Q2 2023 SilverBow Resources Inc Earnings Call
If you'd like to ask a question. During this time simply press the star followed by the number one on your telephone keypad, if you'd like to withdraw your question Press Star one once again, thank you, Jeff Maggots, Vice President of Finance and Investor Relations you May begin your conference.
Thank you David and good morning, everyone. Thank you very much for joining us for our second quarter 2023 conference call with me on the call today are Sean Woolverton, our CEO .
Steve Adam our CFO and Chris <unk>, our CFO .
Yesterday afternoon, we posted a new corporate presentation to our website and will occasionally refer to it during this call we encourage listeners to download the latest materials.
Please note that we may make references to certain non-GAAP financial measures, which are reconciled to their closest GAAP measure in the earnings press release.
Our discussion today may include forward looking statements, which are subject to risks and uncertainties many of which are beyond our control.
These risks and uncertainties are described more fully in our documents on file with the SEC, which are also available on our website with that I will now turn the call over to Sean.
Yeah.
Thank you, Jeff and thank you everyone for joining our call. This morning.
Silver both second quarter results demonstrated the impact of our oil focused development program and the team's ability to meet and exceed our objectives.
Our differentiated strategy is delivering growth while living within cash flow this year.
And we are well positioned to generate significant free cash flow over the next 18 months.
I'm pleased to report that during the quarter, we published our inaugural sustainability report.
With this report we now have the standardized framework in place for investors and other key stakeholders to fully appreciate our ESG stewardship.
Okay.
Turning to results.
Second quarter production came in at the high end of guidance and increased 40% year over year.
Our production growth was driven by strong performance from our oil assets.
As our oil production exceeded the high end of guidance and has nearly tripled year over year.
As Chris will further detail the rapid shift of our production mix resulted in 75% of revenue derived from liquids.
Paired to less than 33% a year ago.
On the cost front, our operating expenses came in below guidance across the board.
For the full year, we are lowing, lowering our capex guidance by approximately 10% to a range of $400 million to $425 million.
Our efficiency gains and cost savings year to date, along with several optimizations to the DNC schedule by Steve's team are allowing us to reduce our capital spend while still delivering our full year production guidance.
We also introduced full year 2023 free cash flow guidance of $10 million to $30 million.
Higher liquids production lower capex spend and a ramp in our gas volumes at year end is expected to drive positive free cash flow on a full year basis.
The ability to self fund our differentiated growth profile is a core tenet of our strategy.
While 2023 represents a significant increase in oil production, we remain focused on a balanced commodity approach.
During the quarter, we made several.
Strategic advancements in our long term gas development plans.
In Webb County, we leased additional acreage near our Dorado dry gas position.
Where we have seen some of the best returns on our portfolio.
Importantly, we also entered into pipeline gathering agreements on new infrastructure coming online by year end, which will support our multiyear development plans in this area.
We are planning to allocate capital to our gas assets over the second half of the year.
We plan to complete a DUC four well Austin chalk pad and move in a drilling rig in the fourth quarter.
These actions will ramp up our gas volumes at year end and into 2024 alongside higher anticipated natural gas prices.
Turning to our portfolio. We currently have 10 plus years of inventory identified.
With roughly two thirds liquids locations and one third gas locations.
We have flexibility to adjust development to prevailing commodity prices.
A key objective of the company is to continue to expand our inventory through unlocking incremental opportunities on our on our existing assets leasing of additional acreage and making accretive acquisitions.
To wrap up my prepared remarks, our near term focus is on oil development.
Excellent rate liquids production at year end combined with plans to ramp gas production next year position silver bow to generate significant free cash flow in 2024.
This free cash flow will be used to drive our leverage ratio towards our stated target of less than one times.
Our team has an established track record of delivering on our key objectives through commodity cycles.
With that said I'll turn the call over to Steve.
Thank you, Sean and the second quarter, we drilled 13 net wells completed 15, net wells and brought 15 net wells online.
Our D&C activity during the quarter was focused on our central oil western condensate and eastern extension areas.
Our team is executing on our oil focused strategy this year with results outperforming expectations.
Year to date, our operational efficiencies continue to increase.
The drilling side, our rig cycle times are 10% better than 'twenty, two with footage drilled per day, 14% higher.
We estimate that realize D&C savings or roughly 5% to 10% to date with leading edge market rates continuing to indicate further reductions through year end.
Specific to oil strong well performance drove second quarter production above our guidance range. The performance to date supports consistent and repeatable development results.
Additionally, we are encouraged by the early ongoing tests of the Austin chalk in co development with the Eagle Ford on our oil assets.
And our Webb County gas area, the availability of interruptible volumes to sell into existing pipelines remains unpredictable.
We continue to conservatively plan for volumes to average it firm rates for the remainder of 2023.
That said, we see Webb County gas is a cornerstone to our future development.
We continue to expand our inventory in this area leasing 2200 net acres during the quarter and we have now assembled nearly a 20000 net acre position with 175 identified drilling locations and one of the most profitable gas plays in the country.
As we remain bullish on our long term gas prices and to ensure efficient development of this inventory. We have also secured multiyear takeaway agreements on incremental pipe that will be coming online towards year end.
Turning to results and outlook are.
Our second quarter production of 330, MMC FTE per day was at the high end of guidance with oil production exceeding our guidance range.
For the third quarter, we are guiding to production of 341 Mcf per day at the midpoint, a 3% increase quarter over quarter.
Full year 'twenty three production guidance of 325 to 345 per day is unchanged and implies overall production growth of 25% and oil production growth of 100% year over year.
Yeah.
In regards to our capital budget, we plan to continue to allocate 100% of our drilling capital in both of our rigs to oil projects through Q3, and then as previously mentioned our plan is to have one drilling one rig drilling oil and the other drilling gas starting in Q4.
Of course, we will remain flexible on our capital allocation as we optimize our drilling schedule and completion dates accordingly.
With that I will turn it over to Chris.
Thanks, Steve in my comments. This morning, I will highlight our second quarter financial results as well as our price realizations hedging program operating cost and capital structure.
Second quarter oil and gas sales were $126 million, excluding derivatives with natural gas, representing 64% of production and 27% of sales.
Of note oil represented 63% of second quarter sales compared to 24% a year ago.
During the quarter, our realized oil price was 96% of Nymex <unk>.
Our realized gas price was 84% of Nymex Henry hub, and our realized NGL price was 25% of Nymex WTS.
As shown on slide 22 of the corporate presentation, we have historically realized prices closer to Nymex benchmarks.
Year to date, our realized gas price has been impacted by widening basis differentials and is lower than our historical range compared to Henry hub.
This was a result of a loosening of regional supply and demand more recently, we are observing differentials that are closer to historical averages at the regional market has reverted to a more balanced market.
Risk management is a key aspect of our business and we are.
Proactive in adding basis to further supplement our hedging strategy.
For 2023, and 2024, we have secured gas basis hedges on 155, and 140 Mcf per day, respectively to mitigate further risk.
Our realized hedging gain on contracts for the quarter was approximately $30 million.
Based on our hedge book as of July 31 for the remainder of 2023, we have approximately 180 Mcf per day of natural gas hedged 8900 barrels of oil hedged and 3750 <unk>.
Barrels per day of Ngls hedged using the midpoint of our production guidance, we are 93% hedged on gas and 53% hedged on oil for the remainder of this year.
For 2024, we have approximately 135 Mcf per day of natural gas hedged 8400 barrels per day of oil hedged at 4500 barrels per day of Ngls hedged the.
The hedged amount are inclusive of both swaps and collars.
A detailed summary of our derivative contracts is contained in our presentation and 10-Q filings, which we expect to file later today.
Turning to cost.
Lease operating expenses were <unk> 67 per Mcf.
<unk> and processing costs were <unk> 39 per Mcf.
Production taxes were 7% of oil and gas sales.
Cash G&A, which excludes stock based compensation was $3 9 million for the quarter, our second quarter costs compared favorably to guidance across all categories.
Full year 2023, we are guiding for cash G&A of $19 million at the midpoint.
Which implies cash G&A on an <unk> basis to continue to trend at lower levels compared to 2022.
We consider our lean cost structure to be a differentiator, allowing silver boat sustained profitability during periods of volatile commodity prices.
Adjusted EBITDA for the second quarter was $112 million.
Capital expenditures for the quarter on an accrual basis totaled approximately $117 million.
Full year 2023, we have lowered our capex guidance range to $400 million to $425 million, an 11% decrease at the midpoint.
Our guidance update captures the optimizations to scheduling that Steve mentioned as well as cost savings and efficiencies realized to date.
As reconciled in our earnings materials.
We recorded a free cash flow deficit for the quarter cash flows have been constrained due to ongoing gas curtailments in Webb county over the first half of the year.
As oil production continues to ramp in the second half of the year and gas volumes come online at the at year end, we expect to be free cash flow positive in the third and fourth quarter for the full year, we are guiding to free cash flow of $10 million to $30 million.
Turning to our balance sheet total debt was $726 million.
As of June 30, we had $199 million of availability under our credit facility and $1 million of cash on hand, resulting in $200 million of liquidity.
Yeah.
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 calculations.
On an LTM basis for the period ending with the second quarter of 2023. The contributions from acquired properties totaled approximately $10 million, bringing our LTM adjusted EBITDA for covenant purposes to $467 million and our quarter end leverage ratio to one six times.
Consistent with our strategy of excess cash flow that is not reinvested through the drill bit will be used to pay down revolver borrowings and silver both continues to target a leverage ratio of less than one times.
At the end of the 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.
<unk> continues to execute on its strategy and is positioned for significant value creation going forward.
We project continued double digit growth over the next several years as we get closer to a half a billion cubic feet equivalent per day of production.
In the near term key catalyst for our stakeholders, our continued ramp in oil production and increased gas takeaway capacity at year end.
Our strategy emphasizes operational flexibility and real time capital allocation.
Through our highest returns on investment.
The ability to pivot between oil and gas development has been and will continue to be a competitive advantage for us.
I want to thank our stakeholders for their continued support.
We look forward to providing further updates on our next call and with that I'll 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 then the number one on your telephone keypad will pause for a moment to compile the Q&A roster.
Our first question from Neal Dingmann with Truest Securities. Your line is now open.
Yes.
Hey, good morning, guys.
So my first question is just on your oil development sounds like you're really making strong progress there with the program, but I'm just wondering.
Given the suggestion I think you'd mentioned about a 100% year over year growth can you speak to the number of locations. You. All are identifiers that I believe you have left there and then secondly, what type of efficiencies you are continuing to see in this program.
Yeah, Hey, good morning, Neil.
Thanks for the question.
Yes, so the rigs this year have been focused on our central oil Larian and our eastern extension both areas really that we're built out of acquisitions over the last couple of years. So I'm very proud of the team's integration of those assets and successful pivot into those areas really since the end.
Of last year.
As of today, we continue to look for.
To further expand our inventory there we quantified that we have about 400 liquids locations.
Going forward in.
And that includes the central oil area Eastern extension as well as our historical central condensate of those 400.
100 are in the western condensate area.
And the other 300 plus remain in those other two areas so plenty of runway there.
One of the things that we are doing we drilled a couple of Austin chalk wells.
In.
One is in the central area. Another one in the eastern extension.
Kind of monitoring those early results so that zone, we really didnt, even underwrite any value to in our acquisitions. So we're making efforts to try to unlock incremental value from those transactions.
Great and then just secondly on the web County pipeline gathering agreements you highlighted just sounds quite positive just want to make sure I understand what you know what.
What are the benefits around.
Bringing that on.
Yes really.
Over the last couple of years, just as Webb County gas.
Growth really took off.
By end of 'twenty, two takeaway out of web was cap no probably about $2 five Bcf a day.
So incremental type thats coming on will expand net.
Capacity there is two projects one that we've <unk>.
Contracted with another project that will increase takeaway out of web by another two Bcf a day, so really increasing takeaway capacity for the area and will allow us and other drillers to start expanding our drilling programs once again.
What we really like about it it's kind of aligning up with improved gas prices.
Yes, so for US it was securing some firm capacity on the projects to ensure that we're able to develop our plan over the next several years.
And have the capacity to take that gas away from the county over more into South Texas markets.
Yes, like that upset at Briggs, Thanks, Sean Yes, yes, thanks Neil.
And then as a reminder, everyone to allow everyone an opportunity we ask that you. Please limit yourself to one question and one follow up next we'll go to Charles Meade with Johnson Rice. Your line is open.
Good morning, Sean to you and the whole sorbo team there.
I'd like to ask.
Another question, you could drill down a bit more on your.
On your oil results from from these recent pads and it looks like you've put a lot of good information in your updated presentation I'm looking particularly at slide 13, and it looks like that those two are the two pads that the court and the James Keith that you have in northern live Oak.
It looks like those are the ones that are.
Really contributing most of the outperformance that.
I guess.
Powered youre cheeky results in.
Are hopefully going to continue and if it <unk> <unk> is that the right read or are those the two pads.
That are really the drivers and can you talk about what maybe you did differently or youre seeing differently with the early production results there.
Yes, yes.
I appreciate the question.
Type curve right is kind of a.
Conglomeration.
This area, but would tell you that there is definitely variance across this area.
In reservoir quality reservoir pressures.
Moving kind of out of a little bit deeper area, where the curve and the James Keith exist as you move north like to the Edmond Tom.
So we got an average.
The type curve, you would look and say hey, it looks like the Edmond Tom's underperforming.
Actually those wells relative to their specific type curve.
Are exceeding expectations. So we're really pleased across all of them.
Some of the things that we're doing differently.
I think we're really focused on in zone drilling that the previous operator, as we went through it and re drilled their wells the historic wells that Didnt feel like they did as strong of job. There and then just a very concentrated frac design that we've optimized and other parts of the basin over the last several years.
So that's really the driving mechanisms of the outperformance and now with that said on the Edmond Tom area being a lower pressure area. One of the things that we've done is quickly converted to artificial lift.
And we're just seeing production optimization there.
Flattening decline so some.
Some of the outperformance for the quarter. What it is that we're seeing is just flatter production out of the new wells for a longer period of time. So we're really excited to operationally what we've done thus far.
Got it that's helpful incremental detail that debt.
But you have those I guess.
Region of assets asset specific type curves.
Sean the other thing I want to I want to explore.
Is the <unk>.
You referenced in.
In your prepared remarks, you wouldn't see both of that.
That you guys can flex back and forth between natural gas and oil in that and that you are planning to go back to.
Having one rig when gas directed rig in <unk>, what I'm curious about is.
How.
What's the what's the timeline between between when you make that decision and when you actually.
Our drilling to a different location because of it so kind of you know the elapsed time from from when you when you decide to two when you actually.
When you start to.
Walter course, and then the second piece is.
You know not that Theres, just one price that are you know I recognize it is not just a one price that's still going to be a threshold and that we're buying area on either side of it but but in general can you give us a sense for what kind of natural gas price you're looking at for for when you decide to make that decision.
Yeah.
Yes, yes, no. Good question, maybe break it down first operationally the flexibility we have and then address the price.
<unk> operationally.
We did this.
Late last year early part of this year it takes us less than 30 days to make that decision right. So we will have gas pads.
Ready to go permitted built.
<unk>.
That gives us the flexibility to move the rig. So we're ahead of schedule so essentially.
Within a.
A month, usually it takes a month to drill a pad we will make that decision Hey next pad up is going to be gas.
But we'll have an oil pad ready that PE prices moved in the wrong direction over the next 24 months. So let's go ahead and move to the oil so it's really.
I would say at a month to month decision.
One of the things that we've done to really help grow into the incremental pipeline capacity, that's coming online in the fourth quarter is we have ducks.
That have been.
Sitting as Doug since early this year. So the first actions, we're going to take is to complete the ducks.
And ramp into the incremental pipeline capacity and then as of now supported by gas prices will move the drilling rate starting probably early fourth quarter into the area.
That decision point really the economics down there we like at $3 50, plus in next year.
Right below $3 50 has been hanging in that ballpark for the last couple of months in 'twenty.
25% at $4. So we like that setup and it supports the decision to move the rig you get down below three over.
Neil first 18 months of development like what we saw this year and we would not drilled those projects. So probably just a rough rule of thumb for us would be at $3 gas price wed look to stay in the oil windows.
Got it that is helpful detail. Thank you Sean.
Thanks, Ross I have a good day.
Hey, guys. Thanks for taking the questions. So I will.
The details on the improvements in.
Cost there was cost there was also a cost reductions and also efficiency improvements and you gave the specifics of.
Even.
Efficiency.
Are you seeing or hearing operators also in the Eagle Ford that maybe are not getting the kinds of improvements.
They are getting.
Is that delta coming more from operational improvements or maybe a testament to differences and acreage quality.
And lastly, yes.
The other potential explanation for the Delta would be if you get a lot of improvements operationally, where you're kind of talking about stimulation volume.
Kind of what it boils down to you know stimulation volume per day.
And but that doesn't necessarily mean.
Production.
Volume per.
So you should have a case, where the operational efficiencies really improving.
<unk>.
It is not as good and are you moving into spots of the acreage isn't quite as good and so that would explain the difference in knees.
AIA numbers of production volumes per rig being on a year over year decline that you guys are seeing fantastic efficiency and operational improvements. So if you can just speak to that that would be great.
Yes.
Appreciate the question.
What we believe Youre seeing.
Yes.
Believes this is occurring.
In multiple basins, where the core of the core of the basins in the Eagle. Ford example, as you look at the Karnes trough.
The inventory is just diminishing in overall count.
As well as more infill drillings occurring.
Contrast, silver bow to that as we've acquired a number of properties the properties that were drilling on this year.
We're really from operators that were not very active.
Over the last several years and in fact several of the pads that we've drilled.
We are in areas that had not had drilling on them for probably three to five years.
So it didn't have as dense drilling so we really like the acquisitions, we've made and that we were buying.
Area.
We're acquiring inventory based upon data type curves a bit felt confident.
With.
Even just a five year improvement in drilling and completion practices, we could significantly enhance those type curves and that's what we're seeing so I think.
I think your question is hey, we're just in a little bit different parts of the basin and are areas that we've acquired werent as heavily in densely drilled as some of the other operators in the basin.
Okay. That's helpful. And then my next question.
Hedging.
So.
The 90% you are trying to position gains through 90% hedge on natural gas volumes.
That's a great position to be in right now is where natural gas prices.
Or are presently but.
If we look towards the end of this year kind of trying to Orient myself, because as I understand it and correct me if I'm wrong historically your hedging philosophy more or less has been the kind of hedge about 50% of gas volumes and 50% of oil volumes and then because you're in the Eagle Ford.
And you have the flexibility to move rigs around.
You were able to train to move to a much more heavier oil focus this year and so it ends up being a kind of incidental or historical fact that we.
We find ourselves now at 90% hedged on.
Natural gas, but so going forward as it relates to 2024 and as we approach. The end of this year is that philosophy is that idea of our strategy kind of still intact with the idea is you would position your hedges.
And be content with our hedge portfolio kind of entering 2024, where it's half of your anticipated gas volumes hedged half of your oil volumes hedged for 'twenty four and then that can kind of unfolds in whatever way. It unfolds based on what you do opportunistically during the year.
With your rigs is that kind of the right way to think about it or are you actually looking at either commodities differently based on where you kind of think there might be.
Commodity pricing cycles.
No.
Good characterization.
You look at 'twenty four.
And based upon.
If we held volumes flat year over year.
Which we don't expect to we expect continued growth probably in the double digit range. So you can kind of do that math, but we will just go off.
Flat volume year over year.
As we sit today for both oil and gas we're about 50% hedged.
And that's kind of laid out on slide 24 of the corporate deck, plus or minus some percentages, there but pretty close.
As we get into the fourth quarter and start firming up our budget for 2024.
Get more confidence around the strip well hedged in two more of our wedge production.
As we get closer to year end and typically what we will find as we get towards year end, we will we'll be close to 70% of total <unk>.
Production hedged coming into the current budget year.
So our strategies.
It has been and will continue to be that as we get towards the end of this year and as you described it some of it is that as you get into the fourth quarter and you get more certainty of your plan and what product prices look like.
We'll hedge into it but we have flexibility at least for another quarter or two.
To adjust our plan and not have impacts due to the hedging strategy.
Next we'll go to Noel parks with Tuohy Brothers. Your line is open.
Hi, good morning.
Hey, good morning, all.
Just had a couple of things.
I was.
Thank you all for service cost environment.
We have had I have seen a.
A good bit of variability based on the basin.
Far as.
How the vendors are are behaving and Im just curious at this point are you are you getting a lot of inbound inquiries.
On services from from other vendors.
Or have your are your current guys pretty proactive to the point where.
Youre pretty confident that sticking with Danielle.
Youll get pricing that you're satisfied with.
Yes, I'll, let Steve take that question, yes, yes.
Both the Capex side, and the Opex side and we're looking for further gains both in unit cost as well as our own process efficiencies.
Between now and year end.
Again also on both the Capex and the Opex side Capex seems to be more driven by vendors coming into us with different proposals and different offers many of them being discount related on a regional basis and then the opex side is kind of a mix of less regional and more local but pretty much the same genre.
Offerings coming to us in terms of competitiveness.
Changes in unit costs and different structures the structure in terms of opportunities in terms of how people perform and where incentives. So all said we're looking for.
Continued improvement in unit cost reductions through the balance of the year.
Great terrific and.
I Wonder could you may be sort of refresh my memory on the.
Data for.
You touched on a bit of the infrastructure project out west and.
What sort of capacity is coming online and with the weaker prices how are things looking relative to the existing capacity.
Yes, yes.
Yes.
Kind of.
Point.
Both projects ultimately half a bcf a day each of capacity.
That could ramp up over.
At startup and incremental compression.
So.
Take that capacity from two five to four five.
The area has really kind of stayed at that two five Bcf a day range throughout the year and that's why we're kind of seeing and not a lot of interruptible capacity available to produce into.
But drilling has dropped off because of that as well as low gas prices.
Youre going to see activity most likely pick up.
The first one to really drop both of our gas rigs in December of last year.
And move out the others followed suit.
Throughout the year.
All of those projects are underway.
Continued communication with both companies that theyre going to be ready to go in the fourth quarter.
Great. Thanks, a lot that's all for me.
As scheduling of completions as we get towards the end of the year.
We'll have the throttle dependent upon.
<unk>.
For our production prices and cash flow and we're committed to having positive cash flow for the year. So getting ahead early in the year on cycle times as well as well performance.
We feel like Hey, we can.
To optimize completions potentially duck some wells late in the year and still deliver on the full year guidance. So some of that Capex drop is based upon ducking little bit later in the year as well as what Steve mentioned, what we think is going to be another 5% to 10% of.
Just overall price improvements over the second half of the year.
Okay. Good and then lastly.
Austin chalk well the smoothing in Q4 that is one of your existing rigs correct not a new third rig.
Correct, Yep and say it continuing to stay with two two rigs.
We will continue to look to test the market for best rig pricing and.
Best performing rigs right now we're not in any long term contracts on the rig side. So.
Is the plan.
Great. Thank you.
Yes, Thanks, Jeff.
Yes.
I'll close by again thanking everyone for their interest in silver both appreciate that interest and we look forward to speaking to you on our third quarter call.
[music].