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Presentation

Operator: Good morning and welcome everyone to Granite Ridge Resources First Quarter 2024 Earnings Conference Call. Currently, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this call is being recorded. I will now turn the call over to Wes Harris, Investor Relations [Technical Difficulty]

Wes Harris: Thank you, operator, and good morning, everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Luke Brandenberg, our President and Chief Executive Officer, who will provide an overview of key matters for the first quarter and an outlook for 2024. We will then turn the call over to Tyler Farquharson, our Chief Financial Officer, who will review our financial results. Luke will then return to provide some closing comments before we open the call up for questions. Today’s conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements.

We would ask that you also review the cautionary statement in our earnings release. Granite Ridge disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday’s press release in our filings with the Securities and Exchange Commission. This conference call also includes references to certain non-GAAP financial measures. Information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures is available in our earnings release that is posted on our website. Finally, as a reminder, this conference call is being recorded.

A replay and a transcript will be made available on our website following today’s call. So with that, I’ll turn the call over to Luke. Luke?

Luke Brandenberg: Thank you, Wes, and appreciate everyone joining this call. It seems like we just did this, but I’m always glad to have an opportunity to share an update on the Granite Ridge story. The first quarter built on our track record of workmen-like quarters. Nothing flashy, just continued solid execution. Today I’d like to talk about some of our accomplishments, things to look forward to, and share a bit more about what our strategic partnership initiative looks like as we continue to bridge the gap between operated and non-op. I’ll start with the credit side. We announced last month that we successfully expanded our credit facility to both a $300 million borrowing base and elected commitment. The bigger story is that we were successful in fully syndicating the facility, taking it from six to 14 banks.

Commitments came in nearly 2 times our target, and with the financial strength and capacity of our partners, we believe we can triple our credit facility within this group. Now, this expansion does not change our views on leverage. We still target net debt to EBITDA of 0.5 times and expect that will bounce between about a third turn and two-thirds of a turn. To put round numbers to that based on about $300 million of trailing EBITDA, I expect we will balance between $100 million to $200 million of net debt and average around $150 million or less. I want to extend a heartfelt thank you to our existing banking relationships and for your support and I’m excited to welcome our new banking partners. I’ll now briefly hit on Vital. As I mentioned, last quarter, we received 1.1 million shares of VTLE, about 50-50 common and preferred when we sold certain Permian assets to Vital as part of a tag right we had on Vital’s acquisition of assets from Henry Resources.

This was a compelling opportunity to sell production at an operator premium and we will look to exit this position in an orderly fashion this year and pay down debt to ultimately recycle the proceeds into development opportunities. Now let’s talk about results. Tyler will get into the details, but I’d like to hit on the results as compared to our expectations as well as what we are looking at for the coming quarters. Production came in slightly higher than expected at 23,800 barrels of oil equivalent per day. That was down 8% from last quarter’s reported compared with an expected 10% decline. Now both of those are unadjusted for the sale to Vital. Adjusted numbers, or as Tyler likes to call it, same-store sales, are down 3% compared to an expected 5%.

Primary drivers for the beat, albeit minor, are a bit about performance on the oil side offset by deferrals on the gas side. That is a theme we expect more of as some of our operating partners have elected to defer dry gas production in this price environment, specifically in the Haynesville and Dry Gas Eagle Ford. This may impact our gas production for the year, but we have opportunities in the works to reallocate that capital to oil-weighted projects expected to come online this year. We will keep you in the loop on that as the year progresses. We turned an adjusted EBITDAX of $64 million, which was a bit higher than expected due to help on both oil prices and production. On the deal front, we closed four transactions during the quarter, all were in the Permian and the vast majority in the Delaware side.

Total entry, including carries was $6.8 million for 2.5 net locations. That equates to $2.7 million per net location, which is a bit higher than our target of closer to $2 million, but note, not all net locations are created equal in terms of both quality and development timing. All 2.5 of these net locations have either been turned to sales or are in process, including a 1.4 net well pad that we are drilling through our controlled capital strategy. Additionally, we have nine deals that have either closed since quarter end or are fully agreed to and in the documentation stage with an aggregate entry including carries of $20 million across 10.5 net locations. While each of these transactions are accounted for in our acquisitions guidance number, I would note that not all $20 million will hit in 2024, as some of those carry dollars will go out the door in subsequent years.

On the production side, I mentioned in March that we expected to see a ramp beginning in the third quarter. The deferral of some dry gas production that we had expected to come online in the second quarter, which we are happy about, by the way, will likely slow-down that timeline. We now expect production to be roughly flat for the next couple of quarters prior to a ramp in the fourth. On the CapEx side, the second quarter should be roughly a quarter of our D&C CapEx for the year, but it is setting up to be our largest quarter of acquisitions for the year. It can be tough to tell if a deal will close on June 30th or July 1st, but based on deals closed quarter-to-date and those expected to close in the next two months, we are looking at about 75% of 2024 acquisition CapEx hitting in the second quarter.

Note, this number includes both cash paid in the quarter and carry dollars that hit in the quarter. I’ll wrap up by talking a little more about our strategic partnership strategy. We define a strategic partnership as more than just a deal, in other words, a partnership that gives Granite Ridge access to broader deal flow or more control over development timing. Ideally, it is both or what we call controlled capital. With controlled capital, our deal flow broadens to include operated opportunities where we have control, specifically development timing. Controlled capital not only represents operated inventory that we can develop with a strategic partner, it opens the door to a broader set of asset buyers as we could sell drilling units to operators looking to add inventory.

Operating inventory trades at a premium and will allow us to further build the case that Granite Ridge is undervalued from both a business and some of the parts value. To put some numbers to this, Granite Ridge controls inventory of 40 gross or 21.9 net operated locations in the Permian. In Loving County, we plan to turn to sales a pad of 5.5 net single-mile wells early next month and a second pad of 1.4 net single-mile wells late in the third quarter. We are currently running one rig through a strategic partner and plan to pick up a second later this year. Traditional non-op is the cornerstone of the Granite Ridge Foundation, but controlled CapEx is where we are going. While we now expect controlled CapEx to be upwards of 40% of our 2024 D&C, our goal is for a super-majority of our capital to be controlled in the next several years.

We are bridging the gap between operated and non-operated by demonstrating that non-op does not mean non-control. With that, I’ll ask Tyler to dive a bit deeper into the numbers.

Tyler Farquharson: Thanks, Luke, and good morning, everyone. Average daily production for the quarter was 23,800 BOE per day, up 3% compared to reported Q1 of 2023 and up nearly 11% after adjusting for divested assets. We expect production to be flat through the end of the third quarter before increasing in the fourth quarter and exiting 2024 at a high for the year. Our annual production guidance range of 23,250 BOE per day to 25,250 BOE per day remains unchanged and represents 7% midpoint growth for the year after adjusting for divestitures. Oil production mix for the quarter was 45%, lower than our guidance expectation of 47% for the year, but as Luke mentioned, should drift higher throughout the remainder of the year as some of our natural gas-focused operators defer development projects.

Our adjusted EBITDA was $64.5 million and adjusted EPS was $0.12 per diluted share for the first quarter of 2024. Adjusted EBITDA was down 8% from the prior year due to lower natural gas prices and the impact of divested assets. Per unit lease operating costs were $7.13 per BOE and production and ad valorem taxes were 6.5% of sales for this year’s first quarter, both of which were within our guidance range for the full year 2024. G&A expense excluding non-cash stock-based compensation was $2.76 per BOE for the quarter. Our annual guidance range of $23 million to $26 million is unchanged. During the quarter, our operating partners completed and placed on production a total of 58 gross or 5.1 net wells, with 57% of the activity occurring in the Eagle Ford and 30% in the Permian Basin.

In total, we continue to expect 22 to 24 net wells to be placed online during 2024, with nearly 80% of those wells being in the Permian Basin. Total capital spending during the first quarter of 2024 was $65 million, including $3 million of acquisitions that closed during the first quarter. For the year, we expect our total capital expenditures to remain in our previously guided range of $265 million to $285 million, including $35 million of budgeted acquisitions. We also continued our ongoing quarterly cash dividend. During the quarter, the Board declared an $0.11 per share cash dividend that on an annualized basis represents a 6.7% dividend yield measured against Tuesday’s closing price. Finally, subsequent to quarter end, we successfully completed our semiannual borrowing base redetermination, increasing both our borrowing base and elected commitments to $300 million, and expanding our lender syndicate through the addition of nine new banks.

Our balance sheet remains a strength with pro forma liquidity over $180 million and leverage of 0.4 times net debt to trailing EBITDA, which remains below our half-turn target. I will now hand it back to Luke for his closing comments. Luke?

Luke Brandenberg: Thank you, Tyler. I’ll wrap up by sharing some takeaways from our company-wide town hall that I host each quarter. This quarter’s theme was that there may be temporary dislocations, but ultimately the law of supply and demand will determine the price of GRNT. I’ll start with a temporary dislocation. I believe GRNT is in a period of temporary dislocation due to demand destruction or sustained decline in demand in response to limited supply. In our case, this demand destruction is due to our tightly held shareholder base. We chat with investment firms on a regular basis that seem to buy what we are selling, as demonstrated by their willingness to continue to share their time and follow the story, but our trading volume is not quite enough to meet their investment mandate.

There are plenty of green shoots to point to, but the fact is that time will solve this. We must stay patient and continue to focus on the E or earnings and let the market worry about the P or price. As a management team, we are a bit limited in what we can do on the supply side. Absent issuing shares as part of an acquisition, we do not control the supply of GRNT shares, practically issuing shares is unlikely as it would be tough to find an accretive stock yield given where we currently trade. But there is a lot we can do on the demand front, primarily in two ways. The first is finding more folks to help us tell the Granite Ridge story. Thanks to Steve and Chris at Evercore for picking up coverage and to all the folks that invite us to their conferences and host us for non-deal roadshows.

A list of all our upcoming events can be found in our earnings release. The second is doing the research and pounding the pavement to find investors that we solve a problem for today. As we transition our shareholder base and demonstrate that what we are building is different, repeatable and resilient, I believe that Granite Ridge will re-rate and drive value for investors that put their trust in us. But today there’s a particular group of investors that I think we immediately solve a problem for and as generalists, that benchmark to the Russell 2000. The Russell 2000 is now 7.4% energy and has generally been trending up in the past several years. The NAV-driven valuation of small-cap energy can be tough for the generalist investor. Take the recent back and forth with SilverBow and Kimmeridge.

If nothing else, this goes to show that it is difficult to ascribe current value to long-term oil and gas assets. Additionally, with the current reconstitution, according to RBC, several highly traded Russell 2000 energy names may migrate from the Russell 2000 up to the Russell 1000, including Permian Resources, Matador and Civitas. Granite Ridge can be a part of the reallocation solution by providing the purest asset-level exposure to near-term development in a diversified vehicle with low leverage and a current yield of over 6.5%. We are undervalued now, but one day we won’t be. It likely won’t be a transformative event that causes Granite Ridge to re-rate. It will be a series of many catalysts, transitioning of the shareholder base, increasing trading volume, additional investors showing up on ownership reports, continued workman-like quarters of consistent performance, more and better information on strategic partnerships, and our controlled CapEx strategy.

We believe it will happen, and I invite you to be a part of the Granite Ridge story that the great folks across our organization are working hard to write. Please do not hesitate to reach out, and I hope to see many of you over the next several months. And with that, we’re happy to answer any questions folks you may have on today’s call. Operator?

Operator: Thank you. We will now begin our question-and-answer session. [Operator Instructions] The first question comes from the line of Phillips Johnston from Capital One. Please go ahead.

Phillips Johnston: Hey, guys. Thanks. I wanted to ask about your oil mix. Tyler, I think you mentioned the 45% mix for the quarters below your guidance for the year. I realized you’ve got some deferred gas projects going forward that are going to improve that. But can you maybe walk us through some of the drivers that are going to move your absolute oil production in, I guess, Q4, a little bit higher than that 45% mix?

Tyler Farquharson: Hey. Good morning, Phillips. Thanks for joining. Thanks for the question. A couple of pieces I mentioned, we’re seeing some deferrals on the gas side. I think that’ll help accelerate the oil mix increasing a little bit quicker than we thought. On the last call, I mentioned that just across the year, we start out in the mid-40s and slowly working our way up. If these gas deferrals — some of this is more conversation, but we’re having operators saying, hey, we may duck some wells, we may defer some drilling. Instead of drilling eight wells, we’ll drill four. We actually have an operator in the Permian that’s just simply curtailing gas production in Reeves County due to terrible Waha pricing. So as that continues, I think you’ll see that oil percentage creep up.

You may even break 50% as we get later in the year. We anticipate that in the next several years it’ll be upwards of 50%, but we just expect to creep from, call it 45 to 50 or so, steady across the next three quarters.

Phillips Johnston: Okay. Sounds good. And then I guess your Q1 oil realization was a nice premium to NYMEX. Can you maybe talk about what sort of drove that and how we should sort of think about that relationship going forward?

Tyler Farquharson: Yeah. Sure. Phillips, it’s Tyler. We have some lumpiness in our differentials, if you look back, historically, over the last handful of quarters, and I think you’re seeing some lumpiness again in the first quarter. We did have a small out-of-period adjustment in the first quarter that drove it a little higher. But moving forward, I still think on average, over time, you should expect to see minus $2 to benchmark price.

Phillips Johnston: Okay. Great. Sounds good, guys. Thank you.

Tyler Farquharson: Thank you, Phillips.

Operator: The next question comes from the line of Michael Scialla from Stephens. Please go ahead.

Michael Scialla: Good morning, guys. Wanted to see if I get some more detail on the 5.5 tills that you’re looking at with the partnership. I think, Luke, you said those are coming online in the second quarter. Have any of those been completed yet? And I guess what needs to happen to bring those online?

Luke Brandenberg: Yeah. Good morning, Mike. Thanks for the call and thanks for the question. So that is 5.5 net single-mile wells. They’re in Loving County. And so they actually are completed. I Got the Christmas trees on. They are ready to go actually got a picture two days ago of everything fully ready to turn them on. We’re really just waiting on the pipe. And so the expected turn-to-sales date is June 1st. I love it for it to be earlier, but that’s really what we’re targeting right now. Again, it’s just more piping issues, everything on the operations side is done, and frankly, it was done in tremendous fashion. We came in 14% under AFE on the drilling, 8.5% about on the completion side. Just a data point. The drilling was really more driven by just drilling quickly — not necessarily by material price decreases. The completion side was pretty similar. We’ve just got great crews out there, and they’ve really done a tremendous job.

Michael Scialla: That sounds good. You mentioned the partnership CapEx. Now you’re thinking 40%, I think you were talking in the 30%, maybe 35% earlier. And you see that going higher. Can you talk about where that may go next year and beyond?

Luke Brandenberg: Yeah. That’s a good question. So what we’ve talked about right now, Mike, is we had two rigs we were actually running earlier this year. We laid down one rig, or have another group that we’re kind of trading it back and forth with. There’s a good chance we pick up another rig later this year. That’s the plan. And what I’d say is the second rig for us is really more opportunistic. What it’s allowing us to do is hit some of these short-fuse opportunities. Frankly, the one that we’re bringing on, kind of late third quarter, early fourth quarter, the 1.4 net well pad. That was a neat deal where there was a large independent, who had an expiry coming up and they weren’t going to be able to hit it. So we were able to say, look, we’ll pick up another rig.

We were able to get it from an operator hot rig crew that we knew. In fact, I think they were using the same drilling consultant able to pick it up to hit that unit. So I wouldn’t assume two rigs running full time, but I would assume 1.5-ish rigs next year. And so, I’d expect that you’d see a relatively similar number, maybe a bit higher, call it mid-125 to 130 would be my guess right now.

Michael Scialla: Got you. And then last one for me. I guess, given that the partnership activity is probably going to dictate, to a large extent, your capital spend. It sounds like second quarter is going to be the high watermark for the year. Does that come down in the second half? And I guess any — I know, you haven’t given formal guidance on second quarter, but something in that $80 million for development CapEx for second quarter, kind of in the ballpark?

Luke Brandenberg: That sounds a little bit high to me right out of the gate largely because we don’t have that second rig running the whole second quarter. It’s generally down. Most of the second quarter will pick it up into the third. So I’d expect something pretty similar to what you’re seeing this first quarter, maybe slightly less.

Michael Scialla: Got it. Okay. Thank you much.

Luke Brandenberg: You got it. Thanks, Mike.

Operator: The next question comes from the line of Jeff Robertson from Water Tower Research. Please go ahead.

Jeff Robertson: Thanks. Good morning. Luke, on the controlled capital efforts, are you looking at opportunities both to put together organic deals that Granite Ridge assembles and takes to an operator and look at operators who might be looking like a partner, where essentially, Granite Ridge comes in and works as a capital provider?

Luke Brandenberg: Yeah. Great question, Jeff. Thanks for the call. The answer is yes to both. And so, we look at it from a few pieces, one, with controlled capital via strategic partnership, they’re the ones generating the opportunities, and really, we’re the capital provider for that. Another piece is, we’ve put together units, just boots on the ground. And one thing that we did this last year, and we actually are finishing up documents for another unit this year, where we scurried into an area. We saw EOG putting together a position. And so we scurried in there, started picking up leases. Weren’t the only ones that had the idea. There was another non-op group that was doing a similar thing. And so we, between the two of us, we had enough critical mass to get a drillable unit.

And so what we did is combined forces, went out and ran an RFP process, if you will, to talk to several different operators, and said, hey, we’d like to see these zones drilled. And here’s the date that we’d like to get them drilled by what would it take to get you to come in here and do that? And so that was a really neat opportunity work. I’d call it that broader controlled capital budget, because we did set the drilling plan, we did set the drilling timeline, and we were able to go out and pick the operator. So we’re doing that as well. One thing that we’re not really doing right now, not to say that we wouldn’t, but is coming in and just being a capital source alongside an operator looking to stretch their dollar, we could do that. I think it’s an interesting strategy, but we haven’t really done that to date.

Most of the opportunities that we’ve seen along those lines have a heavier production component than our typical opportunity. And so, we’ve generally shied away from them because we’ve said in the past we’re just — we’re not very good buyers of production because we just end up way off the mark from a valuation perspective. We just see more downside to upside buying production, so we tend to be more conservative, which I appreciate.

Jeff Robertson: Can you characterize how receptive some of the operators are to the terms and conditions and the type of capital that you all bring to bear in these — in the partnership concept?

Luke Brandenberg: Yeah. That’s a great question because it’s one that we’re really proud of. We came up with a bit of a new mouse trap on this control CapEx strategy, and I think it’s very appealing to the right partners. Really what it looks like is we’re taking the approach that we’re bringing the majority of the capital to the table. So we’re going to control the asset, but you, our partner, you’re going to control your company. And so, it really is more of a partnership just at the asset level to where we have control, but they fully manage their company and they own their assets outright. We don’t determine if and when they sell. That’s up to them. They really do like that. Another component I think that’s very attractive is most of these deals are really unit-by-unit deal.

We have an overall structure that we use, but they’re on a unit-by-unit deal. And so what that means is it gives the opportunity toward the operating company, but folks that are out there sourcing the deals, to earn incentives on a unit-by-unit basis, which is particularly helpful given this price environment where you’ve just seen private equity-backed exits extend. The two to four-year deal is now five to seven. But when you have a unit-by-unit carry, it really allows operators the opportunity to start realizing the fruits of their labor sooner and continue to incentivize the team and then frankly continue to reinvest because that’s what they’re doing. We’re seeing partners that are really putting material dollars back into the business because they believe in it and they want to grow it.

Jeff Robertson: Last question on the controlled capital business model your — the Permian accounts for the route on almost 50% of Granite Ridge’s first quarter 24 production. When you think about the different regions that you operate or do you see greater opportunity in some regions versus others for these types of structures.

Luke Brandenberg: Yeah. We absolutely do it. And so what we talk about at the highest level, what this is, it’s representing investments where we are taking more concentration, and we feel comfortable taking that higher concentration because we’re mitigating that by one control but also by higher expected returns. But what that means is, if you’re taking more concentrated investment risk, we want to be very sure that we’re in areas that have the highest probability of success, or, said another way, the lowest variability. And so, other areas that I think are attractive are places like the Eagle Ford, places like the Bakken, where in the right areas you have quite consistent results and just much less variability. I think that’s a big piece of the strategy.

It doesn’t mean that we wouldn’t go other places, but those are two basins that, again, are really known for their consistency and lots of development, such that you’ve got a lot of data points around you to feel good about what you’re underwriting. So I would think about basins that have low variability, that have plenty of development, and just being able to de-risk the subsurface as much as possible.

Jeff Robertson: Thank you.

Luke Brandenberg: Thank you. Appreciate it.

Operator: The next question comes from the line of Michael Scialla from Stephens. Please go ahead.

Michael Scialla: I just want to follow-up on the inventory. Luke said in the partnership, I think you said 29 net locations at the moment. Are all those in the Delaware and most of those in Loving County? I guess just looking for a little bit more color on what that inventory looks like?

Luke Brandenberg: Good question. I may have been talking too quickly. So it’s 40 gross, or 21.9 net locations that we control. Most of it is in the Delaware, but I’d say not all of it. We have some other opportunities we’re working on in the Midland, but the vast majority is in the Delaware, and of that, the vast majority is in Loving County. We have a couple deals in Reeves. We have a deal that we’re working on in Ward. And so we’re covering the broader Delaware Basin. And frankly, the driver of that is. This is one partner in particular. They’re Midland base. They’ve been there a long time. They know everybody and just have a tremendous reputation in Midland. And so they’re getting access to some unique deal flow, which we’re excited about.

But the Delaware is just far less consolidated than the Midlands. You go to the Midland basin and you look around, it’s just much harder to find undrilled units. And frankly, anything that is undrilled, there’s generally a story to it. So it’s a little bit more difficult. And as a result, just more and more deals flow out of the Delaware relative to the Midlands. That’s not intentional. We’d love to continue to put capital to work in the Midland basin as well. Again, just a quantity of deal flow versus hit rate. We’re just seeing a lot higher quality — excuse me — higher quantity in the Delaware.

Michael Scialla: And are most of those that are in the Delaware, are they the 1-mile type of the ones similar to what you just drove?

Luke Brandenberg: It’s a mix. And so these couple that we’ve talked about are one mile, but we have some wells that are over 10,000. They’re going to be, 1.25 to 1.5, excuse me, 2.25 and 2.5. So we are looking at some extended laterals as well. But I would tell you again, everybody’s got drilling info or envious these days. And they can look and find the white spot on the map. If there’s a white space, 10,000-foot unit, everybody’s looking at it. It’s the stuff that’s got a little bit of hair, where you can get scrappy and block and trade. And so, I think our average well in that is probably somewhere around 7,000 feet. And so you do have maybe more 1 mile versus 2 mile, but there’s a good number of extended laterals in there as well.

Michael Scialla: And could you characterize the zones you’re talking about these kind of the primary Wolfcamp A, Bone Spring, or are they more kind of secondary targets? Is that the reason that you had the opportunity to get in there and capture?

Luke Brandenberg: Yeah. It bounces around a lot. So some — its primary zones. And in fact, if I were to say, what’s the majority of the targets? The majority of the targets that we’re going to drill anyways are in the primary zones and that’s where we’ve allocated value. But you do have some secondary opportunities as well. We have an opportunity with a large operator, where they went in and they developed the Bone Spring and Wolfcamp A. And fast forward a few years, the B and C are now actively developed around them, but they had not been drilled yet. And so we were able to farm in on them and drill those locations. The neat thing about that is we were drilling beneath existing wells. There’s just a lot of synergies from a cost perspective.

We’re able to leverage the facilities. In some cases, we’ve talked about turning over operations once the wells are online, which is great. These folks are really good at what they do on the operations side. And so, we don’t have to spend the time, energy or effort managing wells. But if I look at in the majority of the inventory, it’s Bone Springs X, Y and A, but there is a decent number in the B as well, and some C.

Michael Scialla: Thanks for the detail. And just one last one. It looked like your share count went down about 2 million from the prior quarter — your diluted share count. I know your buyback expired at the end of the year. I didn’t see anything on repurchases. Is that just some technical difference in the way that shares for Canada in the quarter or something else going on there?

Tyler Farquharson: It might be the quarterly average. You’re right. The share repurchase ended at 12/31/23. So it could be just average share counts between the fourth quarter and the first quarter. That could have gone down by two million.

Michael Scialla: Okay. Got it. Thanks guys. Appreciate it.

Luke Brandenberg: Absolutely. Thanks for the question.

Operator: As there are no further questions at this time, this concludes today’s conference call. Thank you for your participation. You may now disconnect.