Q4 2019 Earnings Call
Results Conference call.
At this time, all participants are and I'll listen only mode.
A question and answer session will follow the formal presentation.
Do you want to require operator assistance during the conference. Please press Star zero on your telephone keypad. Please note. This conference is being recorded.
Now I'll turn the conference over to your host Mr., Tim Rochford Chairman of the board of directors or bring energy. Please go ahead Sir.
You, operator, and we'd like to welcome all the listeners to the 2019 fourth quarter and 12 months financial and operations Conference call again, My name is Tim Rochford Chairman of the board joining me on the call. This morning is our CEO Kelly Hoffman, Dave itself, our President Randy Broaddrick, our Chief Financial Officer.
Danny Wilson executive VP of operations, and Hollywood, Vice President of engineering, as well as Bill Parcells Investor Relations today will cover the financials and operations for fourth quarter at 12 months ended December 31st 2019.
But.
Most of the special circumstances in the recent events that work, we're experiencing right now all of US we feel it's necessary nuts upmost importance to identify the skus have symbolize factors at both directly and indirectly affect the ongoing operations at the company. So we plan to do that.
Upsets and at the conclusion of the fourth quarter 12 month review well turn it back over the operator and we can open up then for any questions. You may have oh for now.
Randy Broaddrick, our Chief financial Officer to just give us a brief overview. Thank you Randy.
Thank you Tim.
Before we begin I would like to make reference that any forward looking statements, which may be made during this call or within the meaning of the safe Harbor provisions of the private Securities Litigation Reform Act of 1995 for a complete explanation I would refer you to our release issued Wednesday.
Sorry, Monday March 16th 2020, if you do not have a copy of the release one will be posted on the website. The company website at Www Dot ring energy Dot com.
Revenues for the three and 12 month ended December 30, Onest 2019 were 52.2 million and 195.7 million.
Net income for the three months it did was 5 million or seven cents per share.
12 months was 29.5 million for 44 cents per share.
For the three month period net income includes a pre tax loss on derivatives of 6.1 million.
For the 12 month period net income includes a 3 million dollar pre taught pretax loss on derivatives.
Hey, 3.8 million dollar additional tax expense and acquisition related costs of approximately 4.2 million.
Net cash flow from operations was 30.1 billion for the three month period and 107.5 for the 12 month period.
This equates to 44 cents per share for the three months and Dollarssixty one for the 12 months.
Overall sales volume for the three months ended December 30, Onest 2019 was 923384 barrels as compared to 906874 barrels for the three months ended September Thirtyth 2000 night there.
Yes 2019.
Sales volume was 779099 M.C.S. as compared to 731627 Mcf for the three months ended September Thirtyth 2019.
I might be a we basis our sales volume for the three months ended December 31st 2019 was 1 million 53233.
As compared to 1 million 28812 for the three month ended September Thirtyth 2019.
For the 12 month period 2019 oil volume was 3 million a 536126.
And our gas volume was 2.476 million.
472 Mcf.
On a b L E basis that is 3 million 948871.
For the three months ended December 30, Onest 2019 are received price per barrel of oil was $54 a 92 cents.
And our receive price per Mcf of gas was $1.94 cents on.
Yeah, we basis this equates to $49.59.
For the 12 months.
Period are received price per barrel equivalent was $54.27 and to receive price per mcf of gas was $1.54 cents.
On a yearly basis this equates to $49.56.
On our oil price differential from Nymex WT I was approximately $2 per barrel for the three month period and approximately 275 for the 12 month period.
[noise] on prior conference calls, we have made more comparisons of our current results with the prior years results for the same periods.
We refrain from doing that this time in order to spend more time on current events.
Those are those comparisons are in the news release put out yesterday as referenced previously.
However, before I turn it back over to Tim I'd like to highlight a few key points. So I believe would provide clarity regarding items referenced in recent publications.
Can we achieved not only cash flow neutrality, but we were cash flow positive in the fourth quarter in excess of $4 million, that's quite an accomplishment for young company such as ours.
We came in under our annual Capex budget by approximately $9 million.
Our elouise, including production taxes for the three month period was $13.64 per deal we were approximately 27.5% of revenues.
The 12 month period, Ela, we was $14 from 59 cents per be a week or approximately 29.4% of revenues.
Our total DNA for the three month period was $4 in 87 cents per BOE, we were approximately 9.8% of revenues.
These numbers included yearend cash bonuses of approximately 580000.
For the 12 month period, DNA was $5.27 per be a week or approximately 10.6% of revenue.
These your numbers included.
4.2 million an acquisition related costs.
Without the acquisition related cost 12 month, DNA would would've been up $4, a 19 cents per be a we were about 8.5% of revenues.
We are compliant with the covenants of our senior credit facility the balance as of December 31st was 366.5 million.
We do have a scheduled redetermination in may.
As noted as a subsequent events in our 10-K and also in our press release, we have entered into hedges for 2021. They were done prior to this latest downturn.
Well, we do not know what price decks. The banks will use that to breed redetermination. These hedges will help us retain some of our value.
We currently have 5500 barrels a day for calendar year 2020 hedged with a floor a $50 and would have a total of 4500 barrels a day hedged for calendar year 21, with 2000 of that what they floor at 45 and the remaining 2500 with a floor at 40.
Even at a $30 receive price per be a week absent any drilling management as confident that going forward. The company can not only service its current debt reduce it.
With that I'll turn it back over to Tim.
All right Randy Thank you for that I appreciate it.
I'm going to ask Doug Kelly Hoffman, our CEO to review, our three month that our full 12 month operations for 2019 Kelly.
Thank you, Tim and I want to thank everyone for joining us on our call today, we drilled four new one mile horizontal santanders wells on our northwest shelf asset and the first quarter.
We completed tested in filed I piece on eight wells and the fourth quarter of 2019, and the average IP rate for all of those eight wells was 504 before we per day.
That equates to 104 be a we pull out for a thousand lateral foot.
On an average of about 4900 90 feet per well.
We also participated in three non operated horizontal wells on the north west shelf in the fourth quarter.
At the end of the fourth quarter 2019, we had four additional wells in various stages of testing and we perform 20 conversions from U.S.P. the rod pumps in the fourth quarter of 2019, and all drilling activities Workover projects, where all completed on time and they were all within our our proposed budget.
For the 12 months ending December 31st 2019, we drilled a total of 30, new wells and 13 of which were located the CBP 16, those wells with the north West shelf and one of the wells was in ER and the Delaware project that we have.
For the same period, we completed tested and filed I piece on 39 horizontal wells and the average IP or those wells was about 472 view, we per day and that equates about 105 view, we provide for thousand foot lateral [noise].
As it relates to the north West shelf.
Since acquiring the north west shelf in April we drilled a total of 16 wells.
[noise] completed tested in filed I piece on 14 of those wells, which the I'd be right.
Were 555 Boe per day, or 114, B, we per thousand foot.
As you can see the average IP rate for the north West shelf is noticeably higher than the overall company average and that just to give you that compares its 555 versus 472 on the overall company.
The net production the fourth quarter 29 team was approximately 1 million 49200 Beuys per day, I'm, sorry be a week.
That approximates to 11400 view we per day.
When you compare that to the third quarter production of 1.015 million, that's an approximately increase of 3.4% quarter over quarter.
I want to back up and take a moment here to talk a little bit about our 2019 acquisition, which was the wish bone asset.
You know we purchased the asset in April.
Production was down somewhat and that was due to a lack of spending I think all away from October to the time, we took it over in April and once we took it over we got control. The project, we started our drilling and maintenance program, we began seeing some immediate results.
Moving forward to a snapshot today and Danny Wilson is going to give you a little more color about this year in a moment, we now have a multiyear tier one drilling inventory with very high our ours and our ours and ROI even at todays pricing. So this asset allowed us to generate over as Randy said over for me.
And positive cash flow in the fourth quarter alone.
Tim mentioned not at the beginning a call that we believe it's very important to our shareholders that we discussed to current market conditions and how they affect the ring energy. We all are aware of today of the issues relating to the virus and what's happening to companies and what's happening to just an overall communities in day to day life and we're taking necessary.
Gary precautions to protect the company anything that we can do protect our people the company and.
And keep doing what we do best is what we're doing right now some of these things I'm going to talk about here for a moment [laughter]. Currently we have ceased all of our drilling.
As of now we've drilled four horizontal wells in north West shelf, it's possible, we may drill more wells by year end, but we're just gonna have to wait and see how things play out for the next few months and make that decision, we have no obligations or commitments for equipment or services moving forward.
However, if prices improve.
<unk> market changes suddenly it becomes important to show growth or whatever I want to be sure everybody understands we can move equipment out in a day or two [noise].
These are conventional reservoir data is going to give you a little more color on that but if we want to get busy we can get beds, you very quickly and from that start to the end of putting wells online in the tanks and selling oil. It's about 30 plus days, maybe 40 days and we're in the tanks and we're making money that's available to us It got a moment's notice.
We plan to continue capital expenditures for necessary upgrades improvements so long as we can clearly see how they will lower our and when we costs going forward.
Many of you realized in our breakeven may not realize our breakeven cost is under $25. That's a real number.
It's also including lifting cost production taxes DNA Kashi expense is an interesting this excludes capital cost of course.
We intend to make every effort to reduce cost and improve efficiencies.
Already last week began seeing some of the vendors start to lower their cost him. So we're going to continue to see those costs ratchet down a little bit I think you'll help increase margins were constantly running different scenarios internally and those different scenarios or help us stay ahead of the market.
We remain.
Our main objective here is to stay focused on protecting the balance sheet.
[noise], we continue to have ongoing discussions with a number of interested parties regarding our marketing efforts of the Delaware assets. Many of you May know Weve started marketing those assets last year.
At the end of the year, we've had a lot of conversation with lot of people. We've got some very very positive conversations going on today with a number of people I believe that market is going to continue to allow us and others to transact. It just requires a lot of hand, holding things don't happen quite as fast as they used to but they're still happening.
To the extent, we free up cash flow from non drilling activities. We can further reduce our debt. It's very important and let me say that's another way absent of drilling at $30 oil we're confident in our ability to not only service, but we can reduce our debt that's some serious staying power.
Well, we will have Redetermination may [noise].
Currently weren't compliance with all requirements of covenants.
We maintained a close line of communication with our banks.
Very strong relationship or banks and I know Randy mentioned this earlier, but it's worth mentioning again as it relates to our hedges, we have 5500 barrels hedged $50 for the rest of 2020.
4500 barrels hedged for 2021 of which 2000 or those barrels is a 45 as Randy is already stated would be sure everybody takes out away from this call and and the Rangers at 40 Bucks and with that I'm going to handed over to Danny and Holly.
And let them.
Are you a little bit more give more color on some of these ideas.
Well I appreciate that and I appreciate everybody being on the call today I'm going to spend part of my time today addressing some or concerns that have come up a regarding some recent articles that have been written about ring energy.
By persons with.
No motivations and what that contain a series of half truths and some flat out misinformation.
And without giving these articles too much credence I'll address some of the more glaring issues that came out of those because I know a lot of you have questions about those and I know also that we have a lot of new obviously with the turnover in the market. We have a lot of new investors, who may or may be hearing some of this information for the first time, so I'm going to go into a little bit more detail than I usually would.
Yeah.
One of the criticisms that we've seen in some of these articles was the the purchase of our wish bone asset and I'll address that a little bit later.
We've also seen people downplaying the quality of our IPO, because they're not as good as a shale players.
What they are failing to talk about in that is there are failing to mentioned the drill cost associated with those.
And then also you know we've had there was a question regarding our drilling economics why if there are so good we're not ramping up our program.
And I'll address all these.
Let me start out, though by saying you know a comparison between us and the unconventional players is a little bit unfair.
And I'll give you a reason why you know there's several different between conventional and unconventional reservoirs.
The primary zone for of of interest for ring energy has been from the day. We began business has been the St Andrews formation, particularly on the northwest are skewed maleness Central basin platform.
The same Anders is a well established a zone has been producing in the Permian basin for over 90 years.
This produced millions of barrels of oil.
It's a it's a DLNA ties carving it which is considered a conventional reservoir.
For over over the centuries that oil has been produced traditionally carbon isn't sandstones recall conventional reservoirs and that's because they are able to produce without a great deal of stimulation. They had their characterized by high.
Hi, prosody high permeability, which is the ability of the fluids to flow through the zone.
Without much stimulation.
And that's supposed to unconventional reservoirs, which typically though they'll have some frosty, it's it's much lower.
But.
They also do not have permeability a lot of those wells when I'm talking about shales fields chalks, the all considered unconventional play.
[noise] those wells can't produce without hydraulic fracturing.
And that's because the thrilled sizes between the poor spaces are so small that the fluid just can't flow through it so.
So what the difference between our play in those places where are using our hydraulic fracturing too.
And next prosody, that's already existing and also enhance the permeability.
And were as they're creating permeability otherwise their wells would not be able to flow.
So in an impact over no probably until about the last 30 years most St. Andrews completions were done with just acid hydraulic fracturing in the long term of the oilfield is really a fairly new.
And fairly new practice, and particularly on conventional reservoirs. So you know it's it's this zone has been around the long time and has no comparison early whatsoever to the unconventional plays.
Another difference between us and the shale players is that our wells are typically drill to the true vertical depth of around 4500 to 6000 feet, whereas the shales are typically eight to 12000 feet, depending on which which target they're going after our frac job to use about 400 800 pounds per foot.
Versus the sales that need 2000 to 3000 pounds of sand per foot in some cases, even higher.
Our drill cost we spend about 1.7 million to 2.6 million per well depending on the linked to the lateral.
While the shale wells typically cost between seven and $10 million.
One of the I'll call half truths that was pointed out in one of the articles mentioned that 35% of the wells.
Got into production in 2019 had IP rate.
Yeah, we're over double that of our wells what the author failed to mention was that those wells cost three to five times more than ours did so again, that's not a fair comparison without discussing the drill cost.
As for the acquisition of the wish bone asset.
This acquisition was an absolute game changer for ring.
And although we've been very pleased and we are very pleased with the results of our horizontal scenarios program on the Central Basin platform.
The wish bone acquisition gave us the opportunity to add an even greater number of high quality high return wells to our drilling inventory.
As good as our CBP wells are on than the north west shelf wells or even better we're seeing higher IP rates higher rates of return and higher returns on investment.
And to emphasize that I'm done now I'll turn it over to Holly for a few minutes and she's going to go through the economics of our drilling program.
Hi, Thanks Daniel.
We have now had that northwest at North West shelf asset approximately a year, how many continually to discover and refine and this exceptional asset we have continued to such a update our economic when we initially rolled out the northwest shelf curve, we had an understanding of the.
Production profile at the time.
We have stance refine the frac reduced the drilling and completion cost well at the same time decreasing the l., we with smart equipment deployment.
Our production has exceeded our initial expectations, but until we have more data. The production curves will remain a conservative estimate of what we think the northwest shelf can do.
I'm briefly Gonna review that changes on the type curve. These slides and the corporate presentation will be updated by classes of business Tomorrow. So that you can review your numbers at the last at your leisure.
[noise] due to diligent efforts in our drilling completion departments, we have been able to reduce our drilling and completion costs and as recently as today vendors have continued to reduce our costs.
We had initial $2.4 million drilling complete cost for a one mile lateral on the north west shelf.
That's far we've been able to reduce that two at 2.1 million dollar investment.
These savings are on both sides of the equation drilling and completion.
It also includes a larger fracs in the previous operator employed the purchase at the E.S.P. pump, which creates long term savings.
This long term savings translates into a reduction in or L., we model.
When combined with the ROE best well performance.
Both impacts create stellar returns at current commodity prices.
We have modeled a net realized be a we price a 35 40 and 45.
These models have an internal rate of return that ranges from 71% at 35.
She was high is 129 at 45.
Our anticipated price will be positively affected by the hedges that both Kelly and Randy mentioned for example, we have 5500 barrels of crude hedged at $50.
Combining those hedges with an open market price F 29, or $28, we would have an effect of oil price above $40.
This hedged effective crude price with the low cost of drilling and completion and our continued ratcheting down of our Elouise means we can create value even in a depressed market.
We Additionally, updated the CB peakers with regards to LLC.
NGL cost and completion costs, we have seen savings in that area as well.
It demonstrates that the continued development on our legacy CBP assets are accretive as well.
Weve ratcheted down our drilling complete cost from 1.9 to 1.8 and had a slight reduction in l. we.
We have modeled the same that 35, 40, and 45 realized price per BLE and these models have internal rates of return from $46, 46% at $35 to its highest 89% at 45.
At this point I'd like to hand, it back over to Daniel to discuss what we've done in 2020.
And thank you Holly and before I get to that I have a few other things a lot of visit about.
Guess kilian Holly both mentioned I want to remind everybody look we took over the north west shelf properties from wish bone in April 2019, when the acquisition close.
In 2018, a wish bone had a two rig drilling program running in it early in the year and that was in an effort to drive up the production prior to the sale something we would all do.
As the property went on the marketing in Q3 of 2018, they shut down all the drilling and drilling wasn't resumed again until we were until we took over operations in April.
This obviously caused a spike in their production in late 2018 early 2019, and then the production began falling off due to the lack of drilling.
And once once we were able to get back on there and get hold of the property and start drilling in April we were immediately able to arrest the decline in but.
A few months later, we actually had their trajectory moving back into positive direction.
And I bring this up because another article that was put out there was just completely false on the production that they've reported.
Our tried to report a to everybody and make our acquisition looked like it was a failure.
So I want to address that right now that article came out and said that in January of 2019, the average production for oil on the on the nor on the wish bone properties was 60 603 barrels per day.
And that by November of 2019 in had fallen all the way to 40 205 barrels a day, which is 35% decline even though as they pointed out we had started drilling again in April.
This person was obviously very misinformed or was intentionally misleading the public for reasons that one only to that person.
In fact of production on the wish bone properties averaged 6900 35 barrels a day in January of 19, and was 7836 barrels a day in November 2019, which is actually a 13% increase.
Now I'm going to give a little tutorial here for this person. So that next time, they look up our production they'll be able to do it properly.
We can only assumed that the author was unaware that production from newly drilled wells as reported under the drilling permit number until completion papers are filed and approved by the Railroad Commission.
Obviously, the completion reports contain all the pertinent information about the drilling and the completion of the well, but they also are.
Our not filed until the operators rate of filed initial potential test, which can be several months after the wells began producing.
And prior to that time simple search for production by operator number will not show the production from these wells, which is usually during the times of peak production for the wells since it's early in the life.
Once the completion papers are approved by the commission historical production will show up during the normal operator search.
Prior to approval a knowledgeable individual can access the production through a search using the drilling permit number I hope this helps.
Another question, which has been raised by and one of the articles was about our drilling economics and if theres. So superior why we are aggressively ramping up our drilling program.
In the words, the author we should be printing money.
And as you can tell from our financial report, we did generate over $4 million in free cash flow in Q4, which was at all year long that was our stated goal of reaching positive cash flow by the end 29 team. In fact, the author had mentioned that we would have continued outspend in Q4, which obviously turned out to be fault.
Yes.
I also want to address the credit some of the criticism, we've received regarding our non drilling capex [noise].
I haven't been mentioning all year long that we have begun a very aggressive program of rightsizing, our pumping equipment, whether it's through replacing larger E.S. piece was smaller ones [noise].
As a total fluid production in the wells naturally decrease or whether it's by converting the wells to a rod count from DSP the cost savings associated with these programs over time is very very significant.
The Rod conversion program in particular is very beneficial as it reduces our future costs of working on these wells from about $200000 per job down to 20 to $40000 per job and not to mention the savings and electrical cost and other issues that we're not happened to maintain that high high horsepower equipment.
And we are already starting to see the benefits of this program, which is even more important as we move into these times of lower oil prices.
I'm, sorry talking about those other guys now.
As Kelly mentioned earlier.
We drilled 16 wells on the North West shelf in 2019 at the end of the year. We had filed 14 I piece, which averaged 555 Boe per day for an average of 114 BLE per foot.
From the time, we began drilling in a in April we've gone through a and upgrading I would say a refinement of our frac process. We used three different styles of fracs during that period of time and through the efforts of our our engineers in house and with a consultation with other operate.
Orders in the area, we have refine that problem that down to a point, where we feel like we have the optimum Frac program now moving forward.
We use that new Frac design, when we drilled and completed our four wells in Q4.
Preliminary results are extremely encouraging.
The difference now that were to have between those the prior frac jobs in the one that reason now that we're using more perf clusters with fewer perforations per stage.
We're doing a higher injection rates and we're using higher sand concentrations three of the four wells that were frac that with this new design in Q4 averaged had average I piece of 648 Boe per day or 136 Boe per foot. The at the end of the year the fourth well is still test.
And but it was very encouraging we were seeing similar results on that well and while we can't say that all future wells, we'll see this magnitude of increase we are extremely encouraged.
I'm going to take just a second now I'll turn it back over to Holly and she's going to discuss our year end reserves.
Thanks Danny.
As he mentioned we had completed our year end reserves, we acquired the wish bone assets and in April and since that time, we have grown our total proven reserves.
Hi, above 10% with respect to well, despite an FCC well modeled price reduction of about $10 or 16%.
This could only be achieved by a strong PDP base that is accentuated with our rod conversions and reductions in alley and layering on strategic drilling.
In 2019, our year end proved reserves consisted of 71.4 million barrels of crude which is approximately 8% Blackwell as a company percentage and 58.3 Bcf of natural gas.
81.1 million barrels have B O E. In total proven reserves, 58% of these are proved developed.
Overall, we have added pads as well our proven undeveloped locations on our CBP asset. We have 40 identified proven vertical drilling locations 29 proven horizontal locations and over 667 potential horizontal locations.
And our Delaware, we have 43 proven vertical locations for proven horizontal locations and 154 potential horizontal drilling locations on our north west shelf asset, which we've referred to as the wish bone asset we have 57 proven horizontal locations.
And 13 proven non operated horizontal locations.
Hi, 231 potential horizontal locations and all of this adds up to many years of trailing at this point I'm going to hand, it back over to Danny to wrap up.
All right Holly I appreciate it I'm a give you a little more color on on the information that Kelly gave you regarding our activity in the first quarter.
Today, we have drilled and completed four additional wells on the northwest shelf all the wells are on test and performing well.
The first wells were put on NIM production in mid February which is a little later than we would've liked but due to our reduced activity drilling only four wells on a quarterly or actually now having to share frac crews with other operators, we kind of have to get in line or as opposed to couple of years ago or even last year. When we had two rigs running we were.
Dictating the pace.
Completion now it's more of a shared activity with some of the other operators. So because of this delay we are seeing a little bit of a reduction this quarter from last quarter, we expect to see about a 5% to 7% drop in production from Q4 that doesn't reflect on the quality of the wells we're drilling only in the time.
One of the drilling.
The program ahead, if we had moved forward with the drilling program. We proposed early in the year with our with our higher Capex budget.
We we had modeled out that we would have seen some modest growth year. However, with the suspension the program in the event that we do not drilling more wells, we're expecting to see an overall decline in our production from December 2018.
Excuse me to December of 2019 of about 15% to 20%.
As Kelly mentioned earlier in the event, our economic position begins to improve whether it's through a better oil prices are reduced drilling costs, we can easily get back to drilling in a matter of days in fact, we have a drilling rig sitting on one of the locations just waiting to rig up so.
In the event things change, where we can move quickly on that.
And well look while we realize this by suspending the drilling program, where sacrificing some growth.
Our focus continues to remain on free cash flow and the strengthening of our balance sheet, but again in the event that.
Ah think circumstances changes, we can immediately get back to work and we can turn that around very quickly.
And with that I'm going to turn it over to our President David Fowler.
Danny Thank you very much on many of us were.
Speculating 2020 would see a robust M&A market, but due to last week's precipitous drop in oil prices and what we call yesterday, most all M&A talks of what I would say gone into a holding pattern as everyone looks to navigate their way forward and these operative times.
Despite the drop in the commodity prices make no mistake, we remain market aware for potential ideas that we call value add opportunities that we're going to be able to pursue without further leveraging our balance sheet.
Well 2019 as you heard discussed this morning was one of our best growth years in recent times and as Randy mentioned earlier, we achieved our year end objective of becoming cash flow positive as we did so with a cash surplus of over $4 million again, I would like to remind everyone that ARPU.
Production averaged about 11000 net barrels of oil equivalent per day.
Now to achieve a free cash flow positive position.
With what many people would consider a low daily volume is an exceptional feet. When you take into consideration many of our peers, who produce over 10 times, our daily volume or about 100000 Boe per day have only recently achieved free cash flow themselves.
The exceptional well economics on both the CBP and the northwest shelf again. This is what Danion Holly just detail is the cornerstone or foundation of our success and his proven our high stated IR ours are true and is the primary reason we achieved this free cash flow milestone, let me remind everyone. It's only been three.
Here since we drilled our first pilot horizontal santanders wells at the end of 2016 or CBP assets, along with the addition of the Yoakum County asset for the wish bone assets have secured many many years of highly valued horizontal San Andres drilling locations.
In addition to the high rate of return horizontal San Andres Wells. There are some other several other key elements the make us different from our peers and have added to our ability to achieve to achieve this milestone such as it started with a low entry cost for acreage, which was about $502000 an acre all of our.
Illustrations utilize $1000 an acre which was on the higher end.
Again, it's also our high oil product mix, which you just heard reference was 88%.
If you include into that production stream the liquids that goes to about 94%.
When you compare that to our Permian peers.
Typically they're going to be 20% to 25% below our product mix or oil product mix of 88%.
The higher percentage of oil results in a higher net realized price per Boe, we than our peers.
And as illustrated on a bar graph on page 18 of our corporate deck, which is on our website.
Another key factor is our short cycle times of just 32 days now the 32 days was what we illustrated in in 2019 again, that's going to be on.
On page 21 of our corporate debt, let me, let me defined what a cycle time is that's from the time that we spud well to the time, the we turn that well to the tanks.
The quicker we can make that turn obviously the quicker we'll see the ability to count production and also see revenues coming from that well typically from the time that we spud a well those high we start seeing revenues can be as early as 90 days and is and is maybe about 120.
Okay. So in that 90 120 day time period is what we can see a return on capex dollars expended.
In comparison on the middle of the Delaware basins that cycle time is five to seven months. So you can see doing it and one month has a tremendous impact short cycle times don't negatively affect IR ours.
As much as it does for other other peers of ours and also be reminded the we don't have any ducts.
Short cycle times also enable us to respond quickly to commodity price fluctuations in days and weeks not months.
Another attribute of the conditional send adverse reservoir is it's lower decline profile, requiring less new wells to be drilled to maintain and grow production.
You'll also note that in the early years, we invested capex dollars to build out our own pipeline infrastructure.
Disposal produced water and transport oil and gas as a result is now paying off and lower lease and transportation costs.
An area that isn't normally highlighted in a lot of people's conversations as DNA, especially on the administrative side. Our DNA is low in relationship to almost all of our peers as evidenced by our Conservative C suite salaries director salaries and bonuses.
All the factors I've, just mentioned result in a low cost structure that equals an all in cost per barrel only $25 now that includes lifting cost production taxes, DNA and interest expense not capex.
Shaving and maintaining a free cash flow position is no easy task in today's volatile somebody even say hostile energy environment and it illustrates a high level of success when it can be accomplished out or low daily volumes only about 11000 net BOE a day and is proof that really is a low cost operator.
As one of the most profitable drilling projects in the Permian coupled with the other factors I just referenced.
Though we all have to quickly tighten our belts.
To address this new 30 dollar price environment that we're in we're confident that reading is well positioned to weather the storm and with that Tim I'll turn it back to you for closing comments.
David Thank you and thank you everybody the entire team doing a great job of illustrating and discussing the key points before I turn it back to the operator and I know, we're all anxious to get to that too. So that we can start with the Q and eight but again reviewing the team we applaud because execution, we did exactly what we said we do.
Yes.
We actually not only reach cash flow neutrality, we surpassed it in the fourth quarter with a surplus of cash by the way we did it with production growth consistently through the year. So with that that really concludes our presentation, we're going to turn it back to the operator.
Open up for questions of the listeners may have operator.
Thank you at this time, we will be conducting a question and answer session. We would like to ask the question. Please press star one on your telephone keypad.
For participants using speaker equipment, and maybe necessary to pick up your handset before pressing the star keys.
The confirmation Tony will indicate airline isn't the question Q you May press star too if you would like to remove yourself from the Q1 moment. Please while we Paul for your questions.
Our first questions come from the line of Neal Dingmann of Suntrust. Please proceed with your questions.
Good morning, Tim and team.
Hi, guys. My first question just dive right into it is more I mean, obviously with the where the stock trading around the liquidity and Capex could you just you Danny you guys and.
Randy and everybody sort of alluded to this but could you maybe get you Kelly all of you I'll give a little more color.
As far as when you look at you know with Redetermination coming up with.
Obviously not drilling any wells just how you look at.
You know sort of liquidity and maintenance capex kind of if I could not intertwined those altogether for the remainder of the year to have the confidence of continued free cash flow.
Yes, I will let me just start off this is Tim Let me, let me start by saying as we.
Hopefully clear in our release or at least from a week ago yesterday I believe it was we have ceased drilling for now thats not to say that drilling and come back into play it will be measured a lot of course by the of the deck itself the pricing, but we know we're confident right now that in that $30 environment that we can we can service the death.
We can take care of the somewhat modest capex.
We have a somewhat budgeted out with infrastructure and the conversions that Danny and Holly mentioned earlier.
We know that I think everybody knows on this call that we continue.
With our efforts to monetize and look to sell the Delaware asset and I can tell you as Kelly mentioned earlier.
Surprising.
Even in today's environment with the last couple of weeks, we still have some very serious interested parties and that they hopefully as we do see a vision that goes beyond just as current pricing environment. So we're hopeful that we can continue to pursue that and then along with the maintenance and the ongoing capex.
So reference to the conversions of the sub pump into the rod pumps, so workovers et cetera.
And at that $30 environment, keeping in mind, a $30 environment gives us a yield much higher than that would that hedged component at $50. So.
We're hoping neal that the added value from October 1st when we were last assignment or assessed value for the Redetermination last fall from that point until now that theres been a number of add value as it relates to the basket on wells that have been drilled uncompleted I don't know thats enough to keep up with the deferred.
And the pricing then versus now I think our price deck that was at $49 and maybe a little change. So we'll have to wait and see what that's going to look like in may, but we're having great communication with the banking group, we're trying to stay up front of this and we think we're going to do a pretty good job, but keeping to maintain it going forward.
It does that include you mentioned I I know you've got set of several times on not having to drill anything necessarily else what about just if data could just comment on the need and how much you could pull back just on no the rods and some of the other infrastructure costs that you had sure Dan Yes, yes, no at Neal and that's a good question, we know everybody wants to know that.
Look we we've taken a look at our budget, obviously, we came out with the earlier one in the in the mid 80 million range.
The new budgets, probably and we havent finalized anything yet, but you know I think right now we're looking at us band of about $40 million to $45 million something in that range with about half of that already being spent in Q1.
You know the deal with the Rod conversions and E.S.P. changes really have nothing to do with the drilling program. Those are the work we're doing on the existing wells.
But but I think you can see I mean, what we're seeing a dramatic drop in our in our costs on pulling these wells as we've been very aggressive, especially last year on getting a lot of these things properly sized in converting to the rod.
I you know are some just for an example on the CBP.
During the first quarter about half of the jobs that we've done now have been rod jobs as opposed and I don't know what I mean is.
Working on wells that we converted last year to raw, it's about half of move have are down that rather than just pulling Sps. So if you look at a difference in that at $200000 well versus 20 to $40000 well. It's money well spent we're going to continue forward with that program we are.
We are pulling it back a little bit we are.
Not as aggressively looking at at that but.
We're still going to be fairly aggressive.
But again out of a 40 to 45 million dollar potential budget moving forward half of it already been spent Q1, you've got to see what the rest of the years going to look like.
Great Great details, Dan and one last one if I could just did it for you or Kelly whatever you guys want to take it just could you just talked about the decline I know you you mentioned I think.
Year end the year end, but again I'm not looking for just that again could you talk about sort of how you'll see it sort of the naturally I guess sort of two parts, but all deal with ascend flex about the decline maybe how you all see it this year more than just quarter to just year end the year end, but maybe your assets and how should we be thank you.
In a plan, where you potentially kind of drilling more wells.
How should we potentially thinking about the decline.
That's a really great question, you know Danny I'd mentioned this is Holly sorry.
I thought you can take you didn't know I'm the girl.
I've got one.
[laughter]. So data you had mentioned year over year declining now we're we're anticipating you know in that 17% to 20% range. You know if we hope to selling now and don't pick up the drought that this year you know we're going to see further decline next year, but its into that flattening phase because we don't have anywhere.
Well on that high steep decline they've already kind of.
Hit therapy factor and have have had a lesser decline. So I would you know anticipate somewhere in the neighborhood as you know 10 to 12. The following year, if we didnt pick up at gel drought that this year.
Good thanks, so much of details.
Our next questions come from the line, having all parts of Coker and Palmer. Please proceed with your questions.
Hey, good morning.
Good morning.
Wondering.
When you were talking about the.
I think improvement you hadn't production from the new Frac design and you said you don't necessarily assume that that every every well we'll be.
The that high going forward I was wondering what would be the source of variability in production at future wells would it just be geology or just different performance like if you.
Successfully brought production forward with the new Frac design, but oh right, but essentially the same you are so what would that variability be.
Going forward.
I'll answer part of that and then I'll, let Holly address the that you are part of that no. So far we have a sample size of now eight.
Wells that we've used the new Frac on now we also have.
We develop this proprietor job.
In relation with several other operators in the area, particularly the steward and they are having tremendous success. The variability EPS will come through the geology not every area is equal we do have and we have different landing zones.
Depending on the area. Some areas, we have multiple landing zones, so that'll that'll be it's a net which.
To answer your question is geology, so, but we are seeing that the wells that we're using the new frac job on our superior so far the results are very superior to the wells that we've done in the past when we look at the definitely 555 Boe per day in and 648 as a pretty dramatic in.
Increase for and really the price it didnt change that much on the as far as the completion goes.
So.
Do I think I think we'll start seeing I think we'll see continued success with that Holly also mentioned earlier that and I'll reiterate for everybody. Our type curve is based on 400 Boe per day.
So you can see there they are far exceeding that how we're not ready yet because of the small sample size to change the type curve.
But I'll, let Holly address that you are coalition.
And so as Danny elated that that geology plays a big factor and how we land these wells.
The same Anderson the northwest shelf is about 400 feet thick, we identified a basically five potential horizontal benches add depending on where you are in the structure. There not omni proud that you don't have five and every well or five and every section and so there is some variability in.
Why is based on landing down. Thank completions, you know the best thing for US to do is take a conservative approach and as we add dealt more data that that can be verified then we'll look at and changing the type curve that he wires overall, our statistical play we are seeing.
Pretty Ken assisting clustering.
But you know where we're looking at exploring all the benches and maximizing that asset yeah, no I think just to add to that little bit.
The bigger frac job with more sand.
In the higher injection rates I think we're opening more zone.
Ill again, we've only had these wells on since mid mid part of Q4, we really can't tell what that you are is going to be but I would expect it they are going to increase just because as I feel like we're draining a larger part of the reservoir with each will.
Great. Thanks.
And just for some perspective.
Across the industry Nevermind roughly how many rigs are are running right now on the northwest shelf from the platform at the moment.
Oh.
I had.
That's a good question I think.
In our particular play now that's all I can really speak about.
I don't I don't know of any of the offset operators, who are drilling on the northwest shelf or do you.
Our field guys haven't reported anybody drilling you know, we we're always in constant contact with a lot of the operators out. There you know we have non op interest in their wells. They have non op interest in our wells and and I, you know talking to steward and Riley I don't believe any of them married drilling.
On the northwest shelf, particularly in the thing Andrew is right now.
I am I'm trying to pick up on Baker rig count and that's a good source of as rig count availability and they haven't listed by operator, I'm just not quick enough and on the CBP no I'm not aware of anybody I mean, we've really been the only company drilling horizontally for quite awhile.
While on the on the CBP.
Right right.
I think that's it for me thanks a lot.
Thank you know thanks all.
Our next question has come from the line of down Mackintosh of Johnson Rice. Please proceed with your questions.
Good morning, everyone. There most of my questions have been asked did a great job kind of walking through everything on the call, but just for point of clarity you talked about.
Earlier in the call I think Brian.
They have into prices do come back and when you when you do get out in the field bring in having a rig and but a geo and.
You know kind of 30 days and then later in the call. You mentioned 90 days, just just kind of.
It's kind of any some color on there about how quick you could get operations back up and running in the event over price recovery next 12, yes, yes, no I mean, if somebody said 90 days that that was incorrect.
The only thing I've mentioned that and typically our cycle time is about 30 to 35 day somewhere in that range, we were a little longer this time.
And as I mentioned it was because.
When we had two rigs running we control the Frac crew, we controlled everything in the field and we occasionally we'll let the Frac crew go and work for somebody else, but now obviously with the reduced activity.
There's a little more sharing and I mean, we werent communication, we share frac crews with steward Riley.
And a few other small operators in the in the area and it's just kind of a coordination thing, but I can tell you nobody else uses the drilling rigs that we use.
We use a rig that's too big for vertical wells, it's too small for those the shale wells.
We use a company called Robinson out of out of the Big spring. They have two or three of these rigs that Dave modified just for this the central basin platform in the North West shelf Sanders drillers.
Those rigs literally I am going sitting on the next location.
So I mean, it's just a matter rigging it up our drilling superintendent our manager and our completion guys have been on the phone constantly as you can tell we're using the lower drill cost now and our economics.
I think theres going to reach a point, where just like it did in 2014, we're going to figure out a way to work at 30 $35 barrel. We did it before we'll do it again, but those costs are going to have come down a little bit bar there.
So it's a can we get it turned around very fast, yes absolute I get these vendors are sitting on our doorstep. They are waiting to go back to work.
So.
We can get it we can get it up and running very quickly.
Alright, great. Thank you all and like I said everything else was answered.
For the following along.
Thanks, Doug.
Yes.
Next question, it's come from the line of John White of Roth Capital. Please proceed with your questions.
Good morning, everybody.
Good morning, John Florida.
Congratulations on the quarter and congratulations on your execution very nice.
I.
Oh I liked seeing you stop drilling and stop your.
Capex devoted to drilling.
And as much as you're continuing your infrastructure spend on rods and pump in the change outs.
Would you it might be helpful would you consider putting out a capex budget for the rest of the year that just addresses.
Those items and as you noted I understand your.
Your offer from an operation standpoint, you can you get back drilling much quicker than than the shale operators that.
For having a having a more precise number on infrastructure spending in a press release might be helpful for people.
You bet, John that's a good that's a great point actually and Thats something that we are working on and we plan on doing that just give us a little more time, so that when we put that out will be pretty certain that we're standing.
Okay. Just wanted to wanted to see suggests that and.
Yeah, I know the Robinson drilling guys Lou Crownover, that's a good group.
Yes, and we're very pleased with their equipment by the way just clarify obviously stewards listening in and they Texas. They have a rig running so [laughter] Oh no. There is one rig running.
Thanks, Thanks for all the information I appreciate it thanks John.
Our next question has come from a line of Andrew Barnes of Alliance Global Partners. Please proceed with your question.
Hi, good morning, calling in for Bhakti, Thanks for taking my questions.
You bet.
If you're able to share how many of your color contracts have you exercise.
So far this year.
Randy is that something you can respond.
I'm.
Sorry, I want to clarify I understand when you say exercise.
What we have is costless collars with a floor to ceiling. So there.
The price declining they've come into play we havent.
It's based on the average price so most likely for March will end up receiving a payment we did not.
Receive or pay anything for January or February as the the price was between the callers.
Does that I'm not sure what you meant by exercising yes, I guess, that's I guess that's helpful. Maybe then just as a follow up to get a little more detail.
Would would then those.
Contract, maybe you can help like kind of in the exercise not exercise just kind of the process one spot prices are below your.
Right.
Below the floor prices.
Then the lowest.
Call prices be paid out first or do you is there a decision process there or is it kind of just whatever.
Rolls off so.
So.
All of our colors for 2020 are the same with the 50 dollar floor and so.
On a monthly basis the.
Average price is compared to that 50 dollar floor and we've received that amount timed the 5500 BOE a day that we have hedged.
So there is no exercising its essentially kind of an automated process once the price for a month is.
Finalized.
If compared to those floors, and then multiplied by the the volumes that we have hedged.
Yes that makes that makes sense. That's helpful. I guess I'm, just trying to figure out kind of.
Yes, these different kind of levels.
Puts and calls kind of trying to figure out.
Which ones will.
For lack of a better weren't disappear first.
None of them really disappear I guess the thing I guess I guess, they come off a month out of time, but we have the 5500.
If you're talking about the ceiling those will all the stay the same for the year we have.
That amount so as far as the floor.
The 50 dollar is the same for all of them and so say the price ends up being $30 for March we will then received $20.
Times to 5500 BOE a day.
I'm not sure how else to right now that that makes perfect sense.
I'm more so.
More so trying to figure out I guess I understand the gain their below the 50, but adds.
[music].
Nick Nick maybe I'm missing something here on the on the on the call prices just trying to trying to figure out how those will change.
Those volumes will change.
As you as you're getting the gains for that as prices are below the put price.
The ceiling won't change it.
Average price.
As you want to stay the same for the entire year.
Okay. Okay. That's helpful. Randy. Thank you very much appreciate the time to detail. Thank you.
Thank you.
Our next question has come from the line of Logan Moncrieff Thomas Capital. Please proceed with your question.
Thank you. Thank you gentlemen for taking my.
Taking my call.
And focusing on the this spring Redetermination no using the reserve report there was published in the K I guess I'm kind of calculating back of the envelope PDP value at strip at around $400 million.
The question is I mean, just kind of the way the banks are kind of gearing up.
I guess you'd assume that there'd be some sort of hair cut to that so.
I guess a question is kind of mechanically kind of how will how does that work if they come in with a borrowing base that.
Lower than what's drawn on the line right now.
Yes.
How much time do you have to cure that in kind of what what options do you have to secure any deficiency. There certainly that's a good question Logan So let's try to address it best we can.
So looking back at the at the value that was given the last Redetermination I think we mentioned earlier in the call that was based on a $49.
Obviously that number is going to change and the result of that is going to so put the pressure on as you're suggesting which you're correct. Rather then expect a 425 million dollar base what would the adjustment look like so one thing that we have to consider is in our favor is that sets.
Last determination that last valuation whether you make up the difference between October 1st and year end, which is a catch up on the third party reserves are making reference to there's also the activity that flowed over both on the completion side as well as the drilling and completion side for the new wells that will add to the basket value whether or not.
That's enough to make up a remains to be seen I doubt that it will be as we're seeing the strip today I can tell you that we've run some preliminary numbers as recent as of late last week and we feel that across the board that we are going to probably still be closer to maybe 500 million of course that depends on.
That's going to be when they run it up at strip last weekend Holly help me. If you can hear I know that we were working on that Wednesday or Thursday.
We were somewhere around 500 million number.
Yeah, I ran it with a step last last week and then adjusted for the hedges and that put us in that PDP number of around 540 million.
And so as you know as as Tim has mentioned it in May add just our borrowing but you know we were and we were near that in our fall Redetermination.
So is it safe to assume that if they use something.
You know the resemble strip here that you're borrowing base would go up would increase.
No I don't know idle speculation that at all I think what we're suggesting is that if they if we stay on the same same similar parameters as before as in past years and with the adjustment from I'll I'll share with you that backlog told her first our PV 10 actually was PV nine on PDP.
One of the round numbers of 675 million for example, a PV 10 at year at year end or at that time was I should say at October Onest was about 650 PV nine was right at that 675, so with adjustments keeping in mind that they were at $49. So with those adjustments now we would until.
The pace at that base when in fact and realistically could come down I guess the other part of your question is to try to respond to that is okay. What can we do about that what our options well we do have.
Free cash flow taking place as we speak so we feel we're in a position where we can whittle away at that at that principle right now not significantly but to some degree. So I think I think it's going to go a long ways to be able to show the banking group that we demonstrated we can do that aside from that you know that we've been marketing for sometime the Delaware asset and.
Even though you would assistant environment today, and say, hey, it's going to write a check well there, but they're not as Kelly mentioned there are those that that maybe not bank in the door down but there are other front door very serious parties that we're still talking to.
Numbers that are reasonable for us to consider.
So that's that's an option.
And of course.
If the bank comes back and says we'll look your new base has been adjusted to 375 million and you borrowed 366 million that gives a very very little liquidity, but we don't plan Logan, we don't have a plant outspend.
So.
I Hope is one thing that's not a strategy. The strategy is we're going to stay with then we're going to stay within the boundaries of our cash flow.
Just step and managed at the best weekend.
Okay perfect perfect and I appreciate you, taking my questions and just one more.
On Q4 production kind of this this scenario.
Where oil stays in this 29 $30 range.
And you just significantly cut your your activity and just what some cash flow a little bit of cash flow will be generated from from the assets.
I'm just kind of gets to.
What Holly was talking about in terms of declines, but what does Q4 production look like under that scenario that draconian scenario.
Q4, Q4 of 20 Q4 of 20 kind of an exit rate production Holly I think your best probably addressed.
I I am me and Danny Airbus looking at each other and neither one of us have that on our cheat sheets that we havent brinavess. So Unfortunately, you know it you know as Danny mentioned it was going to be in that 15% to 20% a reduction from where we currently are and so our euro.
Every year, so and we can do the back of the napkin calculations, but we don't have that number yes, I think you could just kind of kindness shoot for somewhere if you look at our Q4 number.
From this year, just kinda shoot for about 15% to 20% less than that should be you should be in the ballpark.
Right. Thank you for taking my questions. Thank you Logan.
Our final questions come from the line of Richard Tullis of capital One Securities. Please proceed with your question.
Hey, Thanks, Good morning, everyone. Just a quick one for me I guess, probably best for Danny or Holly.
Talked a little bit about.
Higher oil price or lower well costs to get back to drilling can you kind of frame up for US really what you are looking for combo of higher oil price or maybe even more importantly, lower well costs too to resume drilling in northwest shelf.
Sure No and that's a great question.
Richard We you we went through this like I mentioned before we went through this in 2014 and what we saw was that the prices on on Kumar not the commodities, but on pipe on drilling on everything lower down to a point I mean these got these vendors don't want to go out of business, so they're going to lower their cost down whether it's through.
True.
Cuts to their their payroll.
Just whatever it is they're gonna do everything they can to get these these prices down to the point, where we can go back to work.
And I think I think it may take a little bit of time for everybody get to that point.
Neil fleet, depending on if we see any obviously any rebound in the pricing.
We would have to sit down and run our models in C.
At what point can we service our debt pay down maintain free cash flow and then and then also have some excess cash to go back to drilling you know I think that these points will be clarified probably in the next 30 to 60 days I think we'll have a better field because what I what at.
Mentioned, the Kelly and Tim and the rest is I've been surprised at how quickly the vendors have responded.
Typically in the past and all the other downturns, we've been through since I've been in the business, but.
No. It typically takes about six months for the vendors to come to their senses and realize that to you know they're going to go out of business. If they don't lower the prices we were getting calls on after the after that Russia announced they weren't going to.
Getting aligned with opaque we had calls the next day from vendors already slashing I mean, we've had we've seen reductions already anywhere from 15% to 20%.
I expect those to get a little deeper as weak as we continue forward.
Yeah I.
I would I would be surprised if we don't reach a point, where these costs are going to get down to a point. We go back to work at least on a limited basis.
Thank you Daniel that's helpful. Appreciate it.
Thank you Richard.
We have reached the end of the question answer session I will now turn the call back over to management for any closing remarks. Thank.
Thank you operator listen we know that it's a busy time and there's a lot of distractions out there. So once again, thank you for given US your time and listening in this morning.
Everybody stay well thank you.
This concludes todays conference you may disconnect. Your lines at this time. Thank you for your participation have a great day.