Callon Petroleum Co (CPE) 2015 Q4 法說會逐字稿

Welcome to Callon Petroleum Company's fourth-quarter and full-year 2015 financial and operating results conference call.

(Operator Instructions)

A replay of the call will be archived on the Company's website for approximately one year.

I would now like to turn the call over to Erik Williams, Manager of Finance, for opening remarks. Please go ahead, sir.

Good morning and thank you for taking time to join our fourth-quarter and FY15 results conference call. With me this morning are Fred Callon, Chairman and Chief Executive Officer, Gary Newberry, Senior Vice President of Operations, and Joe Gatto, Senior Vice President, Chief Financial Officer and Treasurer.

During our prepared remarks, we'll be referencing the earnings results presentation we posted yesterday afternoon to our website. I encourage everyone to download the presentation, if you haven't already done so. You can find the slides on our website at www.callon.com. To locate the slides, simply click the PDF icon located on the events and presentation page for today's conference call, or alternatively, you may click the current presentations when you get to the bottom of any page on our website.

Before we begin, I would like to remind everyone joining this call that our comments today include forward-looking statements. A variety of factors could cause Callon's actual results to differ materially from those anticipated results or expectations expressed in these forward-looking statements. For a complete discussion of these risks, we encourage you to read our filings with the SEC, including our form 10-K available on our website or the SEC's website.

Today's conference call will also contain discussions of certain non-GAAP financial measures. Please refer to the earnings release we issued yesterday afternoon for important disclosures regarding such measures and the corresponding reconciliations. You may obtain a copy of our press release in the news section of our website. Following our prepared remarks, we will open the call for Q&A.

And with that, I would like to turn the call over to Fred Callon and direct the audience to slide 3 of the earnings presentation I previously mentioned. Fred?

Thanks, Eric. And thank you to everyone for joining us this morning.

I'll start on page 3 with the highlights from 2015, a year which brought increasing headwinds on the commodity price front. In response, we were quick to pivot our activity to almost exclusively focus on the Lower Spraberry, which continues to deliver robust returns in the current environment on the back of a type curve that was recently increased over 1 million barrels of oil equivalent. Of course, this is only part of the story. Beyond the strength of our asset base, our team drove capital efficiency and cost reductions required to not only survive, but thrive in a challenged environment.

As a result, we are pleased with the following accomplishments: the 70% year-over-year growth, exiting 2015 with over 10,500 barrels of oil equivalent per day; a 65% growth in our proved reserves with an all-in resources F&D cost under $10 per BOE; traumatic decreases in our operating cost structure over the course of the year with LOE trending 19% lower on a BOE basis than our third quarter expense, and complete well costs down approximately 36% from 2014. [Cash advantage] from the balance sheet has positioned us to capitalize in incremental drilling activity in the future, as well as a growing pipeline of acquisition opportunities.

As we look at Callon back in 2015, our performance highlights several unique aspects of the business, including an acreage position that is 100% held by production and a singular focus on the efficient horizontal pad development that's allowed us to post operating cost and capital reductions at the top of our peer group. While we've moderated our activities heading into 2016 with a [long range focus], we expect to deliver additional cost structure reductions with relentless focus on internal efficiencies, as well as working closely with our partners on the service side.

Turning to slide 4, you'll see a few specific highlights in the fourth quarter. Callon delivered sequential production growth of 9% and 8% oil, the highest oil content amongst our peer group. Combined with a realized pricing that has continued to benefit from getting fractional gathering system throughout 2015 and LOE that decreased almost 20% from third quarter, we once again delivered adjusted EBITDA margin in excess of 70% in the quarter. These levels of (inaudible) cash generations will be a key driver to our goals on cash flow neutrality, which are now focused to occur earlier, are now expected to occur earlier than previously expected.

Finally, I want to highlight the acquisition of additional working position (inaudible) in November, which we recently followed up with a similar transactions a few weeks ago. [In addition to these types of work increase] opportunities at our CaBo area, we continue to evaluate and bid on [patches] in the Permian with a focus on the Midland Basin. While it's difficult to handicap the probability of getting transactions for the (inaudible), we believe that we have a good chance of adding core acreage positions at reasonable valuations in the coming quarters.

I'll now turn the call over to Gary Newberry, Senior Vice President of Operations, to provide update on the operational front.

Thank you, Fred, and good morning.

I will start on slide 5 with a summary of our year-end reserves and the proved reserve base of the business. We had an exceptional year of growth in both total proved and PDP volumes with a breakdown of 80% oil and 53% proved developed. Equally as important to the 65% growth in proved reserves to the capital efficiency of our business. Our drill bit F&D is just under $9 per BOE, which includes the impact of revisions, including those that are related to pricing.

In fact, the only meaningful price provision that we had satisfied SEC definition of proved reserves on an economic basis, but we removed the volumes since we did not see PUDs at Taylor Draw competing for capital in the near future. We remain prudent in our PUD bookings with only 60 locations currently included on our proved reserves, which are diversified across multiple zones and fields.

On slide 6, we provided some additional information comparing our reserve metrics to a few of our peers on the basin. I will leave this for your review, but we are certainly proud of this relative performance against our other strong, highly respected operators. There are several ways to cut the information, but we believe that the year-over-year change in our PB10 values speaks volumes with respect to the overall quality and value proposition from our proved reserve base. We experienced only a 9% reduction in this metric over 2014, despite a 47% decrease in realized SEC pricing.

Turning to an operations update on page 7, we placed 9 gross wells on production in the fourth quarter, with 6 targeting the Lower Spraberry and 3 central Midland fields. As we've discussed, the Lower Spraberry is our primary focus on the near term (inaudible) -- Okay, I guess we've dropped off?

Ladies and gentlemen, this is the operator. We are experiencing some sound difficulties with the speaker lines. We would like for you to stay on the line. We are going to try to reconnect the speakers at this time. Please bear with us. One moment, please.

Ladies and gentlemen, we've reconnected the speaker line for the Callon Petroleum conference call. Thank you for your patience. Mr. Newberry, you may continue, sir.

Thank you. I'm not sure where the sound dropped off.

I'll restart on slide 7, on the operations update on slide 7. We placed 9 gross wells on production in the fourth quarter with 6 targeting the Lower Spraberry and 3 central Midland fields. As we've discussed, the Lower Spraberry is our primary focus in the near term. Given the exceptional results in the Lower Spraberry, we have been closely monitoring downspacing test by offset operators to ensure optimal development of the resource.

Moving to slide 8, we are very encouraged with the results from wells drilled in a Chevron pattern in the upper and lower section of the Lower Spraberry in our Carpe Diem field. The wells are producing at equivalent or higher rates as previous wells drilled at 8 wells per section at the same TBD.

Importantly, the downhole pressure of the wells drilled on a tighter density is declining at a shallower pace, indicating better access to the resource. Furthermore, the well drilled higher in the section is performing as well as wells drilled at the lower end of the section, which may justify another entire level of development in the Lower Spraberry, supporting even more wells.

Slide 9 illustrates the continued exceptional project economics being delivered in the Lower Spraberry across our central Midland Basin assets. It is great to have access to high quality assets such as these, but I am especially proud of the Callon team and service partners as they continue to deliver and prove well results at lower project and operating costs. Referencing back to our downspacing discussion, we have a significant inventory of Lower Spraberry locations in our central and Midland Basin with the opportunity for more.

Turning to slide 10, we've provided an update on the progression of well costs over the last several quarters. While we delivered exceptional reductions in the first half of 2015 after securing a reduction in rig day rates to $15,000, we have continued to move costs further down as completion costs per stage have moved down roughly 50% over the last year, despite an increase in proppant volumes. We have consistently delivered normalized 7,500 foot wells at a cost of $5.4 million and have been riding recent AFEs for $5.1 million. The more recent cost improvement is the result of increased competition for pumping services, but we continued to look for cost savings across all services to drill, complete and operate wells in the Permian Basin.

Lastly, on slide 11, I wanted to cover achievements the team has made on the LOE front. It is normal to focus on big ticket items like well costs, but we view our ability to lower LOE as critical to our success of being a safe and efficient operator in any commodity price environment. This is especially important in our current environment where every dollar of operating margin matters and contributes to cash flow from operations.

We continue to benefit from our infrastructure investments such as SWD wells and Midstream pipeline connections that produce fields heading to our operating efficiency and production uptime. Overall, we compare favorably with our peers on this important metric with our results being comfortably below the average during the course of 2015.

Joe Gatto, our Chief Financial Officer, will pick up on slide 12 with the financial discussion.

Thanks, Gary. Thanks, everyone, for dialing in.

I'll pick up with an overview of some of the key drivers of our financial performance, including sustained sequential growth in production in proactive management of our capital spending program. These two drivers set the stage for progression to living within our means on a cash flow basis. But there are several other factors that contribute. One of those items is related to transportation differentials.

Looking at the chart on the right-hand side of the page, you can see a summary of our all-in realized differentials to WTI, including the Midland Basin differential and transportation. Gary highlighted the progress we've made on the expense front. We also want to point out the revenue enhancements we've achieved by focusing on moving our oil volumes to gathering system take-away versus trucking, and this is reflected in a reduction in the green bar on our chart. The off-take improvements started in the third quarter and we expect to see continued improvement in this metric into 2016 as we target getting substantially all of our production on pipeline by mid next year.

On page 13 we once again highlighted the dramatic improvements in LOE, but equally important, have illustrated the evolution of our total cash operating cost structure on the right-hand side of the page. In the fourth quarter of 2015, our cash costs, including G&A, were just over $12 per BOE on a two-stream basis -- almost 40% lower than just one year ago. This cost structure enabled us to earn an adjusted EBITDA margin of over $32 per BOE in the quarter, were 73% on a margin basis and provide strong support for internal cash flow generation moving forward.

Turning to slide 14, I'll summarize our 2016 operational plan under the reduced activity program we released in January. We will continue to focus on the Lower Spraberry development, which generated acceptable unhedged returns, even at low extremes of the strip pricing we've seen in recent months. However, we have decided to trade near-term returns to attain our goal of being net cash flow neutral on a corporate basis by reducing our drilling activity in 2016. Given the capital efficiency of this focused program of activity, that's shown on the right-hand side of the page, we are now targeting our cash flow goals in the second quarter of 2016.

The resulting production profile from this capital program has been tailored to live within our means is highlighted on page 15. We expect first quarter 2016 production to be in a range of 11,600 to 11,800 BOE per day, representing an increase of approximately 10% over the fourth quarter of 2015. Moving through the year, we forecast modest sequential growth as we transition to the one-rig development program this month in combination with continued reductions in our operating cost structure.

Slide 16 provides a snapshot of our balance sheet credit metrics as of December 31, 2015. We enter 2016 with a solid liquidity position that is over three times our operational capital program and leverage of 2.75 times debt to adjusted EBITDA. Overlaying an operational plan expected to be cash flow neutral next month, we have a high degree of financial flexibility to compliment the operational flexibility we have demonstrated over the last year.

And finally, on page 17, we've outlined a high-level scenario analysis for an assumed one-rig development program through 2017. As discussed, we've been very focused on the concept of cash flow neutrality on a corporate basis and wanted to provide some additional detail around that as our target comes into clear focus. In order to truly present our estimates on a more comprehensive corporate level, and not just simply looking at EBITDA or cash flow from operations less CapEx, we've outlined our theoretical bank borrowings under on one-rig case throughout 2016 and 2017 to capture broader corporate cash dynamics.

Importantly, the analysis includes estimated changes in working capital, which can be meaningful when transitioning to a lower level of spending. For example, as we move through the first quarter of 2016, we are paying cash for the accounts payable incurred under a higher level of activity and well costs in the fourth quarter of 2015 and then replacing those balances with a lower level of accounts payable due to a moderating level of activity under a lower well cost structure.

Since receivables aren't coming down very much due to increasing production profile and the impacts of hedging, there is a working capital requirement to be funded. In this case, that requirement is approximately $15 million to $20 million in the first quarter, including the timing of our normal equity incentive payouts, which then normalizes for the rest of the year under a sustained one-rig program. We also completed another working acquisition in the CaBo area for $10 million in the first quarter, which contributes to a total $25 million to $30 million of one-time funding needs. However, once we move into the second quarter, the capital efficiency of our program is clearly evidenced by the flattening of the lines under both pricing cases in 2016.

While there are several price, capital and cost assumptions that are incorporated in this outlook, we believe this analysis highlights two key takeaways. One, we expect sustained sequential production growth with a one-rig program, even on a longer-term basis. And two, after achieving our targeted goal of living within our means in the second quarter, we maintain a solid liquidity position of at least 2.5 times our operational CapEx program for 2017 under a strict pricing scenario.

I will now turn the call back to Fred for some final comments.

Thank you, Gary. Thank you, Joe.

Again, as you can tell, we're -- it's a challenging environment, but we feel like we are very focused on the right things, starting with the balance sheet and continue to evaluate opportunities to create value for our shareholders.

So with that, we'll open the call to questions.

(Operator Instructions)

Your first question will come from Will Green of Stephens. Please go ahead.

Good morning, guys.

Good morning, Will.

So obviously great to see the ability to get cash flow positive by next month. I wonder if you guys could -- I know it's a way out, but I wonder if you guys could think -- talk about how you think about 2017. And is this a scenario where cash flow -- being cash flow positive is kind of the first priority? Or say strip was, say, $10 or $15 higher since the returns do seem to be there, would you guys be willing to deficit spend a little bit to see some growth? I just -- ultimately, I want to see how you guys are thinking about balancing that growth and cash flow neutrality going forward beyond just 2016.

Sure. This is Joe. I'll let Gary jump in here. But from a planning perspective and how we think about bringing in a second rig back, it's really not tied to any specific headline price. Certainly cost structure plays into that dynamic. But given how important the goal of living within our means has been, we would certainly want to see a couple quarters of delivering on that goal before we went back into a cash flow deficit of any magnitude.

Clearly, the returns are there to be had, but we want to make sure that we're firing on all cylinders from a cash generation standpoint, continuing to deliver on cost and capital reductions before we start out-spending a little bit. And want to have a clear path on that. But clearly we have the option with second rig being idle to turn that back up in a short period of time, which if we can get there as we planned next quarter and deliver for a couple quarters, back end of the year, if prices are hanging in, it certainly gets on the table again.

But, Gary, I'll let you fill in there how you're thinking about it.

I don't know if I have much to add. It's really around project economics. If we're still delivering solid project economics to cover our costs and balance sheet still looks pretty healthy and we see some stability in the way the cost curve is moving up, what price curve is moving up and costs are still somewhat moderated, then, yes, we'll take an opportunity to take advantage of bringing that rig back up and accelerating our growth profile. But we won't -- we'll be very deliberate about how we make that decision. I think Joe said a couple of quarters and I think that's probably right. Let's see stability in both commodity price and service costs as we go forward before we jump too quickly into that growth race.

Thanks for the color there. And then maybe on the PUD development schedule you guys are thinking about. I know you do have some Wolfcamp PUDs on the books, but most the development this year -- Spraberry -- how should we think about that development going forward?

Should we expect to see you guys keep a fairly Spraberry-heavy program into next year if we're still talking about a depressed commodity environment? Or is it a scenario where now that you guys are 100% HBP, we could maybe see you guys doing some multi zone kind of single-pad development and actually knocking out quite a few more Wolfcamp wells next year in that type of scenario? How are you guys thinking about that development going forward?

That's a good question again. We've been very focused on the Lower Spraberry development specifically because the returns are just so exceptional. And we continue to have good partnerships with service providers helping us achieve those types of returns. And we're forever grateful to all of those that are helping us do that.

But you're right. The Wolfcamp returns, certainly in the central Midland Basin, are exceptional as well. They compete for capital now. It's just that they are not quite as good.

The Wolfcamp wells, certainly in our Pecan Acres, are very good wells. So it comes back to, again, I think the way we ought to be managing this business is good project returns and if price is stabilized, if they start moving upward and costs don't get too aggressively increasing, then I think we can get to perhaps thinking about multi zone developments from similar pads. We certainly are very efficient with the way we develop wells today because we still are doing multi-well development from a single pad, but it's just myopically focused on our best asset.

Okay. So the way we should think about it is if the strip kind of holds out to be correct, then we should still expect kind of a heavy Lower Spraberry development schedule in the first half and then maybe sprinkling in Wolfcamp at some stage later in the game. Is that the way to think about it?

That's the way -- that's exactly what we're thinking about, Will. We're very focused on our best returns in this environment and then getting some stability in the commodity price environment. If that holds in perhaps late 2016 or 2017, we'll start thinking about perhaps other zones that we would bring in.

I just want to emphasize, we've got a lot of inventory in the Lower Spraberry. That could carry us a long way. So we're not short of inventory for what we're focused on today.

Great. Thanks for all the color, guys.

Our next question will come from Neal Dingmann of SunTrust. Please go ahead.

Good morning, guys. Nice quarter. Say, Gary, just a follow-up question on that. Looking at that slide 8 that shows the Spraberry density increasing, is that going from 8 to 11? Your thoughts on -- I know you kind of report how many locations now based on the wider, but your thoughts on now on that 11 using that Chevron pattern throughout more of that northern acreage. Is there anything you could add about that?

Yes, we're very impressed with the well results that are coming from these two wells. So clearly more than eight is justified. We've been paying a lot of attention to what Diamondback and RSP have been doing in this area as well.

And so what this tells us, especially the performance of the upper well -- the upper well is very critical here -- says that that's equivalent to wells that are performing in the lower area, which we thought would be -- we probably would see a distinct difference. And we didn't. So we're very encouraged that the upper section of the Lower Spraberry may well have an entire level of development on its own, which is essentially some of the thoughts that were expressed in some of the slides that RSP put out as well.

But the other key factor is in the lower section of the Lower Spraberry where we're at 840 feet apart, that's actually a wider spacing than we actually have been comparing ourselves to because we've been at 660 with 8 wells a section at the same TBD level. So all of that justifies more opportunity than 11 -- is what it tells us.

Now I'm not ready to jump to 2016 yet, but somewhere between 11 and 16 is probably the right number. Again, we'll be doing some additional spacing tests as we move forward this year. We'll put some wells closer together at the lower level with this as we go forward. But the encouraging part of this is the Lower Spraberry looks to have more opportunity than at least we've defined at this point in time, which is consistent with what other companies have done.

We've watched one offset operator kind of go across and kind of mow the grass or develop the Lower Spraberry really at about 520 feet apart, which is, again, very encouraging for increasing the number of locations for the Lower Spraberry. We're just going to do it in the same manner we do everything. We're going to be deliberate. We're going to do our own evaluation.

We're going to pay attention and learn from others around us as we share information and look at real results. But I guess the summary here, Neal, is we're not done here yet. But this is a good step in the right direction.

I'm glad you mention that 16. That was already going to be my next question, Gary.

Two more things -- just on that slide talking about -- I think it's slide 11 that talks interest some of the cost reductions you have. Any idea ballpark -- you talked about the saltwater and disposal and the chemicals being maybe the greatest potential. Just a comment from you or Joe -- how big could that be for this year?

Well it's kind of interesting, Neal, that -- we worked hard, very hard to get where we are. And every company out there that's still active is doing the same thing. And they are developing the right relationships with their service providers.

What's interesting to me is over the last couple of months, I think maybe it's because of the reduced level of activity that's actually in the basin now with additional rigs coming down, there seems to be an increased energy around competition for services. So we're getting calls quite often from companies that want to do our work that we haven't had relationships with in the past and as well as the companies that are doing our work, saying hey, I think I can move this down a little further. So it's that increased competition across every sector of the business, Neil. It's not any one sector.

It's all sectors that is very encouraging to me because this is kind of what I thought would happen. This industry is very resilient. It's very resilient. We always adjust and we always find a way to be profitable in whatever commodity price environment.

It's just challenging as we're moving down. And so now I think that adjustment is happening actually at a rapid -- more rapid pace. So I can't tell you any one thing.

We're very focused on every aspect of cost that we have in our business. We're very encouraged with recent cost moves from even trucking water -- significant reductions.

We're encouraged with negotiations around more competitive even pipeline transportation services that are increasing our margins. We're very encouraged with every aspect of pumping services on how we can bundle certain things or perhaps disconnect other things or maybe shift current bundling services to another provider and still get an incremental cost reduction.

So I can't tell you any one thing, Neal. But we're focused on every aspect of our cost whether we spend $100 or $100,000. And what I'm very encouraged with is we're just getting so much cooperation from our service providers because they are finding ways, themselves, to do things a little better. It's that creative, innovative thought that has always been present in our industry that I think is now starting to even accelerate as the challenges become even greater.

Okay. Great thoughts, Gary. And then just last quick one if I could. Joe, obviously you guys did a nice buyback on those preferred, obviously generating very nice return -- being able to use common for that. Just your thoughts -- is there more availability to do that -- your thoughts looking forward to either buy that or pay down some of the debt? Thanks, Joe.

Sure. That was a nice opportunity under [389] exchange that we did preferred for common. There's some of those opportunities out there on a select basis. But I wouldn't say it's broad based.

It's an instrument that's pretty much held in retail type of hands, but sometimes there are larger chunks that if people see the value proposition, our common stock are willing to do that on an attractive basis for us and find a win-win. And certainly with this transaction, we are able to bring in savings about $500,000 a year from the dividend that are repurchased or exchanged preferred shares. But it will be select. I wouldn't expect it to be broad based at this point.

Thanks, guys.

Our next question will come from Ron Mills of Johnson Rice. Please go ahead.

Good morning, guys. Gary, a little bit follow-up on the increased density slide.

Ron, we're having trouble hearing you.

Is that better?

Yes, much better. Thank you.

Good. The question is on the increased density slide. You perform that test at Carpe Diem. Is it something that you think, from a spacing standpoint, can be applied across CaBo and/or Pecan Acres as well or is there something about Carpe Diem that makes it more tenable?

No, no. We would expect that to apply across all of our central Midland basin assets, Ron. We don't make a distinction there.

We did it at Carpe Diem because we had a good opportunity to do that with some existing wells there that were producing at high rates. And we wanted to make a good comparison at one of our best assets. So, no, that should apply across all the central Midland basin fields.

So when we look at the increased well count, or inventory going from 126 to 143 wells, am I correct in assuming that there is a lot more upside to that well count as you get more comfortable and more data on the increased density results?

Yes, sir. That is true. Again, I think at least it's only two pilots that we've done. But what I see with our work and what I see with Diamondback's work and what I see with RSP's work, there is significant upside to that number.

Can you remind on the Lower Spraberry in that area, in the central Midland Basin, what the thickness is? And in the Chevron or [stagger stack] -- whatever you want to talk about -- is this similar to having an upper and a lower Wolfcamp B that you talked about in prior conversations that now it looks like you may have two zones with multiple development opportunities?

Yes. Ron, again, I don't have the right -- the exact number for the thickness, the gross thickness of the Lower Spraberry there. But it is very similar to what we talk about with two levels in the Wolfcamp B the southern part of our asset, certainly at Garrison Draw and our [Neal] assets at Bloxom. But even this pattern, I think it really demonstrates that even with 240 feet vertical separation between the two levels, we've got equivalent results from wells that are performing quite nicely and delivering solid returns. So clearly enough in the section that we have today. I don't think it's as thick as the Wolfcamp B south but the well results themselves speak volumes for getting access to the resource that's available.

Great. And then on the well cost, the last $300,000 or so of cost improvement, what were those related to -- just another 5%? And do you think you're approaching the cost limits there, or what's your outlook going forward?

Primarily a good chunk of that number was related to additional competition and interest in pumping services, actually. And then all the associated services related to pumping services, whether it be plugs or pump-down services, sand, chemicals, a good chunk of that was that. But the other part of it was really achieving more efficiency, chopping off a day here or there and drilling wells.

Now we're still very encouraged with the pace of drilling. Knocking off a day here or there reduces costs and that's a significant impact to any of these costs that we talk about.

I don't think we're at the bottom. I always think what is the next step? What is it? And then all of a sudden it just materializes because of the partnerships and the discussions we have with our service providers and the focus and drive that the team has in getting prepared for even potentially a lower commodity price environment. And I always ask my team, okay, now we've positioned ourselves for 30. What can we do to position ourselves for 25?

We have those types of internal discussions and we challenge ourselves as a team on, okay, maybe we can think about these things differently. Or maybe we can think about these -- maybe we can approach other service providers that have shown interest in a way that might encourage innovation and creativity from our current service providers. That is very helpful in the discussion. That challenging dynamic environment that gets me more and it gets us all more because we're continuing to work and operate and deliver results in this very good basin to be in in a challenging environment.

So I can't tell you where I'm going next. I'm just saying I don't think I'm at the bottom.

Got you. And then last one for me and maybe for Joe, it's the -- on the M&A or A&D market out there, any commentaries? Is it starting to become more constructive? Are you seeing more deals in the Midland as well as the Delaware, kind of buyer/seller expectations? Any description on how that M&A, A&D market is today versus three months ago?

Ron, we are seeing a lot of activity on the opportunity front. Now we saw a lot last year as well. It was probably more biased to the Delaware than the Midland.

But I think at this point we're seeing things sort of equalize a bit in terms of the opportunity set. And as you know, we're obviously a bit more focused on the Midland basin, although we'll keep an eye on the Delaware.

The discussions we have ongoing, I think that we have some at our working interest partners in the CaBo area, as we've talked about. We picked up some additional working interests the past quarter. So we have that ongoing activity.

There are some packages to add new acreage and positions. And we think that maybe prices are coming down a little bit, but not dramatically at this point because, at the end of the day, these are good assets that can earn a very solid return, especially for us. As someone who has proven to get down the cost curve and generate a return allows us to be in a position to hopefully meet where a seller's expectations are and still earn a compelling returns, going to compete for capital in our portfolio.

So we are hopeful that in the coming months that there will be some opportunities that get to the finish line. But you just don't know. Overall tone, though, I would say it's been a bit more positive than we saw last year in terms of trying to bridge the gap.

Perfect. That's all I had. Thank you, guys.

And next question will come from Phillips Johnston of Capital One. Please go ahead.

Hi, guys. Thanks. Just a question for Gary on your Lower Spraberry reserve adds last year. For both your PDP wells and the PUD locations that you booked, a comment on what the average AUR that [DM] gave you credit for. Was it relatively in line with your type curve or was there some conservatism or any other factors that may have led to the bookings coming in below your type curve?

Again, we're very encouraged with meeting or exceeding the type curve that we've actually published. And as you all know, we have a third party do all of our reserves, DeGolyer and MacNaughton. And with that comes some level of conservatism.

But they see the way we project our wells and they see -- we see the way they then potentially modify those projections up or down. But I can tell you we're very close, very, very close, very little separation between DM's reserves and what we're actually delivering. So I would suggest that as you would expect in the SEC definition of reserves, that they are more likely to go up than down.

Yes.

So we're very aligned with those definitions.

Okay. Makes sense. And then just a question for Joe. You guys are now generally spending within cash flows. So you're not adding any debt here. Your projected leverage ratios at the end of this year and next look fairly comfortable, even on strip pricing. My question is, if we assume that prices don't go lower from here, and if we don't assume any acquisitions, do you rule out the possibility of new equity issuance or is that something that you would still consider?

We obviously pulled a pretty big lever on the operations side but by reducing our program to one rig. And that's how we like to manage things. We want to live within our own means.

We don't want to be over-reliant on capital markets at any one time. And I think we've been pretty clear in the past and still of the mindset that we view the equity markets to be useful to support our acquisition initiatives. And as we said, we're looking hard at a lot of things.

So to the extent that could help us position ourselves and be a little bit more active on that side of things, that's our first step in terms of accessing the public markets. But it's good to see that they are still open and can be constructive moving forward to support our growth initiatives.

Okay. Thanks, Joe.

The next question will come from [Gabe Dowd] of JPMorgan. Please go ahead.

Hi. Good morning, everyone. Joe, I think you touched on this in the prepared remarks. But maybe just going back to production guidance and ultimately what the trajectory looks like throughout 2016 and maybe what a 4Q over 4Q exit rate looks like.

I think that at this point we have a nice jump into the first quarter of 2016. And I think we're currently running towards the top end of that range that we've provided.

But moving through the rest of the year, we will see a moderating in growth for moving down to one rig of activity. But given the results of the Lower Spraberry, we do have a slight uptick. It's exit to exit.

You're -- from first quarter of 2016 to end of 2016, Gabe, is that--

From 4Q 2015 to 4Q 2016, any thoughts on what that could potentially look like?

Yes, it's about 10% or so.

Okay. That's helpful. Thanks for that.

And then just maybe on LOE guidance -- so 4Q came in pretty strong. And it looks like maybe in 2016 it kind of ticks up a bit. Was there anything specific going on in 4Q that maybe we should be aware of? Or how should we think about that?

In terms of the guidance there, it will directionally trend down over time. So the way we forecast that, we want to be a bit conservative. You never know when you're going to pick up a work-over here or there.

So we would rather be on the low end or below that guidance range than trying to get that right and get the timing. So it might look a little bit funny in terms of, well, you came in at under seven in the fourth quarter and now you're above that. It's just really to capture -- work-overs will happen.

So it's just tough to forecast. And so we just continue to build that in. But we should definitely see a trend down over time.

Got you. That's helpful. And then maybe just one more. So I guess the increase to the Wolfcamp type curve, which I guess maybe bringing you guys essentially in line with some of your peers, maybe just a little bit more color on that and what you saw that gave you comfort to lift it. And then, ultimately, on that slide that you show with economic inventory at certain price levels, does this now shift some Wolfcamp inventory into that kind of $30 bucket? Or how are you thinking about that now?

Again, the Wolfcamp delivered solid results certainly in the central Midland Basin assets as well as even Garrison Draw area and Bloxom in the southern assets. Not quite as good there, but still good. But this inventory on page 9 as we break out inventory around $30 oil or lower, then that's still primarily focused on our focus on the Lower Spraberry.

We've got two exceptional Wolfcamp B wells coming back. But they are in the Pecan Acres area and we're paying attention to that. One of them was drilled and completed by RSP and our partnership on the east side of Pecan Acres. And the other one was drilled and completed by us.

Those are very good wells that justify moving that type curve up. And so that inventory is pretty solid in the Midland -- central Midland basin. But, no, we're still focused on significant high performing results, primarily in the Lower Spraberry.

And, Gabe, I think on that, on that slide, we have a dotted line to sort of capture. We think there will be a chance of maybe moving some of these bars around. We prove to ourselves we're delivering on the low end of Gary's comments on the well costs that [forwarded] this over time. Once we feel comfortable, we can deliver those types of well costs on a sustained basis, combine it with the type curves we're talking about today and shift this around over time.

But as Gary said, right now it's really focused on Lower Spraberry. When it's this volatile an environment, you're not sure what you're going to wake up to. But I think there's room to move some of that around.

Yes, it's simple blocking and tackling in our business. We've got to do everything well and do everything right and we're not afraid of the Wolfcamp. But we know what we're delivering in the Lower Spraberry. Very encouraged with what we see in the Wolfcamp too.

Got you. That's helpful. Thanks, guys.

Our next question will come from Mike Kelly of Seaport Global. Please go ahead.

Hi, guys. Good morning.

Good morning, Mike.

Current economics that you lay out in slide 9 is certainly impressive with 40% rates of return at $30 oil in the Lower Spraberry. But these are project returns. And given that you're thinking about being maybe a little bit more acquisitive going forward -- I guess this is a question for Joe.

Curious how you guys think internally about full cycle returns that will fully burden the cost structure with some level of acreage or leasing expense. Maybe asked just a little bit different way, just how you get a comfort level of paying current market rates, which are still fairly high, in the current environment. Thanks.

Sure. As we think about A&D opportunities in the market, going back to my earlier comments, you're not going to -- things are still on headline numbers that look not cheap. We get that. And when we look at the returns in the Lower Spraberry, certainly it's a high bar to clear.

There's not a whole lot that competes heads-up with that. But we do see an opportunity to compliment that with new acreage, new opportunities that will approach that and broaden out through the portfolio of NAV potential for us.

But going back to my comment earlier, the only way that we think we're going to be competitive is really the operational structure that we have. Right? We're proving ourselves as a very capable horizontal operator that, in this environment, importantly, has been able to push down the cost curve as well as anybody. And without that ability, I think, yes, it is hard at face value to say, well, how are you going to get returns that come within spitting distance of this?

But when you think about what we can accomplish as an organization on drill and complete costs and the operational efficiency, we think that's really our advantage here to step into some new positions. Overlay that with the fact that we are 100% held by production. So to the extent that there are opportunities that shake loose in the coming months and quarters that are driven by operators, private entities that don't want to put more money in the ground because they are maybe not as efficient and they haven't been pursuing a sustained horizontal program to allow them to deliver lower costs, we can step into those positions and theoretically maybe can get them a little bit cheaper, just because of that dynamic to hold acreage, and shift activity from our existing fields over there and not have to increase our overall CapEx budget.

So there's a lot of ways. In this market you have to look at things. But we think we're pretty well positioned to selectively step out and find opportunities that are going to be additive to the portfolio and, more importantly, put this organization to work on a larger footprint that we're set up to do.

Okay. Got it. Joe, maybe just switching gears to the balance sheet, just curious on your preliminary thoughts for the spring borrowing base redetermination season here. And your PV-10 really didn't get whacked here at the end of the year and you guys are still growing production. So just anything you could share with us on your thoughts on how those -- how that should shake out with the banks. Thanks.

Sure. This has been -- I guess you think of the past as borrowing base redetermination has always been sort of an every six-month event. But starting with early last year, we made it a much more frequent dialogue and being close with the banks and what they are thinking and us trying to help them understand what we're doing on the business side, the cost reductions that we're getting. And it's been an ongoing process and dialogue really over the last year and a half, very hand in hand.

So we have a pretty good pulse on that type of analysis and this has not been any different the last couple months. We shared our reserves back in January, I think, as a first pass of where we were coming out and recently went back to our lead bank and shared sort of our bank case for the reserve determination that will kick off here in the next few weeks. But I think the feedback here is that we would expect today -- and, again, we have to go through the formal process -- but I think the feedback is that we should be hanging around the $300 million number through this redetermination.

Great. Thank you.

The next question will come from Chris Stevens of KeyBanc. Please go ahead.

Hi. Morning, guys. Just wanted to touch on M&A really quickly, again, here. I know you evaluate a pretty wide range of deal sizes, but is there an upper bound you guys think you would be able to handle or that you would be comfortable with? And does that change at all Midland versus Delaware Basin?

We are certainly seeing some larger packages that are out there ranging from the $10 millions to $200 million to $300 million type of opportunities. I think that's probably the upper bound of what we're looking at from a financing execution standpoint in this type of a market. And certainly there's a lot of options for us.

Talked about the public equity markets. There's also I think a large pool of capital, whether it be working interest partners or more private capital that are looking to put money to work in the Permian, looking for good partners like ourselves. So you add all of that up.

We look at a variety of different alternatives to tackle larger opportunities. But I would say $300 million or so is probably the upper end, maybe a little bit more, that we've evaluated when you get a little bit creative. But -- so it will be obviously a needle-mover for us for something in that weight class.

And between the Midland and Delaware, I don't think we make a distinction on size necessarily. The Delaware has to check a lot of boxes for us and a lot of things have to come together.

But for the right opportunity, I don't think it's going to be penalized by size for the right transaction in the Delaware. We have to have a vision for a development program that over the next 12 to 18 months as we overlay cost efficiencies, long laterals, the things that we're doing in the Midland, in the Delaware, if we see a clear path to seeing returns approaching where we are in the Midland, then that's a good opportunity and we're not going to constrain it by size parameters.

Okay. Got it. And, I know you guys have been also pretty active in testing different things on the completion design. Can you maybe just update us on some of the recent things that you have tested and maybe what you see now as sort of the standard design in terms of prop and stages, clusters, et cetera?

Yes, this is Gary. And what we've mostly experimented with or tested is really the sand loading. And we've gone from anywhere from 1,000 pounds per foot of sand to 2,000 pounds per foot of sand.

I guess generally my comment would be that in good rock, we're seeing less benefit from the higher sand concentrations, incremental improvement from the higher sand concentrations. So we're pulling back a good bit from the highest levels of 2,000 down closer to 1,500 to 1,700 pounds per foot. And the areas that aren't quite as good, I think, clearly, the industry and other areas, as we follow that and pay close attention and stay on the upper end of the learning curve of this activity, some areas would require more sand to get better returns.

But where we're focused now, we think we're honing in on 1,500 to 1,700 pounds per foot, which is about the right place. We haven't experimented much with stage spacing yet or stage length yet as far as that goes. We're right around 250 per stage, still 4 clusters per stage, still use limited entry perforations.

And we're looking at some work right now about potentially reducing that stage length and then some work also about extending that stage length. It's all around, again, getting the best return for the project.

So that's really our next step aside from more spacing tests to find inventory. Our next step would likely be using some variation of stage lengths. But we haven't done much with that in our own portfolio.

Great. Appreciate the color.

Our next question will come from Kyle Rhodes of RBC. Please go ahead.

Morning, guys. Appreciate all the color. On the 11 well density pilot, the data certainly looks promising early on. How much time do you guys need there on any of the higher density tests planned for this year, whether it's 12 or 16, before deciding that's kind of the optimal development plan going forward?

Given all the work that -- again, I will compliment RSP and Diamondback on this issue, they have done more work in this area than we have. And we pay close attention to what they are doing and we see the well results, at least whether they're publicly or traded as we trade information across different areas. And it won't take us long to hone in to what we think to be the right number going forward.

But we will be cautious that we don't overcapitalize an area. So, again, with what those guys are doing in a single level, a single TBD level being much closer spacing than what we're show going on this page and what RSP just recently put out with some of the things that they are thinking about, it won't take as long to get on to a number that we're comfortable with going forward with our inventory.

Okay. Got it. That's helpful. And then I guess would you contemplate any change in the completion design as you have some of these tighter tests later this year?

Again, that's possible but all these wells were completed in an equivalent manner. And so as long as we're seeing those types of returns or better, then we would keep it the same.

Okay, great. And then just any update on your middle Spraberry well? Is that still holding in at expected levels? And any early thoughts on EUR there?

We're still excited about that. We had a great IP-24. We had a very good IP-30. It's still doing well.

I can tell you that it's a single test for us and [petrophysically] that zone is going to work quite well. And again, I'll compliment the other companies I've talked about respectfully on this call because they have done a lot of work in that zone as well.

So we're encouraged. We're not to the point where we think we've optimized our completion design there yet. I think we can do better with the next one.

But I would say that that well is more comparable to a Wolfcamp well more so than a Lower Spraberry well at this point in time. So still encouraged. We don't have another test planned for this year because of just where we're staying very focused on returns. But very encouraged with that well.

Okay. And then just maybe a final one for me, for Joe. As we move through 2016 into 2017, how are you thinking about starting to layer in some additional hedges?

For 2016 on the oil side, I think we're in pretty good shape, around 60%-some. Really don't see a whole lot there, especially moving to the cash flow position that we're targeting. As we look out to 2017, starting to take some interest with what's going on there, especially in a volatile market if there's some extra value you could leg out from monetizing some of the volatility and [collar-type] structures.

But with the returns that we're seeing in the Lower Spraberry and us getting increasingly comfortable with the cost structure that we can deliver on even with an uptick in prices, things in the mid-[$]40s start to make sense for us to at least layer in a little bit of that protection. We'll slowly wade into that. But we are seeing some interesting things that just make sense from a risk management standpoint without taking too much optionality away.

Very good. I Appreciate all the color. Thanks.

Our next question will come from Tim Rezvan of Sterne Agee. Please go ahead.

Hi, good morning, guys. Most of my questions have been answered. I just had one that I was curious on.

Is there any update on your efforts to block up your kind of northwest Midland county acreage? I know it's something you've discussed. Is that dead? Is that still being kind of discussed? Or I guess where do we stand on that?

No, no, no. That's always an option there. We may get a call any day. We don't expect it because that is [Faston Orlin] Ranch. They like to do their own thing.

They have suggested they would love to see and watch and pay attention to what we do to further derisk and make their acreage even more valuable. But at the end of the day, they have expressed no interest in partnering with us. It's a matter of fact statement.

Okay. That's all I had. Thanks.

The next question will come from Irene Haas of Wunderlich. Please go ahead.

Hi, thank you. So tremendous results coming out from the Lower Spraberry and the Chevron [patch]. I'm just kind of curious, is this thick enough to fit in certain layers, just to be greedy? And then also, is the Wolfcamp B thick enough here to also accommodate another layer? Can you replicate this configuration in your other formations?

Irene, I'm not quite sure I heard the exact question on the Lower Spraberry, but clearly there's opportunity for two levels. I wouldn't expect I would push it beyond that in the Lower Spraberry. And the middle Spraberry is still being more further defined, primarily by RSP more so than by us.

We just want to make certain that in this market we stay focused on good returns. But the middle Spraberry petrophysically has every opportunity to perform as well.

Good. So they're in that thickness for you to fit in the Chevron patch. And then is Wolfcamp B thick enough in this location?

No, I don't expect the Wolfcamp B to be thick enough in the central Midland basin for the resource we're shooting for. But certainly the work going on in the Lower Spraberry is encouraging. And the other thing that we'll be doing later this year, again, in our partnership with RSP and Pecan Acres is doing an A well in that area.

We're very, very excited about the Wolfcamp B and the Lower Spraberry performance. And we want to see what we can do with the A. That will be a 10,000-foot test drilled adjacent to the two wells that were just drilled.

And again, the company that's led the development around both A and B test have been RSP. So we're happy to be partnering with them on that. So the A, I think, is a good data point to look for later in the year.

Great. Thank you very much.

Sure.

Our next question will come from Jeff Grampp of Northland Capital Markets. Please go ahead.

Good morning, guys. I think you had talked about having five of six of your major fields on pipe now and plans to get Carpe Diem there by midyear. Can you talk about expectations for where your corporate differentials go once that last one gets on pipe?

Yes. We have -- we've been realizing this over the last couple quarters. So it's getting staged in. Looking back to earlier this year, running about $250 on average across all of our fields, we would expect, once we get everything up and running, that's going to equate to something a little more than $1 savings from that number once we're all dialed in. And, yes, that's what we see right now.

But Gary I think alluded to that we are seeing some of the tariffs on our existing pipeline connections coming down as well. So we haven't really factored that in. Not sure if we can continue to push on that side of things. But just to give you a ballpark, we're probably going to save a little bit over $1 from that $250, $270 range that we were running earlier this year.

Okay. Perfect. That's helpful. And then last one for me, just kind of wondering, you guys obviously are in a great position from a cash flow CapEx standpoint, pretty well hedged. But if oil weakens further, kind of how do you guys think about kind of funding the plan?

Do you cut a rig? Do you slow completions? Or do you guys feel pretty comfortable given cash flow is pretty robust and your hedge book is pretty well put together?

I think we generally feel pretty good where we are for the reasons you highlighted. And equally as important, continue to deliver on the cost side. That's the thing that we can control and we continue to see progress beyond what we've budgeted for that gives us a bit of a cushion as well. I mean the options of delaying completions and such are always there.

That's really never been our first move because we view that as taking a bet on the commodity. As things don't improve, you've sort of stranded drilling capital in the ground. And that doesn't make much sense for us. So we think that we've built a plan now under a 1 rig scenario that gives us a lot of room to manage through a lot of scenarios at this point.

Fair points. Thanks for the color.

Okay.

And ladies and gentlemen, we have time for one last question from Ipsit Mohanty from GMP. Please go ahead.

Hi. Good morning, guys. Thanks for squeezing me in -- getting to the top of the hour.

But really just -- this has been asked often. Let me just take another angle. Gary, in regards to the downspacing and [low stream] being associated with recovery factor, there have been some concerns about the drainage from vertical drilling, vertical Spraberry that has been done over the period. Now when you look at this -- not just you, but your peers -- you talk about recovery factors, is this being accounted properly -- the drainage that has happened historically?

I believe, again, that's an interesting conversation because there's a lot of vertical wells that have been drilled in this basin. And the encouraging thing is we're seeing the wells that have been on the longest. We're not really seeing that drop off because of that potential depletion effect.

So what I see is accessing really is resource that is new and captured and won't be achieved just through vertical development. That's why I'm very excited about where the industry is headed. That we don't have a vertical well even [thought] -- we don't even think about vertical wells anymore.

So potentially there could be isolated areas that you may run into a part of a frac that may be more depleted than others. But as you extend that length of that lateral across a section, which is the minimum length we're drilling, or across two sections, you're accessing significantly new resource that is very well represented in the type curves that we're achieving.

Okay. And you talked about the type curves, so it just struck me, do -- in your experience in drilling so many wells in that particular zone -- do you agree with what some of the peers are saying that the wells tend to come lighter than the Wolfcamp but the decline is shallower? Is that something that you're seeing in your wells as well?

I'm not -- I don't catch what --

Some of the peers are saying about the declines with further higher density drilling. I think that was your question, whether or not I'm seeing moderated declines, if I have a higher spacing or density.

General type curve question, lower IP.

No, no, no. Again, the Wolfcamp -- again, the way we -- it's kind of a general way, a way we operate again. We don't really pull our wells really hard early time. So even some of the Lower Spraberry wells that we had and even some of the Wolfcamp wells we have after two or three months, we're still increasing production because of the way we perform them.

But in general, if it's a general question that you're asking, then, yes. The decline in the Lower Spraberry because of the porosity development and the access to the resources is generally lower than that of the Wolfcamp.

Okay. And my last one is, again, on slide 17. Just curious about some of the assumptions that you've laid out for 2017. You talked about the borrowing base being the same. But just in terms of operating costs and well costs, have you taken status quo to what you have right now to draw out those two scenarios for 2017? Or have you taken any further trend down in well cost operating expense?

Both on operating costs and capital, we're sort of looking at sort of holding in where we are today on what we're delivering on a leading edge basis. LOE is going to benefit from an increased amount of production and leveraging some of the fixed components of LOE. But we haven't assumed any further reductions that Gary talked about -- chemicals or things like that.

So it's things that we have good line of sight on. Some of that could be impacted in terms of what pricing scenario you're looking at. You just don't know. But we're not going to get that right. So we sort of left things in terms of what we're delivering on today throughout this two-year type of forecast.

Okay. So if you could see any further improvement in costs, organic or service providers or operating costs, you'll probably feel better outlook for 2017?

Yes. I think that's a fair statement.

All right. Thank you, guys.

Thank you.

Thank you.

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 his closing remarks.

Thank you. Once again, we do appreciate everyone taking the time to call in. We appreciate all the questions and if anyone has any questions in the meantime, please don't hesitate to give us a call. Thank you so much.

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