Alvopetro Energy Ltd. (ALV), an oil and gas exploration and production company, reported its fourth-quarter results for 2023, highlighting a 26% increase in production despite earlier demand disruptions.
The company's President and CEO, Corey Ruttan, outlined the financial performance and strategic plans during the earnings call, focusing on the Murucututu project's potential and the company's commitment to shareholder returns through a balanced capital allocation model.
Alvopetro's production reached 2,143 barrels of oil equivalent per day in the fourth quarter, with a notable 35% increase in gas production in March 2024 compared to the previous month. Despite a decrease in 2P reserves, the company reported an increase in volumes associated with the Caruacu zone and declared a dividend of $0.09 per share for Q1 2024.
Key Takeaways
- Q4 production increased by 26%, reaching 2,143 barrels of oil equivalent per day.
- March 2024 gas production rose by 35% from February.
- The company reported a decrease in 2P reserves but an increase in Caruacu zone volumes.
- Alvopetro's netback margin stood at 90% in Q4.
- A dividend of $0.09 per share was declared for Q1 2024.
- The company has returned over $40 million to shareholders since Q3 2021.
- Alvopetro aims for a production target of 18 million cubic feet per day.
Company Outlook
- Focus on derisking and unlocking the value of Murucututu fields.
- Plans to reach a production target of 18 million cubic feet per day in the near term.
- Long-term vision to double the production target.
- Capital program focused on optimizing production and developing Murucututu and Cabure assets.
Bearish Highlights
- Decrease in 2P reserves reported.
- Uncertainty regarding the impact of high hydro reserves and renewable energy growth on Brazilian gas demand.
Bullish Highlights
- Increase in volumes associated with the Caruacu zone.
- Industry-leading netback margin of 90%.
- Strong free cash flow generation capacity.
- Attractive natural gas pricing and operating margins.
Misses
- Demand disruptions and higher nominations from partner led to initial production decrease.
Q&A Highlights
- Alvopetro is open to new growth opportunities but prioritizes the Murucututu asset.
- The company is not actively seeking to be acquired but would consider compelling offers for shareholder decision.
- Redetermination at the unit could impact reserves; final decision expected by late March or early April.
Alvopetro Energy Ltd. remains focused on delivering results and providing value to its shareholders. The company's balanced approach to capital allocation, strategic development plans, and commitment to shareholder returns position it for potential growth in the competitive oil and gas market.
As the company moves forward with its development programs, particularly at Murucututu and Cabure, investors will be watching for the impact of these initiatives on production levels and overall company performance.
Full transcript - Alvopetro Energy (ALVOF) Q4 2023:
Corey Ruttan: Good morning. Thank you for joining us today for our Q4 Results Webcast. I'm Corey Ruttan, President and CEO, and I'm joined by Alison Howard, our CFO, and Adrian Audet, our Vice President, Asset Management.
Alison Howard: Good morning, everyone. Just a few administrative items before we start. We are recording today's earnings call, and there will be a replay on our website later on today. All participants are in listen-in only mode. We will be having a Q&A session at the end of our presentation. If you're logged in online and watching on Zoom (NASDAQ:ZM), you can use the Q&A button at any time to log your questions, and we will get to those at the end of our presentation. If you are dialing in, you can send us an e-mail at socialmedia@alvopetro.com, and we will answer the questions that we get by email. And then lastly, as per usual, we could do go through various, non-GAAP measures and forward-looking statements, so please, we encourage you to review all of the cautionary statements and other advisories that you'll find in our corporate presentation, at the end of that corporate presentation that's on our website. With that, I'll hand it back over to Corey.
Corey Ruttan: All right. Thank you, Alison. Okay. So just, show this chart that we all often show, it shows all of our production history since starting, our production from our Cabure field back in July of 2020. You can see in 2023, we did have a decrease due to some demand disruptions with, in the State of Bahia with our off-taker Bahia Gas, particularly in the in the second and third quarters. We also saw some higher nominations from our partner at the Cabure unit, which did impact the amount of production available to Alvopetro. So, the net result is, you can see, we actually had an increase in the fourth quarter of 2023, up to 2,143 barrels of oil equivalent per day, that was a 26% increase over the third quarter, and our 2023 average production averaged almost the exact same number at 2,142 barrels of oil equivalent per day. We did see lower demand from Bahia Gas at the start of 2024. You can see that in the January and February production that we've already announced. We did have that production increase up again, in March. We announced yesterday that our gas production for March to-date is a little over 11 million cubic feet a day, which is up from just over 8 million cubic feet a day in that February number that you see there, so about a 35% increase.
Adrian Audet: In the in the last month, we updated our reserves contingent and perspective resource report with GLJ as the evaluators, and this was previously announced in February 26 this year. Just some highlights of this report. We had 0.8 million barrels of oil production produced in 2023, but we only saw our 2P reserve decrease by about 0.3 million BOE. The primary reason for that is we had additional volumes associated with the Caruacu zone within our Murucututu field that we're producing and/or pursuing, sorry. We'll talk more about that in the later slides. And this increase more than offset some of our technical revisions and production results from other wells and fields. Alvopetro continues to focus on derisking and unlocking the contingent resource reports and values we have associated with these fields at Murucututu. A note on the Cabure asset, these reserves are based on the 49.1% working interest as of December 31, and that redetermination of this is currently underway. The chart below shows the buildup and the relative magnitude of the 1P/2P reserves as well as the contingent prospective resource report value. We also plot in the enterprise value of Alvopetro, and it's just under half of the total 2P value of the reserve report. Here we can see our gas pricing that we use in the reserve report evaluation. This is from our GSA with the offtaker Bahia Gas. If you recall, this gas pricing is reset semi-annually, so February and August with the last reset of February of this year. So this is based on three benchmark pricing: Henry Hub, Brent pricing, and National Balancing Point in the U.K. You can see the historical pricing as well as the forward-looking pricing that's from GLJ Petroleum Consultants. And then the green line on the top is the ceiling price and the red lines are lower price with the contract. And then the Alvopetro effective price is the black line you see there. And it's effectively tracking the ceiling price in the near-term here. We have a strong natural gas price relative to our peers with downside protection from lower price here.
Alison Howard: So just diving into the results from the quarter and for the year, so building off what Adrian was talking about, and our realized price overall in the quarter. If you recall, this chart here shows our operating netback, that's our profitability per barrel of oil equivalent. We expressed it per barrel of oil equivalent, that's the green bar that you see. So we were just under $70 in Q4 2023. So our realized price overall was $77.60, so that includes our natural gas price, a realized price of $12.85 per Mcf in Q4. It was just down marginally from Q3, mostly due to foreign exchange. We do get paid in local currency, and there was a slight devaluation of the Brazilian reais relative to the U.S. dollar. So our overall realized price decreased from $78.90 to $77.60 in Q4. And then from that realized price, to compute our netback, we take off royalties, that's shown in orange. And then our operating expenses, production expenses in gray there. Royalties were once again quite low. Recall that our natural gas royalties are based-off of the equivalent value of raw unprocessed gas, so closer to Henry Hub. So with Henry Hub pricing staying relatively low, our royalty rate was about 2.7% in the quarter. And then our production expenses, we did have a 26% increase in production from Q3 that Corey was talking about earlier. So on a per BOE basis, our production expenses did go down. We did see a slight increase overall in dollar terms on our production expenses. But with those higher volumes, it decreased per BOE. And we ended the quarter with netback of $69.69, and that's very similar to -- for year-to-date 2023, was just under $69 netback. And overall, if you look at that green bar relative to the realized sales price at the top there, we show our netback margin as a percentage of that price, and at 90% in the quarter and overall for the year, that's quite remarkable. And on the next slide, we like to compare that to other companies operating in Latin America and in North America. And comparatively speaking, Alvopetro's netback margin at 90% is over 40% higher than those other companies. So it's very profitable production that we have. And when you combine that with our low tax rate, we were eligible for a tax incentive in Brazil, and it reduces our effective tax rate to just over 15%. It makes us very happy to be operating in Brazil with this kind of fiscal regime. So moving on to funds flow for Q4. Just a reminder, funds flow is a non-GAAP measure. It's most close to cash flow from operating activities, but before adjusting for working capital. So we saw an increase in -- just under $3 million from Q3 to $12.4 million of funds flow for Q4. Most of that was that 26% increase in sales volumes. We did see, like I talked about before, a slight decrease in the realized price and a slight increase in production expenses with higher production and also bringing our Bom Lugar 6 well on production. Current tax also was marginally higher in the quarter with higher earnings. And then G&A was actually a little bit lower with some final year-end bonus adjustments. So ended the quarter with $12.4 million of funds flow. And then annually, funds flow also decreased here by about $2 million. Again, the big change was in the sales volumes. It was -- sales volumes were down about 16%, but our realized price was 12% higher, so that offset a lot of that. Royalties were also lower just with lower Henry Hub pricing in the period and then also lower sales overall. Other income was higher, higher interest income in the period, and then offset by higher production expenses and current tax. Just last year, we benefited from some costs that were immediately deductible for tax purposes, and we didn't have as much of that. But overall, our effective tax rate is still very low in Brazil due to that incentive we received. So we had funds flow of just over $48 million. So moving on to net income. Our Q4 net income was $652,000. So that was a decrease up just over $5 million from Q3. The main reason for that, despite having higher production and sales in the period was we did recognize an impairment losses of $11 million. So that was on two different properties. It was on our Bom Lugar fields, just $4.2 million on Bom Lugar, and then on one of our exploration assets, Block 182. So that was the main reason for the difference in the quarter, partly offset by some foreign exchange gain -- higher foreign exchange gains and then a deferred tax recovery compared to an expense in the period. And then looking at our net income annualized, again, similar to the Q4 explanation. The big difference there is on the impairment. And the current tax was marginally higher and then offset by lower deferred tax and higher foreign exchange gains. So just moving on to our balance sheet. We ended the year with $13.1 million of working capital, that included cash of $18.3 million. So a very strong financial position at December 30. Our working capital was -- or at December 31, our working capital was $1.7 million higher than September 30. And just a reminder, we are debt-free. We had a credit facility previously in place that was fully repaid and we've been debt-free since September of 2022.
Corey Ruttan: All right. Thank you, Alison. So yesterday, we declared our first quarter 2024 dividend at $0.09 per share, that represents a current yield at our current share price of about 8.8%. We obviously did reduce the dividend this quarter, and that was just to align with the lower production levels that I talked about at the beginning of the presentation. And it's very consistent with our long-standing balanced stakeholder return and reinvestment model. And you can see since the inception of the dividend in the third quarter of 2021, it represents over $40 million or $1.13 per share in dividends return to shareholders. So we're pretty proud of that. This slide walks through that balanced capital allocation model that I talked about, where we're looking to reinvest roughly half of our cash flows in our business, and return the other half to stakeholders. So if you focus on the bars on the upper left chart here, the line, the green line with the black dots just shows the cash flow or funds flow from operations per quarter. As Alison noted, we had funds flow of $12.4 million in the fourth quarter. And then each of these stacking bars just represents where, on a quarterly basis, we've allocated that fund flow. So you can see early on here, the vast majority of it went to repaying our debt and paying some interest. The green crosshatch lines here is that debt repayment. We did that on an accelerated basis. We introduced the dividend, which is the dark green in the third quarter 2021. Very little yellow bars, so that's the reinvestment. And that's partly because we actually had pre-invested a lot of capital in developing our Cabure asset before it came on production. And then more recently, you can see this being a bit more balanced where we've got some capital reinvestment happening as well as the stakeholder returns. So if you look at it in total, since coming on production from Cabure, this is where all of the funds flow has basically went. We've had cumulative funds flow from operations now of over $130 million. Of this, the yellow, 44% of it, has been reinvested in the business. Almost exactly -- well, 48% has gone to stakeholders, in the various shades of green. So between our capital lease payments, debt repayments, interest, dividends and some share repurchases. You can see where that's all went. And then the remaining 8% is just what's been basically dedicated to strengthening our balance sheet, growing that cash position that Alison talked about and what gives us flexibility for our future operations. So we think we've built a pretty strong platform. Our focus is very focused on our next phase of growth. You can see our near-term target is to look at getting to 18 million cubic feet a day, which is 3,000 barrels of oil equivalent per day and a longer-term vision to basically double that. On our core base of operations, our gas plant now has a capacity of at least 18 million cubic feet a day. At our Cabure unit, we are looking to expand the productive capacity of the unit this year with a development drilling program as well as the installation of compression. And then probably the biggest growth opportunity we have in our inventory is our Murucututu project. This is a 100% working interest project and it sits immediately north of the Cabure unit. So the Cabure unit sits, hopefully, you can see my pointer, but sits right in the middle of the map sheet, and our Murucututu asset sits immediately to the north of that. So firstly, this year, what we're looking to do is completion and optimization projects on our three existing wells that we've invested in here. They're all pipeline connected to our central field processing facility at the 183-1 location. So our 197-1 well, we're looking to do a chemical treatment here very soon. On our 183-1 well, we're looking to do a recompletion and stimulation of at least one of the up hole Caruacu zones that previously tested gas. And then lastly, our most recently drilled well at 183-A3, we're just in the process of completing a production logging operation that will help us finalize our completion plan for that well ad we'd look to do that sequentially with the work at 183-1. So we're finalizing the plans and services for all that work, but we're hoping to execute that all in the second quarter here. One of the other things that we've been doing, just south of the 183-1 well pad that we have here, we're constructing a new 183-D well pad. And so following all that optimization work, we'll now be positioned with three well pads that are all pipeline connected to our centrally located facility, and we can grow multizone development wells from each of those three well pads. GLJ has assigned a combination of the reserves, best estimate contingent and prospective resource to this asset. So you can see 4.6 million, 5.4 million and 9.6 million barrels of oil equivalent, respectively. So our goal here is to migrate all the reserves there to production -- the reserves and resources into production and cash flow, which will help underpin our longer term growth plans here in the State of Bahia. So in conclusion, I certainly believe Alvopetro continues to offer an attractive investment proposition, no matter what your investing focus is. As Alison pointed out, I think we continue to deliver some pretty strong results. We've got very attractive natural gas pricing with industry-leading operating margins, a clean balance sheet and strong free cash flow generation capacity that all help support our balanced reinvestment and stakeholder return model. For value investors, as Adrian pointed out, we're trading at less than half of our 2P NPVs. For yield investors, the 9% dividend that we declared yesterday represents an 8.8% dividend yield, with quarterly dividends paid in U.S. dollars. And for growth investors, I think we broke out a pretty exciting and organically funded capital program ahead of us with a lot of potential relative to our current enterprise value. So with that, I'll stop sharing the presentation, and we'll turn it over to the question-and-answer period.
A - Alison Howard: Sure. A question we have here is with respect to the Bahia gas, who is our natural gas customer. What do you think Alvopetro's risk exposure is given that we have one main customer on whom all the prospects are dependent?
Corey Ruttan: Yeah. So first of all, from a risk perspective, this is probably the best counterparty to be dealing with for the area that we're in. We do have a location advantage with Bahia gas whereby we're directly connected into the distribution network. So that helps us realize higher net realized prices. And it does create an advantage for the local consumers as well. So one of the things we're looking to do, I guess, to manage that risk exposure, as it was portrayed as, is I think the single biggest thing that we can do is add more 100% working interest production to our portfolio. And then in turn, we can increase our firm nominations to Bahia gas, which would then increase kind of the floor or base guaranteed revenues that we have from that counterparty. Now that being said, we are looking at other alternatives to have flexibility, but recognize the advantages that I talked about earlier. The last dynamic, Bahia gas had committed to a lot of their demand or the natural gas supply side of their book of business for both last year and this year. They're going through a process now to define what that looks like for 2025. So they've got a lot more flexibility moving into next year, which I think will help mitigate those risks as well.
Alison Howard: Okay. What is your guidance for CapEx and drilling for 2024 and when do you see production volumes rising over 2,000 BOE per day?
Corey Ruttan: Is that one for me?
Alison Howard: Well, I can take it.
Corey Ruttan: If you want to do the capital part of it.
Alison Howard: Okay. So in our public disclosure and in our press release yesterday, the main, as Corey talked about, our main focus is working on our 100% Murucututu assets. So we have projects to optimize production from the three existing wells on that field, that's an estimated cost of $4.2 million. So we'll be working on that over the next little while here, and then future development there will follow that depending on those results. On our Cabure field, we have agreed to a five well development plan with our partner. And our estimated cost over the next couple of years would be $6.2 million at our 49% working interest. And then also, we have a compression project planned that's 100% Alvopetro, just over $3 million. So those are the main CapEx projects that we have coming up.
Corey Ruttan: Okay. Yeah. And I think the answer to the second part of that question is really, it's two parts. It depends a little bit on the production allocations that we're getting from the Cabure unit, as well as both the pace of development within our Murucututu asset, as well as the type curve basically that we're generating from drilling new wells there. So obviously, with better results, we would need fewer wells and less time to reach that objective. So it's a difficult question to answer with -- down to the month.
Alison Howard: So we have some questions around Murucututu and unlocking the value there given recent exploration and production results, and what are our thoughts there, specifically with respect to 183-A3?
Corey Ruttan: Yeah. So that's why, I guess, our capital program initially is focused on the initial three wells, because we think we have a lot of potential in those three wells. A good example of that is our 183-1 well. I think in fairness, the expectations out of the Gomo zone have been below expectations, but we've got the same Caruacu sands that we encountered in the 183-A3 well sitting right above the Gomo zone in that well. And we actually tested gas a long time ago from that well. So this, from our perspective, is an opportunity to optimize the fluids that we're using for the completion, optimize the stimulations, and at least for one of those Caruacu zones, demonstrate the potential that we have there. And then we can apply those learnings to the 183-3 well, which we've already announced. Like, we've got a tremendous amount of potential net pay there. We've completed it with the sliding sleeves that give us, on a conventional basis, very limited access to the reservoir, but with a stimulation allows us to -- the objective there is to access a much bigger component of the reservoir. So step one, we're figuring out what sleeves we want to have open versus closed. And then, we'll design the stimulations and the final completion after that work. So -- and then in sequence, then we'll take all those learnings and apply them to the future drilling -- development drilling locations.
Alison Howard: Okay. And then we have a question here on, do you have any sense that any of the demand disruption is related to your established pricing relative to others or are your prices still generally competitive?
Corey Ruttan: Yeah. I think some of the things that you've seen with Bahia ga are more a function of -- what they're trying to do with their business is and they've got a very kind of low risk approach to this is, they're making an estimate of what their demand is for 2024. And then well in advance, like before the year even started, they're basically going to all their different counterparties and filling up their slate of gas supply on a firm basis. They want to make sure that's contracted firmly. And in addition, they're contracting the transportation. So unlike the gas that comes from us, a lot of the other gas comes from other parts of the country and the gas supply part needs to be matched with the transportation. So I think some of those earlier decisions on those commitments has been impacting their ability to certainly take flexible gas, for example. So I don't think we're necessarily the cheapest gas from -- like there's nine or -- well, 12 different suppliers now for Bahia gas, but I think our gas is certainly competitive.
Alison Howard: Okay. We have a question on what are our plans. I think we had a question on the plans for Murucututu field, which I think we went through in a lot of detail. And then -- but we haven't really spoken yet about Bom Lugar. So we wanted to talk about on Bom Lugar.
Corey Ruttan: Yeah. Sorry, about that, and I think this leads on to the very first question that I answered is, I think given our strategic infrastructure position, given our desire to increase our 100% working interest in natural gas production, obviously, our priority is Murucututu, I think we still have potential at Bom Lugar, but when you look at the depth of our development drilling inventory at Murucututu, that's obviously a bigger priority for us.
Alison Howard: Okay. There's a question here. Can you provide any additional color on new development work at Cabure?
Adrian Audet: Yeah. Well, I can handle that. So at Cabure, there's two major projects. One is the development drilling program, where we have a five well infill drilling program to target both the Caruacu and the Pijica (ph) reservoirs within the unit. And then the other major chunk of capital is a unit compression system. So we're going to be installing two natural gas compressor units that will lower the operating pressure of the entire field and increase deliverability.
Corey Ruttan: Yeah. I think the answer that Alison gave earlier on the capital program recognize that, in all likelihood, some of that development drilling capital will probably be in this year and some of it will probably be in 2025, is our guess.
Alison Howard: Another question around Brazilian gas demand. Has there been a significant impact on gas demand due to high hydro reserves and the impact of renewables growth, and if so, how much of this is one-off and how much is structural?
Corey Ruttan: Yeah. No, I think there is certainly a push for renewable energy in Brazil, and you're seeing that segment of the energy supply matrix increase. I don't have the specific percentages for you. I think some of the demand disruptions that you saw last year were not just in Bahia. There was some felt more broadly in Brazil. A lot -- a good chunk of that had to do with the timing of major turnarounds of facilities and plants. So I don't think we have a big structural gas demand challenge in Brazil.
Alison Howard: Okay. Can you give a more detailed update on Block 183 and the 183-B1 well and the follow-up work this year? Are there any prospective resources booked with regards to the prospectivity?
Adrian Audet: Yeah. That's a great question. So for this wellbore, no, there is no contingent perspective resource associated with the discovery we've made there. That's not included in any of our evaluations with GLJ as of yet. Internally, we're still reviewing the effectiveness or efficacy that we would see from a fracture stimulation from that well, and making plans accordingly so that we can go in and do the right completion and see what we can do from a production rate. As we previously disclosed, the conventional rates were low, but we still think there's something to pursue, but it's, again, not in our prospective or contingent resource.
Alison Howard: Okay. So we have a couple of questions around the value proposition. Is the value proposition today and going forward different than it was two years ago given recent difficulties, i.e., the impairments that we just announced?
Corey Ruttan: Yeah. Well, we've seen a fairly large devaluation in our share price. So I think it's relative to that. I think we significantly derisked a big part of our -- if you look back to the time before we came on production, obviously, we've -- between completing the construction of our gas plant, getting our gas sales agreement in place, getting the unit development, there's a lot of those initial risks that we've kind of overcome. I think our risks now shifted more to be weighted on the Murucututu development that we're undertaking over the next several years. So there's probably a bigger component weighted to that as opposed to the original construction of our assets. So it's all relative to our share price. Obviously, if you look at -- if we have success at our expected levels, if you look at the amount of reserves, production and cash flow we can potentially add from Murucututu, it's a pretty big opportunity.
Alison Howard: On that value proposition, there was another follow-up question. Is there anything that the company can do to give value to the shareholders and send a message to calm the markets given the recent drop today?
Corey Ruttan: Yeah. Well, I think the biggest thing is we need to stay focused on our business plan and deliver results. And it's focused on our upcoming -- a big chunk of that is focused on our Murucututu work coming up.
Alison Howard: Okay. And then we have a few questions around the redetermination at the unit, which includes our Cabure field. Can you speak any more to your expectations? Is it potentially lower 2P reserves and is that part of the reason for cutting the dividend?
Corey Ruttan: Okay. So that's two -- a couple of parts. So first of all, we're right in the middle of this, so it's hard for us to comment on it. We do expect a final result here near the end of March or in the early part of April. And depending on that result, yes, it does have the ability or the potential to impact our reserves positively or negatively. I would say, it did not at all impact our decision on our Q1 dividend. The Q1 dividend was purely a function of what -- this was our production and cash flow that we're estimating, this is the portion that we've said gets allocated to stakeholders, and that's the portion that we're paying.
Alison Howard: And do you have any update on the timing of when you will find out the final decision on this arbitration and agreement with the partner?
Corey Ruttan: Yeah. Sorry, that was -- like I said, at the end of -- it will be the -- we're expecting it to be late March or early April.
Alison Howard: Okay. And are you looking to find other lands for growth if Murucututu does not meet your production goals?
Corey Ruttan: Yeah. No. Certainly, that's part of our GLJ team's workflow. They're always looking for new opportunities, be it new blocks or acquisition opportunities, those types of things. So we'll continue to look at those. But given our strategic infrastructure in the location of our Murucututu asset, and we've got all the pipelines and infrastructure in place, that's obviously a high priority for us.
Alison Howard: And then the last question I have here is, do you think Alvopetro can be acquired? Or what are the prospects of getting acquired in the future just like Petrominerales back in 2013?
Corey Ruttan: Yeah. Well, this has happened at least a couple of times to this management team with Pacalta back in Ecuador and Petrominerales in Colombia. So these things are always possible. We would -- I don't think that's personally a solid business plan. Our business plan needs to focus on all the things that we talked about today and focused on growing and diversifying our production base. Now that being said, if someone comes along and makes a compelling offer to our shareholders, that's something we would put forward to the shareholders, and everyone listening on this call would have a say in that and a vote and get to decide for themselves whether that's something they think makes sense to accept.
Alison Howard: Okay. And I do not have any further questions.
Corey Ruttan: All right. Well, thank you. I'm sure there'll be some additional questions people have. Feel free to call us and we thank you for your time. And we look forward to updating you when we do this again in May. Thank you.
Alison Howard: Thank you.
Adrian Audet: Thank you.
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