Alvopetro Energy Ltd. Q1 2023 Earnings Call
Cash was utilized during that period. So you can see earlier on when we first came on production.
Most of the focus was on.
Repaying our outstanding credit facility that Dallas and highlighted we did that in a very accelerated manner. That's the gray cross hatching that you see here and very little money spent on kind of reinvestment in our business in the early days.
We then introduced the dividend in the third quarter of 2021, which is the solid green.
And more recently you can see we've been investing.
In our business and I think youre going to start to see the results of that as we progress through this year if.
If we look at it in total.
Since July of 2020 through to the end of the first quarter you can see again the allocation so just over a third.
Two capital expenditures, a little under half two returns to the various stakeholders that you see here and then a big wedge.
Related to growing that cash and working capital position that Alan highlighted and you can see the gap between the cash flow and the cash outlays in the current quarter that contributed to that big increase, bringing our working capital and cash position up to close to $21 million.
One of the things of note here is that the cumulative funds flow from operations.
Since we came on production here is $97 million. So in the month of April we would've surprised surpassed $100 million.
Funds flow.
So moving on to our organic growth plan.
Our targets your visions been pretty consistent we've had a near term goal of 18 million cubic feet, a day, which is coincident with the capacity of our gas processing facility and a longer term vision to basically double that we.
We did complete the expansion of our.
<unk> gas plant in the middle part of last year up to that $80 million plus level 18 million cubic feet a day plus level.
We've also been working with our partner on expanding unit capacity at cap rate and I think we've got some plans to drill some development wells starting later this year.
Most of the growth is planned to come from America to two asset it sits immediately to the north of cap rate.
Adrian is going to walk you through that but we've got all the pieces in place now to execute our multi well multiyear development program here.
That's focused on the converting reserves and resource to production and cash flows.
And I think we're going to have some some exciting news from that.
As as the months progressed through this year. In addition, we've started our work at Boeing a garden, where we've got up to two wells planned. This year. One of them is included in our in our undeveloped reserves.
It also has up or sorry deeper exploration potential in two formations there.
And Adrian will show, we spud that well.
In April at right at the end of April .
Lastly on the exploration side of things, we did encounter some significant hydrocarbon columns and bulk of the exploration prospects that we drilled last year and we are still in the process of evaluating opportunities to enhanced permeability from from those zones.
Debt to repair what we think could be near Wellbore damage caused by either the drilling fluids. The completion fluids that we use so.
That will work, we'll progress through this year and based on those results. We can define a forward plan for core.
Those blocks.
Thanks, Thanks, Corey so as you recall, we're drilling a step out well it bummed mcgarr, that's offsetting an existing production well.
And the main target here is our oil reserves in the <unk> and they go more global formations and we'll be extending it down to a deeper exploration target in the <unk> and the Agua Grande.
As we've noted we've initiated drilling here, we started at the end of April .
Currently at 11% or 50 meters, but just finished this meeting job last nights or looking forward to drilling out and finishing as well next in the next few weeks here.
This is just October show you guys the.
Evolving our deep basin gas play and how it fits in with the rest of our infrastructure.
Initially when we started we drilled the 197 one in the 183, one well in the northeast and then we discovered cabaret and we focused on that to build the infrastructure signed a long term gas sales agreements built our UPN and initiated production in cash flow from the cap rate cap rate asset and <unk>.
Now we're in a position where we can realize the value of the tight gas that we discovered.
Yeah.
So in 2022, we completed the nine kilometer pipeline two to 183, one location and this is where we built the production facility to manage production from the Merck Merck to asset we.
We built another pipeline to 197 one.
This is this is a shot of the production facility of 183. One. So this is more kind of managed all the production from these tight gas well so to speak.
Drill and complete and put them online pretty soon.
Okay.
So right now we're stimulating the 197, one wellbore. So it's just a shot at what the Ah patient looks like like today.
Currently we're in the process of.
Pressure testing surface equipment Youll see here and then we'll initiate the diagnostic.
Fracture test and then conducting late stage on stage for today. So we have already completed the first three stages. So this is the last or the top stage there on the logs on the left.
And then once that's done we'll initiate the flowback period at the well and then.
Just put it on production to our production facility you saw on the previous slide and then our PGM start selling gas.
So we're looking forward to the multi year development.
Multiyear development plan for this well we've got a lot of.
Prospects.
Opportunity here.
So in 2023, Mr production from 197, one and then initiate drilling at the 183 D. One location. There 180, <unk> who've got up to two wells in 2023 to drill and complete put those immediately on production.
And.
The overall objective is to migrate this resource into production and reserves with this pad based drilling.
De risked the production potential of up to 20 million cubic feet a day.
Alright, Thank you Adrian and just to wrap up again, we've talked about this before but I continue to believe that elbow Petra offers an extremely attractive investment proposition no matter, what youre investing focus is.
I think as demonstrated from our Q1 results and another record for US we're delivering some pretty solid results.
Attractive gas sales agreement, a clean balance sheet, and we're really well positioned to execute.
This organically funded capital program for value investors, where we're trading at roughly <unk> NPV about half of our <unk> our dividend yield is almost 10% again paying quarterly dividends in U S dollars and for growth investors again.
Very exciting organically funded capital program and if you look at the potential value that we can create from that capital program, especially when you consider it.
Relative to our current enterprise value I think it's extremely exciting.
So with that Allison if we could start the question and answer period, just a reminder.
If you want to.
Submit a question just click on the Q&A button within the ribbon, indicating.
Indicating zoom to log your question.
Oh, yes, yes quite a few questions.
A lot of them are around reduction in production in April .
Combining those together bats.
The first ones are around our partner.
At cabaret and can you give more details regarding your partner nominating for higher level since your partner have priority over our petro regarding combinations or is it just the key that both patients are nominating higher levels that demand is not there.
Yes, so the week so.
So just to recap our partner when they produce gas they sell it.
True thermal power projects, when our gas gets produced and sold.
Ship it down the transfer pipeline that Adrian highlighted process it through our gas plant and sell it to Bahia gas so.
The way our contract works is that.
Both parties are entitled to their share of production.
But any production thats not being nominated before by the other party.
It can be made available to the other parties. So no I wouldn't say there is priority <unk>.
What's happened in the past is that there wasn't any.
<unk> or dispatch from thermal power projects that our partner has such that we had availability of.
Production. So it really is quite a unique thing and although our production decreased.
When we've talked about this before but the way our agreement works.
We instead of sharing every molecule based on our working interest every day.
We have basically piggy banks that contain our <unk> reserve. So when we produce down our pipeline, we're taking reserves out of our Piggy Bank and then the same thing happens for a partner when they are producing so it's just really changes the rate at which we are producing are.
Our <unk> reserves and as a result doesn't really have a significantly.
Significantly there is some small PV impact, but it's not really a significant impact on our net present values.
Do you have the best gas for your share cap rate production for the remainder I've been here.
Well again, thats going to be a function of what happens with with our partner.
Our strategy all along has been to make sure that we build a second production platform for natural gas that complements cabarets so that.
Although there could be volatility within our within our cabaret production at the end of the day our.
Our plan is to try to produce consistently at our plant capacity, whether it's coming from mercury, two or cap array or various combinations. So that from an external shareholder perspective.
It looks as consistent as we had before.
Yes.
How low can our sales volumes at all if our partner decide to take up all the entitlement what percentage of sales.
Sorry, that's part one.
Yes, I think that's pretty consistent with the earlier question.
Roughly.
The field capacity has been.
In and around the 600 650000 cubic meters, a day level and were entitled to basically half of that so.
Can you comment at all on the percentage of sales reduction that was deemed to match demand.
Yeah.
It was kind of overlapping I would characterize the btu of gas portion is.
I think.
It really <unk>.
Absent.
Uh huh.
It was probably <unk>.
Seven to 10 days within that period that we were impacted just because of the key of gas and then we had kind of a coincidence things happening at the same time the main issue or the main message on Bahia gas is they're basically back to.
Asking for as much gas they could take from US I think it was a unique thing that happened in the month of April and they just have to manage their book of business and all of their firm commitments and then if theres any slight changes in demand. They were just trying to be very fair to all of that all of the various producers and make sure. They were taking all their firm.
<unk>, which had an impact just on our flexible component of our deliveries.
So was there any specific reason.
That caused a lower demand for industrial gas.
To be able to that.
Yes.
As indicated.
A short term reduction in demand, but I think it was also just a function of how they had committed for the month for firm capacity. So they have the ability to adjust that we also have the ability to adjust as we put more production on the.
The ability to adjust our firm volume. So if we wanted to increase our firm component.
That's something we could look at doing in the future.
But.
It looks like we're back to the statements as we've always been like for you guys.
Are there any efforts to add any uptake partner with it so.
Yes.
The gas or in a new city or in new states.
Yes.
We have a benefit that our infrastructure is tied directly into Bahia gas. It does create a net realized price advantage for Bravo a patent troll.
We're very happy with our relationship.
But there is movement afoot, where there is more and more.
Contracts being signed directly with end users.
Our preference would be to continue our relationship with Bahia gas, but.
There have been a lot of requests from other producers for.
Access directly to our to our guests.
It's certainly a possibility.
Okay.
Most of those questions on that particular issue.
Didn't have a question on why they were asking rates declined sharply.
3% of sales.
It was about 3% of sales in Q1 compared to 7% previously so I'll answer that so the bulk of our.
Volumes are from natural gas.
Natural gas royalties in Brazil are based on a reference price.
Which is linked to Henry hub and its more of the value of that raw unprocessed. Scott. So we saw a decline in Henry hub, and our and our and increase in our gas price into our contacts are therefore as a percentage of sales on a per LTE came down so.
Going forward a more function of what you expect Henry has to be compared to our natural gas basins.
That percentage, but yes as of right now.
The royalty rate in Q1.
Likely to persist in the short term any limit Scott Henry hub prices.
We did have a question on bond mcgarr and.
We're fine with our in.
In.
Locate ads.
So I don't think we went through that in detail today.
There is in our corporate presentation. Upon the guards is north of our <unk>.
Gas assets and in our corporate presentation on slide six.
Its more evident on the map.
I don't know if you want to comment on that.
No thats rates within the same basin, just just to the north of this.
North of the map sheet that you saw for cap array and Mercury.
Yeah.
Okay.
Yeah.
Okay. The next question is on one.
197, one.
What level of production would you expect once in a while.
On stream.
Yes, I can comment on that R to P estimate for the 171 is roughly 180 Boe per day.
And that's something that as we finish our final stage of completion and put this thing on flowback will will refine.
An update.
Tier one.
Yes, sorry about tier one average.
Thanks, Greg.
Okay.
Any details on the share about when the share back share buyback will start and at one time.
Well, that's something our board will continue to evaluate in the context of the overall stakeholder return.
Portion of the pie and let's say, which is the balance between dividends and share buybacks.
We indicated before.
We don't want to get into discussing water.
Trading strategies or what the what the orders with our broker are but.
We will continue to evaluate that so it's hard to give guidance on that.
Yeah, and just to confirm Theres been no buybacks to date.
On that.
Can you a little bit more on that drilling are you, having discussions with the drilling that supplier and a drilling company.
All of the issues you've seen.
From recent wells, including 180, <unk> did you have any similar problems on wells proceeding pretty well.
Are you going to delayed rather development until you can overcome this problem.
Yes. Thank you.
<unk>.
So we're certainly working through these problems no. We're not we're not delaying the drilling of our next projects of course, where we're reviewing everything with our service providers are my providers.
The products and the technology that we're using as it should be first class for the basin globally for prevent prevention of.
Invasion and damage to the reservoir is just when the results aren't as expectations for Butler investigate this so that's not something we've been concluded.
But that's something we're working in parallel, but we're not going to delay the other.
Could do two development wells they are in different formations.
I think almost sand and the <unk> is different.
Formations, we saw problems within 180 <unk>.
But.
Yes, hopefully we evolved the understanding of what happened in those two wells.
But it's not something we've seen in our other development wells and cap array or an initial discovery wells for marketers.
Okay.
We'll give you a new reserve report a key deal with two additional development Wells at America Q2 this year.
Yes, I think by the time, we drill those and we get a little bit of production history, we're probably fairly close to our coincident with our normal reserve reporting timing, but we can evaluated depending on that timing.
Okay.
I'm sorry.
Sorry, but you have a couple more questions back to the key attack what is their actual firm volume commitments.
Yeah. So right now we have 300000 cubic meters a day, which is between 11 to 12 million cubic feet a day of firm and the rest of it's flexible.
Yeah.
And what other prospective off takers expect a similar gas pricing formula as your current contract with <unk> on that.
Okay.
Most of that most of the contracts or percentage of Brent base, but.
From what we're seeing in the market I think it's.
It's relatively consistent.
This next one is probably for Adrian as well do you have an estimate of cost differential between net fracture stimulated vertically in a horizontal multi stage.
Well in this region.
111 thing to point out there on that is if we look at the logs.
Four stages that we're completing other current well to develop that with the horizontal multi stage isn't really applicable the way that the <unk> sands are overlaid on each other and then separated by shales.
We really need to go in there with the vertical multi stage fracs and as we drill and logged in with better place those products specifically, so it doesn't lend itself to a horizontal multi stage development program at this point.
As we drill more wells, we might learn a bit more but at this point, it's noteworthy on the books.
True comparator.
Okay and then the loss we have a couple more questions around the balance sheet.
The strength of the balance sheet and that large amount of cash we have right now and it just continues through the year, even if there is a share buyback.
Is there any Emma.
M&A potential.
M&A opportunities would you look to wrap up capex would it make sense to purchase the fractionator slacks.
Any acquisition that sort of thing.
Yes, well, it's always impossible to comment on business development things. If there is an inorganic way that we can create shareholder value, we would certainly evaluate that but.
But our primary focus is on organic growth from the assets that we were reviewed today.
And we'll continue to evaluate.
Evaluate that going forward.
Okay, I think that is it for questions.
Yeah.
Alright, well. Thank you if there is any follow up questions from anyone feel free to reach out to us directly and we look forward to updating you in three months time.
Thanks, everyone.