be the goal. But there will be numerous factors that go into that decision. Ultimately, we have to look at the performance of the business, the liquidity position, what maturities look like, what the market looks like at that point in time. So, there will be numerous factors that weigh into that decision, but we will have to make the preferred distribution or address the preferred prior to making a common distribution.

Okay, understood. Thanks.

Yes.

And thank you. And our next question comes from Patrick Fitzgerald from Baird. Your line is now open.

Okay. Congrats on getting the new deal done.

Thanks.

I wanted to ask about the Crude Oil Logistics segment. Obviously, there is a lot of moving pieces in the $45 million reduction, but assuming oil is at current level or it stays at current levels based on the new deal with Extraction, what would you expect the impact to be versus what you had or what you have now kind of on a full year basis?

Want to start?

No.

Yes. So the $45 million impact as we mentioned about $5 million of that’s related to the legal costs. The remainder is driven by volume and then rate. Under the new structure, as Mike discussed, we have what we call a price adder. In today’s environment, we would have a benefit from that price adder. The key to what the earnings profile would look like would be volume. So, Extraction has – they have emerged from bankruptcy. They are looking to start to increase their production. They have activities going on within the basin. Higher price environment obviously should support their activities, but that will be the driver for the Grand Mesa asset, which is the biggest piece of crude, will be what ultimate volumes are moved on the pipeline. Under the new contract, as we mentioned, there is not a minimum volume commitment. So, we are aligned with Extraction and with their production profile. So, they can increase production as well as other producers in the basin. Extraction just happens to be the largest as well as other producers in the basin. If they can increase production out of the basin, that will be to our benefit on Grand Mesa. In the guidance we put out, what, 3 or 4 weeks ago, I will tell you, did not factor in $57 or $58 crude prices. So that’s a benefit to this point in time. The key will be what does that mean from a production profile perspective.

Okay. And how much of a benefit would that be or some range – what kind of a range of benefit would that be?

Yes. I mean, the – what I think you’re getting at is what is our rate on Grand Mesa, what – I think we’ll – what we can say is that the rate, not where it was historically, which was about $4.40, but it’s also not where some people speculated at $2 or less. And with the rate adder, as prices continue to increase or stay at these levels, we get back closer to what our existing – or previous rate was. But again, the key is going to be volume.

Okay, great. Now under the new deal, you can still buy back both your ‘23 and your later-dated senior notes up to $200 million. Where does that fall in the priority spectrum?

Yes. It’s a bit of a balancing act, but obviously, we want to de-lever. We also need to address near-term maturities. We will be generating pretty significant excess cash flow over the coming quarters. I would expect us to look at all options between the ‘23, ‘25 and ‘26. There are – I think there is good reasons to address the ‘23 first because of the near-term maturity, but then you also can capture more of a discount on the ‘25 and ‘26. So it will be a bit of a balancing act, so to speak, but I think all options are off the table. Mike, I don’t know if you want to add?

Yes. I think I would just add we’re definitely focused on ‘23.

Okay, great. And then just – you kind of talked about it a little bit, but $500 million to $585 million midpoint. You said water is going to be a big component of that. If you could – any additional color on – by segment, how you would expect that to occur would be helpful?

Yes. We would expect crude to be fairly consistent with this year’s earnings. It’s our expectation for next year right now. Again, higher commodity price could be a benefit there. Liquids, as we mentioned, we are expecting liquids to perform better than it did this current year. Last year was an anomaly to the upside. There were several onetime items that impacted last year to the good. So we are not expecting to get back to that level necessarily in liquids, but we are expecting improvement. And then water, again, water, if you look at the current run rate of $66 million, that’s a benefit on what we’re seeing for this year-to-date. We have – we’ll have a full year of Poker Lake, which we only have 6 months in the current year, as well as the growth that we’re expecting primarily in the Delaware Basin. We are looking at some improvement in the DJ and the Eagle Ford assets but not significant. It will be driven by the Delaware and what we have going there.

Alright. Thanks a lot.

And thank you. And our next question comes from [indiscernible] from TPR. Your line is now open.

Yes. Thank you for taking my question. I was wondering if you could help me understand the change in gross margins in the Crude Oil Logistics between the second and third quarter. There’s a 10-point deterioration. Are those onetime items that are permanent change in the profitability of that business?

So that – the gross margin in crude will be driven by what the shape of the market looks like. So if earlier in this year we were in a contango market, that will drive or could impact the margins that we generate in that segment as we are – would be holding barrels in that business versus in a backward-dated market where we are trying to liquidate the barrels. If you look over time, the margins, the crude oil margins do have some variability to them depending on what the – again, what the shape of the curve looks like.

Okay. Thank you.

Primarily, crude is driven by – historically has been driven by the transportation fees.

Okay. Then another question on the preferred accruals, assuming that there is no preferred payments in the few quarters coming forward, how much – what’s the total accruals across all 3 classes per quarter or per year, if you know?

It’s between 8 – at the current rate, it’s between $85 million and $90 million per year.

Okay. Thank you.

Thank you. [Operator Instructions] And our next question comes from Philipp Duffner from Aurelius. Your line is now open.

Hi, thanks for taking my question. I was wondering on the Grand Mesa pipeline, right? The volumes fell like pretty dramatically quarter-over-quarter. Could you give some more color on what were the different components that caused that breakdown and also to what level could they rebound or do you expect them to rebound this quarter and going forward?

Yes. So that completely relates to Extraction and their restructuring. So they entered bankruptcy in June. Their volumes came down significantly in our fiscal third quarter, October through December. With our new contract in place, we are expecting those to go back beginning this quarter. It will take some time for them to recover back to what their prior production levels were. They are active in the basin, but it will take some period of time.

Got it. And you mentioned earlier that they diverted some barrels. Did you mean by that they actually put it on different pipelines and those will come back to you like immediately or is there also a delay to that impact?

Correct. Those barrels are coming back this quarter.

Got it. And can you give some more color in terms of the gross profit per barrel in the water segment? I mean, how much scope is there for that to decline from the $0.61 per barrel?

So the disposal rate per barrel, as we increase barrels in the Delaware Basin on pipe, could come down a little bit. However, the operating expenses per barrel in that basin are also lower. So our margin is about the same as compared to some of our ancillary bases as well. So while the disposal rate per barrel could come down over time as we add more pipe barrels in that basin, the OpEx per barrel should come down at relatively the same level.

Got it. And just in terms of like quarter-over-quarter, you’re looking at EBITDA increasing from around like $125 million to $145 million based on the guidance. Can you give some color? I guess on that quarter-over-quarter period, what are going to be the main drivers here?

Sure. So, the incremental volumes coming back on Grand Mesa for crude, we had some one-time charges during the quarter, about $11 million related to the Extraction settlement between legal and a write-off of minimum volume deficiencies. We also are expecting water volumes to continue to grow through the quarter. And then remember, our liquids business has some seasonal components, where our propane business generates most of its profit kind of this call it, November, December through March.

Thank you. That’s helpful.

You bet.

And thank you. And our next question comes from [indiscernible]. Your line is now open.

Yes, thank you. Good afternoon guys. I have two questions. First, I may have missed it but can you give us some insight? Was there any debt repurchased during this quarter at a discount or otherwise?

There was a little bit of debt repurchased during this quarter. In total, during the year, we repurchased about $125 million of face value notes and spent about $75 million, so a net $50 million debt reduction from repurchases.

Okay. Second question, can you give a little color or insight if you have had it from your customers regarding the expected ramp-up for volumes on Poker Lake?

Yes. So the Poker Lake volumes came online exactly how we expected it. We have seen an increase coming into this calendar year and expecting those volumes to continue to increase through this year. We have no reason to believe that those volumes will not be in line with the producer expectations.

Okay. Thank you very much guys.

Yes.

Thank you. And our next question comes from [indiscernible]. Your line is now open.

Hi, good afternoon guys. First question is if God forbid, if oil were to fall back into 20s, 30s, how secure is the global agreement with Extraction? Would they be again easy to retrieve themselves from the contract or divert barrels to another pipeline?

No, those – the barrels would be dedicated. The question would be how – what does their drilling activity look like at that – at those levels. But any barrels produced on the dedication would come to our system.

Okay. And then the leveraging from what we are – from what I’m seeing, is going to be very slow possibly in the next, I don’t know, 5, 7, possibly 10 years to de-leverage the business to an appropriate level before paying preferred and common. But ballpark figure – this is a hypothetical question. What would be the EBITDA if all three segments were at full capacity? Say the premium was at 3 million barrels, Grand Mesa was at 150,000 barrels, what would be the EBITDA if all three segments were firing on all 8 cylinders, ballpark figure?

It could be more money than we can count. I don’t know what’s in – it would be a happy day. But I think to your first observation, if we were to – if your EBITDA is $600 million and your debt is $3 billion some, if you are reducing your debt by $300 million, that’s half turn a year.

Okay.

So just on that math, it would take 3 years to get down to 4.5x if there was no increase in EBITDA, which over the – we expect better results each year from our water business. So yes...

I appreciate that.

10 years.

And one final – okay. And one final question. As a retail investor that owns tens of thousands of shares of NGL and I think I speak for the retail community, what would be the incentive for us to stay invested? Now that the dividend is gone to the bondholders and possibly for the next 3, 5 years, what would you think would be our incentive to stay invested for long-term? Thank you.

I don’t know that I can say much about buying and selling our equity because we’re in a blackout period. So all I can say is watch what I do.

Okay. Thank you very much, Mike. Appreciate it.

And thank you. And our next question comes from [indiscernible] from JPMorgan. Your line is now open.

Hi. Thanks for taking the questions. I know you guys can’t comment on customer-specific volumes, but when you say that that’s all the deferred volumes during the quarter, were they shipping any volumes on Grand Mesa? I’m just trying to bridge into what current transport volumes look like in 4Q and run rate going forward?

Yes. So there – it’s limited of what we can disclose regarding shippers on Grand Mesa. So as we stated, they had – they didn’t deliver volumes. They did defer a significant amount of volumes. They are bringing volumes back. So unfortunately, I can’t give specifics around it, but they did deliver some volumes during the quarter.

Okay. Thanks.

Thank you. And our next question comes from [indiscernible] from Lonestar Capital. Your line is now open.

Hi, guys. Thank you for taking the question. When you created your guidance for next year’s EBITDA, did you have any revenue adds from the new XOG contract baked into guidance or was guidance included at the full – yes, next year’s guidance?

Yes. We built next year’s guidance based off of the new contract and the settlement with Extraction.

And did that – did your estimates assume – well, I guess I’d ask what did your estimates assume for the price of oil vis-à-vis the revenue adds?

Yes. When we put this guidance together as we were working with our bank group and it was less than $50 a barrel, we were below where the price adder is today.

And if you were to reassess guidance, assuming current oil prices stay steady throughout the year, how would that change your guidance?

Well, it wouldn’t be lower to me.

Assuming – I understand. Assuming your volume estimates stay the same and assuming oil is where it is versus below – the below $50 that it was.

Yes, hard to answer. There is obviously a lot of things that go into putting together our guidance. Just the crude price alone would have a benefit. As Mike said, it wouldn’t be lower, but quantifying that right now would be difficult.

Okay. Unrelated topic, given what New Mexico cited about using freshwater for drilling and fracking, is there any opportunity for you to take the produced water that you currently dispose of in wells and recycle it and sell it back as frac water?

Yes, definitely. We think that’s a – it’s taking something that was a cost to us to dispose and turning it into a new revenue stream in that the producers, for the most part, we think of – developed the chemistry to be able to use the produced water. And so we think that’s a real growth area going forward. We are already selling produced water. And I don’t know if we set that out separately in our financials.

Not yet.

Not yet. So we may – it may be something we do. So you can see how much it is.

And do you have ongoing conversations with current customers or current drillers in the New Mexico area to explore that opportunity?

Yes.

Okay, great. Thank you very much.

Thank you. And I would now like to turn the call back to Trey Karlovich for closing remarks.

Great. Again, thank you everybody for joining us. And this was an important quarter for the company. We have addressed, as we have mentioned, quite a few of the unknowns and uncertainties, gotten back on our front foot and looking forward to a successful fiscal 2022. I hope everybody stays safe and healthy.

Ladies and gentlemen, this concludes today’s conference call. Thank you for participating. You may now disconnect.