Callon Petroleum Management Discusses Q4 2013 Results - Earnings Call Transcript

Mar.13.14 | About: Callon Petroleum (CPE)

Callon Petroleum (NYSE:CPE)

Q4 2013 Earnings Call

March 13, 2014 2:00 pm ET

Executives

Fred L. Callon - Chairman, Chief Executive Officer, President, Chief Executive Officer of Callon Petroleum Operating Company and President of Callon Petroleum Operating Company

Joseph C. Gatto - Senior Vice President of Corporate Finance

Gary A. Newberry - Senior Vice President of Operations

Bobby F. Weatherly - Chief Financial Officer, Executive Vice President, Corporate Secretary and Director

Analysts

Will Green - Stephens Inc., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Joseph Bachmann - Howard Weil Incorporated, Research Division

Chad L. Mabry - MLV & Co LLC, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Philip L. Dodge - Noble Financial Group, Inc., Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Thomas H. Decker

Raymond J. Deacon - Brean Capital LLC, Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2013 Callon Petroleum Earnings Conference Call. My name is Philip, 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.

Fred L. Callon

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?

Joseph C. Gatto

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, PV-10 measure and adjusted net income. Reconciliation and calculation schedules for such non-GAAP financial measures are available on 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, turn it back to you.

Fred L. Callon

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 2 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 and commodities business as a Managing Director with both Merrill Lynch and Barclays 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 and 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're also very fortunate to have 2 outstanding new directors joining the board: Matt Bob, managing member of MB Exploration; and Jim Trimble, Chief Executive Officer and President of PDC Energy. Matt and Jim both bring a tremendous amount of industry experience to the board. We look forward to working with them.

I'll now turn to our 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 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 costs 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 and 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 strength. While the majority of our drilling activity this year we focused on the upper and lower Wolfcamp B and 4 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 and potential locations through downspacing and testing of new zones, we continue to pursue complementary acreage and producing-asset acquisitions. On this front, we've 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 4 zones in this 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 of capital. On this front, we recently announced the closing of a 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?

Gary A. Newberry

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're very pleased with exceeding our 2013 exit rate goal of 3,500 barrels 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 2-rig horizontal program.

Looking forward, our pad development initiatives, which were recently expanded to 4 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 4 horizontal wells online in the first quarter so far and are currently in various stages of completing 5 additional wells, as well as drilling 5 additional wells. Starting at East Bloxom, the Neal 652 had a 24-hour peak rate of 1,395 barrels of oil equivalent per day and a 26-day average rate of 1,013 barrels of oil equivalent per day through March 10, 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 pressures 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 3 additional wells in the field, including a Wolfcamp A and 2 upper Wolfcamp B wells, which were drilled from the same pad.

At Garrison Draw, we are in the process of drilling out plugs in 2 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 2 wells versus our first horizontal well on this field, which had a 24-hour peak rate of 991 barrels of oil equivalent per day for a lateral length of approximately 4,600 feet. These 2 wells are expected to be placed on production later this month.

Rounding out our recent southern Midland horizontal program activities, we are drilling a 3-well pad at Taylor Draw in Reagan County, with 1 well targeting the lower Wolfcamp B and 2 wells targeting the upper Wolfcamp B.

I will now turn to the central Midland Basin and our Carpe Diem field, where we brought 2 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 of oil equivalent per day. They are now in the process of being put on artificial lift, which we will believe -- which we believe will lead to higher initial production rates in the coming days. We are encouraged with these early results, and we'll be providing updates on this new core horizontal development area as the year progresses, including 2 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.

Bobby F. Weatherly

Thanks, Gary. Our net income for the quarter was $1.3 million or $0.03 per diluted share. This figure included a net pretax 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 noncash unsettled hedging gains. Excluding these items and the related income tax effect, adjusted net income was essentially breakeven.

Operating revenues for the 3 months ended December 31, 2013 included oil and natural gas sales of $26.5 million from the average production of 3,848 barrels equivalent per day. These results include approximately 1 month of contribution from our Medusa Field and 2 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 for 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 this 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 for the fourth quarter 2012 to $6.4 million in the fourth quarter. However, on a cash basis, our G&A expense decreased by $700,000 between these 2 periods, with an offsetting increase of $2.7 million primarily attributable to noncash expenses and the mark-to-mark 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 noncash impacts related to our share-based incentive programs.

Discretionary cash flow for the 3 months ended December 31, 2013 totaled $15.8 million. And net cash flow provided by operating activities, as defined by U.S. 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 9 wells drilled in the fourth quarter versus 5 wells drilled in the third quarter and 8 wells completed in the fourth quarter versus 7 wells completed in the third quarter as drilling activity with our 2-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 2 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 I will turn the call back to Fred for a few final comments.

Fred L. Callon

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

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Will Green from Stephens.

Will Green - Stephens Inc., Research Division

So I think you guys have 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 kind of break down what in that number would be completely Permian and then also kind of any downtime you guys encountered in December in the Permian that may have kept that number a little bit lower?

Gary A. Newberry

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

Joseph C. Gatto

No.

Gary A. Newberry

I didn't think so. So that's all Permian number for the 3,611. And so -- 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. Electrical outages allowed all the tanks to fill up. And then once we got 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 also, actually, it further deferred, actually, our wells that we just recently talked about at Carpe Diem from coming online sooner. Oh, I'm sorry. It wasn't -- 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, I guess, is my point. But I guess we're enjoying those benefits in the first quarter of 2014.

Will Green - Stephens Inc., Research Division

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 kind of drilled, completed and then you guys kind of notifying us about it? And I assume that's going to be at Carpe Diem, but correct me if I'm wrong there.

Gary A. Newberry

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 probably third quarter. So you probably won't hear about that until late third quarter. So that's the timing for that.

Operator

And your next question comes from the line of Hsulin Peng with Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

So I know you guys were talking about the new design with more -- using more proppant. And I was hoping to get more color. Can you just kind of 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?

Gary A. Newberry

Sure, Hsulin. Let me try to put -- I'll just try to quantify it for you. Typically, what we've been doing up to this point is we've been bumping -- each stage, you'll have around 75,000 pounds of 100 mesh. Then it'll have close to 140,000 pounds of 40/70 mesh sand that we place in each stage of any horizontal lateral that we've built up to this point in time. And we've been paying a lot of attention to what goes on out in the industry, 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 40/70. Still doing nothing but slickwater 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 being -- having access to much more pressure and much more rate early time. You see those types of 30-day rates of 1,000 barrels a day, and we get pretty excited about that. Now it's only 2 data points. We're actually frac-ing the 3 wells at Bloxom now with the same manner. And as we mentioned before, the 2 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.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

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

Gary A. Newberry

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 the entire lateral length is going to cost an incremental cost of around $1 million a well.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. Sounds good. And then second question is -- I know you guys were -- I think you guys were testing some vertical wells in Borden and Lynn County. Can you just give us an update in those 2 counties?

Gary A. Newberry

You bet, Hsulin. What we've done, again, we -- just think back. We're really excited about what the results are of the Lacey Newton well. I mean, after months of production, that well's 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 2 to 4 weeks, once we do all 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.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, great. And then last question, and then I'll go back in the queue. It's great that you got the additional credit facilities in place now. And I guess 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 to -- that you will consider to accelerate your CapEx, if need be, as you kind of go through 2014?

Joseph C. Gatto

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 2-rig horizontal program. So we'll have a good amount of liquidity day 1 today, when we have these facilities closed. And also, the borrowing base, as you've seen, 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 2-rig program sort of 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 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 2 credit facilities we put in place to certainly handle the base program and also handle some incremental growth on top of that.

Operator

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

Joseph Bachmann - Howard Weil Incorporated, Research Division

I had a couple of questions. Gary, just talk about infrastructure. So you guys have enough takeaway for this year and into next year with the spending so far. Is that fair?

Gary A. Newberry

Yes, Joe. I guess you're talking about offtake for production. But in production, also, all the water and sand and pumping services and everything else necessary to do a manufacturing type of program, and we had 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 tight on gas. But we see solutions in the near term on that just working with other pipeline companies that have more capacity, as well as other plants that have capacity. But no new 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 on the pipelines on those areas to where we can actually get, one, increase our margin and kind of get rid of a lot of trucking. That will likely happen in the last half of the year. But with the amount of production growth down at Bloxom and in the southern Midland Basin, several companies are starting to lay line right across us.

Joseph Bachmann - Howard Weil Incorporated, Research Division

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 ultimate EURs?

Gary A. Newberry

We've been playing around with it. So 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 have allowed 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.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay. And then looking at that lower Spraberry well, knowing that you guys work with RSP, are you able to kind of get data from them on how they were able to drill those -- their lower Spraberry so effectively?

Gary A. Newberry

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 opening their office, doing a major technical exchange with their technical team. And that's generally what we like to do and we're paying attention to some of the major operators that 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 it -- we do things pretty well and we could probably help them, and I'm sure we could learn something from somebody else.

Joseph Bachmann - Howard Weil Incorporated, Research Division

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 paying off the -- to paying off the revolver or anything that's left outstanding there?

Joseph C. Gatto

Yes. So I guess the 2 pieces of financing we have is the borrowing base fee, so the first lien, which is really just transferring our existing balances under that into 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. I mean -- and we've scheduled it to be timed in conjunction with the redemption of the notes, which we anticipate to be April 11. So the redemption will be just around $50 million to take out the rest of the senior notes, and we will be drawing a little bit more than that and we'll just use those proceeds to pay down the first lien facility.

Joseph Bachmann - Howard Weil Incorporated, Research Division

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

Joseph C. Gatto

Correct.

Operator

Your next question comes from the line of Chad Mabry from MLV & Co.

Chad L. Mabry - MLV & Co LLC, Research Division

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 kind of core operated areas. And maybe what kind of scale you might have within those opportunities?

Joseph C. Gatto

Gary, I could start on that. And certainly, if you want to jump in. But Chad, this is Joe. Yes, we're excited about that opportunity for 2 sections. Just south of our East Bloxom Field, an area we obviously know pretty well and I'm encouraged with the results that we're seeing over time. But yes, there are other opportunities in that area, and it probably come in 2 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, they didn't set up Day 1 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 -- in that perspective?

Gary A. Newberry

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 the, 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 kind of get involved with some folks that don't have as much expertise or capability going out and initiating a horizontal development program. So that's kind of 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 3 sections North, South, just like we do. Some companies want 4 sections to push with 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 I guess, the summation of all of it is that we see things just like this because we're 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'll never stop. We've got a whole team working this 24/7, essentially.

Chad L. Mabry - MLV & Co LLC, Research Division

That's great color. And I guess, 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?

Gary A. Newberry

Yes, that's correct.

Operator

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

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

Gary A. Newberry

Yes. That varies depending on where we are in the basin. But at the end of the day, the deeper wells in the basin -- I'll just say it, the deeper wells in the basin have a -- are a good bit more pressure, a good bit more energy, and they flow at higher rates longer. And we kind like them to flow at higher rates longer, of course. And so we're not in a rush to pull them part, and we're not in a rush to put them on artificial lift. That shallower wells in the basin, the Garrison Draw and Taylor Draw, they come on pretty strong, but then they drop off a little quicker because of that -- it's really a difference in pressure regime, I think, is what it is. But similar oil and place targets. It's just it's got a different pressure regime because of depth in the basin. So I think depth matters. And so what we're doing, actually, what we're actually experimenting with right now is, do we let them flow under natural pressure like we've done, 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 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 we get -- 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 installations, similar to what we did on the 652 well. 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 and your gas lift on and you're starting to help the well flow through a gas lift installation sooner to where you can have the more defined drawdown curve on the gas lift. And similar to the question that was asked earlier, does that help you with lift higher or larger EURs? That just might -- because now you have a very controlled drawdown regime, as you're stepping down in a gas lift system. Now gas lifts itself has its benefits and it has its drawbacks. It's very difficult to keep the compressors running some of the coldest days and you have to design them properly to run in the hottest days. So you get extreme temperature shifts in the Permian. So they have their drawdown -- their drawback too. And we're experimenting right now with both the lift systems. And frankly, we haven't landed on one, other than we predominantly done natural flow back and sub pump installations. And then after the sub pump then, and it's down to 200 to 300 barrels a day of oil, then we'll go in and put a Rod pump on it just to reduce overall cost.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it. I appreciate that color. If I kind of apply that thought to Carpe Diem, and I believe you said earlier that the 2 wells in Midland had come on at around 800 a day, it was naturally flowing. What would you expect if you put those on artificial lift, what's kind of the impact on those wells if I heard you correctly earlier?

Gary A. Newberry

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

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

Gary A. Newberry

Again, I do. I think so. I mean, 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 in 30 days out. We don't take high rates before or anything else. We take peak rate in 30 days out, I assume that's the 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.

Operator

And your next question comes from the line of Philip Dodge from Noble Financial.

Philip L. Dodge - Noble Financial Group, Inc., Research Division

I want to go back to the lease 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 that be interesting about it that we don't know?

Gary A. Newberry

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 have been working it some time.

Philip L. Dodge - Noble Financial Group, Inc., Research Division

Has there been any drilling on them in the past?

Gary A. Newberry

There's one producing well. There's one vertical well on the lease, but it's very sparse. There's a -- 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. And so as 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.

Philip L. Dodge - Noble Financial Group, Inc., Research Division

Okay. And second, the more important thing, I wanted to thank Bob Weatherly for all the help that he has 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.

Bobby F. Weatherly

Thank you, Philip. 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, Philip.

Operator

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

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

A quick follow-up on one of, 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 time frame 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?

Gary A. Newberry

The 2 Carpe Diem wells, are 2 wells that we fraced under our old method. And so that won't be the indicator. But we certainly saw very high, steady flow rates coming those under their natural flow in the month of January. And so we were pretty excited about that. And then they have flown throughout this period of time at pretty good rate. The pressures are 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 than Carpe Diem than it is at Bloxom. An so I actually expect, my personal expectation is I think we're going to get some pretty solid results. And the Diamondbacks immediately to the East of us. And they're -- I think their best well is 1.5 miles East of where we're at. And RSP is really 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's still -- it's going to take us some time to figure it out, it's going to take us time some to get these wells on sub pump and see what the real peak rates are going to be in the real definition of that type curve is going to be. But I would expect pretty nice EUR share.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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

Gary A. Newberry

Now you're going to have to make me come clean on all of this stuff, aren't you, Ron? Because now you asked me a very specific question I've got to ask -- I guess, I've got to answer. But actually, the 652 flowed at a fairly strongly 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, "What? What's wrong with that well?" The 653 is flowing seamlessly. I mean, it was really strong and 2 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's the same concept that we already did. We took the opportunity to do that, and it has 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 controlled drawdown. At the most, we bring them on at a 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.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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

Gary A. Newberry

Ronald, but you will certainly see a significantly higher percentage increase in earlier time performance in production. And EURs, like right now we're talking EURs in the Bloxom area of around 480 to 500. We'd suggest that we're going to get about 550 to 600, those types of ranges. So certainly, well worth the extra costs 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, we think we're learning from it. And we're pretty excited about, at least, the early time performance of the 2 Bloxom wells. And kind of anxious to see these 2 Garrison Draw wells come online.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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

Gary A. Newberry

We did, yes.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. Good. And is that the plan for kind of all yours going forward and until proven otherwise?

Gary A. Newberry

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

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Perfect. Bob, also, congrats on being able to enjoy yourself maybe a little bit. At least every 3 months or so.

Bobby F. Weatherly

Yes, me too. Good idea.

Operator

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

Thomas H. Decker

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

Gary A. Newberry

Joe, you want to talk about the acreage?

Joseph C. Gatto

Our 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.

Fred L. Callon

Yes. Tom, in terms of peers, I mean, I think you've -- obviously, now that we are 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.

Thomas H. Decker

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

Joseph C. Gatto

No. We'll certainly look at them as pure plays, Permian plays. And we'll also look at other small-cap companies that are focused on horizontal growth and other basins as other comparisons as well. But mostly, we're focused on the small mid-cap Permian players.

Operator

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

Raymond J. Deacon - Brean Capital LLC, Research Division

I was wondering if I could ask a little -- 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 kind of be close to the 8,000 level or is that something you'd see in a couple of years?

Joseph C. Gatto

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

Raymond J. Deacon - Brean Capital LLC, Research Division

Okay. Got it, got it. And maybe in terms of the Northern acreage. You talked about being a little bit more confident in derisking there. I guess, are there any key results that you're looking towards in this year or could we hear anything in the next quarter or 2 that would make you more encouraged about the economics there?

Gary A. Newberry

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 -- I'm not going to talk to you much about that, we're still 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.

Operator

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

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

All of my easy questions have been taken here, but maybe a quick one here on the mid-cush differential. It 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?

Joseph C. Gatto

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 just been some anecdotal things kicking around the last couple of weeks with maybe a problem here or there with the pipeline that's sort of rolls into the broader market. We don't have a 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. And it's not the most liquid market for that differential hedging, but we'll look at it. So right now, Ryan, I guess, to answer your question, we are fully exposed to that differential on the sort of financial side. As Gary talked about, one of the things -- it 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.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

That makes sense. And then just in terms of the lateral lengthening, it seems like you guys continue 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 in the queue.

Gary A. Newberry

Well, as far as optimum lateral length, I'm not sure we found it yet. If we just drilled -- we were very comfortable with 7,500 foot laterals, and I've actually said this at various conferences that 7,500-foot lateral length 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 only because as you go in and drill out those plugs. It's just easier to get to the bottom. But frankly, we just -- 2 wells at Carpe Diem, one 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, but we're completing wells so quickly here. But at the end of the day, we got that thing drilled out all the way to the bottom, no problem whatsoever. And so it all -- 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, so that way we can actually reduce our entire cycle time from drilling to first production throughout the whole cycle. So I'd love 7,500-foot wells, because we can -- they're so repeatable. But frankly, I also liked 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 said 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 continue 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.

Operator

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.

Fred L. Callon

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

Operator

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

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