SilverBow Resources Inc. Q1 2023 Earnings Call
P&C activity was focused on our central oil and western condensate areas as expected with the 23 budget we provided in March.
While our game plan. This year remains largely unchanged. Our team continues to increase operational efficiencies optimize drilling schedules and identify cost reductions to drive greater returns on capital.
On the drilling side rig move times. This year are averaging 30% faster compared to 22. This has resulted in 10% more footage drilled per day, along with a 10% reduction in overall drilling costs.
On the completion side, our team achieved an all time record in pumping efficiency on a record path on a recent pad besting our previous high set in for Q of last year.
First quarter Nonproductive time decreased by 30% and same store stages completed per day increased by 25% compared to 22.
Furthermore, we are capitalizing on early cost deflation trends in the market recently, we have seen cost relief on rig day rates tubular goods wellhead equipment and fuel.
Frac services encompassing horsepower sand and chemicals are down 18% year to date we.
We believe key service and material costs will continue to move lower throughout the year.
In our central oil in western condensate areas well performance is in line with our expectations and supports consistent and repeatable results across our oil acreage as we move forward with full scale development.
And our eastern extension area. We are highly encouraged by initial results from a two well pad co developing the Eagle Ford and Austin Chalk, which we brought online early in the second quarter.
One of our rigs will move to this area to drill continuously throughout the second half of the year.
And our Webb County gas area, we continue to monitor regional takeaway capacity.
<unk> ability of interruptible volumes to sell into existing pipelines remains unpredictable. Although we have recently seen some opportunity to sell above firm contracted volumes.
However, this fluctuates daily and we conservatively planned for volumes to average it firm rates.
The Webb County, Austin Chalk Wells were brought online to date continue to exhibit some of the best results across our portfolio and we are excited to return to this area as prices and pipeline capacity allow.
As discussed on our last update we have two four well Austin chalk pads in Webb County, which we deferred completion in late 'twenty two.
We continue to see long term upside from this core area and early in the second quarter. We added approximately 2000 net bolt on acres.
Turning to results and outlook are.
Our first quarter production of 304, MMC FTE per day was at the midpoint of our guidance with oil production at the high end of the range.
For the second quarter, we are guiding to production of $3 25 per day at the midpoint, which implies a 5% to 10% production increase sequentially.
Yes.
Full year 'twenty three production guidance of $3 25 to $3 45 per day is unchanged and implies overall production growth of 25% and oil production growth of 100% year over year.
By year end as Sean noted liquids production is expected to comprise 40% to 50% of our total mix with that I'll turn it over to Chris.
Thanks, Steve and.
In my comments. This morning, I will highlight our first quarter financial results as well as our price realizations hedging program operating cost and capital structure.
First quarter oil and gas sales were $140 million, excluding derivatives with natural gas, representing 66% of production and 38% of sales.
During the quarter, our realized oil price was 96% of Nymex <unk>, our realized gas price was 86% of Nymex Henry hub.
And then our realized NGL price was 30% of Nymex <unk>.
As shown on slide 21 of the corporate presentation, we have historically realized prices close to Nymex benchmarks.
During the quarter, our realized gas price was impacted by widening basis differentials and is lower than our historical range compared to Henry hub.
This has been caused by the loosening of regional supply and demand.
Risk management is a key aspect of our business and we are proactive in adding basis to further supplement our hedging strategy for.
For 2023, we have secured gas basis hedges on 157 Mcf per day to mitigate further risk.
Our realized hedging gain on contracts.
For the quarter was approximately $20 million.
Notably our first quarter hedge revenue per Mcf of $5 84.
Was the highest revenue per unit silver bow has realized to date.
This is impressive considering the declines in the first quarter, Henry hub benchmark pricing compared to last year.
The higher revenue per unit reflects the mix shift impact of higher oil production as well as the strength of our current hedge position.
Based on our hedge book as of April 28 for the remainder of 2023, we have 180 Mcf per day of natural gas hedged 7400 barrels per day of oil hedged at.
<unk> 3750 barrels per day of Ngls hedged.
Using the midpoint of our production guidance, we are 91% hedged on gas and 48% hedged on oil for the remainder of this year.
For 2024, we have approximately 102000 Mcf per day of natural gas hedged 3300 barrels per day of oil hedged and 4800 barrels per.
Per day of Ngls hedged the hedged amount are inclusive of both swaps and collars.
Detailed summary of our derivative contracts is contained in our presentation and 10-Q filing for the first quarter, which we expect to file later today.
Turning to costs lease operating expenses were <unk> 78 per Mcf transportation and processing costs were <unk> 42 per Mcf production taxes were 7% of oil and gas sales.
Cash G&A, which exclude stock based compensation was $6 5 million for the quarter, which includes one time professional fees.
For full year 2023, we are guiding for cash G&A of $19 $5 million at the midpoint, which implies cash G&A on an <unk> basis to be slightly down year over year inclusive of one time fees.
We consider our lean cost structure to be a differentiator, allowing silver voted sustained profitable profitability during periods of volatile commodity prices.
Adjusted EBITDA for the quarter was $111 million.
Capital expenditures for the quarter on an accrual basis totaled approximately $108 million.
Full year 2023, our Capex guidance is unchanged at $450 million to $475 million.
Included in our guidance range at the completion of four.
A four well Austin chalk gas pad in the fourth quarter and opportunistic land spend.
As reconciled in our earnings materials.
We recorded a free cash flow deficit for the quarter.
Cash flows in the first quarter were constrained due to differing the completion of <unk> Webb County gas wells drilled in the fourth quarter of last year and ongoing gas curtailments in Webb County.
The timing of D&C projects and land spend create variability in our quarterly free cash flow results.
Based on our latest guidance and outlook, we expect free cash flow to run at a slight deficit in the second quarter. However.
With strong growth in the second half we are projecting positive free cash flow for the full year.
Turning to our balance sheet total debt was $709 million as of March 31, we had $216 million of availability under our credit facility and $2 million of cash on hand, resulting in $218 million of liquidity.
Silver bow in accordance with our credit facility includes contributions from closed acquisitions for the entirety of the LTM adjusted EBITDA period used for leverage ratio calculation.
On an LTM basis for the period ending with the first quarter of 2023, the contributions from acquired properties totaled approximately $63 million.
Bringing our LTM adjusted EBITDA for covenant purposes to $493 million and our quarter end leverage ratio of 214 times.
So staying with our strategy the last several years excess cash flows that are not reinvested through the drill bit will be used to pay down revolver borrowings and silver Bell continues to target a leverage ratio of less than one times.
At the end of the first quarter, we were in full compliance with our financial covenants and has sufficient headroom and with that I will turn it over to Sean to wrap up our prepared remarks.
Thanks, Chris.
Silver boat continues to execute on its growth strategy and is positioned for significant value creation going forward.
We project continued double digit growth over the next several years as we March towards a half a billion cubic feet equivalent per day of production.
In the near term our key catalysts first Nick holders is our ramp in oil production.
Our relentless focus on our employees wellbeing and safety is paramount to our culture as is our engagement with the community and our environment. We look forward to sharing more of our insights towards safety Kleen operations with the release of our <unk> sustainability report in the near future.
I want to thank all of our stakeholders for their continued support we look forward to providing further updates on our next call.
With that I will turn the call back to the operator for questions.
Thank you at this time I would like to remind everyone in order to ask a question press star one.
One on your telephone keypad, we will take our first question from Donovan Schafer with Northland Capital markets. Your line is open.
Okay.
Mr. Schaffer go ahead your line is open.
Sorry about that.
Muted myself.
So I wanted to start off with interruptible capacity.
I was just curious if you can.
Can give us a sense for magnitude around what or what you may or may not be able to ship to the interruptible capacity I mean, I know that's like Super hypothetical and I think correct me, if I'm wrong, but your guidance kind of assumes.
No no no.
Not having any interruptible capacity on the gas side.
So I'm kind of just thinking in terms of like error bars here.
Of course, he has to have a crystal ball.
But just sort of in theory is this the type of thing where when when interruptible capacity is available that can add like another 5% to 10% of volume, but then maybe maybe that's like one day a week. So then it ends up being de Minimis, just kind of trying to.
To get my mind around how to just think about it more conceptually.
Yes, no I appreciate the question.
And your question around how much availability is there and how sustainable it is is kind of spot on.
When we do see available capacity, it's probably 5% to 10% above what we can produce.
So that's not a bad number but at this point, it's very inconsistent.
<unk> only for a day or so.
We still are guiding towards our firm capacity for the full year.
It's prudent that we do that.
Guidance.
Okay and then.
I also want to ask.
The efficiency again, it sounds like D&C costs, you got the deflation aspects, but also pretty significant efficiency improvements.
And so I'm wondering is this does this is it unfolding in a way that sort of efficiency improvements.
The uptime, you talked about with the Frac spreads.
Is that like is that kind of a proof point or like an unfolding in a way that's in line with their consistent with I think kind of the initial.
Part of the strategy the idea around being.
Just one of a couple of consolidators like in the Eagle Ford before I think the idea of when you guys talked about before was if youre one of just a couple of consolidators. It gives you the scale too.
Two.
You can get some better pricing, but then possibly even more importantly, you can get higher quality crews I know, having a crew that sticks together.
Executes a while and you don't have someone not showing up to work one day or whatever.
This is really important so have you been able to kind of.
Get crews that you feel like are kind of high quality and then retain them as it is it like I guess unfolding in a pattern and the nature of that Youre kind of thinking back to the original consolidation strategy.
Yes, yes, yes.
We're firm believers that with scale, there's a lot of Optionality that comes with it from increased purchase power, but also it brings consistent.
Operations over a long period of time, as we're able to level load our services and we are seeing that play out.
Continually work with our service providers to build stronger partnerships, we pride ourselves on being prudent schedulers and I think we get that feedback from the service providers that.
We put more consistency into their schedule.
As a result, we're seeing improved performance.
Performance.
From their side of the business. So I do think it's not easy to be a consolidator. It takes an operator that has a proven track record and I think our company has demonstrated that and that we continue to best our record performance quarter in and quarter out and I think it speaks to just having a larger foot.
Britain more level loaded operations.
Okay.
That's helpful and then.
That's my last question then I'll.
Paul.
Any others offline or maybe I'll jump back in the queue, but the last question I've got.
Is.
With the new pipelines, you talked about coming online kind of towards the end of the year kind of similar similar type of question to what I was asking with the interruptible capacity can you just give us a higher level of kind of framework or conceptual way to think about.
These new pipelines like like the magnitude of the volume they could move relative to what the takeaway capacity existing.
20% increase 30% increase of what.
The capacity of takeaway from the region, where you are producing.
And then if possible.
What does that translate into for basis or pricing improvements again, I know you don't have a crystal ball on my Benji of course benchmark prices and everything so maybe it's something best to talk about and kind of relative terms, but.
Something along the order of <unk>.
This is going to increase capacity takeaway capacity at 30% and that would tend to translate into like a 10 ish twentyish percent or even more like it's more levered to the capacity again, just kind of trying to get the framework to think about what those could be.
Yes.
Yes definitely.
Web County, dry gas play has really.
Boomed over the last 18 to 24 months as several large operators have come in and start to develop the high quality Eagle Ford and Austin chalk zones.
Takeaway capacity out of that area currently sits around two five Bcf a day.
With the planned expense expansions that are scheduled to come online by the end of the year that probably takes it up not quite double that but takes it to about four five Bcf a day.
Potential expansion so definitely.
Provides for more volumes to come out of the area in the years to come now speaking to what's that mean from a basis differential standpoint. Our view is we're still very bullish on gas.
Especially as you get into 'twenty five 'twenty six.
Timeframe with a lot of new demand coming online in the Gulf primarily on the LNG export front and so I think you look at macro forecast across the big gas basins, and there's going to be a shortage and our belief of gas volumes once we get to that period.
And so this expansion in Webb County, we think is going to be critical to help meet some of the demand needs.
We expect that not only will.
Absolute gas price increase going forward in the strip reflects that but we think basis will tighten back up to more historical levels and we will see close to Nymex pricing as we move forward into the late 2425 timeframe.
Okay, so thinking.
<unk>.
Benchmark goes up and then.
Youre not going to suffer any.
Donald are getting boxed out from benefiting from that so benchmark goes up and you get kind of a clear translation into that okay that makes sense alright. Thanks, guys I appreciate it. Thank you.
Next we'll go to Charles Meade with Johnson Rice. Please go ahead.
Yes.
Good morning, John to you and the whole <unk> team there. Thanks, good morning Charles.
To ask a question about about your your eastern extension and I think Steve touched on this in his.
His prepared comments, but I was wondering if you can.
<unk> for me and for others listening.
What you've done so far in 2023 over there because I think Steve said that you brought on one Eagle Ford and Austin Chalk and also.
I think theres plans too.
When you move the rig there or maybe you are about to move a rig there.
They do more of this Eagle Ford and Austin Chalk. So can you just give us a recap of what you've done so far what you what the plans are for the remainder of 2003 and to extent that it sounds like you do have some well results.
Those are coming in versus your your risk plan, yes.
Yes, you bet.
To recap. This block is a result of two acquisitions that we did one in 'twenty, one and one in 'twenty, two where we can.
Put together just under 20000 acre block and consolidated the working interest within the block and wanted to get that all in place before we went in and started drilling so early in.
'twenty three we drilled our first two well pad.
One Eagle Ford one Austin chalk like you mentioned the <unk>.
Well just came online they are still ramping.
Haven't quite reached IP are just starting to get there. So we wanted to not get out in front of the results on the quarter announcement, but.
To Steve's comment in the script.
We're pretty excited with what we're seeing can tell you that the results are coming in line or exceeding.
To date.
And <unk>.
Comment that we're going to move a rig in there in park. It for the second half of the year should give indication of what we're thinking about the results thus far as well.
Got it and so the rig the rig was they're drilled the two well pad it sounds like it moved up but youre going to youre going to parkland there for the second half.
Look.
That is.
Got it thank you Sean.
And then <unk>.
A follow up to the.
On the the whole A&D landscape.
We've seen some.
My perspective, it looks like the <unk>.
The Eagle Ford, Kevin slowed down and then we got a couple of.
Got an unusual move with a Canadian company coming in.
And making a corporate deal and then this morning, we have a.
A company that's been a longtime player in the Eagle Ford selling disposition and concentrated in the.
In the in the Permian. So I was wondering if you could give us your thoughts about what the what the.
Essential.
And what the landscape looks like today and.
Particularly are there chances for you to perhaps delever through some acquisitions in the Eagle Ford.
Yes, the Eagle Ford.
Definitely has been <unk>.
An area of significant activity really over the last nine months now.
And like you mentioned just over the last couple of days there has been a couple of transactions announced.
As well, one public selling to a private and one private selling to a public so continues to be a range of activity.
And <unk>.
A range of size and scale with many of the packages being announced between prices of a half a billion dollars up to $2 5 billion. So a lot of interest in the Eagle Ford.
For the reasons, we've laid out in the past.
Bae begs the question how much activity remains.
In the Eagle Ford and can silver bow participate in that yes, we still think there is a lot of further consolidation to occur.
Think that Theres two reasons to do that in the Eagle Ford sets up well for it first is the law.
The gas window of the Eagle Ford.
The economics are very strong and look extremely attractive moving into a.
A contango price curve. So we think there is an avenue there and then we think that is.
It's becoming more coming more into <unk>.
Views it.
Core inventory starting to dry up in a lot of basins and we think that there is runway in the Eagle Ford and folks recognize that so we think there is consolidation that can occur, especially in the western Eagle Ford.
Around right now the acquisitions being done near PDP value, but exposes buyers to a lot of inventory that should look attractive in the years ahead.
So yes.
Yes, we think Eagle Ford will remain active in our plan is to be active and we think that through that growth. There is opportunities like you mentioned to to Delever based upon how we structure the deals.
That's helpful detail on your thinking thanks, Sean.
Charles have a good day.
Okay next we'll go to Neal Dingmann with Truest Securities. Your line is open.
Good morning, all thanks for the time, Sean My first question is just wondering a little bit more on how you're thinking about capital discipline specifically.
You've mentioned potentially in the release about slowing gas focus activity later in the year, but I am wondering if oil continues to go lower creep lower like it's Julian and gas remains weak would you all consider going more to a single rate plan in order to.
We forecast will be a nice boost enough free cash flow.
Yes, yes.
One of our guideposts is to spend within cash flow.
And so we're going to continue to adhere to that end.
There's been just a lot of volatility on both commodities, but just over the last really 30 days on oil.
<unk> done it at $20.
Cycle in that short period of time.
So we will continue to monitor both commodity prices and adjust our capital really driven by returns on investment.
And staying within cash flow.
What's good is we have a lot of flexibility in our operations. So no really contractual obligations on the service side.
Any meaningful nbc's or land commitments that can't be handled with with one rig or even less than one rig so.
Yes, we're really.
Plan to stick with the strategy of growing but doing it within cash flow and if commodity prices arent there to accommodate that strategy, we will dial back in.
Our hedge book and the growth that we've already generated year to date to your point.
You have a lot of free cash flow in the near term if we dialed back capital.
Yes, it's really like that Optionality and then my second question is.
How big of a benefit do you believe I mean, maybe even for the remainder of this year next year.
How big of a benefit do you believe your operating efficiencies that you continue to see and potential softening Oss costs could have on the plan.
Yes.
We started to see this early earlier in the first quarter. It's continued to play out both on the operational.
Efficiencies and some deflationary pressure.
It didn't feel like we wanted to.
Lower the capital guidance at this point in time wanted to see how it plays out for another quarter, but yes, we think the way things are setting up there is probably a.
Plus or minus 10% realization that we're seeing year to date, and we think that could potentially double in the second half of the year.
Well great to hear thank you yeah. Thank you Neal have a good day.
Next we'll go to Tim <unk> with Keybanc. Your line is open.
Good morning folks thanks for.
Let me ask a couple of questions.
Charles sort of stole my topic on the eastern extension, but I thought I'd maybe pick at it.
A little more.
So obviously you seem excited you don't have numbers to share.
Was the decision to move that rig for the second half of the year made before.
This pad was drilled.
Or is it something that you are more confident in whats early production.
It came back at you.
Yes.
<unk> had.
Ahead of our plan has us moving the rig there but wanted to.
Just derisk it a little bit both on the capital side, the performance side as well as the reservoir performance side since we hadn't drilled in that area before but had a good feel for what the.
Both capex and well performance would be.
Going in through the acquisitions, but just wanted to make sure we feel still comfortable and felt it was prudent to get two wells under our belt versus getting in there and drilling a half dozen before we saw some results. So really it's the two wells to date, our confirmation of our expectations.
It's a really are sticking with our plan.
Okay, Okay, I guess, maybe.
In the next quarter gets us some numbers around that yes, I know.
Okay I know, it's early but can you talk about the.
The oil cuts there relative to kind of the western liquids area.
Yes.
So our position really spans.
The windows.
With some of it within the volatile window window some of it within the condensate.
Our two wells drilled to date oils, probably in that 70% range.
So more oil rich than the western.
Condensate area.
Our plan in the second half of the year is actually to drill in both windows.
The condensate windows more in that probably 40% oil, 30% liquids, 30% gas.
Ballpark, so kind of a mix there.
So.
We'll probably if I was to ballpark at the second half of the year is half drilling in the volatile oil window of the eastern extension and half in the condensate window.
Okay. Okay.
I look forward to the results there and then somewhat related to that I'm, just trying to reconcile a little bit of housekeeping on the modeling front press.
Press release talks about oil.
It was 40% to 50% of production by the fourth quarter.
Slide decks at liquids of 40% to 60% in the second half of the year.
Oil was 22% of production in the first quarter.
Should we just think about that as sort of a steady ramp kind of mid 40% level by the fourth quarter.
I'm just trying to.
Sort of model that cancellation, good question, and probably we need to look and make sure we're consistent on the nomenclature.
40%, 50%.
Is a reflection of total oil or excuse me total liquids percentage not oil percentage.
Think of it yes, 40% to 50% liquids.
The liquids two thirds is oil one third is ngls.
Okay. Okay, and then just to make sure we clarify that if we have a mix of nomenclature scattered across.
So just to clarify then should we think about.
Oil being.
30, mid 30% of production in the fourth quarter or kind of China.
Get our arms around is that what you're sort of saying.
Yeah.
Yes.
Do the math in my head, but yes, I think we'll be into the 30% probably low thirties.
Okay. Okay. Thank you on that Jeff offline about this just to make sure we're thinking about it correctly.
I appreciate the comments. Thanks, yes, yes, thanks, Tim I have a good day.
Next we'll go to Noel parks with Tuohy Brothers. Your line is open.
Yeah.
Hi, good morning.
Good morning.
Just a couple of things.
Wondering about.
The co development of the Eagle Ford and Austin Chalk are there any particular technical challenges on the completion side or the drilling side or is it more a matter at this point. Thanks.
Great selection sort of pre drill analysis.
Yes.
No.
There is some operational differences between the two zones, but in terms of.
Planning for and taking in advance of the co development, taking that all into account, we're fully aware of it and probably and Steve can chime in on this that the biggest difference is in certain parts of the play we can drill Austin chalk with two stream, but need to.
Set an intermediate stream going into the Eagle Ford So thats, probably the biggest technical difference, we see that the Austin chalk drills is little bit harder rock, so drills, a little slower, but again not not anything different from a frac completion side.
Just proper chemical makeup or anything like that Steve I don't know if I missed anything that you might want to add I think you covered it excellently and then we've just done a little more fine fine tuning on mud weights for both of them for both wellbore stability as well as well control.
Okay great.
Okay.
And.
I was wondering.
We.
And can you.
One months on this sort of a tough near term.
Hi.
Thanks for the reminder, you didn't have the pad that you could move.
I was thinking about other other opportunities if we if we do see sort of a return to volatility that takes us up.
In in your <unk>.
Gasoline out west.
Web County development is over the last five six years so.
Much of the completion was at optimized levels as far as we're concerned so.
We don't see that area as like a high Workover high re completion area and we've been spending more dollars doing that on the oil front as we've gotten some of these assets that were kind of.
<unk> loved over the last couple of years, so we've been having some success on that front, but.
Yes on the gas front, it's really we've got two four well pads that we could.
Complete if.
Prices justified it and there was availability in the pipeline anytime through the year, but the other thing is we're just so efficient.
A two day period, we can move a rig back in there.
Drill a three well pad in a month's time frame.
Habit frac another 30 days out so we can ramp.
Drilling activity up in 60 days there from moving the rig in the beginning first production.
So that's probably our best leverage is just the flexibility of the rig.
Okay. Okay, great. Thanks, a lot I appreciate it have a good day.
Next we'll go to Jeff J with Daniel Energy Partners. Your line is now open.
Thank you I just wanted to circle back to the drilling and Frac savings you talked about the 10% and 18% and I was curious if that's sort of absolute pricing. If theres efficiency is kind of baked into that and if you can help us kind of disaggregate.
The pricing and the efficiency components of that.
Yes.
Definitely a combination would tell you that we're seeing for the most part.
Prices come down across the majority of services and materials summit at different levels, but.
It.
Both service cost and material cost in on.
Drilling completion and even on the operating expense side.
On a production side seen chemical costs come down trucking costs come down as you might expect with lower fuel prices relative to last year.
Breaking it out don't have those numbers in front of us.
But definitely a combination of deflation and efficiency.
Steve.
Have any thoughts or comments that you could add to that yes, a lot of the process efficiencies. We have occurred incurred already experienced from essentially November .
Through where we are right now and looking perhaps for a few more but yet for that to taper down most of it at this point forward now we are seeing in unit cost currently unit costs. So if you kind of weigh that out over the course of the year that kind of split equally.
As we look for about an overall, 17% to 20% reduction in both drilling and completion through the end of the year.
Awesome, that's really great detail, thanks, a lot.
Yes, you bet, Jeff Thanks.
Okay.
And there are no further questions at this time I'll now turn the call back over to our presenters for any additional or closing remarks.
No I'll just close by thanking everyone for joining our call today, we always appreciate the.
The questions and the interest in the company and look forward to further updates at the next quarter call everyone have a nice day.
This concludes today's conference call you may now disconnect.
Okay.
Okay.
Okay.
Yeah.