Q4 2022 SilverBow Resources Inc Earnings Call
With this year's budget, we can accelerate that timeline and we expect liquids to comprise roughly 40, 45% of our total production by year end 2023.
Our key focus areas include our central oil area are western condensate area in our eastern extension area.
We also plan to target the Austin chalk formation across these oily positions, where we are seeing strong performance to date and the potential for future drilling inventory upside.
Furthermore, in addition to shifting both drilling rigs to our oily assets.
We have elected to eight web counting chalk wells pending higher gas prices.
As Chris will further detail, 90% of our gas volumes are hedged in 2023, leaving little downside exposure to gas prices.
At the same time, we are 50% hedged on oil for the year. So as we ramp our oil production will benefit from any uplift in the oil price curve.
To wrap up my prepared remarks, I would like to note that our capital budget is one piece of a multi year strategy, which is unchanged.
We have the roadmap and the levers to pull to grow production EBITDA and free cash flow, while simultaneously expanding our inventory and strengthening our balance sheet.
Our team has an established track record of delivering on our key objectives through commodity cycles.
We see a robust pipeline of opportunities ahead that will that with that we will continue to unlock value for all of our stakeholders.
Stakeholders.
With that I will hand, the call over to Steve.
Thank you Sean Silverado is proud of our operational and safety accomplishments over the past year.
They were the result of cross functional teams working in unison to deliver some of our best results today.
First core to the <unk> way, we exemplified our safety strong tenant by achieving a 0.09 T. Our IR for 2022.
Additionally, our production operations team recently celebrated its <unk> anniversary with zero Osha recordable accident, our team accomplished this while doubling the pace of our drilling activity to two rigs at mid year and managing a much larger asset base. After the integration of numerous acquisitions.
Moving to well performance. We are excited about the results we are achieving from recent wells and the quality of rock we are developing.
A key focus area for silver BOE in 2022 was the development of the Austin Chalk formation, primarily in Webb County.
These wells continued to outperform expectations.
Today, our Austin chalk wells have achieved IP 30 rates, 25% higher on average compared to our historically prolific lower Eagle Ford wells.
Furthermore, Austin chalk EUR is normalized for lateral foot are averaging nearly 50% higher than combined upper and lower Eagle Ford offsets.
Okay.
As of year end, we had over 80, Austin chalk locations in Webb County, and given the thickness of perspective intervals and staggered development, we see further inventory upside across our acreage.
Specifically in our Dorado area, we are seeing some of the highest performing chalk gas wells in our portfolio.
Towards the end of 2022, we brought several chalk wells online in our fast scenario with individual peak production above 20, Mmm Cfe per excuse me Mcf per day. These wells are exhibiting lower decline rates more akin to conventional reservoirs when compared to Eagle Ford wells.
Given the limitations on incremental growth in Webb County that John discussed we are expecting to return to developing this area next year.
Competitively speaking our team assembled and consolidated high return acreage positions across our liquids areas in 2022.
These actions significantly increased our inventory count and economics due to optimized spacing and lateral lengths year.
Year over year, we increased our location count by 85% with over 15 rig years of inventory life of the wells. We are drilling in 2023, most will come from our acquired assets.
On slide 11 of our corporate presentation, we show the key focus areas of our 2023 budget and our inventory runway.
We also see promising Austin chalk potential in many of these areas based on the initial petro physical assessments in well results from silver Bob we see additional inventory upside in the chalk formation.
Moving to operations our team continues to deliver faster cycle times further improving capital efficiencies across all major areas on an accrual basis, our 2022 capex of $328 million was.
It was just below the midpoint of guidance.
Our full year 2022, D&C costs were within 1% of ASC, a major accomplishment considering the commercial pressures from industry wide cost inflation.
If efficiencies further increase throughout the year as we stepped up to a two rig drilling pace and took control of operations on acquired assets mid year.
In the fourth quarter, our D&C costs were 11% below A&P.
During this time, we averaged 13 stages per day with our Frac crew, while exceeding 85% pumping efficiency on numerous pads.
Compared to the first half of last year. This is an increase of four stages per day and efficiency gains of 10% to 20%.
Although efficiencies were already high in recent years running one rig or two rig cadence has provided another pronounced leap in cycle times and Frac utilization.
Regards to our current inventory and inflationary pressures, we are seeing a plateau and cost creep and believe we should see some selective cost deflation in the second half of this year.
For 2023, our capital budget guidance of $450 million to $475 million.
Reflects a level loaded two rig program throughout the year and provides for 52 net wells drilled and 57 net wells completed.
Half of our D&C Capex is allocated to our central oil area with the remainder equally split between our western condensate and eastern extension areas.
Additional non D&C Capex is also being deployed towards various ESG improvement and related activities.
Late last year silver, both published ESG metrics aligned with SaaS <unk> reporting standards and is currently working towards releasing its inaugural sustainability report in the first half of 2023.
To wrap up our first quarter production guidance of 295 to 316 MMC if E per day reflects the deferral of eight well bores in our Webb County gas area until early 'twenty, four and ongoing dry gas curtailments at firm capacity levels.
November 22, we were running two rigs on our gas acreage and by the end of December we had moved both rigs to our oil acreage and Sean mentioned this flexibility is core to our commercial strategy.
First quarter oil production does not reflect the full benefit of a dedicated two rig development program given the aforementioned fourth quarter rig movements.
On a full year basis, our 2023 oil production is expected to increase by 100% year over year and our total production is expected to increase by approximately 25% at the midpoint.
Our dry gas production guidance assumes we are only able to produce at contractual firm pipeline capacity levels through year end.
In January dry gas production average in line with these firm pipeline capacity levels.
In February we were able to sell into some interruptible capacity and thus averaged volumes were slightly above firm pipeline capacity.
However, as mentioned our guidance conservatively assumes we are limited to firm pipeline capacity near term visibility on takeaway capacity remains opaque and we will continue to monitor and assess as the year progresses.
Consistent with our long term business plan, we remain flexible in our development program and opportunistic and maximized maximizing returns for 2023 beyond the pivot point to oil. This year plays right into our multiyear playbook and is a direct reflection of the strategic actions Silver Bowl has made over the.
Several years.
With that I will turn the call over to Chris.
Thanks, Steve in my comments. This morning, I will highlight our fourth quarter and full year financial results as well as our operating costs hedging program and capital structure.
Fourth quarter oil and gas sales were $199 million, excluding derivatives with natural gas, representing 66% of production and 50% of sales.
During the quarter, our realized oil price was 99% of Nymex WTS.
Our realized gas price was 84% of Nymex Henry hub, and our realized NGL price was 29% of Nymex WTS.
As shown on slide 22 of the corporate presentation, we have historically realized close to Nymex benchmarks.
During the fourth 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 the impact of which could extend until additional pipeline projects come into service towards the end of 2023.
Furthermore, risk management is a key aspect of our business and we are proactive in adding basis to further supplement our hedging strategy for 2023, we have secured gas basis hedges on over 150 Mcf per day to mitigate further risk.
Our realized hedging loss on derivative contracts was $34 million for the fourth quarter and $212 million for the full year.
Based on the midpoint of our guidance and our hedge book as of February 24th Silverado has 73% of total estimated production volumes hedged for 2023.
Broken down by commodity.
The company has 89% of natural gas production hedged, 51% of oil hedged and 46% of Ngls hedged for 2023.
Assuming our production guidance is held flat in 2024, our total production is approximately 40% hedged.
As the amounts are a combination of swaps and collars a detailed summary of our derivative contracts is contained in our presentation and Form 10-K filing, which we expect to file later.
Specific to our gas hedges in 2023, as we're 90% hedged our revenue is very insulated to any downward movement from the current strip.
While commodity prices have been volatile in the last several years, we remain judicious and locking in favorable return on our capital investments.
Turning to costs and expenses fourth quarter LOE was <unk> 63.
Transportation and processing costs were <unk> 35.
Production taxes were five 8% of sales or 40 per Mcf.
Adding our LOE TMP and production taxes together, our total production expenses were $1 38 per Mcf.
Cash G&A, which exclude stock compensation was $5 4 million for the fourth quarter, which was slightly higher than our guidance range due to professional fees.
For 2023, we are guiding for cash G&A of $17 $5 million at the midpoint.
A 7% increase from 2022.
Notably our cash G&A is lower year over year inclusive of our recent acquisitions.
This will drive meaningful G&A reduction on a per unit basis.
We consider our lean cost structure to be a competitive advantage, which allows us to sustain profitability during periods of volatile commodity prices.
<unk>, we expect to continue identifying synergies within our cost structure as we accelerate our liquids development across our recently acquired assets.
Adjusted EBITDA for the fourth quarter was $119 million exclusive of pro forma contributions from acquisitions.
As reconciled in our earnings materials, we generated $2 million of free cash flow in the fourth quarter and $22 million of free cash flow for the year.
Consistent with prior years whichever amount of free cash flow that was not reinvested in the drill bit was used to pay down debt.
While we ended the year at a leverage ratio of 135 times, we remain on track to achieve a leverage ratio below one times.
As previously mentioned, we closed four accretive acquisitions in 2022 in line with our disciplined M&A strategy.
And added additional acreage through leasing activity.
Total consideration for property acquisitions was $593 million.
This reflects a combination of stock and cash used for the acquisitions and transaction related fees valued at the time of close and net of purchase price adjustments.
Cash consideration for these deals after giving effect to purchase price adjustments totaled approximately $370 million.
Capex on an accrual basis totaled $103 million for the quarter and $328 million for the full year, excluding payments for acquisitions.
Our 2023, capex guidance of $450 million to $475 million, which Steve detailed in his comments is based on a steady two rig drilling pace throughout the year.
Yes.
Year end proved reserves using SEC pricing were to two tcf be 77% of which were natural gas and 43% of which were proved developed producing.
Our proved PV 10 was $5 billion and our PDP PV 10 was $2 6 billion.
An increase of 173% and 150% respectively.
Turning to our balance sheet, we exceeded we executed several initiatives in 2022, which allowed us to upsize and extend our credit facility maturity increased liquidity and self fund acquisitions.
In June we initiated a wildcard redetermination in conjunction with the Sundance acquisition.
With the full support of our Bank group, we increased our borrowing base from $460 million to $775 million.
And extended the maturity date of our credit facility by two years out to 2026.
Related bank fees for the upsize and extension of our approximately $7 million, which we do not back out from our free cash flow calculation.
Our year end total debt was $692 million in liquidity was $234 million.
Silver bow in accordance with our credit facility includes contributions from closed acquisitions for the entirety of the LTM adjusted EBITDA period used for for the leverage ratio calculation.
Full year 2022, the contributions from acquired properties totaled approximately $118 million, bringing our LTM adjusted EBITDA leverage ratio to $511 million and our year end leverage ratio to 135 times it.
It is worth highlighting that we remained relatively leveraged neutral while funding $370 million of cash acquisition costs.
At year end 2022, we were in full compliance with financial covenants and have sufficient headroom to execute our business strategy.
And with that I'll turn it over to Sean to wrap up our prepared remarks.
Thanks, Chris.
Silver Bowl 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 a key catalyst for our stakeholders is our ramp in oil production.
Our relentless focus on our employees' well being 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 and clean operations with the release of our inaugural sustainability report in the first half of this year.
On a final note the Eagle Ford has seen a flurry of M&A activity over the last 12 months.
In our view this is a strong signal by the market is being driven by several factors.
One the Eagle Ford is one of the best understood and well defined shale plays which translates to consistency in execution and development.
Second acreage ownership across the basin remains fragmented with doesn't have private operators running small scale drilling programs, which creates accretive consolidation opportunities.
Third the proximity of the Eagle Ford to industrial demand centers International exports and Gulf Coast, LNG combined with existing midstream infrastructure capacity results in higher realized pricing compared to other U S gas basis.
Silver Bowl has been a key consolidator within the Eagle Ford and Austin Chalk and recent announcements by other large operators points to a strong buyer's market for M&A.
I want to thank all 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.
At this time, if you would like to ask a question press star followed by the number one on your telephone keypad.
First question is from Neal Dingmann with Securities. Your line is open.
Good morning, guys. Thanks for the time.
John My question for you to the team understand you guys laid out a nice map as far as.
The two rigs going to be going more after oil I guess my question on that the plan.
And then kind of looking at what is it slide 14, or 50, I guess, it's slide 15.
The plan looks like or you can do more is it more developmental activity in the front of house and then the second half would be more delineation will be made.
Maybe just give you a little bit more color on the nor will it be kind of a mix throughout the year I know there.
Certainly some exciting opportunities in the lower Eagle Ford in chalk. So I'm just wondering when you when I think about those two rigs.
<unk> going to be more pure developmental and the other is more delineation or how should we think about those for the year.
Yeah, Hey, good morning, Neil and thanks for the question.
As we think about where we're drilling in 'twenty three it's across three areas.
Really the western condensate and central oil area or two areas, where we drilled extensively.
Over the last several years.
We feel very comfortable that our drilling in those areas is more along the lines of a development type risk profile.
The third area, where we're drilling is in our eastern extension area and that's an area, where we built a just under 15000 acre block over a couple of acquisitions one in 'twenty, one and one in 'twenty two.
We've been patient and drilling up there waiting to put those two deals together, we're really excited to be out there and drilling it's been a very proven area. Many of the top operators the offset us but.
We're going to drill both Austin chalk and Eagle Ford on that position and so we've got a rig on that area right now as we speak and so.
To your question, Yes, I see this area is a little bit more of a step out and proving up.
Area for us in the first half of the year, but with early success. Our plan is to actually Parker rig there.
Going forward. So we have high confidence in the area, but as always we want to be patient in our development.
Pace.
So that's probably the one area that has a little more.
A step out.
Two.
Is there a threshold you need to return back to web I mean is it three.
$3 four Bucks I mean is there a number or the.
The plan pretty much this year will still stay in that debt that liquids area.
Yes, yes no.
Always are looking at returns in thinking about <unk>.
Views on commodity prices, we always go through a very systematic approach first it's always around operational execution.
Hey, does it makes sense from a timing of service availability, where our rigs currently sit.
And then obviously the takeaway capacity so that will kind of be the first check and then do the returns compete with.
Our oil inventory.
Really a rule of thumb for us is when.
Oil to gas is about a 15 to one ratio our returns are very similar between gas and oil if it's above 15, where it currently sits more in that 20 to 25 range. We will drill a oil every day if it's below 15, we'd actually like we did late last year move both rigs into <unk>.
Gas area. So it's really for our from our view financial deal. We wanted to we will drill the best returns.
And that ratio is kind of a loose guideline for us it may be a signal to the market when we might shift to gas versus just a flat gas price as a signal.
Now I'd like to hit and then two more if I could just on hedging.
You guys continue to be in a better financial spot.
Just thoughts on that.
The future curve is quite still quite good for gas are you looking out to 'twenty four 'twenty five to put more gas hedges on.
Yes, yes no.
Definitely as we think about 'twenty three in the concerns on 'twenty threes volatility on gas, we feel very good about being essentially totally insulated to lower prices, but still exposed to.
If gas prices move higher because we have a lot of color. So right now the strips below our our floors on our callers. So we are asymmetrically exposed to the upside longer term and we kind of like to think about our reserve report from 2022, if you look at the 22 FCC prices.
Being very high $6 $90 oil, but more specific to $6 in the.
75% of our reserves being gas demonstrates really the underlying value of silver both with.
Value of close to $5 billion. So as we think about upside we're very bullish on oil long term debt being end of 24% to 25.
Our excuse me very bullish on gas in that period.
So to your question will we be hedging out it's in contango, but we think theres more upside and so similar to what we've done this year, we made a call on oil left ourselves some exposure to oil probably will look to continue to bolster 24 edging on gas lift will be opening it will stay open on 25, plus just because we're very.
Bullish on gas starting in 'twenty five.
Okay, and I'm, sorry to monopolize just one last one just on M&A I know I know you guys are always looking for accretive deals, but is there opportunities just for little bolt ons or just some trades as you continue to do that I'm wondering how active you are on that these days.
Yes, no good question.
I think we've seen.
Flurry of larger scale deals in the Eagle Ford over the last six months, we were an early mover more on probably some smaller scale deals and feel like that's still is a niche for us and what we've seen in we kind of have a longer term view and really work to map hard, but as our footprint has grown the op.
<unk> set to do more bolt on deals do jv's to drill longer laterals.
To do small offsetting acquisitions that opportunity sets just continued to grow just with a larger footprint. So that's really where our focus is in the near term and we think it adds a ton of value.
Kind of being strategic from an industrial logic standpoint to build on the position that we already have.
Yes, it certainly would be great. Thank you all.
Thanks, Neal I appreciate the question.
Your next question is from line of.
Charles Meade with Johnson Rice your line is open.
Sure Good morning to you and the whole Silverado team there.
Good morning Charles.
Wanted to push a little bit more on some of the same topics that Neal was asking about in the <unk> ratio you cited was.
Really helpful, I guess coordinate but too but to elaborate a little bit more around that so.
We're looking at a strip of oil which is call. It 75, so that would suggest that that at $5.
Henry hub.
Your.
Yeah.
All assets would be about the same.
Really attractive is <unk> natural gas assets, but does that mean that we shouldnt expect you to tilt back to natural gas until five or does it mean that some of your best natural gas stuff maybe starts to work back into the picture.
Yes, I don't know $3 54 box, how should we how should we think about the.
How the how the curve is going to look at them in that regard.
Yes, no no.
Eight.
A follow up on it yes, 15 to one is kind of.
Lucy 13 to 17, the returns become pretty similar so in a.
Four in $60 $65 environment.
We have one rig running in gas one rig running in oil and Thats. Our current kind of view once you get into mid 'twenty four going into mid 25 with the contango in the gas curve in the oil curve being backward dated so that's kind of how we're modeling things out.
One rig in both areas by mid 'twenty four and then.
Our view on gas plays out in 'twenty five.
Probably might anticipate two rigs running in the gas window in 'twenty five but whats great is we have an inventory that we can go either way.
And what we've always said and love about the Eagle Ford and we demonstrated it at the end of 'twenty. Two is we can turn on a dime I mean within two weeks, we were pulling rigs out.
In the oil and gas.
Lot of our peers, just can't do that right that they're only gas and unfortunately continue to drill into a low price curve, which isn't helpful too.
To the pricing dynamics, but we think our strategy of being able to shift is really demonstrating itself here.
Got it.
Certainly.
The advantage to be able to do that I'm going to push a little bit further on natural gas activity. So you guys have these eight docks in Webb County, and it makes all the sense of the world that that you'd wait to complete those given the given the contango in the natural gas curve.
Right I guess, what I'm asking is it fair inference that youre going to wait for something close to $4 like a $4 12 month average two to complete those because they're not they're not in your 2003.
They're not in your 'twenty three capex plan as far as I understand it.
That's call it.
350 kind of took a look as we look forward so.
Should we be thinking about like 375 or four Bucks for you guys to go back in.
Initial work their internal.
Yes.
Kind of in that ballpark with that we've had in the back of our minds.
We'd also look at operationally.
If a window, if we see gas prices starting to get more stable late in the year.
And our window opening up on our Frac spread that primarily serves the two rigs, but sometimes it's so efficient that windows present themselves.
Might slide down in pick kick those two really.
Two pads out, which would really juice our volumes end of year.
Maybe we see a strong winter next year.
Pick up.
In the LNG exports as as Freeport comes back online and hopefully more response from gas players as a whole to dial back on supply. So we're going to be nimble, but I think $3 $54 and earliest probably would be later in the year that we would do something.
That's helpful. Sean I've got a few more questions, but I'll, let someone else hop in the queue.
Great Charles Thank you.
Okay.
Your next question is from Jonathan Schaffer with Northland Capital markets. Your line is open.
Hey, guys. Thanks for taking the questions.
I have.
First of all I want to ask.
I thought it was interesting idea about.
Taking the 2022 pricing reserve report is sort of a data point.
<unk>.
For.
What things could look like.
'twenty 'twenty four 'twenty five.
Rising environment.
Well my question would be yes.
We kind of go through that thought experiments.
What other kinds of adjustments, maybe that there needs to be it gives us a useful data point.
Pricing, but clearly based on guidance your expectations you have.
Growth and production growth in 2023, there could be some changes in.
Production mix.
Oil versus gas. So just curious what the big things are we maybe you would need to.
Adjust for accounted for if we did take something like this.
Yes, as a rough approximation for what kind of valuation could be appropriate in the 2020.
For 2025 timeframe.
Yes, no great question.
Our reserve report at year end.
As we were starting to.
Already pivot towards more oil does reflect the activity.
And out in 'twenty, three but that report.
And then shifts back to a 50 50 split on capital So one rig in oil and one rig.
<unk> gas starting in 'twenty four.
So it's more back to our traditional mix.
Capital allocation.
Now where is there upside it still would be driven by price, but it would be probably in 'twenty four.
A lot of people are forecasting potential strong moves in gas.
North of five 6%.
Probably oil coming down a little bit that reserve report could have even more upside if we converted two rigs of gas.
Going into a higher gas price curve.
So again as we've thought through it.
We feel the stock's very undervalued and that it's very just near term looking by investors. We're really trying to help investors understand the upside potential here is higher gas prices, which.
Pretty consistent view across a lot of forecasters, that's only 24 months out and we really to your point feel like 'twenty. Two reserve report demonstrates the underlying value of the company quite well.
Okay.
Helpful and then.
Kind of related.
I don't know if there's potential upside.
Outside or whether those potential outside here, but the kind of getting at the question of decline rates. So.
<unk>.
What is your current corporate average or blended decline rates with.
Yes sort of if you will.
You hit the pause button and Werent doing any more drilling.
I know that can be sensitive to new too.
While the recently come online, but also like you guys said in the prepared remarks, some of the Austin chalk wells are are starting out with lower than expected.
The decline rates I mean, the production level itself is great, but they are declining actually slower.
So youre getting a more mature kind of base over time, so just kind of curious of where that puts us.
Our kind of current decline rate and maybe where that would be in like a 2024.
Is that reflective if it's a trend towards the lower decline rate at all.
That's reflected in the reserve report or not.
Yes.
The reserve report reflects.
Our best estimates are a reserve engineers best estimates as well as our auditors on what wells are declining off at but in general.
We're seeing coming out of 'twenty two into 'twenty three about a 30% decline on our base PDP assets.
That will remain a little.
Flat over 'twenty, three because we have curtailment occurring down and our high rate gas areas and we've been choking back some of our large Austin chalk wells, which to your point exhibit different decline rate than the Eagle Ford.
Seeing initial declines out of the Austin chalk in that.
<unk> 55 to $65 range, where Eagle Ford is more 75 to 85 range. So.
Yes that shift to Austin chalk.
We're seeing some benefit to that on the base decline.
Counter to that.
Going from one rig to two rigs.
In 'twenty, two and then maintaining that two rig.
We are shifting more of our production to more recent well so as more of our production comes from newer wells, we'll be fighting and increasing decline rate. So.
Probably seeing more of a move up in decline over the next year or two but.
That's being driven by the large capital program.
Sure sure. Okay, and then just one last question.
For the eight DUC ducts that you added in Webb County.
Could you tell us.
What the capital spending was drill those.
Then what incremental Capex would be needed to complete them I'm, just what I'm asking because I'm trying to get at the center of the idea of.
I apologize.
Embedded growth and some other context, but the idea of like where you've already spent the money so the capex.
Impacts on cash flow and other stuff has already been there, but we're not going to really see any benefit from that.
Until 'twenty four 'twenty five.
How much of that capital has been laid out already that won't need to be incurred later.
And then what would be required leader.
Yes, no we're seeing wells down in Baskin.
Area.
Is the low back in late 2021, we had pushed them down below 5 million.
More recently, that's all in drill and complete more recently, that's pushed upwards of seven five.
So.
Drilling makes up probably 40% $35, 40% of the spin.
So across those eight wells.
Total investment would be close to $60 million $65 million.
We've already probably sunk about $25 million to $30 million in those wells. So.
Definitely.
That's a little bit of a stranded capital for US right now, but again, we think economics in the contango on the gas curve just makes sense too.
Kind of a whole hold ground on those going forward.
We've got another $35 $40 million to spend to bring that all online.
Bring it on quickly being that they're drilled.
Yes.
Okay great.
Thanks for taking my questions.
<unk>.
I'll pass it on thanks.
Thanks Tommy.
Your next question is from the line of Noel Parks with Tuohy Brothers. Your line is open.
Yes.
Hi, good morning.
Hey, good morning.
Just had a couple of things I was wondering with the shift towards the oily or areas in here.
<unk>.
Between sort of the budget you are envisioning when youre, probably going to leaning between gas year in the current budget.
Any significant delta in the infrastructure facility spending that youre looking at now that you're going to be back on the earlier areas.
Versus the original gas in your budget.
No probably as a whole.
<unk>.
When we were thinking one rig gas one rig oil.
Our overall Capex to go to two is the same but our percentage of what we spend on facilities and land always runs in that 10% to 12% range.
Regardless if it's.
Two rigs oil <unk> gas are a split so.
Pretty consistent 90% of the spend goes the D&C.
That 10 broken between facilities and land, it's probably two thirds facilities. One third land and then we always reserve the right that if theres opportunities opportunistic leasing to do maybe put more dollars to work on land.
Sure sure.
<unk>.
Just wondering.
With you now.
Hang on to those ducks incentive completing them right away.
A little bit about.
The the Frac.
Pace Youre looking at and.
I was just wondering if you are making.
You've made to the plan.
Any any issues with Frac crew access.
Operating in a different end of the play.
Nick why don't I, let Steve address that sure. Thanks, Sean.
Good question Al.
Let me kind of give a little bit of backdrop for up until middle of last year. We were only one rig and so we had kind of a lot of gaps in our frac schedule, but since the middle of last year, but we haven't been able to fully level load frac rig, but we've been there a frac crew in spread but we've been in a position to.
Ryan <unk> on average around 80%, 85% of the load and we've been able to find comfortable fills for those gaps because we have a schedule that looks pretty far out. So so and the timing of all that we've been able to come back pretty fast.
And anything thats, either an opportunity or it's as it is scheduled so for instance, our frac schedule follows pretty much in cadence with our drilling rigs as you know historically, we're not really a Dutch company.
So as it relates to these docs that we do have already in our portfolio, we have flexibility and we have GAAP opportunity by which to take our frac spread to that.
So thats availability right now hasn't been a concern in terms of the efficiency.
Right now our Frac spread is the premier frac spread in the entire Eagle Ford and that's the number for Frac spread in all of America short of three three opportunities in the DJ basin, which are much more difficult much different environment than not even as risk oriented as what we do in the Eagle Ford So very fortunate there from a frac efficiency point of view with respect to that.
Crew that we have been able to use for some time now and continue to plan to use and then products related to that the Frac facility as we look at the all the components to it horsepower sand and chemical we have been able to work with our provider and also hold the line on uncertain certain certain items as it relates to unit cost for that and then.
Second Larry for sand and some of the other needs in terms of our water facility needs for that we've also been able to hold the cost and therefore that why we enabled to offset some of those inflationary pressures that we've talked about earlier and being able to now hold within 1% of <unk> and then some and then also at midpoint of Capex. So we feel comfortable in being able to go with that forward.
Especially with the backdrop of some of the lower decline issues, we're seeing in inflation.
Great. Thanks, a lot and just one last one for me.
When you were talking about.
With the Docs you do have some capital within the ground that.
If you were just completing straight ahead.
Get that return sooner. So it just got me thinking about liquidity.
And.
Yeah of course.
Have a flexibility on the credit line I'm, just sort of thinking.
Maybe for the rest of this year and a little bit of Crystal ball stuff I'm asking but.
<unk>.
If you decide you are going to do a transaction or maybe gas responded more quickly and you decide you will get.
I'm going to go a little bit more aggressive on activity.
All things being equal would you see yourself.
If you decided to do some debt financing more gravitating towards the credit line with a variable rate.
Or.
Would you be thinking more.
After that market's about.
We want fixed fixed rate kind of the Devil. We now so I know it's kind of a.
Very amorphous question, but just curious what your thoughts on that.
Yes.
Just like we think about drilling capital right.
In getting the best returns on our drilling capital same on.
We look at that in credit so always trying to assess what's the best.
Cost of capital that we can get.
Keep risk mitigated.
What I would tell you our our view would probably lean more towards fixed so that we know what that is and where it's going forward.
Now our debt with that said is variable and it's moved up on us so.
Both.
The revolver and our second lien have a variable component to it so we've experienced that.
I think that hey, if we found a fixed rate that works for us and we could term out some of that variable debt, that's something we would do.
Got you okay. Thanks, so much great. Thank you.
Your next question is from the line of Tim <unk> with Keybanc capital markets. Your line is open.
Hey, good morning, everyone. This is slate on for Ken today, just a couple of questions.
For one I was wondering if you could talk specifically about the cost deflation youre seeing with the rig and are you seeing anything similar on the pressure pumping side.
Yes, maybe I'll, let <unk>.
Steve kind of briefly touch on that.
High level set the stage.
See cost pressures peak and now are even starting to see a little relief. So.
Encouragement on that front.
Thank you Sean.
Yes.
We're in a situation right now where the market on the rigs in the Eagle Ford.
And I'll just space specific to that at least on the gas side theres rigs that are coming down and on the oil side. There is even some rigs that are kind of either changing shape of coming down that said the market prices such that we are seeing softening on the rig contracting side for rigs both in the near term and also.
Some conversation in the longer term.
That said, it's even further supported by the backdrop of term on contracts. So we're seeing shorter term on contracts and in some cases pad to pad with quality equipment. So that's kind of the near term outlook on rigs and we're kind of expecting that deflation to continue into the second half of this year and then we will see where 2004 it takes us on the Frac.
<unk> spread side, we're seeing a lot of those costs, just basically plateau and level out.
With some softening in certain areas, especially say for example on things like water transfer and support and service and to some degree on sand sand has been kind of bimodal with a higher at a lower cost structure, we're entering into that lower mode right now as we see some of these volumes ticked down in the aggregate Eagle Ford area.
Got it that's very helpful. And then for my follow up maybe just a bit bigger picture I believe you all have highlighted kind of a longer term $50 50 gas to liquids mix for your portfolio. I was wondering maybe just kind of a timeline on that do you expect that to be in over the next two.
Two years two to three years or is that kind of maybe a bit longer term view 2020, 520, <unk> that comes with this LNG build out.
Yeah.
As we look at.
Getting to the end of this year, we're starting to approach the 50 50 mix.
So as we stay with that one rig.
<unk> 24 is one gas <unk> oil.
We'll probably stay in and around that 45 to 55 split the year over year.
Where we would see it start to move away from that and maybe go more gas heavy as if we shifted allocated the capital the two gas rigs so.
We're getting to that 50 50 mix almost this year and it will stay that way assuming a one.
One rig oil one rig gas scenario.
Great. Thanks for the question Thanks for the time.
Yes, thanks for the question slate I appreciate it.
Your next question is from the line of Charles Meade with Johnson Rice. Your line is open.
Hey, guys. So forgive me if I missed this but.
Thinking about the.
You are.
PDP PV 10 at the strip it looks to me based on some of the coordinates you gave US is probably around 1415 I don't know if you gave us that number or if that number is in the right.
Ballpark.
Yeah, I would hate to speak to it and that we're looking at that quite often and the strips always moving so I don't have like a firm number.
Off the top of my head we're looking here.
Yes.
What we provided was at SEC pricing.
So we don't have that in front of us.
Okay.
You did mention Sean.
The total PV 10 was I think you said just under 3%.
It was right at three.
Okay.
So thats kind of not a bad inference right that maybe you could get into a debt at year end. We were 45, the year end value of $5 billion reflected just under 45% PDP.
So Ryan yes.
I would say take that and apply it.
That's where I was going yes, that's it okay I appreciate it Charlie.
Thank you.
There are no further questions at this time I will now turn the call back over to the company for closing remarks.
I appreciate everyone's interest in the company I appreciate the questions and we look forward to our next call and sharing any update.
In.
The second quarter I appreciate it thank you.
Ladies and gentlemen, thank you for participating. This concludes today's conference call you may now disconnect.
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