Callon Petroleum's (CPE) CEO Fred Callon on Q1 2014 Results - Earnings Call Transcript

May. 9.14 | About: Callon Petroleum (CPE)

Start Time: 10:00

End Time: 10:56

Callon Petroleum Co. (NYSE:CPE)

Q1 2014 Earnings Conference Call

May 9, 2014 10:00 AM ET

Executives

Fred L. Callon - Chairman and CEO

Gary A. Newberry - SVP, Operations

Joseph C. Gatto - SVP, CFO and Treasurer

Eric Williams - Manager, Financial Reporting

Analysts

Philips Johnston - Capital One Securities

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

William Green - Stephens Inc.

Ronald Mills - Johnson Rice & Co. LLC

Jeffrey Grampp - Northland Capital Markets

Adam Fackler - MLV & Company

Timothy Rezvan - Sterne Agee & Leach, Inc.

Ronald Mills - Johnson Rice & Co. LLC

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2014 Callon Petroleum Earnings Conference Call. My name is Mark, and I'll be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I’d now like to turn the conference over to Fred Callon. Please proceed.

Fred L. Callon

Thank you and good morning. We appreciate you taking time to be part of our first quarter ’14 results conference call. Before we begin, I'd like to ask Eric Williams, our Manager, Financial Reporting to make a few comments. Eric?

Eric Williams

Thanks, 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 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 or 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 first quarter 2014 results news release and in our filings with the SEC, both of which are available on our website.

Fred L. Callon

Thank you, Eric. Again, thank you for taking time to join -- excuse me, to join our call this morning. I think our first quarter results provide a good snapshot of the repeatable growth platform we built in the Permian over the last several years. This is our first reporting quarter without production contribution from our divested Gulf of Mexico operations, but our trajectory continues upward even without that production that was monetized for $100 million in late 2013.

From a top line perspective average daily production in the Permian increased by 46% over the last quarter to 4,355 barrels of oil equivalent per day. Below that top line, our results also benefited from the impacts of efficient program development with LOE coming in below guidance and just over $10.50 per BOE.

While these are encouraging results, this is just one quarter that needs to be looked at on a longer term basis. On that note, we’ve provided an updated production and expense guidance for calendar year 2014. Our midpoint for total forecasted production was increased to 5,250 barrels of oil equivalent per day. We currently estimate our exit rate for the year will be in excess of 6,000 barrels of oil equivalent per day under our current two rig horizontal program.

On the cost side, we now forecast the midpoint of LOE including workovers, to be less than $10 per BOE on average for 2014, as the impact of horizontal wells continues to improve this number.

In terms of a longer term outlook for our Permian business into next year, we estimate incremental production growth of over 35% in 2015 over 2014, assuming no acceleration of our current two rig program. Our revised 2014 production guidance represents meaningful change for outlook and is a result of two key factors that we’ve increased our type curve and EUR estimates.

First we now have extended production data from our initial drilling in the central Midland Basin, the Carpe Diem field and second we have compiled data from several wells and three Southern Midland Basin fields using a new completion design that has led to improve production rates in the EUR.

(Technical difficulty) bit more difficult to quantify given its scope. The impact of being efficient program development mode, operating two horizontal rigs alternating between four core fields can’t be overlooked. This type of efficient operation doesn't happen overnight, it is the product of over the last year infrastructure facilities development that now provide capacity to deliver on the growth potential of our asset base.

I’ll 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 A. Newberry

Thanks, Fred, and good afternoon to everybody. I will pick up where Fred left off and provide some more commentary around our recent upward EUR revisions and our operational outlook.

In March, we discussed two key initiatives for our operations. The testing of larger completion designs in the Southern Midland Basin and the commencement of horizontal development in the Central Midland Basin.

I’m pleased to report that both efforts have produced solid results and have given us the conviction to increase our production guidance for 2014. More importantly, we expect these factors to contribute on a longer term basis in the form of improved EURs and higher returns on capital.

Before I review our revised EUR and type curve assumptions, I want to point out two key points. These estimates are for 7500 foot laterals based on data from actual long lateral wells and have not been derived from a gross up of a shorter horizontal. Secondly, all of the EUR and production data that I will discuss is based on two stream reporting. We have estimated that these numbers will be approximately 15% higher on a comparable three stream basis.

I will start in the Southern Midland Basin for a review of our revised type curve and EUR estimates. In Reagan County where our Taylor Draw and Garrison Draw fields are located, the EUR estimates are in the range of $475,000 to $525,000 barrels of oil equivalent with an associated cost of $6.3 million to $7 million. At our East Bloxom field and Upton County, the EUR estimate is $575,000 barrels of oil equivalent with an associated cost of $7.5 million. Please note that these well cost estimates do include the costs for larger completion designs, which essentially plays 10% to 20% more sand per stage in the lateral.

Moving to the Central Midland Basin, on our Carpe Diem field, our two recent wells have produced 30 day peak rates of 902 and 919 BOE per day and 50 day peak rates of 831 and 809 BOE per day. These day points combined with offsetting well performance, support our EUR estimates of 575,000 barrels of oil equivalent for a 7,500 foot lateral at a cost of approximately $7.3 million per well and 660,000 barrels of oil equivalent for 9000 foot laterals at a cost of $8.5 million per well.

We are obviously excited about this type of performance from our growing list of horizontal wells on production, which now stands at 29 that we brought seven horizontal wells on production in the first quarter. We expect to bring wells on at a similar rate over the course of the year as we continue to alternate between drilling and completion at our core fields to minimize overlapping activity and reduce the burdens on existing infrastructure.

With a solid foundation of inventory that is now being efficiently turned into production on a repeatable basis, we continue to test concepts to enhance overall resource recovery. Our first initiative is increasing development of staggered laterals targeting different zones from the same pad. We have established production from three Wolfcamp zones in the Southern Midland Basin and are now beginning to develop them simultaneously from the same pad.

At East Bloxom, we recently placed a three well pad on production with two upper Wolfcamp B and one Wolfcamp A well and are currently drilling another three well pad at Bloxom with two upper Wolfcamp B wells and one lower Wolfcamp B well. Also with our second horizontal rig at Garrison Draw, we’re currently drilling a two well pad with one upper Wolfcamp B well and one Wolfcamp A well after bringing on two lower Wolfcamp B well that’s wells on the same pad earlier this year.

Another initiative which is linked to the larger completion designs is allowing wells to flow back longer under controlled natural flowing pressures before placing them on artificial lift to avoid pulling the wells too hard and damaging the fracture stimulation or the formation. As our completion techniques have been proved over time, we’re seeing higher initial producing pressures in our wells and longer periods under natural flow, which gives us an opportunity to study this issue and the potential impact on longer term well performance.

We are currently using this process at East Bloxom on the 346H, the Wolfcamp A well along with two Wolfcamp B wells that I discussed as part of the staggered lateral pad development. The A well was completed in early April and continues to produce at steady natural pressures comparable to our Wolfcamp B wells on the same pad. At this point, the Wolfcamp that have similar EUR recoveries as the Wolfcamp B at East Bloxom.

In the Northern Midland Basin, we drilled a vertical exploration well in Lynn County that encountered water filled porosity in the primary objective horizons and were subsequently plugged and abandoned. In Borden County, we continue to test and evaluate our second vertical well. The Matthew bear at 27-1 well had porosity developments throughout the Mississippian formation. However, it seems the fracture stimulated communicated with water in the deeper Ellenberger formation.

We plan to isolate the water production to improve draw down, to further evaluate the prospectivity of the Mississippian formation. I will finish by saying that our program development and operations -- program development operations are fully transitioned in the manufacturing mode at our key fields.

In addition to capital efficiencies and repeatable production growth, this mode of operation frees up our team and they get dedicate more time to optimization efforts as well as the evaluation of opportunities to expand our footprint in gaining access to additional acreage, so that they can turn the resource potential into cash flow as part of our program development model.

I’ll now turn the call over to Joe Gatto, our Senior Vice President and CFO

Joseph C. Gatto

Thanks, Gary. Our reported net loss for the quarter was a $111,000 or essentially breakeven on a per diluted share basis, which figure included in the impact, the following items are on a pre-tax basis. Non cash, unsettled bosses of 1.6 million related to a mark-to-market of our hedging portfolio. Non-cash expense of $2.7 million, related to a mark to market valuation of equity incentive awards, they’re value based on simulated stock price moments over time and again $1.1 million on the sale of legacy offshore equipment.

It also includes non-recurring items relating to the earlier timing of employees during the quarter and expenses incurred for a proxy contest, that was ultimately withdrawn. Including these items in the related income tax effect, adjusted net income was $4.4 million or a $0.11 per diluted share in the quarter. Operating revenues from the three months ended March 31, 2014 include oil and natural gas sales of $33.3 million from average production of $4,355 BOE per day on a two stream basis.

As Fred noted earlier, this represent a sequential increase of 46% over the fourth quarter 2013 Permian production. Oil production in the quarter represented 85% of total production on a volume basis and contributed to 93% of our total revenues. A proportion of oil production was above guidance of 80%, get to near-term gas curtailment mostly in Midland County. We currently forecast a similar oil percentage of production in the second quarter for normalizing the second half of the year.

Our average realized commodity prices for the first quarter were $93.12 per barrel of oil and $6.54 per MCF of natural gas, including Btu adjustments for NGLs. On a barrel equivalent basis, this equates to $84.82 for BOE produced in the quarter.

I will now move to expenses and note that all of our expenses were within with the low guidance, with the exception of production taxes, which were elevated due to higher than anticipated realized pricing relative to our budgeted levels. Our total LOE for the quarter, including workovers, was $10.78 per BOE for the quarter, which was below our expectations on guidance. This increase was largely attributed both to an increase in proportion of horizontal production in our total production mix. Horizontal production represented approximately 76% of our total production in the first quarter and is forecasted to increase throughout the year.

Moving to G&A expense, we had two one-time items in the quarter related to retirements and a threatened proxy contest that contributed to a $3.7 million increase in income state expense in the quarter. In addition, with a non-cash expense of $2.7 million related to the mark to market value of our phantom stock incentive awards plan. As a reminder, the mark to market value of these awards is determined on a quarterly basis based on Callon’s current stock price multiplied by a number of shares that is determined based on Callon’s simulated stock performance relative to our peer group over time.

Excluding the impact of these nonrecurring and non-cash mark to market items, adjusted G&A expense was $4.5 million in the first quarter of 2014, which was equal to the comparable amount in the fourth quarter of 2013. Interest expense occurred during the quarter was $977,000 compared to $1.6 million for the previous quarter. This decrease is primarily from the partial redemption of our senior notes, which occurred in December of 2013. We expect to similarly benefit from a reduced overall cost of debt capital with the full redemption of our senior notes which was completed on April 11.

I will now move to cash flow and related items. Discretionary cash flow for the three months ended March 31, 2014 totaled $18.7 million or $0.46 per diluted share. In addition, adjusted EBITDA for the fourth quarter was $21.9 million. Our total operational capital expenditures for the quarter were $53 million on a cash basis. These expenditures included the drilling of nine gross wells with an average working interest of 90% and the completion of seven gross wells with an average working interest of 96%. The average lateral length of the completed wells in the quarter was 7,315 feet, which was above our planned average lateral length of approximately 7,000 feet for the year.

Our first quarter drilling plan included an increased number of drill wells as we finished wells that were delayed by weather as it occurred last December. On the completion side, the pace of roughly seven wells per quarter as seen in the first quarter is reflective of our ongoing operations as we continue in program pad development mode.

As we’ve discussed, Callon has transitioned to using larger completions in our Southern Midland Basin fields. We believe that this initiative is contributing to improve production rates and providing a potential for greater reserve recoveries and returns on capital. As a result, we intend to incorporate this new completion design on an ongoing basis with an associated cost of approximately $500,000 to $800,000 per well depending on formation depth. This program is estimated at approximately $9 million to our current operational capital budget of $185 million for the year.

We are also evaluating the timing for our first well on the recently acquired acreage in Upton County, which will impact our capital budget and overall drilling schedule for 2014. We will be providing more formal CapEx update on our second quarter earnings call, but we currently estimate that the total net increase in operational capital from these items will be approximately $15 million.

We ended the quarter with liquidity of $127 million based on our current borrowing base in the initial availability under our second lien facility. The first borrowing base redetermination under our amended revolving credit facility will be based on reserves at the end of this month providing the opportunity for a near-term increase in the borrowing base, following the recent increase to $95 million based on year-end 2013 reserves.

As part of the continued focus on reducing our cost of capital, we recently completed the full retirement of our senior notes. Pro forma for that transaction, our total debt to the first quarter adjusted EBITDA on an annualized basis stood at 1.3 times at March 31.

As previously discussed, we recently revised our 2014 annual production guidance upward to a range of 5,100 to 5,400 BOE per day with an oil contribution in the range of 82% to 85%. Our cost guidance has also been updated as part of the production increase with LOE estimates in the range of $9 to $10 per BOE and adjusted G&A in the range of $9 to $10 per BOE.

We’ve also established second quarter ’14 guidance with production in the range of 5,000 to 5,250 BOE per day and estimated oil contribution in the range of 82% to 84%. LOE including workovers in the range of $9 and $10 per BOE and adjusted G&A in the range of $9.50 to $10.50 per BOE. In terms of hedging for the balance of 2014, we currently have approximately 52% of our forecasted oil production and 33% of our forecasted natural gas production, hedged under swap agreements tied to NYMEX prices. These figures reflect 2014 oil swaps that were recently executed for 1,000 barrels of oil per day in the third quarter at $99.87 per barrel and 700 barrels of oil per day in the fourth quarter of $96.92 per barrel.

I’ll now turn the call back to Fred, for few final comments.

Fred L. Callon

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

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Philips Johnston from Capital One. Please proceed.

Philips Johnston - Capital One Securities

Hey, guy, thanks. What are the determining factors in terms of whether you add a third rig either later on in the year or early next year?

Fred L. Callon

Yes, I think the -- a couple of factors I think as Gary has talked about, we feel like we have a very efficient operation with our two rigs rotating now between our four fields and I think we’re -- would like to basically add a fifth field at some point or area of operations that we could add into the mix. And as we mentioned before, we continue to look at acreage opportunities, typically some bolt-on type opportunities in our focus area there in Midland County area, so we’re hoping that we will have an area that we feel like its ready to -- that would help justify adding a third rig hopefully sometime later this year.

Gary A. Newberry

This is Gary. I will just add that we’re quite efficient with what we’re doing now, with the four development areas, two rigs going back and forth the infrastructure that we’ve got built, I mean we’re fracking wells the week after the rig moves off. I mean, so we’re quite efficient with that. We want to stay efficient with that to make certain we’re utilizing our capital very, very well. But just to highlight a couple of things, we talked about a new position that we acquired in the last quarter in southern Upton County. So we’re talking about a two rig program, don’t be surprised if a rig comes and goes occasionally, a rig of opportunity, to kind of test that area and potentially even test what we see is significant potential even in our pecan acres area there in just close to our Carpe Diem field. So we may have a rig of opportunity that comes and goes even this year, which is kind of part of the added capital that we’re talking about now.

Philips Johnston - Capital One Securities

Okay. And what are your current thoughts on the vertical appraisal program at (indiscernible), given the latest two results. I guess the Lacey Newton well was very impressive, so I assume you are at least highly encouraged still. I'm just kind of wondering what your approach is, going forward?

Gary A. Newberry

Well, we’re trying to balance how we best put the money to work and I have got to tell you, we’re really excited about the potential that we have in horizontal development, Southern and Central Midland. Very discouraged with our Lynn County exploration effort. We had good porosity across, but it was water field. That’s just the nature of our business. We really can’t do much more with that right now. We still have some tweaks to do with the current Matthew bear well that in order to fully test the prospectivity of the miss. We just got connected somehow to water in the Ellenberger. So we will fix that and see what that well will do to test it, but frankly I’m starting to think that that’s really a vertical play. It’s a vertical play that could be very nice vertical play in isolated spots where we know we had good resource potential. But I don’t want to take away focus from my team right now on what we’re doing on the horizontal side.

Philips Johnston - Capital One Securities

Okay. And just lastly, can you give us a little bit more color on your upcoming lower Spraberry well that you planned in the third quarter in terms of what your expectations are, what kind of lateral and stages are you planning for that well?

Gary A. Newberry

Yes, that’s when we move the rig back now to Carpe Diem in Central Midland Basin. That will be a three well pad. It will be two wells in the B and one well in the lower Spraberry. And that will be a long lateral. That will be an (indiscernible) foot lateral. We are working kind of hand in hand with RSP in that area. We know RSP has a good bit of experience in drilling those wells. We are encouraged with what they reported. We are encouraged with the recent results that Diamondback has reported. We think our wells are going to be just as good or better. So clearly that’s a good area, no question about it. It’s been derisked by other players and we’re happy with that.

Philips Johnston - Capital One Securities

Okay. Great job on the execution, guys. Thanks.

Gary A. Newberry

Thank you.

Fred L. Callon

Thanks.

Operator

Your next question comes from the line of Ryan Oatman from SunTrust. Please proceed.

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

Hi. Good morning.

Fred L. Callon

Good morning, Ryan.

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

Very good review of the well results, new EURs, very good overall presentation and a lot of my questions have been kind of preempted here. But can you just remind us of your overall acreage count in each area and each of the four fields currently? And then also, looking at the 35% plus growth for 2015, is that predicated on kind of this year’s capital spend level of $185 million to $200 million or do you see the potential through rig efficiencies to drill more wells and spend a little bit more capital to get that same sort of growth?

Gary A. Newberry

Ryan, I will -- again, I don’t have the exact acreages by field. But I can tell you we got about, in our derisked areas that we’re operating quite efficiently on with our two rig horizontal program, the Southern and Central Midland Basin, we’ve about 12,700 net acres in that area. And so I just don’t pay much attention to this to the exact area, because I look at it in the length of horizontal development that I can get and the longer the horizontal I can get and the more efficiently I can develop that acreage that’s kind of the way I look at that. And then we have still in the northern area that we’re not as excited about is about 13,000 acres. So, still a lot to do with that 12,700 net acres sort of a minimum of three de-risk levels likely now four with all the work going on in the lower Spraberry. Significant inventory of work to do if we start counting opportunities in the three levels that we know are working on our area, would get to like 266 horizontal wells. So, significant well beyond 10 year inventory of work. We started counting the lower Spraberry which we’re about to prove up ourselves even though others have already proved up around us, you get out to about 370 wells. So we’ve got a lot on our plate, excited about it.

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

That’s great color there. And Joe maybe a quick here, I mean you guys have been pretty successful in working capital management here. I mean do you day’s payable and receivable remaining near-term ratio as moving forward?

Joseph C. Gatto

I think that on a day’s payable and receivable rate, I don’t think that changes all that much. I think what you’re seeing over the last quarter or so is really that the two rig program getting its strut. We put the second rig to work in third quarter last year, but we’re starting to -- really started clicking along with that. So, some of that gets front loaded in that first quarter with an increase in payables that we’ll start to unwind a little bit in the second quarter as that comes down. But on a day’s payable and receivable basis I think those are reflected in there just we had a pretty big ramp in going into this year on the activity side, but that will start to normalize as the year goes on.

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

Perfect. And then finally just talking through the exit rate. I wanted to kind of understand, I mean its 6000, did I hear you correctly there, and I mean is that kind of 6000 to 6250 or do you think you do above or how should we think about the rounding I guess of that 6000 number?

Joseph C. Gatto

I’ll take a quick shot at that. I want to provide certainly some direction for the long-term of an exit rate. It is a little bit tough pinning down exit rates. What we think about exit rates historically was to take the average of December for instance, and that’s how we based the last years I guess 3500 per BOE per day. 6000 I think is a number that we feel very comfortable with. There are some timing issues with pad development and when you expect pad to be coming on. So, that number is probably more reflective of the average for the fourth quarter, I mean not necessarily a point in time or a month in time. So, we feel good about that number. It certainly could be higher but given -- trying to pin down a month in time with all the activity that we have going on it's a little bit difficult. So, probably I didn’t answer your question as directly as you would like, but I think overall we feel good with that number as it's certainly an average for the fourth quarter now where points in time shakeout in that mix, it could certainly be higher.

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

Great. Now that’s helpful, I mean so it's not a -- obviously there is some fluctuation, but for an average for 4Q that’s a hopeful number for us to think about. And I’ll hop off here, but one last one, I mean we did hear a large Permian operator this week discussing the potential for cost inflation at 2015 of about 10% I mean seemingly across the board whether it be for labor rig conclusions. Are you guys seeing that type of upward pressure and can you just comment on the broader service, and I guess gas processing environment while you’re at it? Thanks.

Gary A. Newberry

Yes, we are seeing some upward pressure on cost, but we’ve actually been able to control that to a certain degree with the partners that we use in order to complete our wells. Now we’ve got two practice rigs running. Those rigs are locked in for a couple of years and so, we’re good with that now. And then, our fracture services, there is certainly cost increases for certain items and products, but as we continue to push our laterals longer our cost per stage still continues to be going down. So, we seem to be optimizing that in a way that we think makes sense. If we can get more efficient with developing our acreage position with longer laterals even in a higher cost and brand we can deliver a better value position for you all and for us.

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

That’s very good. And I think you guys mentioned a little bit in terms of gas processing, what you’re seeing there and kind of like more Midland counties specifically. Can you talk about, it sounded like those bottlenecks were being taking care of here in the short-term. Can you provide a little bit more color there?

Gary A. Newberry

Yes Ryan, I’m sorry I missed that one, but yes. In first quarter we had procurement both at in Southern Midland -- Southern Upton at Bloxom field as well as in Carpe Diem or Central Midland Basin and that experience is that all other companies are experiencing too. I mean we know who our offsetting operators are. We talk to them on a regular basis. We see this happening and of course it's all around timing for infrastructure expansion. It looks like we’ve fixed the Upton County stuff for now, and we are still curtailed a bit in the Central Midland Basin on gas capacity to move the product to a plant. There will be pipelines coming into the area in the third quarter which should alleviate that.

Ryan Oatman - SunTrust Robinson Humphrey, Inc.

Perfect. I’ll hop back in the queue. Thanks.

Operator

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

William Green - Stephens Inc.

Thank you, guys. Walking through, I appreciate all the color you guys gave on kind of the upcoming completions and everything you guys have done to date. I wonder if you could maybe help us with how many wells have been turned to sales so far in second quarter and maybe how many are kind of in the process of being completed that will get turned to sales before the end for the quarter?

Gary A. Newberry

I know that we’ve already turned three additional wells to sales. Will, my team is executing so well, I don’t even count these wells this way anymore, but I look at a schedule hence if I can’t answer your question. So, second quarter at least according to our schedule and my team is doing quite a good job staying with this. It looks like we’re going to have again another seven wells coming on in the second quarter, and that will be a combination of wells in both Central and Southern Midland. So Central Midland and Southern Upton and Reagan. So, same pace, same turnover as we just reported from first quarter or second.

William Green - Stephens Inc.

Got you. And I would assume that you guys are getting a little bit quicker as you move through the year as well, drilling base, completion base, all that sort of stuff.

Fred L. Callon

Yes, we compare ourselves to ourselves as well as to others every well we drill. And we’re getting better at every stage at the drilling cycle and we expect to improve somewhat over the year and importantly the cycle time from spud to first production is shortened simply because of the nature in which we’ve designed our facilities, the nature in which we planned our work, and the reliability of the partners that we have in helping us complete our wells. So, yes we’re getting better throughout the year. Hopefully we will be able to talk about significant improvement sometime later in the year, but our cycle time is as good as anybody’s when I’ll see what's reported by other companies out in the Basin.

William Green - Stephens Inc.

Great. And then the last one I wanted to hit on is, as you guys obviously have a lot of kind of vertical points controlled throughout your acreage position. Have you guys looked at the Middle Spraberry or Jo Mill up there in Midland County and how does it look to you, is that something you guys might test at some point. I know it's not on the list for this year, but maybe early ’15 or something like that?

Joseph C. Gatto

No, we have looked at will, and we do see it as being very perspective certainly in Midland County, likely both the Carpe Diem and Pecan Acres. So we’re excited about that potential. It's on our list of opportunities. I just didn’t go up to that high of a number when I was talking about those numbers earlier.

William Green - Stephens Inc.

Great. I appreciate the color guys.

Joseph C. Gatto

Thanks Will.

Operator

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

Ronald Mills - Johnson Rice & Co. LLC

Good morning. Maybe for you Gary, if you look at your 2014 program, how should we think of the program amongst your four project areas and/or if you look at the three formations plus the first test at the Spraberry, how does the activity look by formation?

Gary A. Newberry

Again most of our work is focused on still the Upper and Lowed B throughout our areas. We’ll have that first Spraberry test in Carpe Diem or Central Midland Basin in the third quarter results, probably in the fourth quarter. We’re talking about even another Spraberry test later this year even potentially Pecan Acres that would kind of pull up all the city permitting and things like that, that’s just another perspective type well. And then now that we feel good about the A. I mean the A, haven't given me a lot of detail about the acreage I am still trying to learn about it. But the A is performing quite well at Bloxom, and so we feel that, that data point as we further define it is going to give us a every bit of opportunity the way the B gives us at Bloxom. And we’re, as I have mentioned we’re about to test that very same concept at Garrison Draw. So, we think that’s going to spread across and so the A will become more of our portfolio in 2015 and beyond, but most of this year it will still be focused on the Upper and Lower B.

Ronald Mills - Johnson Rice & Co. LLC

Okay. And then on the updated EURs; is there much difference between the Wolfcamp, the Upper versus the Lower Wolfcamp B. It sounds like it's too early for the question or to answer that question on the Wolfcamp A, but how about between the two Wolfcamp B zones?

Gary A. Newberry

We don’t see much difference Ron at all. We see it very perspective in both levels. Micro seismic supports two levels and it looks like it's working well for us.

Ronald Mills - Johnson Rice & Co. LLC

Okay. And then you walked through the drilling inventory in the three main zones and what the base case was in terms of lateral length. But if you’re going to start drilling it seems like some longer laterals, if you look at your acreage positions it by area or just in more general terms, how much of your acreage sets up for the 7000, the 9000 foot laterals versus some areas where you may have to drill a little bit shorter?

Gary A. Newberry

Yes, all of our acreage is set up nicely for long laterals, Ron. And in fact what I would suggest is, the areas that we’ve been drilling shorter lateral is simply because of geography because of the way the leases are set up, we had two sections north-south. We’re now starting to convert that to 10000 for laterals. So, we’ve become very efficient from a capital perspective in developing that set of two wells, two infrastructures it's going to be one well efficiently completed long laterals with good rates. So, nearly all of our acreage now sets up for the long laterals. Again, the longest we’ve drilled has been a 9000 foot lateral at Carpe Diem it went very, very well. The clean out or the drill out after we completed the well went quite well. So, we have a high level of confidence that we can repeatedly achieve 10,000 feet now that we’ve gone to that level especially Carpe Diem was our deepest and longest lateral, and we’re ready to convert to that model. So, where we had three sections north-south now, so that’s -- our shortest laterals will be probably 7500 feet for the most part going forward. And where we have a single section here, there kind of like the new stuff we just got in the first quarter, we will be looking to partner with other players north and south of us to again be very efficient with the way we develop these areas going forward. And those guys around us are all very capable drillers and completion companies just as we are. So, I think partnering is the right way to go.

Ronald Mills - Johnson Rice & Co. LLC

Okay, that’s it for right now. Congrats you guys.

Operator

Your next question comes from the line of Jeff Grampp from Northland Capital Markets. Please proceed.

Jeffrey Grampp - Northland Capital Markets

Good morning guys. I was hoping to talk a little bit more about you guys referenced the three well pad in East Bloxom with the two Bs and the one A. Can you give us anymore kind of incremental detail around results there if you saw any benefit or anything as far as kind of doing the stacked well bore orientation there?

Gary A. Newberry

I don’t know if I would suggest if there is benefit to be doing it stacked wise, I mean we see there is plenty of separation to support both levels of development. The stacked, the lateral at the pad development simply allows us to be very efficient with developing three wells, sharing the mode cost for the rig, minimizing the move time related to a rig, actually doing different fracs across the entire section to the point where you can frac more stages in a given day and complete more work over a shorter period of time. So, the pad development is clearly a major issue associated with being very efficient. And of course we moved to pad development early time. We had a lot of confidence in what our technical team saw and the potential, and so we have been utilizing pad development really from the beginning, and now our goal is to get incredibly good at that. But to give you a little bit more color about the three well pad specifically your question, we put more sand in these wells, and we just didn’t want to take the risk of hurting that stimulation. So, we have actually controlled the drawdown on all three of these wells. We wanted to see is if we had a really good opportunity here to compare what we have really known potential in the B with how the A well would perform specifically against these other two wells drilled and completed at the same time. And so we’re looking at these three wells as early a test for what we see as long-term potential for the A. And we look at this data every week. And so we’re plotting production, we’re plotting casing pressure, we’re plotting all kinds of things on these three wells so that we can understand from a technical perspective how well we’re connected to the resource in the A versus the B. Now the A is a little bit lower pressure, but frankly it's performing essentially the same. And in fact the way we’ve kind of operated this, it's a little too soon to tell but the way we’ve kind of operated this with controlled drill down to where we avoided real high peak rates. We actually did, we intentionally avoided that on these three wells, so that we could get a sense for a longer term stable performance as well as how the pressure regime in these wells was actually changing or perhaps staying the same. So, if you take a look at this data, and I’m looking at it right now, frankly I am encouraged with how stable it is and potentially even the slight uptick over time. So, we got a lot to learn here, but we’re excited about the A.

Jeffrey Grampp - Northland Capital Markets

Okay, great. Thanks for that color. And then just curious in reference to the well cost that you guys just provided us with here, does that assume some benefit from pad development or is there some potential to take those costs lower as you guys kind of ramp up doing some pad development with more frequency?

Gary A. Newberry

No, that all includes the benefit of pad development.

Jeffrey Grampp - Northland Capital Markets

Okay, got it. And then last one for me, it sounded like with these kind of pressure management things that you guys are looking at doing here. It sounds like there is maybe some potential for further EUR increases. Given that these floor rates you’re looking good, is that kind of the right way to think about it or that already kind of reflected as well in the EUR numbers that you guys provided us with?

Gary A. Newberry

I am very comfortable with the EUR that we talk about. So, over time I would expect that those numbers would still have an upward trend to that.

Jeffrey Grampp - Northland Capital Markets

Okay, great Thanks for that guys. Good job on the quarter.

Gary A. Newberry

Thank you.

Operator

Your next question comes from the line of Adam Fackler from MLV & Company. Please proceed.

Adam Fackler - MLV & Company

All of my questions have been answered, but I appreciate it. Thanks guys.

Operator

Your next question comes from the line of Tim Rezvan from Sterne Agee. Please proceed.

Timothy Rezvan - Sterne Agee & Leach, Inc.

Hi, good morning folks. I had a question more on a liquidity angle. First to clarify, Joe did you saw $177 million of liquidity?

Joseph C. Gatto

$127 million.

Timothy Rezvan - Sterne Agee & Leach, Inc.

$127 million, okay. And clearly there is an upward trajectory to that when your credit facility gets redetermined, you see cash flow pushing closer to $100 million this year and the borrowing base, I mean what, is it that fifth field that’s the big impediment to adding that third rig, because you have a pretty substantial inventory right now. I’m just trying to understand what the milestones are to add that third rig?

Joseph C. Gatto

I mean, Gary addressed this earlier, but given the production growth we’re having and how that adds to our liquidity on the borrowing base and the reserve adds. I think we feel pretty good about that sort of trajectory as well as just where we are from an absolute leverage standpoint. And if you look back at last year with bringing in equity like proceeds from the sale off the Gulf of Mexico, the sale of our perpetual preferred, we got a lot of room on the balance sheet from just an overall debt capacity it being at 1.3 times debt to EBITDA right now. So we don’t see the capital side as being constrained. I think is, when we add the third rig we are in program development, we want to add a rig in a similar vein and want to capture all the efficiencies, so it's really just finding the right configuration for Gary and his team to put that rig into a steady development program, so Gary can add to that but, I think we’re just continuing to assess the resource potential we have. We want to alternate between fields. We don’t have a lot of overlapping, drilling and completion activities going on at any one time, but there are opportunities within our existing asset base in the coming months to add that third rig.

Gary A. Newberry

And I’ll just say since Joe invited me to say a few words. Again what we’re doing in the new stuff we just got at Southern Upton and what we’re thinking about doing with our Pecan Acres. Maybe that does, after we kind of figure out how to get that done in an efficient manner, and that does give us adequate room to move back and forth again with the third rig. But we just had a little bit of work to do around that with our existing acreage position. And then I could, you guys are right we have lots of opportunity on our existing position. And we could go ahead and build out additional infrastructure to park away in a field. But with that we got to be very careful with the way we execute so that we utilize this capital smartly. I’m really impressed with what the team has done to this point in getting very good at executing on these wells, minimizing the cycle time and utilizing this capital on a smart way to where we don’t delay these production ramp ups, in fact we’re trying to accelerate them even further. So, with the new additions with Pecan Acres maybe we get there later on maybe 2015, but we’re always looking for that opportunity.

Timothy Rezvan - Sterne Agee & Leach, Inc.

Okay, I appreciate the detail there, and then I’ll ask one last one. What are you seeing out there on the market as you try to put together more acreage, is there more opportunity in a certain part of the field there, how big do you think you can grow either in terms of acreage or pricing?

Joseph C. Gatto

I’ll start on that. I think we certainly see opportunities as we’ve demonstrated here certainly in the last quarter, an opportunity to add 1000, 1500 acres per quarter around our existing core areas. I think we’re really finding some immediate opportunities to add value. Finding some acreage that might not be set up for long lateral horizontal developments day one or just get lost in some larger company’s portfolios that we can pick up and really spend the time and focus with our land team and operations team to turn that into some nice opportunities. We certainly did that as Garrison Draw with a couple of follow on deals after we got into that position. So those opportunities are sort of part of our day to day that we’re out there and that what we find, a pretty good pipeline of those in addition to trade opportunities, partnership JV type opportunities. So, that’s all part of just more efficiently expanding our existing acreage in core areas. Over the last quarter the 1500 net acres we added was at a cost roughly around 5000 per net acre which we think is pretty attractive especially if we can add value on the backend, that’s one part of the approach. The other part is going to be looking at larger opportunities which we are certainly looking at everyday. Those are most likely to have production associated with them which allows us to use that as a base of some financing and take on some larger opportunities. We have a lot to do as Gary talked about but in our minds we have the team from a technical or operational standpoint that, things are clicking well. We certainly have the capacity to add a third and fourth rig with the existing organization we have and we just really need to find those types of opportunities in a smart way. But once we do, I think we’ve demonstrated what we can do with acreage when we get in our hands, so that’s going to be a continuing effort for us.

Timothy Rezvan - Sterne Agee & Leach, Inc.

Okay. Thank you so much.

Operator

(Operator Instructions) Your next question comes from the line of Ron Mills from Johnson Rice. Please proceed.

Ronald Mills - Johnson Rice & Co. LLC

Gary, just one I forgot to ask you. You’re using the larger fracs I think more in the south where it's, it maybe a little bit lower pressured. Any thoughts about testing more or higher proppant concentrations even up in Midland County?

Gary A. Newberry

That’s a good question, Ron but the simple answer is likely not. And the reason is, it's deeper and because of the depth we start reaching some of our pressure constraints in getting the sand away, so we are happy with those results. We’ll be paying close attention, very close attention to how others frac their wells both RSP, Diamondback and Pioneer. But right now all our formulas are about the same in that area simply because of the depth and higher pressures necessary to frac the wells.

Ronald Mills - Johnson Rice & Co. LLC

Great. Thank you.

Operator

I would now like to turn it back over to Fred Callon for closing remarks.

Fred L. Callon

Thank you. Again we appreciate everyone taking the time to call in. And in the meantime, if anyone has questions please don't hesitate to give any of us a call. Thank you again.

Operator

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.

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