Q3 2020 Centennial Resource Development Inc Earnings Call
This call is being recorded.
A replay of the call will be accessible until November 17 2020.
By dialing eight Fivefive 859, do 056 and entering the conference I'd number 369, do 456 or by visiting seemed Daniels website at Www Dot C. D E.
Oh I see that.
That's gone.
At this time I will turn the call over to Mr. hates me read.
The newest director of Investor Relations for some opening remarks. Please go ahead Sir.
Thank you rent.
And thank you all for joining us on the company's third quarter call.
Presenting on the call today are Shawn Smith.
Keith Executive Officer.
George Colitis, or Chief Financial Officer.
And Matt garrison, our Chief operating officer.
Yesterday November 2nd.
We filed a form 8-K with an earnings release reporting third quarter earnings results for the company and our operational sorry, and operational results for our subsidiary Centennial resource production LLC.
We also posted an earnings presentation to our website that we will reference during today's call.
You can find the presentation on our website under presentations at Www Dot ceded inc. dot com.
I'd like to note that many of the comments. During this earnings call are forward looking statements that involve risk and uncertainties.
They could affect our actual results and plans.
Many of these risk are beyond our control and are discussed in more detail in the risk factors and the forward looking statements sections.
Our filings with the security and Exchange Commission income.
Including our quarterly reports on form 10-Q for the quarter ended at 930.
Which will be filed with the FCC later this afternoon.
Although we believe the expectations expressed are based on reasonable assumptions. They are not guarantees of future performance and actual results or developments may differ materially.
We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers.
Any non-GAAP measure we use a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation, which are both available on our website.
And with that I will turn the call over to Shawn Smith, our CEO.
Thanks, guys.
Good morning, and welcome to Centennial's third quarter earnings call.
On today's call George will first discuss our quarterly financial results liquidity and updated guidance.
Matt will then provide an operational update including recent operational initiatives well results and updated DNC costs, and then I'll follow up with a quick recap of the third quarter capital efficiency gains to date and provide a high level overview of 2021.
But before I hand, the call over to George.
I wanted to point out that what you will hear today stems from our new corporate slogan Centennial 2.0.
Which centers around heightened capital efficiency and the goal of generating sustainable free cash flow.
And the following discussion and begin the presentation materials, you will see the significant progress we've made towards these goals in a very short period of time.
With that said I'll turn it over to George to review our financial results.
Thank you Sean turn.
Turning to our financials on slide 17 of the earnings presentation that oil production for the third quarter averaged approximately 35300 barrels per day.
Which was down 16% over the prior year period and represents a 6% decline from Q2.
Supported by the five wells brought online during August and a reduction in production downtime Q3 oil production volumes exceeded our expectations.
Average net oil equivalent production totaled approximately 68900 barrels per day.
Which was down 10% from the prior year period and represents a 1% increase from Q2.
The relatively flat sequential equivalent production volumes.
Primarily driven by an increase in gas capture a full quarter of ethane recovery and less flush oil production from new wells compared to previous periods.
Revenues totaled approximately 149 million, which was a 65% increase compared to Q2, primarily as a result of higher price realizations across all three product streams as well as higher NGL and gas production.
Excluding the impact of commodity hedges Centennial's Q3 oil realizations were 90% of W.T.I. were.
Were $36.95 per barrel compared to 21 47 in Q2.
NGL prices were up 63% to $12.58 per barrel compared to Q2.
Turning to costs unit costs continue to look very strong relative to our expectations Ella.
LOE per barrel decrease by 7% from Q2 to $3.87, primarily as a result of the continued reduction in equipment rentals and electricity costs.
That will provide further details on elouise shortly but we are seeing very tangible progress on our cost reduction initiatives.
Cash DNA for Q3 was $1.94 per barrel, which was down from 221 during Q2.
DDNA decreased by 6% to $14.10 per barrel relative to Q2, because of upward PDP revisions and lower DNC costs.
Lastly, GP into expenses increased 9% quarter over quarter to $3 in two cents per barrel in part because of higher natural gas and NGL pricing.
In Q3, we recorded a GAAP net loss of $51.5 million driven in large part by sustained low oil prices due to the COVID-19 pandemic.
Adjusted EBITDAX totaled 51 million up from approximately 24 million in Q2, due to higher commodity prices and reduced operating costs.
Shifting to Capex.
As a result of continued muted activity levels and cost reductions Q3, DNC capex was $20 million compared to approximately $21 million in Q2.
In August we completed five wells compared to four completions during the prior quarter and in September we stood up a single rig which spud. The first two wells have a four well pad once.
Once finished this rig will move to our acreage in Lee County, where it will remain for the foreseeable future.
As Matt will describe shortly our DNC costs per well have declined as a result of well design changes and efficiency improvements as well as overall service market conditions.
Facilities and infrastructure capital declined significantly from this for the second consecutive quarter.
Totaling approximately $1.5 million compared to $6.5 million in Q2 and $25 million in Q1.
Merely because much of our needed infrastructure and facility spending has already been incurred for the year in.
In fact, given the pending completion of our substation project, we expect our infrastructure spending to remain modest relative to historical levels well into the future.
We also incurred approximately $315000 in land capital.
Despite the de Minimis land spend we anticipate that our acreage position will grow year over year as a result of recent swaps and trades executed by our land team and we expect to have in excess of 80000 net acres at year end.
Overall centennial incurred approximately 22 million of total capital expenditures during the third quarter compared to 28 million in Q2.
On the previous earnings call. We noted the capital expenditures for the second half of the year would be funded by operating cash flow.
In the third quarter, we generated 10, and a half million in free cash flow and now and we now expect despite the recent slide in oil prices to generate free cash flow in the fourth quarter as well assuming current strip prices.
On slide 10, we summarize our capital structure and liquidity position.
As previously announced in October during Q3, we repaid $15 million of credit facility borrowings and had our borrowing base reaffirmed at $700 million.
As of September Thirtyth Centennial had approximately 314 million pro forma total liquidity, which was up 6% from June Thirtyth five.
Finally at September Thirtyth, Centennial's first lien debt to LTM EBITDAX was one times compared to a maximum covenant level of 2.75 times.
As a reminder, centennial will not have a total debt leverage governor under the current under the credit facility until Q1 of 2022.
Net debt to LTM EBITDAX was 3.2 times at September Thirtyth.
Turning to hedging.
As a result of the Q3 hedge position that we established back in March as oil markets were rapidly deteriorating we incurred a hedging loss of 34 and a half million during Q3.
Looking to Q4 as you can reference on slide 13, we.
We have W.T.I. swaps in place covering 13000 barrels per day, and Costless collars totaling 3000 barrels per day at an average WT price Wi Fi price of approximately 39 per barrel.
Focusing on Cal 21, since our last earnings presentation, we have added significantly to our fixed price protection, particularly in the first half of the year in Q1 of 2021, we've utilized fixed price swaps to hedge 9000 barrels per day.
At an average W.T.I. price of $41.81 and have swapped 3000 barrels per day at an average Brent price of $46.85 for.
For fiscal year 2021, we have hedged approximately 5700 barrels per day on average with a blend of pricing at an average Wi Fi price of 40 to 59 per barrel at a Brent price of 47 79 per barrel.
Right.
On the natural gas side for Cal 21, we have swapped approximately 40000 45000 mmbtu per day.
At an average Henry hub price of $2 or 91 cents.
I'd now like to touch on our updated 2020 corporate guidance on slide 12 of the presentation.
Based upon Q3 results, we are increasing our daily oil and total equivalent production mid points by 1% and 2%, respectively, while slightly lowering full year capital expenditure guidance related to facilities and infrastructure.
Due to strong results to date, we are reducing the midpoint of our LNG guidance by 9% to roughly $4.40 per Boe for the year.
We are also lowering the midpoint of guidance for cash DNA, BDNA severance and AD valorem taxes and stock based comp as highlighted on the slide.
Finally, given ongoing efficiencies we are adjusting our estimates for the number of spuds and completions during the full year.
In closing during our Q2 earnings call back in August we identified the multiple steps we were taking to reposition the company in what we now describe the Centennial 2.0, I Trust is evidenced that we are making significant progress towards these goals with a material reduction in our cost structure improvement in liquidity and the generation of free cash flow.
During the second half of the year.
We continue to be hyper focused on these initiatives and expect that this momentum will carry into the future with that I'll turn the call over to Matt to review operations.
Thank you George today, we are happy to report our fourth consecutive quarter of reduced LOE easy to completion of five ducs in new Mexico, and a return to drilling operations as this challenging and transformative year enters its final months, it's truly amazing how far this team has today.
Today I'll cover several ongoing initiatives centered around improvements in elderly.
Cnf costs and flaring.
As noted on slide six our focus on margin expansion can really be seen third.
Third quarter LOE came in at $3.87, representing a 36% year over year and 7% quarter over quarter decrease.
This fourth consecutive quarterly drop is the result of ongoing initiatives in the field that we mentioned in the last earnings call.
This quarter, we saw the electrification of phase two of our substation in Reeves County, effectively our Reeves County substation detailed on slide seven.
Has reduced our generator count from around 125 in Q3 of 2019 to around 30 in Q3 2020.
And by year end with the third phase of our field electrification completed we hope to see that number of generators dropped to roughly 10. This.
This transition to line power impacts our business in several ways, we've seen significant reductions in rental costs fuel costs and downtime at the well site level.
The line power source is much more reliable and that directly impacts the bottom line, but fundamentally changing our run rate assumptions on downtime.
The profitability of this project can easily be understood but.
But we at Centennial are also compelled to be good stewards of the land on which we operate the.
The transition away from generator power means there will be over 100 fewer combustion engines running in the field.
And well recently touring our field operations.
Enthusiasts from our team members around this project as well as additional opportunities to transition to electric motors wherever possible was evident.
We've also continued to evaluate our producing wells for opportunities to transition artificial lift to gas lift wherever possible.
From Q3 2019 to Q3 2020.
Our utilization of gas lift as the primary artificial lift method increased from 25% to 40% of our wells.
At the same time, we saw a significant drop in SP usage.
The increased reliability of gas lift is undeniable the failure rates for artificial lift have fallen by around 40%. When you compare the full year 2019 average to our year to date failure rate. This.
This reduction in failure rate translates to overall workload lower workover expense driving our lead down.
Continuing with our operations in the field I'm.
I'm proud to share some additional work that we've really been focusing on and that is our gas capture.
As George mentioned earlier, we've put a tremendous emphasis internally on this subject and as usual our employees Didnt disappoint in.
In Q3, we flared less than 2% of our produced gas volumes last month that percentage was below 1%.
Our ultimate goal is to minimize flaring to near zero.
While on the subject I wanted to provide a quick update on our overall SG effort earlier this year Weve constructed in ESG committee comprising of both senior management as well as individual contributors from various departments within centennial.
This committee was designed to improve our overall SG effort.
And disclosure.
As such we plan to publish a fulsome sustainability report in late Q1 of next year.
This will expand on our current disclosures to include greenhouse gas emissions flaring water management bio diversity impacts and workplace safety among other things.
Turning to slide nine.
You can see the results of our five new Mexico Ducks, as we which were all targeted in the third bone spring sand and averaged around 9000 feet of completed lateral length.
Notably all these wells reported strong results with average IP Thirtys and IP sixties of approximately 1900, and 1500 Boe per day, respectively and consisted of 82% oil.
Consistent with our message from last earnings call. We have continued to place a high level of emphasis on our water recycling efforts.
For these wells, we utilized approximately 70% recycled water during the completion.
Our plan is to continue to utilize recycled water to the maximum extent, we are able positively impacting both the capex and the opex costs and remaining consistent with our overall SG initiatives.
Speaking of costs these wells averaged $858 per lateral foot.
While impressive relative to our historical costs on slide eight we believe there is still room to improve as those wells included drilling costs that are higher when compared to our current drilling cost structure.
With our current internal estimates, we believe we can achieve DCNS costs of $750 to $850 per foot going forward, which are inclusive of drilling completions facilities and flowback costs.
Lastly, we believe we are able to combat potential service cost inflation with the higher efficiencies being observed real time, particularly on the drilling side.
Today, you've heard some very impressive numbers for both locally and DCF costs I'm pleased to share with you a portion of the roadmap that we are using to ensure that these goals become a reality.
Over the last several months, we've scrutinized some of the challenges set before our company.
To ensure we have better access to our field operations and to facilitate a more hands on approach to our drilling and completions activity. We've made the decision to relocate our operations group, including the VP of operations to Midland, Texas.
We believe moving the operations team to Midland gives us the advantage and the oversight we've needed.
And believe that it sends a strong message to our stakeholders regarding our commitment of becoming a best in class low cost operator.
With this being election day I thought I'd take the time again to briefly review our limited exposure to federal acreage out.
Out of our over 80000 net acre position spanning both the northern and southern Delaware Basin.
Only 4% of our total position falls on federal acreage.
Additionally, we have 50 approved federal permits and 75 approved new Mexico state permits in hand.
With the level of activity planned on.
Going forward any concern relative to additional regulatory risks on federal lands will not impact the trajectory of our company.
Before I hand, it back to Sean.
I'd like to wrap up by saying how proud I am of our team for truly changing the cost structure of the company, we have been able to significantly lower DCNS costs low costs and flaring. These initiatives, which had been the focus of 2020, we will continue to be structural in nature for us.
As our operations group will now be able to oversee all aspects of their day to day work in person that translates to sustainable progress and underpins our plans to be viewed as an even more capital efficient company going forward.
And with that I'll turn it over to Sean for closing remarks.
Thanks, Matt.
So let's quickly recap what we have achieved this quarter, which is outlined on slide 14.
On the left hand side, you can see our key initiatives, which were taken verbatim from our Q2 slide deck published in August.
On the right hand side, we've listed our actual results from the quarter.
And as you can see we either met or exceeded every goal that we set out to accomplish.
Starting with Elouise, we reduced our per unit cost, 36% through the execution of field level projects and as a result removed over $2 from our unit cost structure. Additionally.
Additionally, we lowered our all in DNC, well cost target by 11% as a result of higher efficiencies and structural design changes.
In early October we received affirmation of our borrowing base inorganically increased our liquidity position by paying down debt during the quarter further.
Furthermore to help protect cash flow from any deterioration in commodity prices. We added approximately 5500 barrels a day of incremental oil hedges in 2021, primarily targeting the first and second quarters.
Lastly, we were able to execute on all of these objectives, while efficiently returning to operational activity during the quarter. Okay.
Overall this was a strong quarter for Centennial and I'm very confident that the recent changes made to our cost structure are more permanent in nature, providing the company with a solid solid foundation going forward.
To further build upon this statement and how it affects the underlying business I'd like to shift to slide five which shows the rate of change of centennial's capital efficiency on certain key metrics.
To start our development program as now underpinned by significantly lower well costs as our current target represents a 40% reduction from last year.
Next we are resuming activity with a much shallower corporate decline rate. We expect this to be in the low 30% range at year end compared to 40% to 50% seen at year end 2019.
This will provide us with a more stable production and cash flow base effectively requiring less capital investment to maintain production targets.
As Matt detailed our electrification and artificial lift projects have removed a substantial amount of LNG from our cost structure.
Which in turn have significantly enhanced our margins in addition to improving downtime in the field.
And let's not lose sight of the fact that we have a very high quality asset in an extremely capable technical team, which is reinforced by our recent well results.
Now with this higher capital efficiency in mind as I outlined earlier in the year. Our goal has always been to generate free cash flow and there's been no change to this for the remainder of 2020, we expect to continue operating a one rig program.
And while we previously anticipated being cash flow neutral for the second half of the year, we now expect to generate incremental free cash flow. During this period at current strip prices as a result of our recent reduction in cost and expanded margins.
For 2021 will largely be targeting a maintenance program essentially holding exit rate oil production flat.
As it stands today this will require approximately a two rig program for next year, depending upon drilling and completion efficiencies.
Given that we expect to generate free cash flow in the second half of 2020, we believe we are well positioned heading into next year.
As we've proven in the past our high quality assets are capable of growing production rapidly that said, we are very mindful of global supply and demand dynamics and the recent pressure on crude prices. These substantial improvements in our cost structure do not give us carte Blanche could drive significant oil growth.
Into a depressed market.
Thus as we develop our formal 2021 plan, we are committed to executing a maintenance program, while preserving our solid liquidity and cash flow profile.
In closing this was a very different Centennial then the company you saw at the beginning of the year or as we know like to call. It Centennial 2.0, a company that is focused on capital efficiency cost control and operational execution, while ultimately generating sustainable free cash flow.
Before we got acuity I'd like to quickly leave you with several key takeaways from today's call, which are outlined on slide 15.
We signet significantly improved our capital efficiency versus previous years, and now have line of sight on free cash flow. This.
This is driven by lower DNC costs, which we believe are sustainable through 2021 and beyond in addition to the material improvements made to our unit cost, particularly Ela we we've.
We've witnessed the resetting of our corporate decline rate and still have one of the highest quality assets within the basin if.
If you take all of these factors combined with no near term debt maturities and solid liquidity you can see why we are so enthusiastic going into 2021. Thanks.
Thanks for listening and now we'll go to acuity.
Thank you.
Sure and answers session will be conducted electronically.
If you would like to ask a question. Please do so by pressing Star then the number one on your telephone keypad.
And then sort of limited to one question and one follow up question.
If you would like to withdraw your question perhaps dependent.
You have your first question from the line of Scott handle your line is open.
Yes, Thanks, Hey, John that was good color on what 2021 might look like so I think that's obviously what bill.
Other folks are focusing on at this point then.
If you were to run a maintenance program and looking at the current strip can you give a sense of what that does that get you to a near free cash flow neutral position or whats your tolerance to our ability to outspend and.
On that maintenance program. If you can give us an idea of like how many wells does that come to play being brought on.
Sure Scott Yeah. Appreciate the question I think you know as we think about maintenance program next year of course, we haven't given formal guidance as to what that looks like yet, but thats certainly what we are leaning towards right now as we've all seen the commodity prices are very volatile and the fact that we swung nearly $5 in the past.
Two days and so it's really interesting to think about how we look at next year, what is going to look like I think what you've seen from us both from a hedging profile as well as how we've managed our debt and liquidity. This year is that we're keenly focused on all of those metrics combined and so while yes maintenance program is our plan next year.
We're certainly going to be aware of our liquidity and our leverage throughout the year. So depending on how commodity prices look that will affect of course, our outspend or if there is one next year at all depending on how you look at prices strip prices today might suggest that there might be an outspend, but again, it's really difficult.
To forecast what that looks like if there were a modest our spend next year, which we'll see how that looks.
If you think about Q3 and Q4 this year, where we generated positive free cash flow that positive free cash flow is enough to support a maintenance program next year, even if there were a slight outspend. So it's essentially a debt neutral situation. So we feel very comfortable that we can attain a maintenance program from an exit.
At rate of 2020 that make sense.
Yeah, Yeah that does I appreciate it and I'm sorry did you say did you have an idea of the well count that would would keep take to keep production flat.
We haven't provided that yet Scott I think you can use about 18 wells per rig.
And we said approximately two rigs next year. So I think that gives you some rounding numbers that without getting some specifics on our 2015 guidance. It gets you pretty close.
I appreciate that and then you talked about them or their discussion I think by Matt on you know I guess students of swaps and trades and getting to around 80000 net acres and can you give us a bit of color on what's happening around your position is that related to the noble Chevron.
Deal and where do you all fit in sort of this consolidation conversation I mean part of its getting your cost structure down to make a better business, but there is also the part where it's getting some scale and sometimes it's for relevance rather than just.
Corporate efficiencies sure Yeah, Scott as a multiple questions I think within that question, but those are all good ones you know acreage.
Acreage position, but as we've said in the call is going to exit the year greater than 80000 will likely be more specific of that next quarter as we get to the end of the year and can truly tally up how we've done it's a big compliment to our land team they continue to.
Have be proactive on trades and swaps with our offset operators, increasing our working interest in existing units turning non up sections into operated sections and oftentimes those trades are.
Are not exactly one for one on acreage and so we've been able to add cost free.
Acres to our position throughout the year. So that's that's how you have seen that you saw that our land spend for the quarter was very modest and so again, we spent very little on land, but we're still able to increase our position. So so feel very good about that the second part of your question was really about consolidation and I think that you know the industry has certainly.
Seen a wave of that particularly with the large and even some midcap companies I think that size and scale are a good thing and it will make its way down to the to the smaller companies right now we haven't seen a whole lot of that and I think it's a matter of time when that occurs from well how do we fall in.
To that kind of corporate consolidation world I think that anything that.
Looks constructive to our shareholders.
Accretive to our metrics and then can generate value for the stakeholders to the company. We would certainly consider that and I think somewhere down the road a getting bigger does does make sense for us what we are focusing on today, though is all about cost and then de levering the company I think getting to free cash flow and continuing to organically de la.
Over the company.
Is what we're focused on today.
Thank you.
Thanks Scott.
Thank you. Your next question comes from the line of Steven Nic cards.
Please go ahead.
Hey, guys.
Just wanted to see with Threeq 20, wolkoff at $858 per lateral foot.
What do you see that the drivers to get those costs down about 750 850 range that you're looking for on a go forward basis.
I'll, let Matt take this call. This question.
Yeah.
The numbers that we talked about with regard to the ducks.
Were around $858 per lateral foot and and yet what we were mentioning in the script was.
It was really that we had the advantage of re.
Recent completion activity recent facilities builds and but but those costs of 850 sorry.
Sorry, 58 were burdened by a kind of an older drilling design program.
That that was utilized before we shut down in kind of rebuilt that department.
So the expectation of getting closer to the $800, Mark which is which is kind of within the range of what Weve described in this in the presentation.
A really going to be execution of our drilling efficiency plan, you know and that is what I've seen so far is.
A real focus on the flat time improvements on the drilling rig lit.
Little things like trip times, and connection speeds and things that that are just.
Taking frankly minutes, where they used to take hours those.
Those kinds of things Whittle away at your daily cost.
And they improve your efficiency in the field. So it's a lot of just blocking and tackling change.
Changing different wellbore designs casing programs in Texas, and improved drilling efficiencies up in new Mexico, That's how we plan to attack and focus on getting to that $800 foot range and really those are the the structural changes that.
That I keep implying when we walk through the script and talk about the importance of the engineers being there in the field in Midland being physically present to just maintain that.
At really high level of oversight on all those flat times is that does that answer your question.
Yes, that's great.
And then just as a follow up I just wanted to see if you think there's maybe an opportunity for you to do another debt for equity swaps. Some time, maybe next year.
Yeah. This is George Steven I think.
Right now.
We're very focused on our cash flow profile and maintaining good liquidity.
We wouldn't comment on any type of corporate initiatives.
Specifically like that and we were very pleased with the outcome of the exchange we executed back in the spring time, which reduced our total debt by $127 million and reduced interest expense.
But as I said right now.
We're very focused on.
Reducing our current cost structure, improving liquidity organically and.
Starting to pivot towards 2021 planning and guidance as we move into early next year.
Okay, great. Thanks.
Thank you. Your next question comes from the line Barr Nunn Bush Airlines.
Good morning, John.
Got a question if we could revisit some of the some of the improvement jog made on that front and cost structure in general.
Yeah with you give an updated full year guidance, but how as you kind of exit the year and we think about 2021, you know a lot of these things do seem like you are pretty sticky and just as we kind of think about the cost structure next year versus this year.
So it's safe to assume there's going to be some some further improvement on an annual basis.
Yes. Thank you pointed out done it's a you know as Matt described we're very proud of the team for driving down a lot of those costs and they a lot of them are as you describe more sticky in nature, the electrification and the that swap out.
Fees to gas lift those kind of things are material improvements that are going to be around going into next year and beyond so feel good about that we still have.
Little bit left on the electrification to finish up in Q4, which ought to help remove some additional generators from the field and so there are still some projects that we think and can help move ela, we down on a notional sense that being said.
If you look at our guidance, you'll notice that LNG is up a little bit I think from from where we ended Q3 for the year and part of that is just the denominator of that and that production will be down a little bit in Q4, because our lack of activity in the second and third quarter of this year, So what weve.
Said is that if we hold a maintenance program that will be from the Q4 level.
Our lease exit rate of 2020 going forward. So if you want to think about kind of a Q4 l. OE run rate going forward, that's not a it's not a bad place to use as an estimate until we give 2021 guidance.
Okay, great. Thanks, and then I guess, just a little more on that we've talked about it but you've got a rig back out there now we look at the updated guidance at the mid point a couple of more spots.
But the completions or maybe.
Half a completion, so what would be some of the things that might push you to bring some wells voluntary ended the year is kind of the plan for the next two months to really just put them for a couple more docs back on the books to kind of help you mitigate that decline and and really get going on that maintenance program as we move into 21.
Right, Yes, I appreciate that so we've got as we mentioned we have a rig in Texas right now drilling essentially it's a it's a four well pad and so the timing of which those wells.
Get to total depth and then depending on how we fall kind of relative to our capital program and what not and the timing of which those wells could be ready to complete all of that gives a little bit of variance.
Variance as to exactly how many wells will be completed this year, we think about completed wells as first flow back so.
Theres a lot of moving parts that could come towards the end of December and whether or not those roll into 2021 or 2020 completions. That's why there's a little bit of a variance on that range. So that being said, we're pleased so far with the way these wells our drilling and look forward to bringing them online you know either.
Their end of this year first part of next.
All right. Thank you thank.
Thank you.
Thank you again as a reminder, if you would like to ask a question over the phone simpler for US are the number one on your telephone keypad.
Again that would be smaller than the number of on your telephone keypad.
Your next question comes from the line Jordan.
Please go ahead.
On a bed on decline rates you touched on it earlier, but just trying to get a sense you kind of have an idea of what the incremental impact on reducing decline rate size on overall breakevens and then kind of along with that just what sort of a steady state 2021 made no.
[noise] program might do to that 30% to 35% decline rate that you guys were talking about moving into year end.
Sure. Thanks, George for the question, we haven't provided a breakeven number out there.
Just something we Havent put forward I would I would just encourage you to look at our costs and kind of come to your own conclusions there, but it's.
I feel very good about our capital efficiency as well as our as our operating costs and I think we are pushing those in the right direction, which help lower breakeven costs of course from the corporate decline rate question, we're going to exit the year as we mentioned between kind of 30% to 35% range I think if you hold that number relatively.
Steady throughout 2021, you're going to be in the right ballpark and that is due to the fact that we are planning on adding a little bit of activity of course, we added a rig in September of this year. What we said on the call is that we're likely to have two rigs running next year and so with that level of activity I would expect our corporate decline rate to be.
About flat through 2021.
And just to follow up on that just on the infrastructure spend thats clearly come down pretty significantly not only this year, but compared to last year as well.
Do you think are we at a stage now where we're kind of in a steady state spend on infrastructure are there other kind of yellow.
Although we are enhancing projects that we could look for that might cause that to go up.
Moving into the year end going into it.
Yes, Jordan, it's George.
The majority of our infrastructure spend in terms of major projects has been completed a lot of that occurred in 2019 at the front end of this year, we had some some spending particularly in Q1 on a boat.
But as we look at major projects.
We do see a significant decline in infrastructure spending.
Not only from the beginning of this year, but year over year from 2020 into 2021.
As we think about obviously, we guide facilities and infrastructure capital together. So it is one bucket.
And as we look towards next year on the facility side.
Because we're going to be complete.
Completing.
Wells on a more normalized basis in terms of our resumption of activity.
We will see some degree of increase in the facility spend but on infrastructure, we're feeling very good about where we are.
In terms of not having much spend going forward.
Yes.
Jordan you might have cut out there I'm sure does that complete your questions I apologize.
I believe so rins do we have any more questions in the queue.
Again as a reminder, if you would like to ask a question over the phone simply press Star then the number one on your telephone keypad.
You have the next question from Needham Your line is going to be.
Hello.
Hi, you've got to Sean Smith here.
Hi, Sean how are you doing well, Sir how are you.
Guys I just wanted to get clarification, because I know there is a little bit of confusion as far as well.
Compliance goes my understanding that we have an additional 180 days that we can apply for is that correct.
Are you talking from a delisting warning.
Point of view, yes, Sir yes.
Yeah, we have we received a delisting notice in August we have until February for compliance in the first phase. There is a second phase that would extend that to August. So there's frankly, a lot of time too.
To deal with the NASDAQ listing requirements and other avenues to address that I'm sure I'm sure you've seen many companies address that through stock splits and what have you.
But.
We're still early days relative to that and don't anticipate any issues there.
Understood guys. Thank you so much for the clarification.
Thank you.
There are no further questions at this time presenters. Please continue.
Thank you all for participating this concludes todays conference you may now disconnect have a great day.
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