Q1 2021 Lonestar Resources US Inc Earnings Call
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And really not talked to watch ladies and gentlemen, thank you for standing by walk on to the Lonestar Resources' first quarter 2021 financial results conference call. At this time, all participants are in a listen only mode.
And there will be a question and answer session. Following our presentation and instructions will be given at that time. Please note. This conference is being recorded today. The 12th of May 2021, I would now like to turn the conference over to your host Frank Bracken Chief Executive Officer. Please go ahead.
Yeah.
Good morning, and thank you for joining us as we review our first quarter 2021 results and get you caught up on operations and.
As always I'll refer you to page two to review our disclaimer on forward looking statements and then ask you to turn to page three.
Over the past year Lonestar successfully restructured its liabilities simplified its balance sheet and further reduce debt by utilizing free cash flow at March 31, 2021, net debt of 239 million provides $36 million on liquidity and a debt to adjusted EBITDAX ratio of two one.
Lonestar continues to target a debt to EBITDAX ratio of one and a half within the next day quarters and the combination of continued high performance of our drilling and completion program and price certainty afforded us with our hedge book.
And let leads us to be highly confident in achieving those goals, let's touch on some highlights from the recent quarter.
Current production is up 22% from first quarter levels.
While we did reported a 29% decrease year over year that really is a function of.
The fact that we went for an extended period of time without bringing new wells on stream I'd also remind you that that production stream and the current quarter.
<unk>, a 75% crude oil and Ngls on an equivalent basis resumption.
The resumption of development activities has increased production at current rates of 12005 hundred barrels a day and I would also note that lonestar expects further growth and production and the second half of the year and for rates to average between 13000 and 413800 barrels a day during the second half as we see the more fulsome benefits of our <unk>.
Capital program.
Adjusted net income was $1 five a share and the company is on track to continue to report strong earnings on.
On an adjusted basis.
Adjusted EBITDAX was $22 9 million, while discretionary cash flow was $19, one which was nearly in line with last year's results. It's no no. It's worth noting that <unk> discretionary cash flow was negatively impacted by $5 $4 million of hedge losses realized in the quarter, while <unk> result.
It was positively impacted by $8 2 million of realized hedge gains and improved wellhead price realizations and reduced cash expenses are what balance of those two out to yield essentially flat results.
As a result, after spending a little over $11 million.
Lonestar reported free cash flow of $7 million and the quarter, which is a sharp about face from the negative $15 million from the prior year.
The returns of our capital program are outstanding ranging from 79% to 112% at $55 oil and $2 75 gas and we will continue to focus our program on our high return high return extended reach laterals at cyclone Hawkeye and horned frog.
Company continues to expand its drilling inventory.
And in an environment, where I think the industry is becoming.
Increasingly inventory poor.
Lonestar boasts a robust inventory at December 31, 2020, we had 109 proved undeveloped locations and an additional 115 probable undeveloped locations for our third Party Engineering report.
At 2020 ones currently projected pace of well completions of 10 per year or <unk> locations alone represent 11 years of inventory.
Overtime, Lonestar has been especially successful and increasing its drilling inventory on its core assets of cyclone Hawkeye and horned frog, where its well returns are outstanding recently Lonestar concluded a series of primary term leasing dispositions and acreage trades that increased our acreage position at horned frog and and doing so.
<unk> nearly doubled our inventory of extended reach laterals I'll discuss that deal further and our operations update.
As it relates to 2021 guidance.
And as production increases as the through the year as we bring new wells on and we expect to continue to register improvements and total cash cost per Boe.
And with production and and.
Discretionary cash flow ramping up our current budget would generate 30% to $35 million of free cash flow, which equates to a free cash flow yield of 35% to 40%.
At this moment Lonestar intends to principally focus this free cash flow to continue to reduce long term debt and associated interest expense.
Now turning to page four please.
Before we take a dive into on the performance of our capital program I'd like to recap the net results of our restructuring and acquaint you with the robust asset value that underpins the equity within that current capital structure.
Our restructuring, which was completed on November 30 of last year was value preserving and consensual through that process $250 million of unsecured debt and $100 million of.
Preferred equity were exchanged for common equity, while free cash generated and the second half of 2020 reduced bank debt by $45 million.
The net effect has been to streamline our balance sheet and reduce net debt to $240 million, which consists of and RBS and and amortizing term loans.
Reduce long term obligations and increase revenues.
Reserves and commodity prices puts the equity at a extremely undervalued position today at year end 2020, the PV 10 of our PDP reserves alone stood at $361 million at $55 oil and $2 75 gas that means our PDP value.
Less debt.
Equals $121 million or $11 per diluted share. It's also noteworthy worth noting that internally, we see continued ramp up and that PDP PV 10, as we bring on our 10 well program.
Now please turn to page five.
The graph on the top right indicates that the reduce long term obligations eliminate interest expense and dividend payments totaling $37 million annually with 2021 expected interest expense of $14 million.
I would note that we expect to reduce interest expense each quarter as we further reduce debt with free cash flow, which will also reduce our average LIBOR spread on our RV L. Further cutting interest costs.
The graph on the bottom right summarizes our guidance.
Which we've already covered but drives home the significant level of free cash flow, we expect to generate in spite of hedge losses, which at the strip will exceed $30 million and 2021, but then decreased dramatically as the price and our book escalates.
Escalates and 'twenty, two and 'twenty three.
Please now turn to page six.
As we mentioned Lonestar reported net oil and gas production of 10000, and 377 BOE a day.
I would note that we did experienced modest reductions in oil and gas sales as a result of temporary shut and shut ins related to winter storm Yuri.
<unk> production consisted of 54% oil, 21% Ngls and 26% gas.
Resumption of activities have boosted current production is as noted by our little Longhorns there.
As a comparison.
And current rates are 12500 barrels a day lonestar expects further growth and the second half of the year.
Which which should boost rates to somewhere in the mid 13000 barrel a day equivalent ranges.
That will also serve to establish a more profitable higher margin base upon which to run our business.
Now turning to page seven please.
Let me start assets continued to deliver favorable wellhead realizations with <unk> 21, wellhead prices of $42 63, a Boe.
And that's up 47% over the prior quarter.
Lonestar is wellhead crude oil realizations were $55 74 that reflects a $2 <unk> discount to <unk> on.
Our NGL price of $21 96.
Weighted to 38% of FW Ti substantial improvement over a year ago.
Lastly, in the quarter, our wellhead natural gas prices price averaged $5 35.
Reflecting a $1 79 premium to Henry hub.
Ordinarily that debt debt discount is about 10.
The first quarter natural gas dips were positively impacted by the effect of high realizations achieved and February resulting from increased gas prices during winter storm here.
On the expense side of the equation Lonestar initiated and aggressive cost reduction measure starting in the second quarter of 2020.
Which continue to deliver a lower operating cost structure from for the company. Both on an absolute dollar basis and a per unit basis. The graph on the top right shows that our lease operating expenses, which do include Workover expenses and are shown in black.
We're 44% lower on an absolute dollar basis and were cut 22% on a unit basis from $5 81 to $4, 55% year over year.
The graph on the bottom left shows that our total cash expenses, which include the cash portions of lease operating gathering processing transportation production taxes, G&A and interest were reduced 18% from 2028 per Boe.
And to <unk> 70 per BOE, a day, it's only logical that our unit cost structure is poised for further reductions as production ramps up over the course of 2021.
Please now turn to page eight where we will start to dig into operations.
The cornerstone of our central region operations on our cyclone and Hawkeye assets, which continue to perform extremely well on today's call. We will we will discuss three sets of wells, which are highlighted on the leasehold map on page eight.
Now page now turning to page nine.
Our joint venture with Marathon was kicked off in 2020 with the Hawkeye 14 through 16 pad.
These wells were augmented by a trade, we did with EOG, which not only elongated the laterals, but got us into some better rock.
These wells average nearly 500 BOE a day and their first month on stream and on.
Outperformed bond gotten Hawkeye base case type curve by 55% cumulatively.
As you can see on the graph on the top right quadrant.
Just on this outperformance our third party engineers upgraded their <unk> by 27% to 900000 Boe per well at year end and you can see that these wells continue to perform very well compared to that upgraded forecast.
The economics associated with these wells as summarized in the bottom right quadrant and are at a 100 and or at our 123% currently and needless to say were placed.
Now please turn to page 10.
In February of 'twenty, one Lonestar began flowback operations on three gross one five net wells the Hawkeye 33, 34% and 35. These wells recorded initial rates over a 30 day period of 938 BOE a day, 91% of which was crude oil.
Recently Lonestar introduced artificial lift operations on these wells and they've responded favorably with current production rates still averaging over 800 BOE a day.
These 11000 and foot laterals were completed for $6 $5 million, which is a nice savings compared to the Hawkeye 14 pad, which were completed for $7 $7 million.
The production graph on the right side of the page show a high degree of conformance to our third party type curve and it completed our completed well costs, our new Hawkeye wells are on track to earn 77% internal rates of return at $55 and $2 75.
Lastly, I'd add that we have in fact initiated drilling obligations on our next three well pad and the Hawkeye area and we expect those wells to come on online late in the third quarter.
Now please turn to page 11.
We will now move to our central region, where our recent activity has been focused on our high return horned frog asset and Lasalle County, and will discuss flow back operations on our recent two well pad at horned frog west and drilling activity on newly acquired acreage on the alderman one and two wells and some excellent news regarding <unk>.
And you'd ongoing lease acquisition activities now.
Now please turn to page 12.
In March 2021, Lonestar began flowback operations on a two well pad involving the horned frog West number one and two lonestar has a 100% working interest and a 78% NRI and these wells. These.
And these wells commenced flow back a little over two weeks ago and to date have registered initial production rates averaging over 500 BOE. A day production is currently comprised of 77% crude oil and Ngls on an equivalent basis and the chart on the type of top rate reflects a high degree of conformance with our type curve.
The chart on the bottom right reflects that these wells are the oil list, yet and our horned frog area and early indications are that they may be our most productive on a per foot basis.
These wells were placed on stream and a cost of $6 $1 million, which is a striking savings over our last pad of identical identical lateral length, which caused $8 $6 million at these completion costs and production at the type curve. These wells will generate over 100% internal rates of return.
Now please turn to page 13.
Page 13 depicts our leasehold position and associated development locations and our year end Reserve report with proved reserves totaling $30 4 million Boe and PV 10 of $193 million at 55 and $2 75.
Page 14 updates that position and associated development locations from a net result from a series of transactions, we've executed year to date.
Now please turn to page 15 to discuss the details of our ongoing efforts to build inventory on our highest return on asset.
Through a combination of primary term leasehold acquisitions, leasehold dispositions and and acreage trades Lonestar has meaningfully enhanced its position on its horned frog asset.
Net effect of these transactions is to increase our leasehold by about 15% to roughly 7300 acres.
Much more importantly, it reconfigured that acreage in terms of development geometry.
And to not only accommodate significantly more drilling.
Increasing the number of drilling locations exceeding 5000 feet and lateral length from 11% to 20 <unk>.
All of which are owned by Lonestar to 100% and increase the average lateral length across the horned frog position from just a little under 9000 feet to a little over 10000 feet, which impacts reserves and returns on a per well basis.
Most importantly, the transactions increased our proved reserves at horned frog from $30 2 million barrels equivalent to $40 1 million barrels equivalent and increased PV 10 on the asset from $193 million to $280 million.
As the graph on the top right quadrant demonstrates lonestar has been able to generate consistent organic growth over a significant period of time and we expect to continue this strategy moving forward.
And lastly, Lonestar also completed drilling operations on two 100% wells and our horned frog south property, the horned frog alderman number one and number two.
These wells reserve represented a step out from our horned frog South block in terms of well control and to assist and optimizing these results. We used a new suite of Petro physical logs derived from our new pilot hole and a recent completed pre stack depth migration to assist and reservoir characterization and Geo steering.
Because we have the benefit of thru bit lateral logs on these two new completions, we have a lot of data on these wells that most operators wouldn't have at this point and time and our analysis of this log gives us optimism that these laterals have been drilled and rock that is among the best we've completed at horned frog to date in terms of effective porosity.
At current projected well costs are two new wells would generate IRR exceeding 100% if they conform to type curve fracture stimulation operations on this on these wells are scheduled to.
Commence later this month with first production anticipated in July.
Now please turn to page 16.
Not to go into too much detail. This provide this page provides a lot of detail on on.
On the timing of recent wells and future wells and summarizes it and a term of.
And in terms of timing on drilling and completion operations as well as working interest and lateral lengths to give you and some assistance and tying your models to our guidance.
Please now look to turn to page 17 to wrap things up.
I'd like you to think of <unk> 'twenty, one as a stepping stone as it should represent a trough for production costs and profitability drilling and completion operations have already lifted production by 22%, which will drive revenues higher and the second quarter.
This factor combined with benefits of stringent cost control and our restructuring have cut cost cash operating cost by 18% or $3 50, a BLA.
Again, we would expect to see further improvement and our per unit cost structure as production ramps up.
Our long term debt and associated interest expense are now at very manageable levels and facilitate significant free cash flow.
We will focus our capital program on on areas, where we've demonstrated years of excellence in terms of technical acumen and returns and wrote results are yielding returns ranging from 79% to 112%.
Our 2021 program has very little susceptibility to increased service costs as we've locked in all of the high dollar items.
Our program is expected to increase average daily production for the second half of the year to a range of 13004 hundred to 13800 BOE a day.
We keep building inventory and our core area at costs that are barely a blip on our capital budget, which drives further growth and our proved reserve base.
And I think the best way to summarize our 2021 guidance is that we are on track to use free cash flow to repay bank debt to a level of $230 million at the midpoint of guidance, which at year end would yield a debt to unhedged EBITDAX ratio of one eight which I think would represent excellent progress towards giving the <unk>.
Company, the flexibility it needs to position lonestar for growth through drilling and asset consolidation and the Eagle Ford shale that concludes our prepared remarks, and I'll now turn the call over to the moderator.
Ladies and gentlemen, we will now begin the question and answer session. If you would like to ask a question. Please press. The one followed by the four on your telephone and wait for good loans to be announced.
If you would like to cancel your request you made one followed by the theory at any time to remove yourself from the queue.
We will take the first question from Charles Meade with Johnson Rice. Please proceed with your question.
Good morning, Frank and thanks for all of this this detail that you've out you put together and presentation.
Good morning Charles.
And particular pages 13, and 14 I like the the ability to flip back and forth there and see what you guys have done.
And horned frog.
So far this year.
A question for you. If you were if you were to kind of.
How would you characterize the opportunity set and not just here at horned frog, but also it and other other parts of your portfolio.
And if you kind of break it up by.
And how much of it is leasing.
How much how much of the opportunity set is trades and is there.
Our acquisitions are just from a small acquisitions like.
I guess you could call leasing the type of acquisition.
But maybe with the acquisitions with some PDP is that in the mix at all.
Yes.
I would say, yes to all of the above Charles.
We've been at both of these areas for over five years now and.
And it's.
It's kind of funny, if you talk to investors and say well can you keep doing it and each year, we keep doing it.
And it's it's not.
It's hand to hand combat these are areas that.
Typically are largely HB pede.
And we'll we'll use all means necessary to continue to grow those positions, but I would tell you that.
And the same environment.
And that has persisted for the past several years.
At horned frog and cyclone and Hawkeye.
Still exists and maybe may.
Maybe more advantageously for the company so we.
We have we have our eyes on more lease hold and these areas.
And I think the and so it can take a lot of different forms. It can it can tape and we've bought and asset out of bankruptcy and the Hawkeye area for example, so.
We have lots and lots of tools on the Swiss Army knife I think the thing to emphasize is that we've always been able to do these kinds of things at really minimal costs.
The general continuing to use that free cash for the highest return purposes is really important and.
And we've not tied up a lot of money nor created any really significant drilling obligations.
Out of any of the activities that we've debt.
We've used to grow these positions.
So that's an important point, but in short.
Yes. There is there is more to do out here, we've got identifiable targets and they they don't always drop in your lap when you want them to they take a lot of work and some patients, but we're confident that we can continue to do this kind of thing and build the position out further.
Got it and then.
On your.
I got your comments about the second half rate being 13, 4% to 13 eight.
Do you care to kind of give any indication of where you think your year end exit rate would be.
What.
Look I think I don't think it would be too off too far off from that range.
It really depends on on on well timing as it relates to both getting the the alderman wells on at horned frog and then the 910 and 11 pad on.
So I'd rather be a little more circumspect at this point and and suffice it to say that.
That not only will we produce and that range for the second half of the year on average, but it'll even be dependent upon.
When we decide to.
Get rig back up for the 2022 program.
Got it thanks, Brian.
Thank you Charles.
As a reminder, once again to register a phone question and the one followed by the four on your telephone.
And we have no further questions in the queue.
Alright, everybody who will thank you for joining thanks for the question and we look forward on building on the results of the first quarter and look forward to.
Getting back together with you and and.
And the next 90 days.
Ladies and gentlemen, this concludes the Lone Star Resources' first quarter 2021 financial results Conference call. Thank you for joining US today you may now disconnect your line.
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