PDC Energy Inc (PDCE) 2016 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy 2016 first-quarter earnings call. As a reminder, this conference call is being recorded. I would like to now introduce your host for today's conference, Mr. Mike Edwards, Senior Director of Investor Relations. Sir, you may begin.

Good morning, everyone, and welcome. On the call this morning we have Bart Brookman, President and CEO; Gysle Shellum, CFO; Lance Lauck, Executive Vice President; and Scott Reasoner, Senior Vice President of Operations. We posted the slide presentation of the Company's remarks today on the investor relations page of our website, pdce.com. I would like to call your attention to the forward-looking statements on slide 2 of that presentation.

We will present some non-US GAAP financial numbers on the call today. So I would also like to call your attention to the appendix slide, where you will find the reconciliation of those non-US GAAP financial measures.

With that, let's get started, and I will turn the call over to Bart Brookman, our CEO. Bart?

Thank you, Mike, and good morning, everyone. We began 2016 with a very strong first quarter. Our production was in line with our expectations despite a significant snowstorm in late March which dramatically impacted midstream reliability. The Company's capital programs are on target in 2016 for our guidance midpoint of $425 million. The operating costs for the Company for the quarter came in slightly better than expected, and our equity placement in March provided an even better reinforcement to our balance sheet as we navigate through these challenging times.

Let me cover some of the first-quarter highlights. Production was 4.6 million barrels of oil equivalent. That is a 58% improvement from the first quarter of 2015. And our Wattenberg operations grew production at a pace of 66% quarter to quarter. In March, the Company turned in line a record 34 wells, setting us up for a very strong second quarter. Again, this was a record for our operating teams, and we executed this without a single environmental or safety incident.

The lifting costs for the quarter continue to show improvement to $3.35 per barrel of oil equivalent. That is a 40% improvement from prior-year levels and in line with our guidance for 2016.

And as we covered at analyst day, our oil deduction in the Wattenberg continue to improve and should average $6.50 a barrel or slightly better in 2016.

Then from a financial perspective, in March, again, we were extremely pleased with our equity offering of approximately $300 million, which was (inaudible) peer leading discounts. We had quarter-end liquidity of over $900 million. Capital spend for the quarter came in slightly lower than expectations due to the timing of projects, and Scott will cover this in more detail later in the call. Adjusted cash flow for the quarter was $91 million, or $2.19 per share. And we are extremely pleased with the overall cost structure of the Company, and Gysle will cover this in a lot more detail in a moment.

And last, we had our banker meeting last week, and we don't expect any material changes in our bank line.

Now, what can you expect for the balance of 2016? Again, we continue to expect our capital spend levels to be approximately $425 million. Again, that's at the midpoint of our guidance. And a midpoint guidance production level for the Company for 2016 continues to be 21 million barrels of oil equivalent. Based on where oil and gas pricing stands today and our outlook for the balance of the year, we anticipate running four rigs in the Wattenberg through year-end. We should spud approximately 140 wells: five of those in the Utica and 135 in the Wattenberg.

We will continue to focus on cash flow neutrality and our balance sheet strength. And the Company will continue to push the series of technical enhancements both in Utica and Wattenberg. These include our longer laterals, completion modifications, our mono-bore drilling and the evaluation of our downspacing projects.

So in closing, I would like to thank many of you for your attendance at our recent analyst day. Hopefully, we achieved our goal of providing additional clarity around our operating plan and technical enhancements and we continue to earn your confidence in our strategic business plan.

Last, I would like to thank Gysle for his dedication and efforts the last eight years. This is most likely his last Q call, and we wish him well in retirement.

At this time, I would like to turn the call to him for a financial update.

Thanks, Bart. And good morning, everyone. Thanks for joining us this morning. I will make a few high-level comments. And, as I always mention, please see our first-quarter Q and press release that was filed this morning for a more detailed analysis of the quarter.

We started 2016 as expected: with lots of late-quarter activity in Wattenberg. The five wells we are drilling in Utica have progressed very smoothly, and we recently released the rig. Total Company-wide production for the first quarter was 4.6 million barrels of oil equivalent, or 50,216 barrels of oil per day, as Bart noted. That is up from 2.9 million barrels of oil equivalent, or 32,162 barrels of oil per day, in the first quarter last year.

Our first quarter reflects our continued success in the Wattenberg drilling program, where we turned in line a record 47 wells in the quarter. Most of these, however, were later in March, so less impactful in the first quarter but positive for second-quarter production. Scott will discuss production in greater detail shortly.

Despite a further decline in commodity prices, we still saw growth year over year in adjusted cash flow from operations. Aided by our hedge position of $66.8 million realized hedge gains in the first quarter. Now I will get into some of the metrics in the first quarter.

Although year-over-year production increased almost 60%, our first-quarter oil and gas sales were up only slightly to $75.4 million, compared to $74.1 million in the first quarter of 2015. Oil, natural gas and NGL prices all declined year over year. Crude oil prices net of differentials in the first quarter of 2016 averaged $28.29, down 29% from $39.82 in the first quarter of 2015.

Average natural gas prices were down 43% from the first quarter of 2015 and net NGL prices were down 42%.

The $66.8 million net realized hedge gains in the first quarter compares to a net realized hedge gain of $50.4 million in the first quarter 2015. Sales plus realized hedges were up approximately 14% this quarter over the first quarter last year.

Production costs on a per-unit measure were down about 45% year over year. Production costs include lease operating expense, production taxes, and transportation gathering and processing costs. For the first quarter 2016, we averaged $5.13 per barrel of oil equivalent, down from $7.43 per BOE compared to the same quarter last year. Scott will talk a little more about lifting costs in a few minutes.

DD&A included depreciation of fixed assets and depletion of oil and gas properties. The increase year over year is due primarily to the increase in production but also to a slight increase in the overall DD&A rates year over year. Per-unit depletion rates on adjusted oil and gas properties for the first quarter 2016 were $21.08 per barrel of oil equivalent, compared to $18.92 per BOE for the first quarter last year. We expect the current DD&A rate will decrease as the year progresses.

G&A increased slightly over the first quarter of 2016 compared to the first quarter last year. However, G&A on a per-unit basis decreased 31% to $4.99 in the first quarter from $7.20 in the first quarter last year.

Adjusted net loss, which is a non-GAAP metric in the first quarter, was $37 million, compared to adjusted net income of $7 million in the same period 2015. We recorded a $44.7 million reserve in the quarter related to a seller's note that we received when we sold our dry gas Marcellus interest in October 2014.

The standard for reserving a receivable that's in collection is not reasonably assured under current market conditions. There is still a chance that conditions improve and payment could occur; just no assurance at this time. Excluding the allowance and its tax effect, we would have an adjusted net loss of $9.3 million in the quarter.

Adjusted cash flow from operations is defined as cash flow from operations excluding changes in working capital. As Bart mentioned, adjusted cash flow for the first quarter was $91 million, or $2.19 per diluted share, compared to $74 million, or $2 per diluted share, in the first quarter last year.

Adjusted EBITDA in the current quarter is $53 million, down significantly compared to $82 million in the first quarter of 2015 as a result of the $44.7 million reserve on the note. And that back, and the current-quarter numbers would be $98 million. Adjusted (inaudible) quarter, which was also impacted by the reserve, was $1.27. That translates to $2.35 if you add back the reserve that I mentioned just a moment ago, and that's compared to $2.23 in the first quarter 2015.

With respect to liquidity, we are in the middle of our spring bank redetermination. As Bart mentioned, we have confidence in our solid reserve additions, but we realize there is currently a lot of conservatism in the energy lending sector. That said, we do not expect a material change in our borrowing base or commitment level as a result of the determination. We expect to know the outcome next week.

For the purposes of the table on the slide showing PDC's borrowings, we assume a $700 million revolver and a $450 million commitment level from our fall 2015 redetermination.

We began 2016 $37 million drawn on the revolver. In March, we completed the equity offering that Bart mentioned for approximately 6 million shares and net proceeds of just under $300 million.

We retired the debt on the revolver as of March 31 and had a cash balance of $239 million. With cash and a $700 million borrowing base net of a $12 million letter of credit, we have $927 million of liquidity at quarter-end. Our 3.25 convertible notes are maturing in 10 days, so $150 million of our cash would be used to settle the principal balance of the notes.

Finally, our hedge summary includes hedges on the books as of April 15. We rolled off the first-quarter hedges for 2016, so the 4 million barrels and the 24.5 BCF reflect our hedge volumes over the next three quarters of 2016.

What is not shown here are some gas hedges for 2016 and 2017 and some oil hedges for 2018 that we added this week. Our normal practice is to add small increments and hedges when we hit certain price targets, so none of the new hedges are material individually or in the aggregate.

We are still well-hedged for the balance of 2016, with about 61% of our expected crude oil volumes hedged at a weighted average floor price of $73.92 per barrel. We have over 65% of expected gas volumes protected at a weighted average floor of $3.52 per MMBtu.

Besides what we added this week, we added some oil hedges for 2017 and 2018 during the recent run-up in prices that are included on this table. The new hedges were cost as callers with floors at $40 or above. For 2017, we have 4.5 million barrels hedged at a weighted average floor of $46.33 per barrel. We have about 33 BCF of natural gas hedged in 2017 at a weighted average floor of $3.50 per MMBtu. We have some good hedge volumes on the natural gas side for 2018 and have a closer to 1.8 million barrels of oil hedged in 2018 after this week's adds.

Now I will turn it over to Scott for a discussion of our operations.

Thank you, Gysle, and good morning, everyone. It will be a pretty brief update on my end, as we went through a really deep dive about a month ago at our analyst day here in Denver. That presentation is available on our website, and I really encourage you to use it as a resource throughout the year or to take a look at it if you are unfamiliar with the PDC story.

As both Bart and Gysle mentioned, we are very pleased with the way our team executed the first quarter. Production averaged just over 50,000 barrels of oil equivalent per day, which was slightly above our internal expectations despite the late-March snowstorm that Bart mentioned. That amounts to essentially two days worth of production impact.

On slide 12, you can see several highlights of our first quarter. Our commodity mix was right in line with our expectations at 42% oil and 61% liquids. As we stated at analyst day, we expect full-year oil to be between 40% and 42% as we turn in line a number of higher GOR intercore wells this year.

Sequentially, our production decreased slightly compared to the first quarter of 2015 due to the previously mentioned late-March snowstorm and the timing of our turn-in lines. Our turn-in lines were heavily weighted to the beginning of the fourth quarter and the end of the first quarter. On that note, we turned in line a Company record 34 horizontal operated wells in the month of March alone.

Our LOE continues to trend in the right direction, and our first-quarter LOE per BOE came in almost exactly at the midpoint of our full-year 2016 guidance given at our recent analyst day.

Taking a closer look at our turn-in line activity here on slide 13, you can see a breakdown of not only the first quarter but our expectations throughout the remainder of the year. I would like to point out that nearly half of our full-year 2016 SRL turn-in lines were completed in the first quarter. This means that for the remainder of the year, we will be heavily weighted toward the longer lateral MRL and XRL wells. Our longer lateral wells are the larger producers and have shallower declines than our SRL wells.

The last comment on this slide relates to the Utica drilling. As you can see, we have released our one rig in the Utica as we had finished drilling operations on all five planned wells and are now in the completion phase. The program has been doing a little better than expected in terms of both cost and timing.

Next, on slide 14, you can see the breakdown of our capital program. Our first-quarter CapEx came in better than expected primarily for two reasons. We had some miscellaneous Wattenberg charges that came in less than anticipated, and we shifted the net well completion in the Utica to the second quarter in order to not only keep that completion crew running continuously, but hopefully dodge any early spring and cold weather back east. To date, we are probably tracking a little below the midpoint of our full-year capital guidance of $425 million. However, our annual guidance remains the same.

Next, we have a popular slide from our analyst day that brings into focus the returns of our Wattenberg program at various prices in lateral lengths. I think this is a very important slide to continue showing and to really hammer home the quality of our projects, and to reiterate that our decision to drill in the Wattenberg continues to be based solely on internal rates of return and economics. You can see at the bottom-right of that page that our SRLs, MRLs and XRLs are all comparable in terms of F&D internal rate of return and PD10.

The last thing I will point out is that we project a strong 33% to 37% internal rate of return based on the NYMEX price forecast highlighted in the middle set of bars. With the recent running commodity prices, we believe our returns are starting to move towards the higher internal rates of return on the right side of these bars.

The important thing to drive home here is, again, our drilling decisions and program are based on delivering strong rates of return, which, as you can see, we are able to do at current pricing.

Shifting over to the Utica on slide 16, you can see here a snapshot of our 2016 program. As I mentioned earlier, we recently released our rig, as the drilling has been completed on all five wells for the year. Our team continues to reduce drill times as we work toward more efficient operations and improving economics. Currently, we are finished fracking the Neff well, which is a 10,000-foot lateral well. The results from this well will be compared to our more typical 6,000-foot laterals. We expect the Neff and the two Mason wells to be turned in line in the third quarter, with the two-well Miley pad being turned in line in the fourth quarter.

Lastly, our overview slide gives some of the more granular details such as Niobrara versus Codell and horizontal versus vertical production that I will let you get into on your own.

With that, I will turn the call back over to the moderator for the Q&A.

(Operator Instructions) Irene Haas, Wunderlich.

Quickly, the uncollectible notes, what was the timeline once you first found out about that? And any hope for collecting eventually?

Hi, Irene. This is Gysle. As I mentioned, the standard for reserving is based on current conditions. And you can't -- when you run out the reserves at current gas strip, it doesn't leave much room for any excess cash as you look at it today.

So the answer is, yes, there is opportunity. If prices increase greater than what the strip is over the next four years, that note could be collected. It's a bullet note, so there's no principal payments until maturity. And interest is paid-in-kind interest. So there is no default on the note. And if you have faith in gas prices, which I think it wouldn't take much to get it up above the current strip to make this thing at least partially realizable that far out in the future. It's kind of a long-winded answer, but it's a strong maybe. How's that?

Okay, that's good. Thank you.

Neal Dingmann, SunTrust.

Bart, can I ask you kind of a typical question? Obviously with oil trending up, how do you all think about increased activity? I know you addressed this at the analyst day. But is it -- do you think more about if you are able to hedge around that, further out you would potentially add some more? How do you all think about expanding the rig count?

Neal, right now I think the answer is we are very content in our four-rig plan in Wattenberg. We continue to watch our drilling efficiencies. We feel like we have some upside on drilling pace from those as we go through the year. So I think it would -- most likely, we will not be adding additional rigs in the Wattenberg. We are not in a position right now in the Utica to drill any more wells. That would be a 2017 decision. So, overall, I think the market can expect us to continue with our current rig pace.

Okay. And then just one last one. Gysle, I just want to say congratulations on the retirement. And just a quick one for you, Gysle. Kind of on Irene's question on that, is that payment -- is that just based on what conditions -- is it not based -- because, again, it doesn't appear to me that that counterparty has missed a payment in the past. And how does that vary? Is it more just on what they generate or their ability to pay it?

It's on their ability to pay in the future. As I mentioned, there is no opportunity to a missed payment if you are paying interest in kind. So the time -- the collection day will be when the note matures, and there will be no changing of -- no movement of cash prior to that.

Got it. Thank you all. And congratulations again, Gysle.

Brad Carpenter, Cantor Fitzgerald.

Gysle, I would also like to add my congratulations on a great career and your retirement. I guess if we'd start just on the late-March weather impact, was there any carryover into April? Or were things back up and humming as we entered the second quarter?

This is Scott. And really we saw that to be a very short impact. What happened is the heavy snows hit the power lines out there and took out the power for our midstream providers and left us -- all of us with that issue. They recovered as quickly as the power company allowed, and I think it was four or five days total. And as I said, that didn't take down every one of their facilities but equated to about two days worth of production impact for the quarter.

Okay, got you. Thanks. And then after the follow-on offering this March, you got a nice sort of cash on your balance sheet and even more dry powder when the borrowing base is included. Outside of the note maturing here in a few days, how are you thinking about the priorities for cash usage? Or in this environment, is simply staying on the balance sheet as dry powder your top priority?

The second. The strength of the balance sheet as we go forward, executing our capital programs and, as I noted in my comments, really focusing on trying to be cash flow neutral as we go through the balance of the year. It won't stop Lance and his team from, as we've noted, continuing to look at projects that we find incredibly -- we will be very selective in that process, very finicky in that process. But right now, again, it's the strength of the balance sheet.

Okay, great, I appreciate it. And congrats again, Gysle.

Welles Fitzpatrick, Johnson Rice.

I hate to be the guy to bring it up, but can we talk a little bit about the ballot initiatives? Does the recent Colorado Supreme Court decision in the industry's favor, does that help at all? I know those are independent processes, but is there anything to update on that?

Yes, and I don't know if they are 100% independent. Obviously, the recent ruling is reflective of the state's rights in regulating versus local communities. And the ballot initiative right now, there's four of them, Welles. Again, there's a setback. And bear with me here; I am going off memory. There's a setback. There's a local control, which ties back to the local communities having more authority. There's a right to a clean environment. And then there's the rights of communities to ban any business, which the last seems really silly to us.

But, overall, the opposition right now is in the signature-gathering phase. We don't know where this is going as we go towards August 8. August 8 is the final day. The signatures have to be presented to the state, and that will be the point we determine whether there are any ballot initiatives.

And the only thing that I can say is that the industry continues with their campaign, continues with the promotion of the benefit -- the safety aspects and the economic benefits. It's an aggressive campaign. It will intensify if these ballots end up being on the ballot in November. And we have confidence. The industry is unified in this. It is funded. And, like I said, it's going to be an intense campaign if they end up going to the voters.

So hopefully I answered your question. And, again, we obviously were very pleased with the ruling here this last week.

No, that's perfect. I appreciate all the detail. Thank you all.

Ipsit Mohanty, GMP Securities.

My first question on slide 15, when I look at those tight curves as far as MRL and XRL, seems like SRL and MRL are controlled and bought back at the same rate, but not XRL. Could you just comment on the difference in the procedure of how you bring them and probably that's what feeds into the IRRs and PD10s?

I do what I -- I will give it the best shot I can here, Ipsit. I guess when we look at -- first of all, keep in mind that the SRLs and the MRLs are based more on our data then in our peer companies' data. So when you see that, we feel like those numbers are more accurate where we choke our wells back early in the life of the wells, and thus the IP's are very similar. And then what we see on those little reach laterals is that shallower decline.

When you move to the XRLs, you are looking at something that is much more based on projecting off of our peers' data. And we don't have as good a support for that. So I would say at this point we really have made that adjusted on our extended-reach laterals more based on what we see offsetting us. As we get more data, I would suspect that we will see that XRL start looking early time more like the other two. But then we will see a much shallower decline on those than we've seen on either of the other two.

So I really think that's what we are faced with right now. It's because we just have drilled our first XRLs. We haven't fracked any of them yet, so we really don't have any data on our own on those.

Okay. Fair enough. And then just a broader question on your thoughts on the recent synergy acquisition and just M&A in general in the basin. Given that officially the synergy, the novel leasehold, kind of sat in between your middle core? So if you could just talk about what you thought.

Yes, let me start and Lance can jump in here. We obviously keep our eye on the market, and congratulations with both companies on the deal. We recognize the acreage that was transacted and intertwines very closely with PDC's northern middle core acreage.

And, Ipsit, as far as any comments, I just think it's additional data to support the quality based on the dollars transacted and the acreage. And it just supports the quality of the core Wattenberg position. Hopefully, it's additional data for the market to say, hey, this is very real, and it's one of the leading unconventional plays in the country. So we think it is support for that and it's support for the quality of our position.

And Lance, if you want to add anything to that.

No, I think that covered it pretty well, Bart. And it's a good summary of the opportunity there between the two companies.

Bart and Lance, do you think it's the start of -- maybe it's a start of the bigger guys like Canada can also -- sort of loosening some of the acreage, or do you think it's just a one-off?

Ipsit, I can't comment if it's a start of something bigger here. I think it was opportunistic for both of these companies. And where all the companies are going next, it would be hard for me to comment.

Got you. Thank you.

Mike Scialla, Stifel.

Lance, you mentioned you have been adding some hedges here. Just wanted to see your appetite for adding more. Is there a limit? And then also the differential -- oil differentials come in a little bit. I'm wondering if you can lock that in or if you have any desire to lock that in here.

Well, let me -- Mike, let me start with the second part of the question on the hedges. I will turn that back to Gysle.

We have been very pleased with the incremental contracts we've been signing for our crude oil. And when we talk about differentials, we are talking from NYMEX all the way back to the wellheads. So it's all-inclusive of fees, marketing, et cetera. And the recent incremental deals we have been signing continue to get better.

So we like what we are seeing. One of the tasks that we have for our -- for George Courcier here and our marketing teams is to determine at what point in time do we want to start considering locking in for the longer term. And there's a lot of factors that go into that. And it's based upon what do we see the takeaway volumes of the basin looking like over the next several quarters versus production volumes from the field.

And what we are seeing is that additional pipeline takeaway capacity coming into the basin that will -- in the fullness, this latest pipeline coming in towards the fourth quarter 2016 that will have substantial amount of takeaway capacity.

So we want to continue to watch and monitor. When we see that we think we've got the right sort of timing, we will start to potentially thinking about layering in some longer-term differentials out of the basin.

Yes, Mike, on the hedges, we absolutely have an appetite for more. Our philosophy has not changed. We will look for opportunities when prices have spiked to add small layers over time. We have what I will call our safety hedges in place for 2017, and we are very, very close to 2018. I would call -- I would say we are there based on the volume and the floor -- the price of the floor that we have in place. Meaning that if prices stay very depressed for a long period of time, we are okay.

So we are in the mode now of watching the market and adding small layers as prices run up and just increasing the hedge coverage in small increments for 2017 and 2018. And we will probably start looking at 2019 towards the end of the year.

Thanks for that, Gysle. And I just wanted to ask a general question on the play of -- it seems like a lot of these plays, we found out that the wellbore orientation doesn't matter all that much. But starting to get the sense that maybe in this play, at least part of the play, it does. Any commentary there?

Mike, I will give you our view on that. And I think it's -- our first impression was it didn't really matter. We looked at a variety of wells, different directions, and it really looked to us like you could drill them in either direction. I would think the more we see the data and you move to the northwest flanker, I would just say may be even the northwest part of the field, around really north of there or west of there, you start to see that that orientation may need to be east-west. And we have got wells both directions. We've got some of our peer companies that have drilled both directions. But the more we see that data, the more we like what we see going east-west over north-south. And it's got to be the rock stress that we are dealing with out there that is pushing us. I think we are finding that it's more influential than what we thought originally.

Thanks, Scott. And Gysle, congratulations as well on your retirement.

Thank you, Mike.

David Tameron, Wells Fargo.

One more congrats, Gysle. Best of luck. Can you guys talk about -- I guess you talked a little bit at the analyst day, but service costs, Bart, what do you expect to -- or efficiency is maybe the better way to put it. What do you expect to keep or retain even if commodity prices go back to [$55], [$60]? How much of the gains do you think you'll maintain?

David, this is Scott. And I guess when we look at this overall -- and I showed that graph at analyst day where you showed a fairly close correlation with the costs and the price of the oil -- the price of oil. What we see on the efficiency side, particularly on the drilling side, we are seeing these days continue to come off. And that part of it, we believe, will stay as things pick back up again. And we are really not looking at the price as much probably as we are the rig count. Is what is going to drive obviously that supply-demand equation to come to the point where the service companies will be looking for a lift in their revenue streams.

But it really is -- in overall terms, it's the drilling side that's been most of that. The cost reductions on the other side -- on the completion side are really mostly associated with the reduction in service costs.

I will say that we are still getting more efficient there as well as we -- instead of hauling water or piping water, Lance's team has got us moving oil via pipeline now. Those kinds of things all help us, and that's efficiency that comes -- part of that on the operating expense side; but some of it, the water particularly, on the capital side.

So do you keep half of it, you think? Or care to give me a number?

That's hard for me to say. I think that might be a little long. I don't think we would say that quite that much. It depends on what your perspective is on what you are gaining back. But I don't think you keep half of the overall cost reductions. Again, assuming that you run back up to $100 per barrel for oil.

Okay, okay. And then second question is more general in nature. But as I think about downtime in the field, one thing obviously we've seen is as -- not downtime midstream-wise but downtime on the op side. One thing we've seen in all these plays is everybody is ratcheted back. It's just less downtime. And I'm sure that's better crews, but also probably less wells being shut in, as well as good fracks, et cetera.

Can you talk about -- have you seen that impact? And I know you guys' rig count hasn't moved. But obviously the basin rig count has come way down. Have you seen that impact at all in the field? Has that helped?

It really has, David. I think when we are -- when we are talking about our execution in the field, it is much cleaner. The operations -- the guys have the services they need really when they need them. And that is part of having excess capacity in the service industry. I think we are benefiting from that right now. And as things pick back up, that's part of what you will lose in the efficiency process. It's -- when you need a water truck, the water truck is there and ready to go. When you need the rigs moved, they move immediately versus the times there were delays associated with that. So all those things help in our efficiency.

Okay, appreciate it. Thanks, guys.

Michael Hall, Heikkinen Energy.

I will focus a little bit on the efficiency again as well. I'm just curious -- I believe you all have budgeted about seven days spud to release on the monobores for your drilling times this year. Correct me if I'm wrong on that first. But we've heard of some operators being able to deliver even quite a bit below that -- sub two days, even. As you spend more and more time at the monobore, I'm just curious what your outlook is for reducing drilling days even further and what your thought process is for deploying capital relative to potentially drilling more wells during the year. Would you bring those wells on or just put them in a backlog? Or how do you think about that?

I'll start with the discussion on rig pace and see if we can explain where we are at there. I think when we start talking about seven days, that's from spud to spud. We include all the down time, all the moves, everything involved. And when you start hearing two days out, assume that's a different measurement than it's probably spud to rig release, or there is a variety of different numbers -- spud to TD. I really don't know.

But the idea that seven days is the bottom of where we can get is probably not the case. But I don't see there being as much movement as that as in the other -- the longer laterals, where we are at 11 and 14 days.

We see the -- those longer laterals with more room to move. And I think that's fairly obvious when you even do the math of those medium-reach and extended-reach laterals relative to the standard lateral time.

If you look at where we are in the process, we have converted all of our wells at this point over to monobores, even our two-mile laterals. We are at this point drilling on monobores. It is definitely saving a day or two, and that kind of number is what I think we are holding to.

As far as where we can go, I think, like I said, that standard-reach lateral is one of -- maybe there's -- and this is a stretch at this point. Maybe there's another day in there beyond that. And when we list that, we say six to eight days and shoot for that middle point. There's another day in there. On the other laterals, there is more room to move.

In terms of what does that mean for the spin to the year, obviously if those wells get drilled faster -- which, like I said, we are expecting some of that -- we will be looking at our capital spend. And I think we will still be very focused on maintaining that cash flow neutrality. And we will have that discussion as we see those numbers start to roll in.

So I guess that's the best answer I can get. That two days seems really short to me from spud to spud, but I don't know the measurements that you are seeing out there.

Yes, that makes sense. Maybe it's more spud to TD versus spud to spud. That's a fair comment. And then on -- and that's helpful color as well. Thank you. Then on the -- I'm just curious, on the timing of completions in the quarter, was that as expected or not in terms of the heavy weighting towards March (technical difficulty) this quarter?

Probably a little bit of delay in there. Some of that is the way we group our wells and the way our teams do that such that we are not fracking next two wells that are already producing. And it's a very logistical -- long-term logistical project. Project as far as the predicting of how -- when you get all of the drilling done and when you get those completions done, our teams do a phenomenal job of keeping that all together. But there are times when that gets -- there is a little bit of delay in the system. And a little bit of a delay can mean some -- obviously, some fairly significant issues when you start completion. So I would say we were close but probably just a little bit behind.

Okay. Fair enough. Appreciate the time. Thanks, guys.

(Operator Instructions) Eli Kantor, IBERIA Capital.

Question on the borrowing base. Most of your peers this spring have reported anywhere from a 5% to a 30% reduction. Can you talk about the driver behind the reaffirmation? I assume most of it was related to the reserve growth. What price deck the banks used, any preliminary thoughts for this fall?

Yes, this is Gysle. The banks use various price decks, so I can't nail one down for you. At least our bank group does. And the driver primarily for us is the reserve adds from the fall. So -- and obviously prices in the spring are lower than they are in the fall. And I think it's more weighted towards the front end of the bank strip, meaning the first four years, as opposed to the back end of the bank strip. So the dynamic is with these horizontal wells, the new wells come off pretty quickly, so you get value upfront. And then it diminishes.

So it's a lot -- the pricing aspect of it has a lot to do with it. And the lead bank has a lot to do with it when you compare one company to another. But, again, the main driver for our comfort to where we are now is the reserve adds.

And Eli, this is Bart. Just to confirm, we don't have final reaffirmation of the bank line. That will happen next week. My comments and Gysle's comments were based on all the data we have and some communications with the bank. We don't expect a material change in our bank line.

One question on the acquisition front. It looks like your Midland basin peers had a lot of success selling equity to finance acquisitions that are priced below where their stock trades on a dollar-per-acre basis. It looks like you are in a similar position with respect to this most recent DJ Basin transaction.

Two questions. One, did you look at or make a bid on the assets that Noble sold? And are there other opportunities where you could essentially bootstrap an acquisition with your premium currency?

Yes, Eli, this is Lance. As far as any discussions around the Noble synergy deal, we are not going to comment really on which deals we look at and which deals we don't look at. So, no data from that front.

As far as our level of interest inside what we call the core area, the answer is yes. We are interested in those types of positions inside the core area that we focus on that can drive additional value for the Company going forward. And we outlined during analyst day some of the key criteria we look at in any acquisition. But deals that we would look like -- look at in the core Wattenberg are deals that we like.

It's just -- when you look at the greater DJ Basin, that was the areas that we've talked about also at analyst day that we have really less focus on and really no focus on outside of what we call the core area.

And Eli, to your question of would we use paper in a transaction, we really can't sit here and map how we would fund the transaction. So many factors that go into that -- the production mix of the transaction, the development schedule of the asset, obviously the size of asset, whether the seller was interested in our paper. So it would be very hard for us to map any type of path on that decision.

It is probably fair to say we're not opposed to it.

I think that's -- I agree with that, Gysle.

Thanks, guys.

[Stark Reny], RBC.

I just had one quick question, if you guys can follow up on any developments you have had on the Reader pad. If I recall from the analyst day, it kind of indicated that there was slightly steeper-than-expected declines in the last week or so of production. Just curious if you had any updates there.

Really don't. I think what we want to see there is about six more months of data. The short-term movements in those wells -- there's everything from production issues -- and I think that I asked the team about that after looking at that in greater detail. There was -- they were managing paraffin issues in those wells. And so they brought plungers, and that slows things down a little bit. So we need to give them a little more time, I think, is the best way to look at that and make sure we have adequate data to have any further judgment. I

I think that our view of that is still the same. Obviously if it stays between that middle and outer core line, we're going to be very pleased with that. There's a lot of questions we will be asking ourselves then in terms of how we manage our well counts, that kind of thing.

And at the same time, if it continues to taper down toward that outer core line, we will be looking at that and looking at the value versus the volume recovered or covered there and try to figure out what is the best mix in terms of wells and how we place them within the ABC Codell L benches and how that all shakes out. So I really think we are going to looking about six more months of data.

Okay, excellent. Thank you.

I am showing no further questions at this time. I would now like to turn the conference back to President and CEO Bart Brookman.

Thank you, James, and thank you, everyone. Thank you for joining the first-quarter call and your ongoing support in the Company. With that, we're done. Thanks.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day. You may all disconnect.