Callon Petroleum Co (CPE) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2013 Callon Petroleum Earnings Conference Call. My name is Phillip, and I'll be your operator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Fred Callon, Chairman, Chief Executive Officer. Please proceed, sir.

Good morning, or good afternoon, I should say. Thank you for taking time to call into our fourth quarter 2013 results conference call. Before we begin, I'd like to ask Joe Gatto to make a few comments. Joe?

Thank you, Fred.

At this point, I'd like to remind everyone that this conference call contains forward-looking statements, which may include statements regarding our reserves, as well as statements including the words believe, expect, plan, and words of similar meaning. These projections and statements reflect the Company's current views with respect to future events and financial performance. Actual results could differ materially from those projected as a result of certain factors.

Some of these factors are discussed in our filings with the Securities and Exchange Commission, including our 2013 annual report on Form 10-K, available on our website and the SEC's website. We may also discuss non-GAAP financial measures, such as discretionary cash flow, PB10 measure, and adjusted net income. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our fourth quarter and full year 2013 results news release, and in our filings with the SEC, both of which are available on our website.

Fred, I'll turn it back to you.

Thank you, Joe, and congratulations to Joe. As most of you know, yesterday, we announced that Joe will become Chief Financial Officer and Treasurer at the end of this month. Again, as most of you know, Joe served as the Company's Senior Vice President of Corporate Finance for the last two years, responsible for the Company's capital markets, strategic planning, business development, and investor relations activities. Prior to joining Callon, Joe spent almost 20 years in the energy investment banking, commodities business as a Managing Director with both Merrill Lynch and Barclay's Capital.

Although he will be stepping down from the Board in May, Bob Weatherly will continue to serve as Corporate Secretary and Chief Administrative Officer. Bob has been on the Board since we went public in 1994, and stepped in as CFO in 2006. I cannot thank Bob enough for his leadership on the Board and as CFO in helping the Company with its transition to a pure play onshore operator in the Permian Basin, with great properties and a top performing operations team.

We are also very fortunate to have two outstanding new Directors joining the Board, Matt Bob, Managing Member of MB Exploration, and Jim Trimble, Chief Executive Officer and President of PVC Energy. Matt and Jim both bring a tremendous amount of industry experience to the Board. We look forward to working with them.

Now turning to a Company update, and start with a review of our recent announcements about our progress on the operation side, as well as some important financing initiatives that we've recently completed. In our operations update released last month, we with highlighted several important data points from our Permian operations, including the addition of almost 10 million-barrels of oil equivalent of proved reserves in 2013 at a finding and development cost of approximately $15 per BOE. This figure includes the cost of infrastructure, which we will be able to leverage as part of our development of multiple zones going forward.

We also provided production guidance for 2014 that translates into 120% increase over 2013 volumes in the Permian. It reaffirmed our exit rate target of 5,750-barrels of oil equivalent per day for 2014, with oil forecasted to account for approximately 80% of our production stream. While the majority of our drilling activity this year will be focused on the upper and lower Wolfcamp B and four core fields with pad development, we will also be drilling the Wolfcamp A and lower Spraberry to further delineate these intervals, and also establish the development of multiple zones from the same pad.

In addition to initiatives to expand our inventory of potential location through down spacing and testing of new zones, we continue to pursue complimentary acreage and producing asset acquisitions. On this front, we recently completed the acquisition of an acreage package near East Bloxom Field, adding 1,280 net acres at a cost of approximately $5,500 per acre. We see the opportunity to target at least four zones in these Upton County properties, and estimate the acquisition added 35 locations to our inventory of potential horizontal wells just from the Wolfcamp zones alone.

We also made significant progress on our strategy to recapitalize the Company following our onshore transition, adding to our balance sheet strength, and lowering our cost to capital. On this front, we recently announced the closing of our new $500 million borrowing base facility, with a reduced pricing grid, and an expanded lender group of 10 banks.

At the same, time we entered into a term loan agreement that we'll initially use to redeem all of our outstanding senior notes and draw upon in the future to support our capital program and other growth initiatives. This is certainly an important step from a financing standpoint, and we're encouraged by the strong support from both our new and existing lenders.

I will now turn the call over to Gary Newberry, our Senior Vice President of Operations for an update on our recent activity in the Permian. Gary?

Thanks, Fred, and good afternoon to, everybody. With the operations update provided last month, my comments will be somewhat limited on this call, and we will be providing additional information on the first quarter call in early May.

I'd like to start out by saying we were very pleased with our defeating 2013 exit rate goal of 3,500-barrel of oil equivalent per day in the month of December, despite some pretty heavy headwinds caused by some tough weather during the month. These production levels provide the foundation for a strong start to 2014, and continued production growth this year from our two rig horizontal program.

Looking forward, our pad development initiatives, which were recently expanded to four fields, have now transitioned into a true manufacturing mode, following the infrastructure development and lessons learned over the past year. We have established a repeatable baseline of drilling execution and well performance, and we will be working on optimization initiatives in the coming months.

One of the bigger initiatives we will be testing is the impact of pumping larger proppant volumes during fracture stimulation. While this will add some incremental costs to our completion designs, we are encouraged with the impact these larger completions are having on recent wells during early time performance, and we will continue to analyze overall returns on capital before implementing as part of our standard procedures.

In terms of an activity update, we have brought four horizontal wells online in the first quarter so far, and are currently in various stages of completing five additional wells, as well as drilling five additional wells. Starting at East Bloxom, the Neal 652 had a 24 hour peak rate of 1,395-barrels oil equivalent per day, and a 26 day average rate of 1,013-barrels oil equivalent per day through March 10th, after putting the well on submersible pump.

An additional well on this pad, the Neal 653, has just been placed on gas lift after flowing under natural pressure since mid January. Both of these wells were completed in the upper Wolfcamp B, with lateral lengths of approximately 8,500 feet. In terms of new wells, we are currently completing three additional wells in the field, including a Wolfcamp A and two upper Wolfcamp B wells, which were drilled from the same pad.

At Garrison Draw, we are in the process of drilling out plugs in two lower Wolfcamp B wells, with average lateral lengths of approximately 8,250 feet. As part of our ongoing completion optimization efforts that I discussed earlier, we pumped a larger volume of proppant per stage in these two wells versus our first horizontal well in this field, which had a 24 hour peak rate of 991-barrels oil equivalent per day for a lateral length of approximately 4,600 feet. These two wells are expected to be placed on production later this month.

Rounding out our recent Southern Midland Horizontal Program activity, we are drilling a three well pad at Taylor Draw in Regan County, with one well targeting the lower Wolfcamp B and two wells targeting the upper Wolfcamp B.

I will now turn to the Central Midland Basin and our Carpe Diem field, where we brought two Wolfcamp B wells on production in early February. These wells produced under natural pressure since that time, with each demonstrating a production rate of over 800 barrels oil equivalent per day. They are now in the process of being put on artificial lift, which we believe will lead to higher initial production rates in the coming days.

We are encouraged with these early results, and will be providing updates on this new core horizontal development area as the year progresses, including two Wolfcamp B wells that are currently in the process of being drilled.

I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO.

Thanks, Gary.

Our net income for the quarter was $1.3 million or $0.03 per diluted share. This figure included a net pre-tax amount of $2.1 million related to a gain on retirement of debt post closing of the sale of our remaining Gulf of Mexico properties, an impairment reserve related to legacy offshore equipment, and non-cash unsettled hedging gains. Excluding these items and the related income tax effect, adjusted net Income was essentially breakeven.

Operating revenues for the three months ended December 31, 2013 included oil and natural gas sales of $26.5 million, from average production of 3,848-barrels equivalent per day. These results include approximately one month of contribution from our Medusa Field, and two months of production from our shelf properties. Excluding these assets and our Swan Lake field, which was also divested in the fourth quarter, our Permian only production was 2,978-barrels equivalent per day through the fourth quarter of 2013, compared to 2,457-barrels equivalent per day in the third quarter of 2013, a sequential increase of 21%.

Our average realized oil price for the quarter was $93.38 per barrel, and for the full year was $97.65 per barrel. Our average realized natural gas price for the fourth quarter was $5.03 per Mcf, and for the full year $4.52 per Mcf.

I will now move to expenses, and begin with one housekeeping item. Starting this past quarter, we have reclassified ad valorem taxes out of LOE and into production taxes. As you will see in our press release and the 10-K filing, this presentation of expenses has been conformed for all prior reporting periods. We believe this will enhance comparability with our peers in the sector.

In terms of results, all of our line item expenses were within previously provided guidance for the year. Our total LOE for the quarter including workovers was $11.33 per barrel for the total Company, and $12.96 per barrel for the Permian. Compared to the third quarter of 2013, Permian LOE including workovers decreased 11% for a sequential BOE basis, primarily due to an increased level of horizontal production. Excluding workovers, Permian LOE was $8.59 per BOE in the fourth quarter of 2013, representing a sequential decrease of 16% compared to the third quarter of 2013.

Total general and administrative expenses, net of amounts capitalized, increased $2 million from the fourth quarter of 2012 to $6.4 million in the fourth quarter. However, on a cash basis, our G&A expense decreased by $700,000 between these two periods with an offsetting increase of [2.7%] primarily attributable to non-cash expenses and the mark-to-market valuation of our share-based incentive programs.

On an annual basis, 2013 total G&A expense was essentially flat with 2012, while the cash component of G&A expense decreased by $1.6 million. The offsetting increase was related to the previously described non-cash impacts related to our share-based incentive programs.

Discretionary cash flow for the three months ended December 31, 2013 totaled $15.8 million, and net cash flow provided by operating activities as defined by US GAAP was $19.1 million for the quarter. In addition, EBITDA for the fourth quarter was $18.5 million.

Our total capital expenditures for the quarter were $59 million on a cash basis, with 91% of these expenditures directed to drilling and completions. These expenditures included nine wells drilled in the fourth quarter, versus five wells drilled in the third quarter, and eight wells completed in the fourth quarter, versus seven wells completed in the third quarter, as drilling activity with our two rig program increased after starting in the third quarter. For the year, our total operational capital were $160 million on a cash basis, excluding acquisitions.

As Fred noted, we recently closed on two important financing transactions that have bolstered our liquidity and reduced our cost of capital. Our first borrowing base redetermination under our amended revolving credit facility will be based on May 31, 2014 reserves, providing the opportunity for a near term increase in the borrowing base following the recent increase to $95 million for the borrowing base, based on year-end 2013 reserves.

In terms of hedging, we currently have approximately 45% of our forecasted 2014 oil production, and 34% of our 2014 forecasted natural gas production hedged under swap agreements. Under our amended credit facility, we have expanded hedging capability, and we will look to add to our hedge positions in the coming months.

On a final note, our previously provided guidance for the first quarter of 2014 and the full year of 2014 remain unchanged. Now we'll turn the call back to Fred for a few final comments.

Thank you, Bob. Again, we appreciate everyone taking time to call in. And now, we'll open the call to questions.

(Operator Instructions)

Your first question comes from the line of Will Green from Stephens. Please proceed.

Good afternoon, guys.

Hi, Will.

So I think you guys had previously talked about averaging about 3,600-barrels a day in December. It sounds like you may have gotten some contribution from the assets that have been divested in that number. Can you guys break down what in that number would be completely Permian? And then also, any downtime you guys encountered in December in the Permian that may have kept that number a little bit lower.

Yes, this is Gary. I don't know of any offshore or asset sales contribution that we have there. Mitch or Joe, do we have any of that in that number?

No.

Yes, I didn't think so. So that's all Permian number for the 3,611, and we were down a good bit of the month actually. It was a very difficult month, and actually our largest asset Bloxom was down probably the hardest and longest, Bloxom and Taylor Draw.

As you know what happened, of course they had the ice storm, had electrical outages. The electrical outages allowed all the tanks to fill up, and then once we got the electricity back and then once the tanks were all filled up, all the trucking services were backed up which caused even further outages. So we were down close to 7 to 10 days in total, which would have had a much more positive number coming out of December.

And it also actually further deferred actually our wells that we had just recently talked about at Carpe Diem from coming online sooner, Oh, I'm sorry, it's actually some of the Neal wells and Carpe Diem. Both those wells were nearly ready to come on, but we could have had a much bigger number is my point. But we're enjoying those benefits in the first quarter of 2014.

Absolutely. That's great color. I think you guys have previously talked about testing the horizontal Spraberry this year. How should we think about the timeline of getting that first Spraberry well drilled, completed, and then you guys notifying us about it? And I assume that's going to be at Carpe Diem, but correct me if I'm wrong there.

No, your assumption is absolutely right. It will be in central Midland Basin at Carpe Diem. We're pretty excited about some of the lower Spraberry wells that are being reported by Pioneer and others, and we're looking to probably see that being drilled, will probably third quarter. So you probably won't hear about that until late third quarter, so that's the timing for that.

Great. Thank you guys for the color.

And your next question comes from the line of Hsulin Pang with Robert W. Baird. Please proceed.

Good afternoon, everyone. So I know you guys were talking about the new design using more proppant, and I was hoping to get more color. Can you just describe for us what is the new well design, and how much proppant per stage, et cetera? And when do you think you'll have results for that?

Sure, Hsulin, I'll just try to quantify it for you. Typically, what we've been doing up to this point, is we've been pumping each stage will have around 75,000 pounds of 100 mesh, and then it will have close to 140,000 pounds of 40/70 mesh, sand that we place in, in each stage of any horizontal lateral that we've drilled up to this point in time. And we've been paying a lot of attention to what goes on out in the industry, and especially some of the higher performing wells that are reported.

And one of the things that we noticed was that in some of those bigger wells, the various companies were actually placing more sand. Some people call it a hybrid frac, some people call it just a more powerful frac. But what we've decided to do is go ahead and increase our total sand content by about 25%.

So what that means is, we'll still be pumping about 75,000 pounds of 100 mesh in each stage just to open up the perforations, initiate the frac, and then we're coming back with closer to instead of 140,000 it's closer to 190,000 pounds of 40/70. Still doing nothing but slick water fracs, we're not doing anything with gels yet, because we think that's still the best way to go.

And as far as timing goes, actually the wells that were flowing back right now at Neal were the first ones we did. The 653 results that we talked about, and the 652 results, those wells are showing early indications of having access to much more pressure and much more rate early time. You see those types of 30-day rates of a 1,000 barrels a day, and we get pretty excited about that.

Now it's only two data points. We're actually fracking the three wells at Bloxom now with the same manner. And as we mentioned it before, the two wells at Garrison Draw that were -- we just got them drilled out, we'll be completing those wells with sub pumps here shortly, and we'll see what type of initial results we get from there.

But these fracs, it takes a little longer to pump. We're placing more sand, we're going to a little bit higher pressure, using a little bit more water. But at the end of the day, we think it's going to pay out pretty big dividends by higher EURs in the end.

Okay, no that's great color. And can you also quantify the incremental cost for us?

Yes, I would say that the incremental cost, Hsulin, would be for the wells that we're drilling now for like 8,000-lateral feet completed, doing that the entire lateral length is going to cost an incremental cost of around $1 million a well.

Okay, got it. Sounds good. And then second question is, I think you guys were testing some vertical wells in Borden and Lynn County. Can you just give us an update in those two counties?

You bet, Hsulin. What we've done, again, just think back, we're really excited about what the results are of the Lacey Newton well. After months of production, that well is still just steady, steady at 90-, 95-barrels of oil a day. And we've done a lot of technical work around how do we repeat that result, and that's really what our goal is, is to try to repeat that result. Prove that that's a repeatable vertical play, which would be incredibly profitable.

So what we've done is we've just drilled the well. We've only drilled the well. We've got some logs, we're not going to talk too much about it at this point in time. But we'll be completing that well in probably the next two to four weeks, once we do all of the petrophysical work on it, and then we develop the right fracture stimulation. And then we'll provide those results to you probably in the May call.

Okay, great. And then last question, and then I'll go back into queue. It's great that you got the additional credit facilities in place now, and the question is do you feel comfortable funding your 2014 CapEx entirely with your cash flow and the current credit facilities in place? And what are some potential drivers that you will consider to accelerate your CapEx if need be to go as you go through 2014?

Yes, Hsulin, this is Joe. In terms of the credit facility, both the borrowing base and the second lien, we certainly think that that will cover 2014, and then some under the two rig horizontal program. So we'll have a good amount of liquidity day one today when we have these facilities closed. And also the borrowing base as you've seen, as it continues to move up and providing additional liquidity as we get through the year, especially with the pace of development we're on with a two rig program up and running.

In terms of accelerating CapEx, certainly, that's something that's driven first and foremost from the operations side and Gary's team and looking for opportunities potentially to add a second rig later in the year. We constantly look at those types of opportunities. Right now, we haven't made any formal decisions.

So that's one driver, and then also we don't budget for acquisitions. But clearly, we recently made one. It's a little bit smaller, but that could certainly be a catalyst as well. But we'll continue to review those types of additional growth opportunities, but we think we're off to a really good start with the two credit facilities we've put in place to certainly handle the base program and also handle some incremental growth on top of that.

Great, thank you so much.

Your next question comes from the line of Jeb Bachmann from Howard Weil. Please proceed.

Afternoon, guys. I had a couple questions. Gary, just talking about infrastructure, so you guys have enough take away for this year and into next year with the spending so far. Is that fair?

Yes, Jeb, I guess you're talking about off take for production. But in production there's also all the water, and sand, and pumping services, and everything else necessary to do a manufacturing type of program. And we got all that in place as well, but clearly not curtailed on oil at this point in time.

We're getting a little tight on gas, I'll be honest with you, getting just a little bit of tight on gas. But we see solutions in the near term on that just working with other pipeline companies that had more capacity, as well as other plants that have capacity. But no challenges whatsoever on the oil side.

In fact, we're really looking forward this year to having several pipelines get really close to our major development areas and get hooked up onto pipelines on those areas to where we can actually get one increase on margin and get rid of a lot of the trucking. That will likely happen in the last half of the year. But with the amount of production growth down at Bloxom and into Southern Midland Basin, several companies are starting to lay line right across it.

And, Gary, with the tightness on some of the gas takeaway, is that allowing you or have you guys been playing around with your choke management on these wells to see if that increases in ultimate EURs?

Well we've been playing around with it a little bit, Jeb, but it's difficult for us to see under controlled flowback conditions whether or not that's making much difference. We certainly control it ourselves, and we like seeing nice pressures. We like seeing good rates.

But during early flowback, we actually even control these rates ourselves because we want to make certain that we allow that fracture stimulation to close gently and hopefully not flow too much sand back into that lateral. But at the end of the day, Jeb, where we are is that once we get on a nice decline, nice trend of the pressure depletion and we get that type curve performance, we're still just a little bit tight on gas. But again, we'll see a solution to that shortly.

And then looking at that lower Spraberry well, knowing you guys work with RSP, are you able to get data from them on how they were able to drill their lower Spraberry's so effectively?

Yes, we'll be talking to RSP. We actually share surface infrastructure with them at Carpe Diem. They're immediately South and West of us, as you know, and North of us, and we have their production data. We know how they frac those wells.

We have spent a whole day over in their office doing a major technical exchange with their technical team, and that's generally what we like to do. We're paying attention to some of the major operators, and we've met with RSP, we've met with another smaller company. And gosh, we'd love to be able to exchange data with anybody, because I think we do things pretty well and we could probably help them and I'm sure we could learn something from somebody else.

Okay, great. And last one for me for Joe. Just trying to clarify, on the borrowing base, that initial draw of $62.5 million, is that for in addition to buying back those high yield notes to paying off the revolver or anything that's left outstanding there?

Yes, so the two pieces of financing that have the borrowing base piece or the first lien, which is really just transferring our existing balances under that is that new piece now. What you referred to is under the second lien facility. We will be making a draw of $62.5 million under that facility, and we've scheduled it to be timed in conjunction with the redemption of the notes, which we anticipate to be at April 11.

So the redemption will be just around $50 million to take out the rest of the senior notes, and we'll be drawing a little bit more than that. And we'll just use those proceeds to pay down the first lien facility.

Okay. So that $22 million outstanding at the end of the year that's going on the $95 million?

Correct.

Okay, great. Appreciate it guys.

The next question comes from the line of Chad Mabry from MLV & Company. Please proceed.

Thanks, good afternoon.

Good afternoon.

Congrats on the acreage acquisition. That looked like a very nice price there for that package down by East Bloxom. Just curious on your thoughts on additional opportunities there to acquire acreage either around East Bloxom or other core operated areas, and maybe what kind of scale you might have within those opportunities.

Gary, I could start on that, and certainly if you want to jump in. But, Chad, this is Joe. Yes, we were excited about that opportunity for two sections just South of our East Bloxom field, an area we obviously know pretty well, and encouraged with the results that we're seeing over time. But yes, there are other opportunities in that area, and they'll probably come in two forms.

One, being additional acreage type acquisitions. But also the opportunity to do some trades, doing some shared allocation well development, as well in the area.

So similar to what we had done at Garrison Draw if you recall, we stepped into that position. That was a little bit broken up, didn't set up day one for long laterals. But we've been working that area, completed a trade out there recently. We continue to look at opportunities to bolt on around that acreage position. So we see a similar opportunity in this acreage.

We think we have a little bit of a head start down there just given our knowledge of that part of Upton County, that hopefully we can put together some more acreage in that part of the world. Gary, is there anything else from that perspective?

Well, we're working with lots of different parties in and around our current acreage position, as well as the stuff that we just got. And we have a vision that that's going to turn into something bigger, given at least the reputation we have, and I think the type of results we're delivering. People are interested in what we're doing, and I think that helps us get involved with some folks that don't have as much expertise or capability of going out and initiating a horizontal development program.

So that's opened some doors for us actually. And we generally understand the strategies of many companies that are working in the Basin. A lot of companies want three sections North/South, just like we do. Some companies want four sections to push for 10,000-foot wells.

We work very hard to land positions in and around what we're doing, and to land positions of those that have land around us to where we can see or we can visualize trades and swaps, or JVs in certain wells to where we can potentially even drill to earn some acreage. So we're being very creative on how we expand our acreage position.

So the summation of all of it is, that we see things just like this because we are working hard. We're able to get it for a pretty good price, and we're going to continue working it hard throughout the year. We never stop. We've got a whole team working this 24/7 essentially.

That's great color. And as a follow-up, is it safe to assume that any locations associated with this acreage would be incremental to what you have on your inventory listed on your presentation?

Yes, that's correct.

Great, that's it for me. Thanks guys.

Thanks, Chad.

Your next question comes from the line of Mike Kelly with Global Hunter Securities. Please proceed.

Hello, guys, good afternoon.

Hello, Mike.

I was hoping to just understand a little bit better here what's the standard procedure with bringing these wells online, letting them flow under natural pressure, and then putting them on artificial lift. And just understanding the implications of putting them on artificial lift and the effect on production, what type of boost do you get from it?

Yes, that varies depending on where we are in the Basin. But at the end of the day, so the deeper wells in the Basin, I'll just say it. The deeper in the basin have a good bit more pressure, a good bit more energy, and they flow at higher rates longer. And we like them to flow at higher rates longer, of course. And so we're not in a rush to pull them hard, and we're not in a rush to put them on artificial lift.

The shallower wells in the Basin, that's Garrison Draw and Taylor Draw, they come on pretty strong, but then they drop off a little quicker because it's really a difference in pressure regime, I think is what it is. But similar oil in place targets. It's just it's got a different pressure regime because the depth in the basin. So I think depth matters.

And so what we're doing, or actually what we're actually experimenting with right now is, do we let them flow under natural pressure like we've historically done, and then let them push that pressure off to the point where we can then safely reenter the well and run a sub pump, and then get a significant boost in production? Because you've got all that back pressure, you've got a whole column of fluid of the back pressure on that formation.

So it's not flowing at its full potential, until you get a sub pump in there and then start lifting it from the bottom. And so sometimes we get the highest IP or highest rate from our natural flow depending on where we are in the Basin, and sometimes we get a significant uplift with the sub pump installation, similar to what we did on the 652 well.

Got it.

But just to complete the answer, I don't want to belabor this too much. We're also experimenting with gas lift. Now on gas lift, you have some natural flow for the first week or so, but then you're kicking your gas stream on, your gas lift on, and you're starting to help the well flow through a gas lift installation sooner, to where you can have a more defined drawdown curve under gas lift.

And similar to the question that was asked earlier, does that help you lift higher or larger EURs? That just might, because now you have a very controlled drawdown regime as you're stepping down in the gas lift system. Now gas lift itself has its benefits, and it has its drawbacks. It's very difficult to keep the compressors running in some of the coldest days, and you have to design them properly to run in the hottest days. So you have extreme temperature shifts in the Permian.

So they have their drawback too. And we're experimenting right now with both lift systems, and frankly, we haven't landed on one. Other than we've predominantly done natural flowback and sub pump installations. And then after the sub pump, then it's down to 200- or 300-barrels a day of oil, then we'll go in and put a rod pump on it just to reduce overall cost.

Got it. Appreciate that color. If I apply that thought to Carpe Diem, and I believe you said earlier that the two wells in Midland there had come on at around 800 a day, and it was naturally flowing. What would you expect if you put those on artificial lift? What's the impact on those wells, if I heard you correctly earlier?

Yes, we actually just in stalled sub pumps on those wells after they flowed for some time under natural flow. So we'll have those wells pumping on sub pumps probably in the next week.

Okay. And do you think that's the real true 30-day rate to go, to look at, and assess for you guys in that particular field is when they're on artificial lift versus natural flowing?

Again I do. I think so. Those wells are pretty strong already, but I think we'll get an incremental uplift in sub pump installations. And I think we'll do that on both wells. And then, the way we always do our 30-day rates is we take peak rate and 30 days out, and we don't take high rates before or anything else. We take peak rate and 30 days out. I assume that's a standard in the industry, but that's what we do. So wherever our peak is, that's where we give you our 30-day rate from.

Got it. Appreciate the color. Thank you very much.

Your next question comes from the line of Philip Dodd from Noble Financial. Please proceed.

Thank you. Good afternoon, everybody. I want to go back to the leases acquired in the December quarter. First, is there any history on those leases, vertical drilling or did they come from the University lease sale, or what would be interesting about it that we don't know?

We actually bought those from -- we actually approached the owner of those leases, and we bought them directly from them. They were actually trying to sell their whole package, and we went ahead and carved those out and got those on our own, just because we had been working it some time.

Has there been any drilling on them in the past?

There's one producing well. There's one vertical well on the lease, but it's very sparse. Hunt Oil actually drilled a horizontal well not too far from there, and we're a member of the core consortium for wells and data exchange in the Permian Basin, so one of the core wells is actually close to this area. And so we've done a lot of petrophysical work on it, and we think it's a good spot to be in. But it's not an area where a lot of people have drilled horizontal wells, or there's been significant vertical wells yet.

Okay. And the second, more important thing, I wanted to thank Bob Weatherly for all the help that he's been to me over the years. And, Bob, I don't know whether you'll be in these calls in the future, but in case you won't, I'll wish you all the best.

Well thank you, Phil. I do intend to be on some in the future, but it's always nice to hear somebody say something nice about you. Thank you, Phil.

Made it as nice as I could. (laughter)

Your next question comes from the line of Ron Mills from Johnson Rice. Please proceed.

Hello, guys. A quick follow-up on I think Mike's question, maybe Gary. The fact that I would assume in the deeper parts of the Basin, higher pressure and flow naturally longer that should be considered a positive. How have these recent wells that you just put on pump, how did they flow in terms of timeframe, and at least on the information you have relative to some of the earlier wells you put on? Are you seeing any improvements coming from your completion enhancements?

The two Carpe Diem wells are two wells that we fracked under our old method, and so that won't be the indicator. But we certainly saw very high steady flow rates come in those under their natural flow in the month of January, and so we're pretty excited about that. And then they've flown throughout this period of time, at pretty good rates.

The pressures have now dropped off to the point where we can actually kill them with water, and go ahead and install the sub pumps. But they're very similar, Ron, to the wells that we've been seeing down at Bloxom historically. Which is our really nice area of development.

It's a little deeper at Carpe Diem than it is at Bloxom, and so I actually expect -- my personal expectation is I think that we're going to get some pretty solid results. And then Diamondback is immediately to the East of us, and I think their best well is 1.5 miles East of where we're at.

And RSP is real excited about what they're doing just North of us, and immediately to the Southwest of us. So that's a pretty exciting area to us, but it still it's going to take us some time to figure it out. It's going to take us some time to these wells on sub pump, and see what the real peak rates are going to be, and the real definition of that type curve is going to be. But I would expect pretty nice EURs here.

And then similar commentary about the Bloxom. The 652, how long did that flow naturally before you hooked it up versus say the 653 that's been producing for 50 days? Are you seeing something, a similar type performance prior to putting the pump in place?

Now you're going to have to make me come clean on all this stuff aren't you, Ron, because now you asked me a very specific question. And I got asked, and I guess I've got to answer. Actually, the 652 flowed at a fairly strong rate, and then it died. It actually died pretty quick.

We actually think it was all in and around some cold weather interruptions and everything else, and it just flat died. And we said well, what's wrong with that well? The 653 is flowing famously. It was really strong, and two wells side by side.

And we just thought we maybe had a bridge in the curve. Went in and we actually cleaned it all out, and ran the sub pump in it and it's the same concept we already did. We took the opportunity to do that. And it just come on really strong.

So all these wells will act a little bit differently, but at the end of the day what we're looking to do is bring them on slow, do them under some type of control drawdown, at the most we bring on at 100-barrels of fluid an hour. And that's total fluid. And then see the long-term performance. But the 652 honestly, Ron, it didn't flow that long, but the 653 certainly did.

Okay. And then maybe, this may have been a follow-on to Hsulin earlier, you talk about potentially spending another $1 million on the larger fracs. I assume that's off of your, call it $6.5 million or so costs that you have in your presentation. So you're looking at plus or minus 15% cost increase. What are the hopes in terms or what should be the expectations in terms of production and/or EUR lift versus that 15% increase in EURs?

Well our hope is we'll certainly see a significantly higher percentage increase in early time performance and production. And EURs, like right now we're talking EURs in the Bloxom area of around 480 to 500, which suggests that we're to get above 550 to 600. Those types of ranges.

So certainly, well worth the extra cost if we can actually see that time on time again, every time we do it, and that's what we're experimenting with. We're pretty excited about what others are doing, and we think we're learning from it. And we're pretty excited about at least the early time performance of the two Bloxom wells, and anxious to see these two Garrison Draw wells come on line.

So the Bloxom wells, did you complete those Bloxom wells with the larger fracs?

We did, yes.

Okay, good. And is that the plan for all yours going forward until proven otherwise?

Yes, we didn't do it at Carpe Diem. But from this point forward, now that we're starting to see that type of a early time result, we're pretty excited about it and we're building it into our program.

Perfect, thanks again. And, Bob, also, congrats on being able to enjoy yourself maybe a little bit, at least every three months or so.

Yes, me too, good idea.

There you go. All right, guys.

Thank you.

Your next question comes from the line of Tom Decker with Morgan Stanley. Please proceed.

Good afternoon. You've answered so many of the technical questions, now if you could just -- after your latest Upton purchase, and what is your total net acreage in the Permian? And then, one of you made a comparison, you said you made to your peer group. Who do you consider in your peer group, please?

Joe, you want to talk about the acreage?

Yes, please.

Total net acreage in the Permian is about 32,000, 33,000 net acres right now, about 14,000 of that is in the Southern and Central part of the Basin.

Yes, Tom, in terms of peers, I think obviously now that we're a pure Permian player, we're looking at the RSP, and Diamondback, Laredo, and obviously the largest being Pioneer in terms of where we're focused.

Okay. I just didn't know when you were talking to your peers you were just talking like Diamondback and Laredo, and I just didn't know if you included something like Approach or even if they're just too far South of you.

We'll certainly look at them as pure play Permian players, and we'll also look at other small CAT companies that are focused on horizontal growth. In other Basins, there's other comparisons as well, but mostly we're focused on the small mid-CAT Permian players.

Thank you.

Your next question comes from the line of Ray Deacon from Brean Capital. Please proceed.

Yes, hi, good afternoon. I was just wondering if I could ask, with the 21 horizontal wells you've drilled so far in the Permian, what's been the average lateral length on those? And will the average for this year be close to the 8,000 level, or is that something you'd see in a couple years?

If you look back on the average, on the 21s, it's not exact, but it's roughly around 7,100 feet on the laterals, and this year just over 7,000 is what we had planned. So similar this year to what we've been doing.

Okay, got it. And maybe in terms of the Northern acreage, you talked about being a little bit more confident in derisking there. Are there any key results you're looking towards this year, or could we hear anything in the next quarter or two that would make you more encouraged about the economics there?

Yes, I think I mentioned earlier that we've drilled a well, and we've got some cores, and we've got some logs, and we're looking at it, and trying to figure out generally what it tells us as it relates to our pretty exciting Lacey Newton well. And beyond that, we're not going to talk too much about that. We still are working very hard to put together the right completion for this well.

We'll have it tested probably before our next call. And then we're in the process of drilling another well in our Lynn County acreage, and hopefully we'll have it down and logs and core evaluated and potentially tested before our next call as well. So we might be able to give you a good bit of detail on the Northern acreage during our next call.

Got it, great. Thank you.

It looks like we have time for one more question, and that's going to come from the line of Ryan Oatman from SunTrust. Please proceed.

Hi, good afternoon, everybody, and congratulations, Joe, and Mitzi. All of my easy questions have been taken here, but maybe a quick one here on the Mid/Cush differential. Looks like it's widened out from a little less than $5 in 4Q to about $10 currently. How exposed is Callon to that differential, and what can you do to isolate yourselves from movement there?

Yes, certainly, we've seen that move out, and we do see it from time to time just given the pipeline projects keeping up with the pace of production out there, and there's been some anecdotal things kicking around the last couple weeks with maybe a problem here or there with the pipeline that rolls into the broader market. We don't have basis differentials in place right now for that spread.

I think we are getting to a point in terms of having enough critical mass to start thinking about those. It's not the most liquid market for that differential hedging. But, we'll look at it. So right now, Ryan, to answer your question, we are fully exposed to that differential on the financial side.

But as Gary talked about, one of the things that doesn't address that directly, but I think will help us certainly this year is moving a little bit away from the trucking elements of off taking oil. Which certainly will help in our overall margin, going from trucking to getting on some of these pipelines that are being developed near our core areas.

No, that makes sense. And then just in terms of the lateral length, it seems like you guys continued to push the envelope there towards 7,000 feet and beyond this year. What do you think the optimal lateral length is in the Permian? Is it 8,500, is it 10,000, is it 7,000? And with that, I'll hop back into the queue, thanks.

Well as far as optimum lateral length, I'm not sure we've found it yet. We were very comfortable with 7,500-foot laterals. And I've actually said this at various conferences, that 7,500-foot lateral lengths seem to be probably very simple and easy to drill these days. You can do it quite efficiently.

The risk of completion is less than a longer lateral well as you go in and drill out those plugs, it's just easier to get to bottom. But frankly, the two wells at Carpe Diem, one of them is 9,000-foot lateral, and it drilled just fine. We went in and I think it was 31 or 32 stages, I don't really remember the exact number, we're completing wells so quickly here.

But at the end of the day, we got that thing drilled out all the way to bottom no problem whatsoever. And so, I'm gaining a lot of confidence in the team that I have, especially the team that's working the site. I've got some great people that are out there executing this work in a way that minimizes risk, and gets it done in a safe way, and gets it done in a timely manner as to where we can actually reduce our entire cycle time from drilling to first production throughout the whole cycle.

So I love 7,500-foot wells, because they're so repeatable. But frankly, I also like just what we did, and if I could push them further I would. Simply because I can get access to good resource, I can get that well completed with minimal capital, and I can enjoy really a better chance of success for a really good well.

I like the thought that Pioneer says that they want to target 10,000 feet. We're not quite there yet, because we don't have the acreage position they have. But once we get bigger and we've continued to add-on to the acreage that we have in and around our areas, you'll see us pushing them as far as we can get to the edge of the lease line.

Thanks, Gary. Congrats on obviously working that longer, and we look forward to hearing more in the days ahead.

You bet.

Ladies and gentlemen, this will conclude the question and answer portion of today's call. I would now like to turn the call back over to Fred Callon for closing remarks.

Again, thank you. We do appreciate everyone taking time to call in, appreciate all the questions. And in the meantime, if anyone has calls don't hesitate to give any of us a call at any time. Thank you so much.

Ladies and gentlemen, that concludes today's conference. Thank you all for your participation, and you may now disconnect. Have a wonderful day.