Mar 5, 2015
Executives
Eric Williams - Manager of Finance Fred Callon - Chairman, Chief Executive Officer Joe Gatto - Chief Financial Officer and Treasurer Gary Newberry - Senior Vice President of Operations
Analysts
Will Green - Stephens Phillips Johnston - Capital One Ron Mills - Johnson Rice Jeb Bachmann - Scotia Howard Weil Ryan Oatman - SunTrust Chad Mabry - MLV & Company Andrew Smith - Global Hunter Mo Dehghani - Northland Securities
Operator
Good morning, and welcome to the Callon Petroleum Full Year and Fourth Quarter Financial and Operating Results Conference Call. All participants will be in listen-only mode.
[Operator Instructions]. Please note this event is being recorded.
I would now like to turn the conference over to Fred Callon, Chairman and Chief Executive Officer. Please go ahead, sir.
Fred Callon
Good afternoon. Thank you for taking time to join our fourth quarter 2014 results conference call.
Before we begin, I’d like to ask Eric Williams, our Manager of Finance, to make a few comments. Eric?
Eric Williams
Thanks, Fred. At this point, I would 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 belief, 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, included in our 2014 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, adjusted EBITDA and adjusted net income.
Reconciliation and calculation schedules for such non-GAAP financial measures are available in our fourth quarter 2014 results news release and in our filings with the SEC, both of which are available on our website.
Fred Callon
Thank you, Eric. Again thanks everyone for joining this morning.
Last month we announced our year-end reserves and 2015 guidance as well as initial results from wells from our Ca-Bo Acquisition that were in excess of our previous expectations, especially for the Lower Spraberry formation. We’re very pleased to report 121% increase in our proven reserve base which stood at 33 million barrels of oil equivalent at year-end 2014, the crude-developed component of 55% and 78% oil content.
The underlying additions of 15.7 million barrels of oil made at an average drill-bit F&D cost of $13.91 per barrel, which was a decrease of approximately 10% over 2013 results. With only 53 horizontal proved undeveloped locations carry December 31, we continue to employ conservative booking philosophy across our asset base.
Of that total horizontal PUD number, only three are associated with Lower Spraberry which is expected to become a larger contributor to our asset profile over time. In addition, we carried only one vertical PUD location at year-end, which was recently drilled and now on production as the company focuses on its horizontal development program going forward.
In last night’s release, we announced strong production growth with an increase of approximately 155% over 2013, on the strength of our horizontal drilling program and completion of our Ca-Bo acquisition in the fourth quarter. Even with our reduced capital budget, we’re forecasting growth of approximately 15% for the fourth quarter of ‘15, from this most recent quarter.
While sustained growth in our assets is an important objective, our pursuit of that goal is also governed by a strict focus on capital efficiency and financial discipline. Despite the pull-back in commodities, we estimate average returns of 25% of our drilling program at $55 flat realized oil prices and assuming the well cost reductions achieved to-date.
As Gary will discuss, we’ve continued to make significant strides on further well cost reductions that would increase these returns, further reduce our F&D cost. Although we expect to spend above our current cash flows this year, we pre-funded a large portion of our activity with long-term capital raise of almost $430 million last year, which is complimented by $250 million borrowing base facility, which was less than 15% drawn at year-end.
As we look at execution of our drilling program over the longer term, we remain focused on progressing to a cash flow neutral position based on current oil price curves. Given our expected well cost and operating cost reductions combined with the outlook of production levels, assuming two-horizontal rig program, we believe that the cash flow breakeven position could be achieved by the second half of 2016.
I will ask Gary Newberry, our Senior Vice President of Operations to discuss our operational results for the fourth quarter and an update on our 2015 outlook.
Gary Newberry
Thank you, Fred, and good morning. With the operations updated provided last month on the data provided on our latest investor presentation on the website, my comments related to new operational data points will be limited on this call.
And we will be providing additional information on the first quarter call in early May. From an operational perspective, we dedicated a great deal of focus during the fourth quarter to the integration of the Casselman and Bohannon acquisitions, which closed on October 8, with our assumption of operatorship on November 1.
I’m pleased to report that the transition is going well and we have also made progress, developing good working relationships with our working interest partners. In addition, we’ve had constructive conversations with offset operators and secured off-lease surface locations for our planned wells in 2015, which effectively allow us to access an incremental 10% of completed lateral length.
This progress combined with the encouraging initial well results in both the Wolfcamp B and Lower Spraberry make us even more excited about the potential for this new core area. Daily production in the fourth quarter was 7,270 barrels of oil equivalent per day, and included the impact of weather related downtime at the end of the quarter, at the time when we were producing around 8,000 barrels of oil equivalent per day.
LOE decreased by 7% from the third quarter as we continue to leverage fixed cost across our growing production base and benefited from reduced downtime due to improved chemical treatments and raising rod pumps in vertical wells. During the fourth quarter, we instituted a more stringent framework for performing work-overs of mature vertical wells, with the decline in commodity prices.
Our resulting reduced number of expected work-overs combined with lower associated work-over service cost is a key driver of our LOE forecast over the course of 2015. As previously released, we have made the decision to reduce our drilling pace to two horizontal rigs starting this month.
We expect this program to result in approximately 24 net operated wells being placed on production in 2015 across our core acreage position in Midland, Upton and Reagan Counties. During the first quarter of 2015, we estimate five gross wells to come online at our East Bloxom and Taylor Draw fields in the Southern Midland Basin, and contribute to an average daily production range of 7,800 to 8,100 barrels of oil equivalent per day, representing a sequential growth rate of approximately 10% over the fourth quarter of 2014, despite the impact of weather during the first two weeks of January, and additional weather impacts experienced late last week.
We’re certainly pleased with the quality of our asset base and its ability to generate robust returns in the current commodity price environment. Our key contributor to the return profile is the well cost reductions our team has been able to secure over the past few months by working closely with our service partners.
Our 2015 budget that was released in early February, incorporated reductions across several key capital cost categories based on the progress we made with our service partners through the month of January and implied achievable reductions in total well cost during the first half of 2015 of approximately 15% relative to 2014 levels. As of today, we are writing AFEs for total well costs that are already 20% below levels in 2014.
Fielding on that momentum with a broad range of service partners, we now believe that total well cost could be down 30% from 2014 levels in the second half of 2015, which would be ahead of our original expectations. These incremental reductions will result in well cost of approximately $5.1 million for 7,500-foot laterals and $4 million for 5,000-foot laterals.
And importantly contribute incremental rates of return of approximately 10% to 15% assuming a flat realized oil price of $55 per barrel. We firmly believe that this pace and magnitude of reductions is the product of the strong relationships we have built with key service partners over the last few years, and our willingness to work together through difficult price environments.
While these reductions are important in driving calculated returns on capital, we see additional benefits from the retention of an exceptional highly dedicated and efficient contractor workforce, which will be a differentiating asset for us in the future as other operators reenter the market after deferral of their near-term activity. We’re off to a good start for 2015, and we are well positioned for efficient program development of the four productive zones we have established to date.
While we remain focused on the Wolfcamp B, a longer term performance of our initial Lower Spraberry wells is very encouraging and we will likely attract more additional capital allocated to the Lower Spraberry over time. I will now turn the call over to Joe Gatto, our Senior Vice President and CFO.
Joe Gatto
Thanks, Gary. Our reported net income for the quarter on GAAP presentation was $17 million or $0.30 per diluted share.
This figure included the impact of the following items on a pretax basis: non-cash unsettled gains of $14.2 million related to our mark-to-market of our hedging portfolio, a non-cash gain of $1.7 million related to the mark-to-market valuation of performance-based incentive compensation awards. And non-cash loss of $2 million related to the re-financing of our previous term-loan balance.
Excluding these items and the related statutory income tax rate of 35% for the quarter, our adjusted net income was $3.1 million or $0.05 per diluted share based on our average diluted share count of 56.3 million shares. Operating revenues, excluding the impact of hedges for the three months ended December 31, 2014 were $38.4 million from an average two-stream production of 7,270 BOE per day.
Fourth quarter production volumes represented a sequential increase of 29% over third quarter production comprised of 79% oil. Our average realized commodity prices for the fourth quarter, excluding hedge impacts, were $65.05 per barrel of oil and $4.78 per MCF of natural gas, including BTU adjustments for NGLs.
On a barrel of oil equivalent basis, this equates to $57.44 per BOE produced in the quarter. Our oil realizations include a moderation in elevated Midland basis, differentials that were experienced for several months earlier in 2014, with an average differential relative to Cushing of approximately $5.75 in the fourth quarter versus an average of approximately $7 per barrel for the year.
This differential decreased significantly during the course of the fourth quarter and subsequently settled in an average of approximately $2 per barrel since beginning of 2015. Our hedge position had incremental exploratory operating cash margins with cash settlements related to our hedging position totaling $10.57 per BOE in the quarter.
On a mark-to-market basis, the current value of our hedge portfolio for 2015 is approximately $25 million. Moving to expenses.
Our LOE, including work-overs, was $11.23 per BOE for the quarter, which was slightly above our guidance represented a sequential quarterly decrease of 7%. With the progress we have been making out reducing this expense item, including a decreased number and cost of vertical well work-overs, we expect an LOE range of $9.50 to $10.25 per BOE in the first quarter with ongoing reductions realized throughout the year.
Adjusted G&A expense, which excludes the impact of mark-to-market valuation items, was $3.9 million in the fourth quarter of 2014, a 17% decrease compared to the $4.7 million in the third quarter of 2014. The cash component of this adjusted G&A was $2.9 million for the quarter or $4.35 per BOE compared to $3.8 million or $7.27 per BOE in the previous quarter.
Looking at 2015, we expect to see continued decreases in G&A expense per BOE in the coming quarters. This decrease not only reflects continued production growth but also to a larger degree the impact of an early retirement program and other cost initiatives that we implemented last month.
In total, we forecast that these combined initiatives will reduce total recurring cash G&A including both expense and capitalized portions by over 20% going forward. One-time expenses associated with the early retirement program will be recorded in the first quarter of 2015.
Operational CapEx excluding acquisitions and capitalized items for 2014 in total were $217.7 million relative to a capital budget that was set at $215 million. Operational CapEx expenditures were $49.6 million in the fourth quarter and included the drilling of 5 net wells and the completion of 7.3 net wells.
We expect first quarter 2015 operational CapEx to be similar to slightly above the fourth quarter level, with the early impacts of well cost reductions are offset by accruals for fourth quarter activity under the three-rig program are paid in the first quarter of 2015. With the step-down in drilling activity that will occur once the third rig is released this month, combined with the increased pace of well cost reductions that Gary discussed, we expect to see an increase in cash on impact on capital expenditures beginning early in the second quarter.
For the total year of 2015, we’ve previously released an operational CapEx budget of $150 million to $165 million, and now believe we’re trending towards the lower end of that range with our continued progress on the capital savings front. Looking out to 2016, we currently estimate that our operational capital program would be in the range of $105 million to $115 million, assuming the continuation of our two horizontal rig program and our current views on cost reductions that are achievable by the end of 2015.
From a leverage of long-term capital perspective, total debt to fourth quarter annualized EBITDA was 2.4 times, this annualized EBITDA calculation captures the majority of the impact of our recent acquisition that closed on October 8, and also incorporates meaningful commodity price declines experienced in the fourth quarter relative to trailing 12-month measures. In terms of liquidity, borrowings under our credit facility were $35 million at year end, translated into a liquidity position of $216 million.
Critical to operating in this environment is the generation of strong cash margins per BOE to fund our capital program and compliment the availability under our credit facility. Adjusted EBITDA for the fourth quarter was $32.9 million equating to $49.23 per BOE produced.
This margin compares to an average drill-bit F&D cost of $13.91 per BOE in 2014 highlighting our ability to generate cash flow at relatively high margins per BOE and redeploy that capital at favorable development costs that should continue to decrease with realized well cost reductions in the future. I’ll now turn the call back to Fred, for final comments.
Fred Callon
Thank you, Joe. Again, we appreciate everyone taking the time to call in this morning.
And with that, we’ll open the call to questions.
Operator
[Operator Instructions]. And our first question will come from Will Green of Stephens.
Please go ahead.
Will Green
Good morning guys.
Fred Callon
Good morning, Will.
Will Green
I wonder if we could talk about gas lift. It looks like you guys have had good bit of success there, can you talk about the amount of well you guys have implemented that on?
And maybe think about if you guys are looking at the cost side of the equation, what that could actually do on the LOE side issue, as you move forward?
Fred Callon
Yes, well that’s a good question. Gas lift is something that we truly believe is the right way to go over the longer term, and it helps us on a couple of fronts.
It helps little bit on the capital side and the fact that we don’t have to worry too much about the cost of ESPs, the potential risk associated with producing early time wells on ESPs. It helps what we think is importantly on the production side and helping us actually control the draw-down, we’ve talked about that quite a bit in our previous calls.
And so, really on a gas lift well, we actually let the well flow a little bit longer on its own before we take the gas lift on to help control the draw-down associated with that frac, near the well bore phase because, we’ve spent an awful lot of money establishing that well-bore we don’t want to take too many risk in damaging it. Now, frankly I think as you can see in some of the data that we’ve already published that even though you might get early time a bigger IP on our ESP well, over time you get better overall longer term performance from gas lift.
So, in total, I think as we leverage that centralized gas lift concept and we’re not quite there yet, because we still have had a gas lift compressors, our LOE cost will actually be lower in managing that full cost of operation for the wells. So we think gas lift is the right way to go, we think leveraging existing infrastructure to bring on new wells with gas lift makes sense, it reduces capital and expense and we’ll continue down that path.
Will Green
Got you, I appreciate the color there. And then, you guys looked at using a lot more profit in the second half of the year, it looks like, did you feel like if you hit a point of dimension returns at any point?
Or can we continue to see you guys push more profit down hole and look to hedge returns, I mean it definitely looked like the results you saw were much better with those additional profit volumes. I wondered if you could just give us some color there.
Fred Callon
Yes, Will, again we talk about that quite a bit is because we have seen some encouraging results for higher profit. And we’ve got several tests going right now from 1,000 pounds per foot to 1,300 pounds per foot, 1,500 pounds per foot and 1,900 per foot.
We have all of that data coming together and we’re looking at it. We have seen very encouraging results, but we don’t attribute all of those encouraging results actually to additional profit because we’re actually correlating, we’re looking at lot of technical detail.
And we’ve been getting a lot smarter about how we complete wells. So, we’re correlating in all the production, we’re also correlating in all to the type of formation that we’re completing in every individual well, the brittleness of that formation and its ability to fracture stimulated and propagate that fracture throughout.
And, so though we’re seeing encouraging results I’m not quite ready to say we’re all-in on higher serum concentrations with the upper limits, yet. But certainly more than what we’ve historically done.
Well, I can’t tell you exactly where I’m going to land. I’d be a little nebulous on that but I just haven’t landed on the right number yet to guide you.
Will Green
I appreciate that and I appreciate all the color, guys. Thanks for that.
Fred Callon
Thanks Will.
Operator
The next question will come from Phillips Johnston of Capital One. Please go ahead.
Phillips Johnston
Hi gentlemen, thanks. This is for Joe.
We’ve seen a lot of company issue equity in the last several weeks. I’m wondering if that’s something that’s potential on the table or would you rule that out given that your liquidity is very comfortable over $200 million, it should easily fund the project outspend this year and next especially with the cost savings that you’re now seeing?
Joe Gatto
Yes. Now we’ve certainly seen a lot of deals cross the tape.
From what our take is, most of them fall into the opportunistic category, save a couple out there. And certainly a few of those names haven’t been in the market for quite some time, at least based on our recent memory.
I guess that’s where we might be a little bit different than some of those names after we recently raised equity as part of the roughly $430 million we went out last fall to fund the acquisition. And also to pre-fund a lot of our activity going into 2015 as we saw the potential - to potentially dial-up to as many as four rigs.
So, clearly the commodity price environment has changed and we’ve changed with reduction and our activity going down two rigs and some of the changes that I talked about on our fixed cost structure. So, back to your comment, we certainly feel good about the position we’re in today.
But we do like to see that there is, more options available out there as we look at incremental opportunities in the marketplace going forward.
Phillips Johnston
Okay. And then, you guys referenced that the ‘15 CapEx budget of $150 million to $165 million assumes 15% to 25% of cost savings had in hand through the end of January.
Now there is a little bit of a downward bias to that range. My question is, if you wind up achieving sort of 30% lower cost in the second half of this year, how much downward bias is there to the range, I mean, is that simple as 5% to 10% incremental reduction so $10 million to $15 million or so lower?
Fred Callon
Yes, we don’t have exact numbers on it because as Gary can attest to is a constantly evolving process. And I think we can certainly say that the pace of achieving the reductions versus what we had in our original budget, we’re ahead of that.
And I think Gary and team have done an exceptional job of getting front of some key items on the well cost. I think we’ll probably in a position to reevaluate the magnitude of any potential decrease to that overall operational CapEx range.
And certainly try to refine it to a tighter range as we get closer to mid-year. But now while we’re encouraged with the reductions we’ve got, and we got to follow-through and deliver on those AFPs we’re writing.
But if we’re down solid 30% on total average well cost by the second half, which we think is a strong likelihood than, we’ll give this an opportunity to certainly move towards the bottom end of that range and maybe even then some.
Phillips Johnston
Sounds good, thanks very much.
Operator
Our next question will come from Ron Mills of Johnson Rice. Please go ahead.
Ron Mills
Good morning. Gary, Will asked about the proposition artificial lift.
You now have another quarter worth of data with your more managed and more controlled flow-back than what others are practicing. I’m curious how the production rates are holding up similar to your other two charts showing cumulative production.
Is it showing what you want to say that you’re going to continue to work control flow-back?
Gary Newberry
Yes, Ron, thanks for asking that. Yes and the simple answer to that one is yes.
We’re seeing very, very positive results on more stable well results, even at what we believe would be better than expected type curve. So, under the gas there to control flow back arena but more importantly we have seen indications that we’ve actually damaged any wells.
And by floating back harder, and we’ve actually done a lot of data mining across the basin from the wells that we’ve done a little bit harder, we draw down on as well as others. And we have got to avoid that.
There is, too many examples out there that the early found decline is accelerated because in our opinion those wells have been pulled too hard. So, we intend to keep up that practice and I think ultimately though we may be avoiding a quick high IP number but at the end of the day we’re getting a stronger base, a more stable base and a more predictable and forecasted base in order to grow our new wells with.
Ron Mills
And do you just don’t have enough data to provide the kind of cum charge, I’m just curious if you’re starting to see in your manner versus others the cumulative production under your method cross-over like you did on artificial lift and the higher profit?
Gary Newberry
Yes, I guess we’ve been doing this from almost from the start Ron. And so, I don’t remember I have a lot of data to suggest that we’re improving over what we’ve done.
I can suggest you that a few of the wells that I’ve drawn a little harder on, I wish I hadn’t had done that because offset wells have outperformed them. Frankly, I try not to compare myself too much with offset operators I just wish them the very much, a lot of success.
And as we share data I can’t - I haven’t really put together data that perhaps others are pulling harder on and get cums on. So, I haven’t looked at the data, I just feel confident with what I’m doing.
Ron Mills
And then, on the IRR as you talked about maybe with the well, another $1 million or so well cost savings, another 10% or 15% type uplift than yours, when I look at the Lower Spraberry curve in your presentation, obviously it was a shorter lateral for 7,500-foot, it’s really strong but if it grows up for the longer lateral and have the well cost, what kind of impact does would that have on that IRR charge at Spraberry since that’s a same, you’re going to doing a growing focus?
Fred Callon
Yes, that’s - again, we’re really encouraged with those Lower Spraberry results. We know we’ve got several on ourselves.
We’re just not bringing on a longer Lower Spraberry well at East Bloxom now. And I’m anxious to see that but given the early returns of Lower Spraberry we are seriously considering even high-grading our 2015 program more towards that horizon because it does look like it’s better returns than Wolfcamp B, even at the Wolfcamp B, we’re still very good even in this lower price environment.
So, as you can tell, it’s going to increase as if you look at our investor presentation on page 9, it will increase that rate of return to be a very attractive investment.
Ron Mills
And then lastly, the first quarter production guidance real strong, especially given the weather downtime, is that due to some timing of completions or is that due to some well performance that as we look ahead to your full year guidance gives you a lot of comfort that you’re on track to potential meet or beat that?
Fred Callon
Yes, I would attribute that to well performance Ron. We’ve got some really strong wells that have come on in the first quarter and that are likely outperforming the type curve more so than what we had forecast.
And those are both at Garrison Draw and at Carpe Diem. So, we’re very encouraged with the early time well performance we’re seeing this year.
And we hope to continue that. And some of those wells again link back to what will last.
Some of those wells certainly at Garrison Draw do have some of the higher profit concentrations as well, so, very encouraged with our well performance thus far this year.
Ron Mills
All right, great. Thank you.
Operator
Our next question will come from Jeb Bachmann of Scotia Howard Weil. Please go ahead.
Jeb Bachmann
Good morning, guys.
Fred Callon
Good morning, Jeb.
Joe Gatto
Good morning, Jeb.
Jeb Bachmann
I apologize if some of these have been answered in the prepared remarks. But just looking at ‘15 program in general kind of what zones are you guys are going to primarily target if they’re going to be any new one or two zones that you might look at outside of maybe just the Wolfcamp B?
Fred Callon
Yes Jeb. We’ve been focused on the Wolfcamp B in our operations update we gave.
We kind of spelled out that we would be targeting five Lower Spraberry Wolfcamp A well at our Taylor Draw asset then primarily upper and lower Wolfcamp B. But again what we’re considering now is probably high grading at a little bit closer towards a few more Lower Spraberry results given what we’re seeing early time.
Jeb Bachmann
Would that come at the expense of maybe some Wolfcamp A wells or what zones that would that come at the expense of?
Fred Callon
Likely the Wolfcamp B.
Jeb Bachmann
Okay.
Fred Callon
We only have one Wolfcamp A well planned this year.
Jeb Bachmann
Okay. Then looking at the completion schedule, I mean, what the expectation that costs are going to be down maybe to 30% or more in second half of the year.
What’s kind of the flexibility on completing wells or pushing some wells towards that 30% reduction in costs, it could still keep you within that guided production range for the year?
Fred Callon
Yes, just to be frank we haven’t really considered exploring and completions. Part of the, I’ve kind of tried to explain to you how we got the cost reductions we’ve gotten so far.
And it’s an important conversation to have. We’ve always looked at our contractor partners as real partners and there is enough, margin in this business that we can all participate successfully.
And so, kind of the way we got rig reductions come January 1, because our first rig reductions were actually January 1, and we had a 20% reduction on that date. We had another 20% reduction come March 1, so for a total of 40% reduction.
We’ve been having conversations with both Cactus Drilling company and ProPetro Services since October, recognizing when the price curve ditched in June of last year, we started saying we don’t know exactly where this is going to go. But we all will have to work through this together.
And so, we generally know that they’ve made lots of investments they want to keep that, those work crews working. They’ve got very talent crews, their goals are the same as ours.
Let’s get through this in a very healthy way and then be very successful on the other end of it. So, if I start deferring investments today, based on that type of partnership and communication, that just puts them in more distress.
So I have no intention of deferring completions. I’m going to go ahead and complete wells as we bring them on.
We’ll go ahead and have the completion services on the pad two weeks after the drawn rig moves off. Our timing cycle was very much, very efficient.
And we intend to continue that because of the partnership we have with our contractors.
Jeb Bachmann
I think it’s along those same lines Gary, with those conversions with ProPetro, they’ve talked about maybe entering into a longer term contract within this environment?
Gary Newberry
We, did I that mean come up? Again, our relationship with PrePetro has always been a handshake agreement.
They’ve been very loyal to us, we know, we know with certainty because we padded expressed by other operators. The frustration that they’ve had in not being able to break into the ProPetro Service world that could have easily paid them more of it because of our partnership and our commitment to each other, we appreciate their loyalty and commitment.
Jeb Bachmann
Okay, last one from me. Joe, I might have missed this but one the, the $105 million to $115 million budget for ‘16 which is preliminary.
Is that based on the two-rig program as well?
Joe Gatto
Yes Jeb. After, we reduced activity here this month, just running that program flat into next year.
Jeb Bachmann
And is that baking at 30% on those numbers?
Joe Gatto
Yes, it would be in that zip-code 25% to 30% of bad capital this year on total well cost.
Jeb Bachmann
All right, guys, appreciate it.
Fred Callon
Thank you.
Operator
The next question will come from Ryan Oatman of SunTrust. Please go ahead.
Ryan Oatman
Hi, good morning everybody.
Fred Callon
Good morning.
Ryan Oatman
I wanted to follow-up on that last question, kind of maintaining that two-rig program understanding the cost reductions embedded in it. If oil prices were to rebound into the $60 range and you were able to achieve those cost reductions.
Is that two-rig-program a good sort of number to think about or would you look at adding that third rig and if not what would you want to see before adding that third rig?
Fred Callon
Well, given what we’re going through, I would like to see it little bit more time at $60 before I jump into on accelerated pace, Ryan. We’re still on a fairly volatile world here.
And I’m incredibly pleased with the help and support that we’ve gotten from our major contractors. And again, the effort of trying to get through this together, and not trying to leverage any position one way or another.
So, I would want to see a little bit more time at $60 oil before I drawn in that third rig.
Joe Gatto
Yes, I think that’s right. I mean, from the financial perspective.
Certainly with the follow-through on the cost of seeing that being sustained over a longer period of time which given the partnership to a major how we look at the business we think this is a great opportunity for that especially working with them through a tougher time now. But yes, we saw ticking up $60 to $65 we’ll start looking at some more of the scenarios of increased activity.
But we’re not looking at it as one-off wells here and there, we’re going to do it, add in third rig it’s a whole program effort and that’s not something that we take lightly to take up and down. Certainly we did want to be doing that right now but we had some hard choices to make.
So, we’ll be a little bit sticky in terms of making that decision but I think it all starts with what’s get the cost reduction, with seeing a sustained follow-through. What the commodity will do, the oil will do, but we’ll try to control what we can through the course of this year.
Ryan Oatman
Right, no, that makes sense. And then any thoughts on production under that scenario, would you look for roughly flat-out or would you look for sequential increase is that what you think of it?
Fred Callon
We still see sequential increases I think what we’ve talked about from the fourth quarter ‘14 to fourth quarter ‘15 was roughly around 15% increase there. Certainly sort of taper a little bit on the growth profile, but we would see it in the 8% to 10% range Ryan that is sort of fourth quarter to first quarter comparison going into ‘16.
So, still some decent growth profile on the two-rig program but it will pay for a little bit relative to this year.
Ryan Oatman
Thanks. I really appreciate the level of detail there.
On the operations front, I assume the new presentation slide and the economics are based on the reserves you’ve booked for your proved underdeveloped locations, normalized for lateral length. Can you speak to the significant of that that the fact that these are out of yours and kind of your comfort level with what the reserve engineers gave you on each zone?
Fred Callon
Well, once again these are, I’ve always been challenged I guess in the way I’ll answer this question and the fact that EURs are still under what others around us are reporting. And I’m happy that we’re delivering these.
That there is upside as we can point to on other investor presentations that we’ve listened to and other well results that we’ve seen. We can deliver these EURs, they’re in-line with - well, they are essentially what our third party reserves engineer just finished.
And so, as we book, as you know the SEC rules, the likelihood has to be a higher potential to go up more so than down. And so, I’d like to deliver on what we say.
So, I’m happy with the way this slide, at least on slide 9 at our investor presentation, the EURs that we have and the opportunity for them to go higher.
Ryan Oatman
That’s helpful. And then I see that there is economics there for an incremental 15% reduction.
I guess my question is, I mean, what is causing you to be coming down again quite fast? Are you basically at those improved economics right now?
Fred Callon
We are, we believe we are. And the fact that we made this slide some time ago and we just didn’t update it but we think we’re about 20% today.
And I think as we continue to work with our service partners especially at this price environment they were as that, we expect more and they know that and they know that that’s coming. So, that’s why I’m incredibly pleased with how Proactive got this in ProPetro then.
Now, all of those reductions came in early January, because they knew that we wanted to set the tone and set the pace for how we all work through this together. So, we’re above these 15% reduction curves today.
And we hope to even get better.
Ryan Oatman
That’s great. And then, can you just refresh my memory, I think we’re looking at a $6 million cost versus 7,500-foot lateral.
Does that include upsize completions and if not what would those upsize completions look like?
Fred Callon
Yes, we haven’t landed on what number we would hit on an upsize completion number yet Ryan, but yes, we will be in that range with the type of completion we end up with.
Ryan Oatman
Perfect. That’s it from me.
Thanks for the level of detail guys.
Fred Callon
Thanks Ryan.
Operator
The next question will come from Chad Mabry of MLV & Co. Please go ahead.
Chad Mabry
Thank you. A question for Joe on the borrowing base re-determination, just curious what your initial thoughts are where that might go, if you see any downward revision at all?
Thanks.
Joe Gatto
Yes, we’re starting to get in some data points from the industry that I’ve seen and we’re caveat. We’re just getting into our process with the lending group and have our bank meeting coming next week to strike that formal process.
So, from what I’ve seen people guiding to expectations down 10% to 20% notionally varies but I’ve seen that type of a range. We haven’t received a formal recommendation on number yet.
But for internal sort of planning purpose and getting our head around things we’re going to plan for 10% type of reduction as we think about liquidity. But again that that’s our plan and feel we’re pretty good that that’s our downside exposure at this point.
We do think though that there is a real chance to do better than that. And the reason why we’re a little bit late getting into the process and having a little bit more feedback is that we’re in a pretty neat position with the types of cost reductions that we’ve got and the pace of them, that we’ve got them so quickly that we’re able to formally document them for the banker.
And they’ve been kind enough to spend time with us over the last month and a lot of detail documenting all those cost reductions both from an operating cost and drill and complete cost that we’re running through our database now. So, that put us back a little bit in terms of getting some real feedback but I think that will pay dividends over the course of this process in the coming weeks.
Chad Mabry
That’s really helpful thanks. And I guess one follow-up.
Just curious if you any comments on A&D opportunities in the Midland Basin right now or if it’s too early? And what your appetite for any deals might be?
Fred Callon
I think, we continue to look as we talked in the Midland Basin, we’ve been - we think we’re successful in what we call our bolt-on-type acquisitions. And we think there are going to be more opportunities in this environment as you might expect things are evolving.
And so there has been a lot of deal flow. There are few opportunities out there, we’re starting to see them a few more.
But I can’t say there have been any significant transactions there to start to sort of benchmark kind of where, where prices are going. But yes, I think we’re going to continue to see opportunities certainly in the areas we’re in just like we’ve done in the past and we’ll continue to focus on those.
Clearly in with, now on the balance sheet, we’re not in a position to make major acquisitions this year. But we think we continue to grow our asset base out here and acreage in the right areas where we’re focused now and continue to add to that.
Chad Mabry
All right, good color. Thank you.
Operator
Then next question will come from Andrew Smith with Global Hunter Securities. Please go ahead.
Andrew Smith
Hi, good morning guys.
Fred Callon
Good morning, Andrew.
Andrew Smith
A question about the oil price differentials you noted that the Midland Cushing spread has tightened quite a bit but it looks like realization in Q4 looks a little bit higher than I was expecting. So I was wondering what you were anticipating going forward with this?
Joe Gatto
We’ve certainly seen a lot of improvement. We’re expecting that improvement to come a little bit longer than anticipated.
I think everyone pointed to BridgeTex coming online, thought that everything would fall in place after that. But it turns out some of the pipelines to get to Colorado City and getting to BridgeTex took a little bit longer.
But once I think it’s the Sunrise pipeline came in to serve, in November, December - I mean, basically overnight we saw that differential move from $6, $7 to $2, we’ve seen it cross over positive for a little bit as well. And like I said, we’ve seen our average around $2 over the last couple of months.
And our expectation going forward and based on our discussions with marketers on the ground, that differential should probably hang in the $2 to $3 range for the foreseeable future barring any sort of issues at Cushing which with the fill-up there, you never know what the knock-on impacts might be. So, we’ve actually introduced hedges on about 60% of our volumes for the remainder of the year.
It’s just under $2.40 just to provide some insurance because while we feel very good about the long-term fundamentals and the macro basis differential, local refinery demand is still a meaningful stack of the demand stack and it influences that differential. So, it will I mean, widening of that basis differential will occur.
I don’t think there is any question in it, but it doesn’t happen for very long, it happened for a few weeks here and there as refineries turn around. But just to ensure that doesn’t happened at the wrong place, wrong time we put in some insurance around that.
Andrew Smith
Thanks guys.
Operator
The next question will come from Mo Dehghani of Northland Securities. Please go ahead.
Mo Dehghani
Yes, good morning guys. Thanks for taking my questions.
Fred Callon
Good morning.
Mo Dehghani
On your first Lower Spraberry wells, can you talk about what drove that variance in initial production?
Fred Callon
I’m sorry, where was it?
Mo Dehghani
The first two Lower Spraberry wells, have you thought about that variance in initial production?
Fred Callon
Well, I guess, I’ll talk about the Lower Spraberry in general because I’m not really - we got several Lower Spraberry wells. And of course the more recent one of course is the Lower Spraberry well at the Casselman 40.
That’s been an exceptional well, that’s way outperforming our type curve. It’s in a great area of the basin.
And we’re very keenly excited about that. Same with the well at Carpe Diem, which maybe the well that you’re referring to, that’s a well that we actually cut short because that was a shorter lateral.
But that’s the only reason that you might think that that might be a little lower than expectation than maybe what you might have thought about. But Kendra Annie is a little shorter than what it really should have been and then the Casselman 40 is a little shorter than it, but it outperformed it.
But we’re still very excited about Spraberry in that general area. There will be variations from well to well.
But it will be fine.
Mo Dehghani
Appreciate that. And then second question on the potential swaps and agreements with outside operators on your acreage.
Can you quantify that potential, when it comes up, how many longer lateral wells can you drill in 2015 on that new acreage?
Fred Callon
Yes, what that was, was the four wells that were drilled by Henry, they did a great job building those wells. And they did a great job drilling those wells.
And they drilled down with the surface location on lease, meaning, that as you drill vertically and then build the curve to get into zone, you lose about 500 feet of potential completed lateral length in the well. So the average completed lateral length of the well we drilled on lease would have been around 4,400 to 4,500 feet.
As we have now worked with our offset landowners, they’ve allowed us now to move that location to their rigs, to where we can actually drill vertically and build the curve part of the well. And then answer on to our lease and zone, which allows us then to exempt that completed lateral length about 500 feet.
So, these laterals are now in this new area instead of being about 4,400 feet they’ll be closer to 4,900 feet.
Mo Dehghani
Great color. Thank you so much.
Operator
And the next question will be a follow-up from Ron Mills of Johnson Rice. Please go ahead.
Ron Mills
Gary or Joe, just one quick question on the two-stream versus three-stream chart in your presentation. I think what you are trying to do is compare two-stream to three-stream, where the volume remains the same.
But are you stripping out your liquids and selling them? Or are you leaving the liquids in the gas stream?
And what do you think - you’ll continue to do that going forward?
Gary Newberry
Yes, Ron, we don’t take ownership of the liquids at the lease. We sell it all with the gas.
And we’ll continue to do that going forward. That’s what drives our view in how to report on the two-stream versus three-stream basis as well.
So, we don’t take custody of the liquids. Our read of how to report, means that we should report on a two-stream basis but not everyone I think use it that way.
But we do it on two-stream. We’ll try to provide the information.
In terms of the equivalent volume uplift obviously economically we’d be even two, three - whatever stream you want. So, we just take the value of those liquids with the gas.
And so…
Ron Mills
That volume should uplift pretty similar across your position? Or is that chart representative of your?
Joe Gatto
It’s pretty indicative. We have 1,300 BTU gas, in general, across our fields, it doesn’t vary too much.
So that’s pretty indicative Ron.
Ron Mills
Perfect. All right, great, thank you.
Operator
And ladies and gentlemen, this will conclude our question-and-answer session. I would like to hand the conference back over to Fred Callon for any closing remarks.
Fred Callon
Thank you. Again, we appreciate everyone taking time to call in this morning.
And we look forward to keeping you up-to-date on our progress. Thank you.
Operator
Ladies and gentlemen, the conference has now concluded. We thank you for attending today’s presentation.
You may now disconnect your lines.