Callon Petroleum Co (CPE) 2014 Q4 法說會逐字稿

Good morning, and welcome to the Callon Petroleum full-year and fourth-quarter financial and operating results conference call.

(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.

Good morning. 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?

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 believe, expect, plan and words with similar meaning. These projections and statements reflect the Company's current views with respect to future financial 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.

Thank you, Eric. Again, thanks to everyone for joining this morning. Last month, we announced our year-end reserves and our 2015 guidance, as well as initial results from wells from our Ca-Bo acquisition that were in excess of our previous expectations, especially the Lower Spraberry formation.

We were very pleased to report a 121% increase in our proven reserve base, which stood at 33 million barrels of oil equivalent at year-end 2014, with proved 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 a conservative booking philosophy across our asset base. Of that total horizontal PUD number, only three are associated with the lower Spraberry zone, 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 in 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 the completion of our Ca-Bo acquisition in the fourth quarter. Even with our reduced capital budget, we are forecasting growth of approximately 15% from the fourth quarter of 2015, 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 pullback in commodities, we estimate average returns of 25%, with our drilling program at $55 flat realized oil prices, and assuming the well cost reductions achieved to-date. As Gary will discuss, we have continued to make significant strides on further well cost reductions that would increase these returns and further reduce our F&D costs.

Although we expect to spend above our internal cash flows this year, we pre-funded a large portion of our activity with a long-term capital raise of almost $430 million last year, which is complemented by a $250 million borrowing base facility, which was less than 15% drawn at year-end.

As we look at the execution of our drilling program over the longer-term, we remain focused on progressing to a cash flow-neutral position, based on current forward price curves. Given our expected well costs and operating cost reductions, combined with the outlook for production levels, assuming a two-horizontal rig program, we believe that a cash flow breakeven position could be achieved by the second half of 2016. I will now 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.

Thank you, Fred, and good morning. With the operations update provided last month and the data provided in 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 acquisition, which closed on October 8, with our assumption of operatorship on November 1. I'm pleased to report that the transition has gone 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 a time when we were producing around 8,000 barrels of oil equivalent per day. LOE decreased by 7% from the third quarter, as we continued to leverage fixed costs across a 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. A resulting reduced number of expected work-overs, combined with lower associated work-over service costs, 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 to 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 are certainly pleased with the quality of our asset base and its ability to generate robust returns in the current commodity price environment. A 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 costs 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. Building on that momentum with a broad range of service partners, we now believe that total well costs 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 costs of approximately $5.1 million for 7,500-foot laterals, and $4 million for 5,000-foot laterals. And importantly, contribute to 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 a 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 re-enter 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, the 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 would now turn the call over to Joe Gatto, our Senior Vice President and CFO.

Thanks, Gary. Our reported net income for the quarter on a 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 a mark-to-market or a hedging portfolio. A non-cash gain of $1.7 million related to the mark-to-market valuation of performance-based incentive compensation awards. And a non-cash loss of $2 million related to the refinancing of a 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 counts 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 adjustment 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 has subsequently settled at an average of approximately $2 per barrel since the beginning of 2015.

Our hedge position had incremental exploratory 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, but represented a sequential quarterly decrease of 7%. With the progress we have been making on 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 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 five 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 as 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 increasing cash flow impact on capital expenditures beginning early in the second quarter. For the total year of 2015, we previously released an operational CapEx budget of $150 million to $165 million. And now believe we are trending toward 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 and long-term capital perspective, total debt to fourth-quarter annualized EBITDA was 2.5 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, translating 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 complement 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 will now turn the call back to Fred for final comments.

Thank you, Joe. Again, we appreciate everyone taking the time to call in this morning and with that, we'll open the call up to questions.

(Operator Instructions) Will Green of Stephens.

I wonder if we could talk about gas lift? It looks like you guys have had a good bit of success there. Can you talk about the amount of wells that you guys have implemented that on? And maybe think about -- as you guys are looking at the cost-side equation, what that could actually do on the LOE side as you move forward?

Well, that's a good question. Gas lift is something that we truly believe is the right way to go, over the longer-term. It helps us on a couple of fronts. It helps a little bit on the capital side in 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, in helping us actually control the draw-down. We've talked about that quite a bit in our previous calls.

So really, on a gas-lift well, we actually let the well flow a little bit longer on its own before we kick the gas lift on, to help control the draw-down associated with that frac pack, near the wellbore face. Because we've spent an awful lot of money establishing that wellbore; we don't want to take too many risks in damaging it. 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 an 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 pad gas-lift compressors -- our LOE cost will actually be lower in managing that full cost of operation for the wells. 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.

Got you. I appreciate the color there. And then, you guys looked at using a lot more proppant in the second half of the year, it looks like. Did you feel like you hit a point of diminishing returns at any point? Or could we continue to see you guys push more proppant down-hole and look to hedge returns? It definitely looked like the results you saw were much better with those additional proppant volumes. I wonder if you could give us some color there.

Well, again, we talk about that quite a bit, because we have seen some encouraging results with higher proppant, 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 pounds 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 those encouraging results actually to additional proppant. Because we're actually correlating -- we're looking at a lot of technical detail and, we think, getting a lot smarter about how we complete wells.

So we're correlating all the production. We're also correlating it all to the type of formation that we're completing in every individual well -- the brittleness of that formation and its ability to fracture, stimulate and propagate that fracture throughout. So though we're seeing encouraging results, I'm not quite ready to say we're all-in on higher sand concentrations at the upper limits yet. It's certainly more than what we've historically done, but I can't tell you exactly where I'm going to land. I hate to be a little nebulous on that, but I just haven't landed on the right number yet to guide you.

I appreciate that, and I appreciate all the color, guys. Thanks for that.

Thanks, Will.

Phillips Johnston of Capital One.

A question for Joe. We've seen a lot of companies issue equity in the last several weeks. I'm wondering if that's something that's potentially on the table. Or would you rule that out, given your liquidity is very comfortable at over $200 million? Which should easily fund the projected outspend this year and next, especially with the cost savings that you're now seeing.

We've certainly seen a lot of deals cross the tape. From what our take is, most of them fall under 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.

Clearly the commodity price environment has changed. And we've changed with it, with a reduction in our activity going down to two rigs, and some of the changes that I talk about on our fixed cost structure. Back to your comment, we certainly feel good about the position we're in today. But we do like to see that there's more options available out there, as we look at incremental opportunities in the marketplace going forward.

Okay. You guys referenced that the 2015 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's a little bit of downward bias to that range. My question is, if you wind up achieving 30% lower cost in the second half of this year, how much downward bias is there to the range? Is it as simple as a 5% to 10% incremental reduction -- so $10 million to $15 million or so lower?

We don't have exact numbers on it because, as Gary can attest to, this is a constantly evolving process. 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 the team have done an exceptional job of getting in front of some key items on the well cost. I think we'll probably be in a position to re-evaluate 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.

While we're encouraged with the reductions we've got, we've got to follow through and deliver on those [AFEs] we're writing. But if we're down a solid 30% on total average well cost by the second half -- which we think is a strong likelihood -- then it will give us an opportunity to certainly move toward the bottom-end of that range, and maybe even then some.

That sounds good. Thanks very much.

Ron Mills of Johnson Rice.

Gary, Will asked about the proppants in artificial lift. You now have another quarter-worth of data, with your more managed or more controlled flow-back, than what others are practicing. Curious how the production rates are holding up -- similar to your other two charts showing cumulative production? Is it showing what you want so that you're going to continue to more controlled flow-back?

Yes, Ron, thanks for asking that. The simple answer is yes. We're seeing very positive results on -- more stable well results, even at what we believe to be better-than-expected type curves, under the gas lift to control flow-back arena. But more importantly, we haven't seen indications that we've actually damaged any wells by flowing them back harder. And we've actually done a lot of data-mining across the basin, from wells that we've done a little bit harder, pull the draw-down on, as well as others.

We have got to avoid that. There's too many examples out there that the early-time 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, at the end of the day, we are getting a stronger base, a more stable base, and a more predictable and forecasted base, in order to grow our new wells with.

Do you just not have enough data to provide a cume charge? I'm just curious if you are starting to see, in your manner versus others, the cumulative production under your method crossover, like you did on the artificial lift and the higher proppant?

Yes. I guess we've been doing this almost from the start, Ron. So I don't know that I have a lot of data to suggest that we're improving over what we've done. I can suggest to you that on a few of the wells that I've drawn a little harder on, I wish I hadn't of done that, because offset wells have outperformed them.

Frankly, I try not to compare myself too much with offset operators. I just wish them 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 can get cumes on. I haven't looked at the data, I just feel confident with what I'm doing.

All right. And then, on the IRRs, you talked about maybe with another $1 million or so of well cost savings, another 10% or 15% type uplift in EURs. When I look at the Lower Spraberry curve in your presentation, obviously it's a shorter lateral grossed up for 7,500-foot -- it's really strong. But if you gross-up for the longer lateral and have the well cost, what kind of impact would that have on that IRR chart for the Spraberry, since that seems to be a growing focus?

Again, we're really encouraged with those Lower Spraberry results. We have several now ourselves. We're just now bringing on a longer, lower Spraberry well at East Bloxom now. 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 toward that horizon. Because it does look like it's better returns than the Wolfcamp B even though the Wolfcamp B are still very good, even in this lower-price environment. As you can tell, it's going to increase. If you look at our investor presentation on page 9, it will increase that rate of return, to be a very attractive investment.

And then lastly, the first-quarter production guidance -- real strong, especially given the weather down-time. 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 potentially meet or beat that?

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 their type curve -- more so than what we had forecast. Those are both at Garrison Draw and at Carpe Diem. So we're very encouraged with the early-time well performance that we're seeing this year, and hope to continue that. Some of those wells -- again, going back to what Will asked, some of those wells, certainly at Garrison Draw, do have some of the higher-proppant concentrations, as well. So very encouraged with our well performance thus far this year.

All right, great. Thank you.

Jeb Bachmann of Scotia Howard Weil.

I apologize if some of these have been answered in the prepared remarks. Just looking at 2015, the program in general, what zones you guys are going to primarily target? If there are going to be any new one or two zones that you might look at outside of maybe just the Wolfcamp B?

Jeb, we've been focused on the Wolfcamp B in our operations update that we gave. We spelled-out that we would be targeting five Lower Spraberry Wolfcamp A wells at our Taylor Draw asset, then primarily Upper and Lower Wolfcamp B. But again, what we're considering now is probably high-grading that a little bit closer toward a few more Lower Spraberry results, given what we're seeing early-time.

Would that come at the expense of maybe some Wolfcamp A wells? Or what zones would that come at the expense of?

Likely the Wolfcamp B.

Okay.

We only have one Wolfcamp A well planned this year.

Okay. And then looking at the completion schedule, with the expectation that costs are going to be down maybe a total of 30% or more in the second half of the year. What's the flexibility on completing wells or pushing some wells towards that 30% reduction in cost that could still keep you within that guided production range for the year?

I want to just be frank. We haven't really considered deferring completions. I'll try to explain to you how we got the cost reductions we've gotten so far. It's an important conversation to have. We've always looked at our contractor partners as real partners. There's enough margin in this business that we can all participate successfully.

So 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, 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 dipped in June of last year, we started saying hey, we don't know exactly where this is going to go, but we all have to work through this together.

So we generally know that they've made lots of investments. They want to keep those work crews working. They've got very talented 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. If I start deferring investments today based on that type of a 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 drilling rig moves off. Our planning cycle is very efficient, and we intend to continue that because of the partnership we have with our contractors.

Along those same lines, Gary, with those conversations with ProPetro, have they talked about maybe entering into a longer-term contract in this environment?

It hasn't even come up. Again, our relationship with ProPetro has always been a handshake agreement. They've been very loyal to us. We know with certainty -- because we've had it expressed by other operators -- the frustrations they've had in not being able to break into the ProPetro service world. They could have easily paid them more. But because of our partnership and our commitment to each other, we appreciate their loyalty and commitment.

Okay. Last one for me. Joe, I might have missed this. On the $105 million to $115 million budget for 2016, at least preliminary, is that based on a two-rig program, as well?

It is, Jeb. After we reduce activity here this month, just running that program flat in the next year.

Does that bake in that 30% on those numbers?

Yes, it would be in that zip code -- 25% to 30% the back half of this year on total well costs.

All right, guys, appreciate it.

Thank you.

Ryan Oatman of SunTrust.

Wanted to follow up on that last question, 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 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?

Well, given what we are going through (laughter), I would like to see it have a little bit more time at $60 before I jump into an accelerated pace, Ryan. We're still in a fairly volatile world, here. And I'm incredibly pleased with the help and support that we've gotten from our major contractors. Again, the upward of trying to get through this together, and not trying to leverage any position one way or the other. So I would want to see a little bit more time at $60 oil before I bought in that third rig.

I think that's right, 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 sort of nature of how we look at the business -- we think there's a great opportunity for that. Especially working with them through a tougher time now. We start ticking up $60, $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. If we're going to do it, it's adding a third rig, it's a whole program effort, and that's not something we take lightly to turn up and down. Certainly, we [didn't] 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 -- let's get the cost reduction, let's see a sustained follow-through. The commodity will do what it will do, but we'll try to control what we can through the course of this year.

Right. That makes sense. And then, any thoughts on production under that scenario? Would you look for roughly flat output? Would you look for sequential increases? How would you think about that?

We still see sequential increases, I think. What we've talked about, from the fourth-quarter 2014 to fourth-quarter 2015, was roughly around 15% increase there. Certainly you start to taper a little bit on the growth profile. But we would see it in the 8% to 10% range, Ryan, that fourth quarter-to-fourth quarter comparison, going into 2016. So still some decent growth profile on the two-rig program. But it will taper a little bit relative to this year.

Thanks. I really appreciate the level of detail there. On the operations front, I've seen the new presentation slide 10, the economics are based on the reserves you've booked for your proved undeveloped locations, normalized for lateral length. Can you speak to the significance of that, the fact that these are PUD EURs? And your comfort level with what the reserve engineers gave you on each zone?

Well, once again, these are -- I've always been challenged in the way I would answer this question, and the fact that these 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 in 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.

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. I'd like to deliver on what we say. So I'm happy with the way this slide -- at least in slide 9 of our investor presentation, the EURs that we have, and the opportunity for them to go higher.

That's helpful. And I see there's economics there for an incremental 15% reduction. My question is -- I mean, well costs seem to be coming down again quite fast. Are you basically at those improved economics right now?

We are. We believe we are. In fact, 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 if this price environment stays where it's at -- we expect more, and they know that, and they know that that's coming.

And that's why I'm incredibly pleased with how proactive Cactus and ProPetro have been. All 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.

That's great. And then can you just refresh my memory? I think we're looking at a $6 million cost for a 7,500-foot lateral. Does that include upsize completions? If not, what would those upsized completions look like?

Again, 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.

Perfect. That's it for me. Thanks for the level of detail, guys.

Thanks, Ryan.

Chad Mabry of MLV and Co.

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 [frame]?

We're starting to get in some data points from the industry, that I've seen. And (inaudible) we're just getting into our process with the lending group and have our bank meeting upcoming next week to start that formal process. From what I've seen, people guiding to expectations down 10% to 20%, notionally. It varies. But I've seen that type of a range.

We haven't received a formal recommendation on a number yet. But for internal planning purposes and getting our head around things, we're going to plan for a 10%-type of reduction as we think about liquidity. But again, that's our plan and feel pretty good that that's our downside exposure, at this point. We do think, though, that there's a real chance to do better than that.

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 unique position with the types of cost reductions that we've gotten. And the pace of them that we've gotten them so quickly that we were able to formally document them for the banker.

And they've been kind enough to spend time with us over the last month, in 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 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.

That's really helpful, thanks. One follow-up. Just curious if you have 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?

I'd say, Chad, we continue to look, as we've talked, in the Midland Basin. We've been, we think, very 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. So there hasn't been a lot of deal flow. There's a few opportunities out there, we're starting to see a few more. But I can't say there have been any significant transactions yet, to start to benchmark where prices are going.

But 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, with an eye on the balance sheet, we're not going to be in a position to make major acquisitions this year. But we think we can continue to grow our asset base out here, and acreage in the [white] areas where we're focused now, and continue to add to that.

All right, good color. Thank you.

Andrew Smith of Global Hunter.

A question about the oil price differentials. You noted that the Midland-Cushing spread has tightened quite a bit. It looks like the realizations in Q4 were just a little bit higher than I was expecting. So I was wondering what you were anticipating going forth with this?

We've certainly seen a lot of improvement. We were expecting that improvement to come. It took a little bit longer than anticipated. I think everyone pointed to BridgeTex coming online, thought that everything would fall into place after that. But it turns out, some of the pipelines to get to Colorado City and get to BridgeTex took a little bit longer. But once -- I think it's the Sunrise pipeline -- came in to service in November, December -- I mean, it was basically overnight that we saw that differential move from $6, $7 to $2. We've seen it cross over to positive for a little bit, as well.

Like I said, we've seen, on average, around $2 over the last couple months. And our expectation going forward, and based on our discussions with marketers on the ground, that, that differential should probably hang in the $2 to $3 range for the foreseeable future. Barring any sort of issues at Cushing -- 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 at 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 part of the demand stack, and influences that differential.

So widening of that basis differential will occur -- I don't think there's any question. And if it doesn't happen for very long, it will happen for a few weeks here and there as refineries turn around. But just to ensure that that doesn't happen at the wrong place, wrong time, we put in some insurance around that.

All right, thanks, guys.

Mo Dehghani of Northland Securities.

On your first Lower Spraberry wells, can you talk about what drove that variance in initial production?

I'm sorry, what well was it?

The first two Lower Spraberry wells. Have you thought about that variance in initial production?

I'll talk about the Lower Spraberry in general, because I'm not really -- we've got several Lower Spraberry wells. And of course, the more recent one, of course, is the Lower Spraberry well, the Casselman 40. That's been an exceptional well. It'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 may be the well you're referring to. That's a well that we actually cut short, because it was a shorter lateral. But that's the only reason that you might think that might be a little bit lower than expectation, than maybe what you thought about. But the 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's outperformed it. We're still very excited about the Spraberry in that general area. There will be variations from well to well, but we'll be fine.

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?

What that was, was the four wells that were drilled by Henry. They did a great job building those wells. And they drilled them 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 wells that were 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 [risk], to where we can actually drill vertically and build the curve part of the well. And then [enter] on to our lease end zone, which allows us then to extend that completed lateral length about 500 feet. So these laterals now in this new area, instead of being about 4,400 feet, they'll be closer to 4,900 feet.

Great color. Thank you so much.

Ron Mills of Johnson Rice.

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? What do you think -- you'll continue to do that going forward?

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.

And that drives our view on how to report on a 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 report on a two-stream basis. But not everyone, I think, views it that way. But we do it on a two-stream. We'll try to provide information in terms of the equivalent volume uplift. And 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 -- (multiple speakers)

-- uplift pretty similar across your position? Or is that chart representative of your -- (multiple speakers)

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.

Perfect. All right, great, thank you.

Ladies and gentlemen, this will conclude our question-and-answer session. I would like to hand the conference back over to Fred Callon for his closing remarks.

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.

Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.