Q2 2023 HighPeak Energy Inc Earnings Call
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Good day, and thank you for standing by and welcome to the high Peak Energy 2023 second quarter earnings call.
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I would like to have the conference over to your speaker today Steven's fallen CFO . Please go ahead.
Good morning, everyone and welcome to high peak energy second quarter 2023 earnings call representing high peak today, our chairman and CEO , Jeff Hi Tower precedent, Michael Hollis, Vice President of business development, Ryan High Tower, and I am Stephen Sullivan.
The Chief Financial Officer.
During today's call, we will make reference to our August investor presentation, and our second quarter earnings release, which can be found on high peaks website.
Today's call participants may make certain forward looking statements relating to the company's financial condition results of operations expectations plans goals assumptions and future performance.
So please refer to the cautionary language regarding forward looking statements and related risks and the company's FCC filings, including the fact that actual results may differ materially from our expectations due to a variety of reasons many of which are <unk>.
Our control.
We will also refer to certain non-GAAP financial measures on today's call. So please see the reconciliations in the earnings release and in our August Investor presentation.
I will now turn the call over to our chairman and CEO John Hightower.
Thank you, Steve and good morning, ladies and gentlemen, we want to thank you for joining our call today regarding our second quarter earnings.
My prepared remarks will begin on.
Page four of our presentation.
This is perhaps one of the most exciting presentations in the history of IP.
As you can see we are substantially a different company today than we were just a key short months ago.
Not only is this an exciting time and we have also recently achieved two very important company milestones.
Number one our production has averaged over 50000 barrels a day.
BOE equivalent per day, thus far in the third quarter.
That's an 18% increase over our second quarter average and a 35% increase compared to our first quarter average this.
This increase is in accordance with our projections and continues to track our internal expectations.
Number two going forward, we are now delivering positive free cash flow from operations and at current prices and our two rig cadence, we expect to generate excess cash flow over our capex spend this quarter.
This is a major achievement for the company and for our long term strategic plan from this point forward, we intend to finance all of our drilling activity through operational cash flow and generate significant free cash and reduce our outstanding debt over the course of the next 12 months.
I would say that leads to capital discipline in accordance with our updated development plan. We're currently running two rigs and one frac crew.
Maintain a two rig program.
<unk> one to two frac crews throughout the remainder of this year.
And until our debt refinance has been completed it's too early to discuss our 24 development program.
However, it is still our intention to finance, 100% of our drilling program through operational cash flow, while generating material free cash for debt reduction will talk more about that as we go through the presentations.
Coming off a more active drilling program in the first half of the year, we had an additional 42 gross wells in various stages of drilling and completion at the end of the second quarter.
These wells will be turned online.
And the second half of the year, and we will translate to additional production growth throughout the remainder of the year at current prices. We are approximately one times debt to EBITDA leverage ratio today.
You can save from tables on this slide.
By the end.
This year, we should be under one turn of leverage and generating roughly $1 1 billion of cash flow on an annual run rate basis utilizing $80 oil.
Now turning to the next page slide five.
This slide is really showing.
The rock in our area the growth of our production.
Think about just a few years ago, we were at 3000.
Evelyn per day and today after a 175% compound annual growth rate for up to over 50000 barrels a day keeping.
Keep in mind that comes out of 200, producing horizontal wells with almost 50 more wells coming online between now and the end of the year and we also continue to maintain or sustain peer leading profit margins, which differentiates us from other companies.
So if you look at the US you have to make the assumption that.
This rock in this area is very very good it's very profitable and it meets any bodies tier one asset base Eastern Howard County is fantastic.
And as we look at the accomplishment of this level of growth while staying at around one turn of leverage even while considering volatile commodity prices.
Over the last three years.
Now if you'll turn to slide six.
I'm going to talk a little bit about the margins to continue outpacing the peers. We stated that we actually were improving on our profit margin and this is a good example in fact today our production volume of 50000 barrels a day compared to our peers.
It is worth the equivalent of 80000 Boe per day and that is just phenomenal that's almost a 60% 59% increase compared to our peers. So as mentioned on our first quarter earnings call. Our margin will continue to expand and the reason is because of our.
We have tremendous oil cut.
And that compared to our peers then in depth at almost 50% gas after a year, we continue having 93% liquids.
We also expect to expand and continue.
Expanding our margins on our forecasted production growth and our <unk> reduction initiatives further.
I'm going to turn the call over to my colleagues and he is going to spend even a little bit more time, explaining these margins too.
Those forward and talking about operations, Mike you bet. Thanks, Jack again, staying on this slide over the last three years as Jack mentioned, we had a production growth CAGR of over 175%.
And as we've mentioned in the past not all <unk> are created equal.
Bo mix is quite a bit different than our peers, we are 84% oil and 93% liquids.
This product mix, coupled with our low cost structure generates margins per Boe.
Roughly 60% higher for IP compared to our peer group.
Our gearing to oil price is significantly higher than our peers.
If you believe that the underinvestment in supply over the last couple of years in combination with the growing global demand will further affect oil prices disproportionately to natural gas prices, our margin will continue to expand compared to our peers.
And as our production volumes increase throughout this year, we will continue the implementation of our cost saving initiatives and our cash cost will trend lower further expanding our margin.
Hello for oil companies tends to run higher than our gas company peers on a Boe basis and high peak produces an oil here.
And most every other oil company.
So you would expect our <unk> to run higher on a per unit basis.
Quarter Hello.
Was roughly $8 40.
Bo.
We expect this to trend closer to 750 in 2024.
However, if we normalize high peak second quarter low.
Two our peers by using an economically equivalent amount of the average peers as the dominate.
Terminator.
Our LOE would equate to $5 25 per Boe.
This screen's extremely competitive.
Turn now to slide seven.
We have walked you through the production ramp on slide five.
To date <unk>.
<unk> has over 50000 Boe's per day again, very oily rich. Our current 2023 guide is to exit this year at 57000 Boe per day.
With a two rig program, we plan to turn in line roughly 46 gross additional wells in the second half of 2023.
There were 42 as Jack mentioned at the end of the quarter.
Of which all operated wells are wolfcamp, a and lower sprayberry.
The map to the right side of this slide highlights for the second half of 2023 High peak operated wells are located.
All in known areas.
Offsetting existing production.
Our development focus will continue to be on co developing the wolfcamp, a and lower sprayberry formations.
Which at our current two rig cadence we have over 12 years of inventory and just these two primary zones.
These additional turn in lines and our continued excellent well performance supports our 2023 average and exit production guidance.
Nothing is ever a slam dunk in the operations World.
But you can see very real path to meeting and exceeding our production targets for 2023.
We continue to reap the rewards both economically and environmentally from our significant investment and infield infrastructure.
The capital has already been invested to allow <unk> to operate in a very efficient manufacturing mode.
Our high line electrical infrastructure and the development of our solar farm has positioned us to both mitigate the need for high cost rental generators, when turning on new wells and enable us to drill using highlight power, reducing both our diesel emissions and power costs are.
Opex will continue to trend down as our infrastructure is for further utilized.
We will continue to electrify all prime movers throughout the field.
Reduced third party SWT takeaway volumes.
And optimize our chemical programs simultaneously.
Simultaneous simultaneously, we will continue to benefit on the Capex side of the equation.
From a water recycling system electrical grid.
In our 100% utilization of local website and with my comments now complete I'll turn the call back over to Jack.
Thanks, Mike.
If youll turn to slide eight.
In your presentation.
All of these are looking at what we have consistently increased the value of our asset base. Most of our growth has been the drill bit.
Had a few acquisitions. These acquisitions have added very little at least at the time, we made the acquisition and now we're starting to realize the benefit of these acquisitions are.
Our estimated fourth quarter run rate EBITDAX is projected to be in the range of $1 1 billion at $80 oil.
If you add in additional production going into the fourth quarter and next year, it's much higher than that.
Further our projected leverage ratio by the end of the year should be less than one times, one turn at the same oil price.
We're still bullish on oil prices overall, both in the near and medium term each one dollar a barrel increase in oil price above 80.
<unk> to $16 million of annualized EBITDA.
A $10 per barrel increase in price to 90 would equate to another $160 million of the traditional annual EBITDA for happy.
That's a considerable amount of additional cash flow that can be used for further debt pay down or for reinvestment or a combination thereof.
In connection with our growth profile and our growth in production the value of our proved reserves.
Also continuing to grow.
Our proved reserves at midyear 2003 have increased to $2 8 billion at a flat oil $80 oil price based on our internal mid year roll forward Reserve report.
Our asset coverage our proved reserve value absolutely supports our current outstanding debt and.
In addition on a go forward basis, we will be generating free cash flow, which will further lead to rapid deleveraging.
Company is very healthy and has a pristine balance sheet going forward.
Yes.
Now turning to slide nine.
There's been a lot of confusion relative to.
Our obligations relative to our debt metrics last month, we completed a $155 million equity raise.
And consistent with our past history, both our management team and significant stakeholders.
Dissipated at substantial levels in fact, we we.
We invested almost $108 million of the $155 million.
Thereby not suffering dilution the capital raised from this offering along with our June revenues was used to catch us up on our outstanding payables and to enhance our near term liquidity. This raise plays a crucial role in positioning the company to.
Received more favorable terms on our debt refinancing and to effectively execute our comprehensive long term strategic plan.
Relative to confusion in the marketplace regarding certain dates associated with our credit facility requirements.
I'll take a few minutes to give a detailed explanation of this situation and this slide gives you. An example in conjunction with our recent equity raise our credit facility Bank group.
<unk> amending providing for a postponement from June to September one.
Of the company's obligation to redeem extend or submit a plan for redeveloped for repayment of our February 24 notes. Please.
Please note. This requirement is only in regard to our February 24 notes and does not require that redemption, our extension of our November 24 notes.
I will say it.
It is our intent to redeem our extend both sets of existing notes, but the RBI requirement is only in regard to the February notes.
Also like to say that we have a great working relationship with our bank group, who have been very supportive throughout this process and like to thank them for their continued support as we work diligently to extend our debt maturities.
As mentioned, we are working on a comprehensive debt refinancing structure.
Which will meaningfully extend our debt maturities and it is our goal to extend these maturities into 26 or later.
Similar to our recent equity raise there is a lot of interest from the investment community and participating in our debt refinance I know some people have been.
Thinking that it's going to be difficult to refinance this debt.
But with the balance sheet and the strength, we have in our growth and our production we have multiple term sheets.
In the hand.
Which will meet.
Our financial needs, we are simply working swiftly and diligently to negotiate the most favorable structure and terms for the company with the right group of lenders, which will allow us to achieve our long term goals.
Keep in mind that the current status of the company is completely different today.
Our equity raise enhanced our near term liquidity position and we are now cash flow quality from operations on a go forward basis.
As mentioned, we are producing in excess of 50000 barrels per day equivalent and the value of our proved reserves has increased substantially from our year end 'twenty two report providing substantial coverage in excess coverage for our current debt level.
Our current EBITDA run rate at today's prices approximately $1 billion on an annual basis, which equates to a very modest leverage ratio of one turn right. Now today of course. This goes down as we go forward into this year, we expect the leverage.
Leverage ratio to decrease over time, as we use our free cash flow to reduce debt.
One additional point I would like to mention here is if we decided to stick with our current two rig program in 'twenty four and go into more of a production maintenance mode. At current commodity prices, we werent project to generate roughly $500 million of free.
Free cash flow.
And simply the next 12 months into next year's business.
This is after applying interest expense and factoring in our current dividend. So we could easily pay down our debt by over 50% in the next 12 months. If we wanted this does not include any debt reduction benefits from the free cash flow that we anticipate generating throughout the remainder of 'twenty three either so again Dave.
To all of the reasons I just mentioned I am extremely confident that we're very financially healthy and that we should resolve this debt refinancing shortly.
Please also understand that due to the late stage of negotiations and the confidentiality associated with the terms and the potential investors I will not be able to discuss the status of our details of our financing refinancing project any further at this time.
And unfortunately will not be able to answer any questions. During the question and answer session on this <unk>.
Hey.
However, I will say that management remains very confident in resolving this refinancing with full resolution and we could accept.
Any of these term sheets, we're simply looking for the very best opportunity.
Page 10 is the slide to wrap up and as you can see we continue to check all the boxes.
In this case the circles.
In terms of our.
Hi, liquids rating and that puts us in competition with all the top tier production and the other Midland Park Hill, Permian Basin, and the Midland Basin.
We have a prime oil weighted Permian asset base with high return well economics.
<unk> U S acreage, which was set up to provide maximum capital efficient long term development.
In fact, our drilling it down its signal peak and and flat top are providing 15% to 20% internal rates of return in the various areas and these are tremendous returns on the wolfcamp, a and lower Sprayberry zone.
We have achieved significant scale in over 50000 barrels of oil a day or an economic equivalency basis with our average fares roughly 80000 barrels a day.
Our financial and credit metrics are in good shape right now with visible near term improvement on the horizon, we have strong PDP and proved development coverage and we will now be generating free cash flow from our operations going forward.
We have derisked, our acreage position and have over 12 years of premium inventory just in the water and lower sprayberry zones at our current two rig cadence.
The word de risk. It is very important here because we have now drilled wells across our entire acreage block both in the north and down to the SaaS.
And that should mean a lot that these wells are producing the level that they're producing and then our rocks are good.
In addition, our management team has continued to demonstrate alignment with our public shareholders through our high equity ownership in the company and we remain confident in our ability to resolve our debt refinancing project very soon.
Hence the reason, we invest in a lot of our personal dollars and the company.
Our primary focus remains on generating free cash flow on a consistent basis going forward and fortifying our balance sheet.
Considering all of these points I remain extremely confident in our ability to create additional value for our shareholders and one thing I would like to say simply is.
I always want every shareholder small and large that have a higher return on their investment. It concerns me that we have had so many shareholders that have shorted our position.
And yet all I'll say along those lines is.
To me that is a very dangerous position to be in in light of oil prices moving with the performance we have in our production and the type of rock and returns that we have I wouldn't be doing that as very high risk, but you have to make your own decisions.
You can see we are definitely on a different page in terms of our management and our evaluation of what's happening in the field.
So now all of this.
With my comments complete I'll open it up for questions.
Thank you.
Thank you so much for presenters and as a reminder to ask a question. Please press star one one on your telephone and wait.
For your name to be announced.
Okay.
Your first question comes from the line of John White of Roth.
Capital. Please go ahead.
Hi.
On slide seven.
You've got.
Development drilling focus will.
We will be the wolfcamp, a and the lower sprayberry.
Is that.
True for flat top and signal peak.
Or could you could you talk about what.
What formation characteristics may be different between those two areas.
And the Wolfcamp, a and the lower sprayberry.
Yes, John I'll have Mike answer that question you bet. Thank you John .
Near term development plan calls for the next year or so two years is to drill and co develop and lower sprayberry.
Both in flat top and signal peak.
From an economic standpoint, the a lower sprayberry.
Very similar in both areas. They are almost a lay down economically. So again, it's more fungible as to where we spend capex dollars, whether its signal peak are flat top.
As you can see the wells will have coming on throughout the rest of this year and kind of development plan for <unk> for us to continue.
Kind of a manufacturing mode method of mowing down the AE lower sprayberry with 12 years of inventory in just those two zones and earlier when when it was mentioned the IRR for these wells that was actually a net present value discounted at 10% of about 15% to 20 million.
<unk> per well, so we get our money back that we spend and roughly $20 million of well so highly economic area lot of run room for the two rig program over a decade in just those two primary zone. So again, we're very excited about being able to hold production at these.
Got a levels and grow it.
Little bit into 2024 and be able to hold that for over a decade and generate significant free cash flow.
Thanks for that detail and I'll pass it back to the operator you bet. Thank you John .
Thank you so much.
Our next question comes from the line of Nicholas Pope of Seaport Research. Please go ahead.
Okay.
They may be.
Yes.
Can you hear me yes.
Hey, I was hoping you guys might.
Talk a little bit about.
Kind of the.
The progression of working capital.
Over the near term I think with everything with the equity raise.
I think there was some.
Current ratio metrics that were pushed out and I think accounts payable and kind of built up I was curious once the cash comes in.
From the equity raise what that progression looks like over the kind of the second half of the year with with working capital.
Sure. Nick this is Steve so with.
Equity raise.
Net of a little over $150 million, we use that to.
Our accounts payable current.
And as our liquidity position a bit.
As we are in a position now <unk>.
Generating free cash flow.
Positive cash flow.
We.
We anticipate as we move forward, we will continue to bring the payables down.
That basically is a reflection of the reduced drilling program that we have going from.
Five rigs at the beginning of the year down to two rigs in downturn all sell from four frac crews to two frac fleets.
In terms of the <unk>.
Current ratio.
We did not meet the current ratio at the end of June we don't anticipate that that will be an issue on a go forward basis.
Got it that's helpful. I appreciate it.
Got one more here just looking at our Capex for the quarter.
I think Youll brought online 10, more wells in <unk> and <unk>.
Relative to one Q similar number of wells drilled, but capex was down $80 million. So I was hoping maybe you guys could talk a little bit about.
Well costs.
And maybe what.
Kind of caused that drop despite the higher level of activity if that makes sense.
You bet Nick this is Mike.
As we reduce activity of course, a lot of dollars and a lot of activity has to take place to bring these wells online so in the first quarter.
Lot of the work for the wells that come online in the second quarter were done and paid for in the first quarter. So thats part of why you see so many wells come on in the second quarter and the cost dramatically different on a per well turn in line basis, but when you kind of step back in general and just look at what the.
<unk> pricing is doing things.
Things have leveled off we're actually seeing kind of single digit overall reduction in cost from services, mainly driven from fuel.
Dealer goods of course are starting to see a little softening on horsepower and rig rates.
But it's kind of a twofold answer here as we reduced our rig count and Frac spread count. We were also able to increase the percentage of usage of all of our cost saving initiatives for instance, today, we have 100% of our frac sand needs covered with our <unk>.
<unk> wet sand, whereas when we were running for we had to supplement it with some spot pricing.
It kind of goes to the same point when you plug in just one drilling rig to highlight power that's 50% of our fleet today. So we're able to utilize more of those cost saving initiatives of what youll see on a per foot basis youll see that it is going to be larger than that kind of low single digit just oss.
Reising reduction because we get to see the higher usage of these other pieces, so think somewhere in the kind of 4% to 5% range is what we're seeing today.
Got it that's very helpful.
I'll just squeeze one more in if you let me.
Yes.
Was there any.
Thank you.
Kind of over the past year, you've had a number of.
Kind of onetime impact from.
Shut ins or Frac offsets did you see any of that in <unk> or did you. All think this was a fairly clean quarter from a production standpoint.
So Nick on any one day, you always have whenever you're fracking wells near.
Existing production Youll have shut ins.
Obviously going from the Port Frac crews down to why and you have less shut in but again as we kind of talk through that production profile that you saw on one of the earlier slides.
Early on whenever you offset and you are only producing three to kind of 20000 barrels a day and you have to shut in.
10 to 12 is very impactful when youre producing over 50000 barrels a day and you have to shut in 2500.
<unk> 3000 that is always going to kind of follow that frac crew, one year offsetting existing production.
To that I'll say it is very kind.
Kind of ratable to what you will see in the future.
And unless we go and add a lot more activity and then you can kind of look at it.
Three months out from adding a lot of the rigs then you would see a little a little bit more of that water out effect as we work to accelerate in the future but from here holding a two rig program. This is very ratably ratable it'll be up into the right for growth as opposed to the kind of the saw tooth pattern you saw in the past.
Got it okay, well I think thats plenty of time I appreciate it everyone excellent. Thank you Nick.
Thank you. So much. Your next question comes from the line of Jeff Robertson of water Tower you. Please go ahead.
I joined the call late so I missed you.
Prepared remarks, but I was curious whether or not you have any incremental data points.
Around the eastern peripheral acreage that you all have this maybe impacts your thinking or the prospectively.
Hi, techs position.
You bet Jeff.
Mentioned kind of in the past.
Our farthest northeast pad that was drilled in the and this is up and flat to up.
It's called the Conrad pad is a wolfcamp, a and a lower sprayberry.
Both of those wells kind of IP somewhere close to 1000 barrels of oil a day plus associated gas.
So again that was kind of a seven mile step out from known production back to the West again geologically we knew the rock was good we have all the Petro physics.
Seismic data and core analysis, so we felt comfortable doing that but we prove that here several months back our quarters back and then even if you go all the way into Mitchell County up in Flat-saw Bayswater as an offset operator too as to the south into the east they've drilled some wells right on there.
Very eastern flank of our acreage block of wells going north and well going south both of those wells again testing close to 1000 barrels a day and are still cleaning up.
Pretty recent wells. So again, we feel confident across our entire acreage block and flat top now if you go down to signal peak.
About mid way through about 65 ish percent of the way from west to East in signal peak.
Where we have our eastern most AA and lower sprayberry, well and for the foreseeable future Oliver and lower Sprayberry drilling that we plan to do in signal peak will be from about that.
Three quarters or two thirds of the acreage position from west to east back to the west. So it will be on known acreage, where we have production kind of book ending each side of that and that is where all of our AA and lower sprayberry inventory that is listed sits.
Within so again, we feel very confident in that 12 year inventory life of those two zones with a two rig program.
Thanks, Mike.
Bad yet.
Thank you so much chess and there are no questions at this time and this concludes today's conference call. Thank you for participating and you may now disconnect have a great day.
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