Callon Petroleum Co (CPE) 2014 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second-quarter 2014 Callon Petroleum earnings conference call. My name is Philip, and I will be your operator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Fred Callon, Chairman and CEO. Please proceed.

Good afternoon. Thank you for taking the time to be part of our second-quarter 2014 results conference call. Before we begin, I'd like to ask Eric Williams, our Manager of Finance, to make a few comments.

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 of similar meaning. These projections and statements reflect the Company's current views, with respect to future events and financial performance.

Actual results could differ materially from those projected, as a result of certain factors. Some of these factors are discussed in our filings with the Securities and Exchange Commission, including our 2013 annual report on Form 10-K, available on our website or the SEC's website.

We may also discuss non-GAAP financial measures, such as discretionary cash flows, adjusted EBITDA, and adjusted net income. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our second-quarter 2014 results news release and in our filings with the SEC, both of which are available on our website.

Fred?

Thank you, Eric.

I'm pleased to report another solid quarter for Callon, both on operational and financial fronts, including over 20% sequential production growth from the first quarter. Our team continues to demonstrate its ability to execute our horizontal development program across multiple zones and fields in the Midland basin. We've just completed our 36th operated horizontal well and expect to a total of 40 horizontal wells completed by year-end.

As Gary will discuss in more detail, we plan to capitalize on the skilled team and basin expertise that we have built with acceleration of our horizontal drilling program later this year. We have taken a measured approach to making this decision and believe we're now at a point where it makes sense to pull forward the returns associated with our inventory of over 650 potential locations, while leveraging our operating capacity.

We expect to see the impact of this accelerated activity in 2015, with current plans to drill and complete approximately 40 operated wells next year, in addition to several joint wells with other operators. Based on that forecast activity, we anticipate having over 80 horizontal wells on production at the end of next year, firmly establishing Callon as one of the leading horizontal operators in the Midland basin. We estimate this program will grow annual production by more than 50% in 2015, compared to 2014, and enable us to set a target exit rate of 9,000 barrels of oil equivalent a day at the end of the next year.

I'll now ask Gary Newberry, our Senior Vice President of Operations, to talk about our operational results for the second quarter and our plans to accelerate activity into 2015. Gary?

Thank you, Fred, and good afternoon to everybody.

On our last call, I talked about increases to our type curves as we optimized completion techniques and confirm our type curves with longer-term well performance from our growing number of producing wells. This extended production data has been important in shaping our views of EURs and our development planning process. In some ways, we are still in the very early innings of having a complete picture of ultimate recoveries in the basin, but the data we have and are seeing is encouraging.

I was recently in a planning session with my team, and we were reviewing the performance of our very first horizontal well -- the Neil #321H. That well was placed on production over two years ago, with a smaller completion design than we were using today. At that time, we estimated that this Upper Wolfcamp B well would have an EUR of 420,000 barrels of oil equivalent, which really became the baseline for our type curves in the basin.

Based on recent production data and observed declines, we now estimate that same well to have an EUR of approximately 575,000 barrels of oil equivalent, which is at the high end of our recently provided type curve range of 475,000 to 575,000 barrels of oil equivalent for Wolfcamp B wells with 7,000 feet completed lateral length. We still have much to learn from each completed well, and we remain encouraged by the early time performance of wells with larger fracture stimulations.

On the EUR topic, just as a reminder, we are a two-stream reporting Company. We estimate that our 475,000 to 575,000 barrels of oil equivalent type curves are roughly equivalent to 525,000 to 630,000 barrels of oil equivalent on a three-stream basis.

With a significant resource base delineated across our core development areas, we continue to refine our operations and program development mode. In addition to larger completion designs, we remain focused on optimizing our recoveries by testing different concepts during flow- back, which include flowing back wells longer under natural pressure to prevent damage in the reservoir and testing both gas lift and [sub] pump artificial lift techniques. We believe that these efforts are having a positive impact on our recoveries, evidenced by the early positive signs we see in the extended 90-day production rates of our recent wells.

We've placed 14 Wolfcamp B wells on production in the first half of this year, and seven of these wells have at least 90 days of production history after being run to the battery. These seven wells produced at an average rate of approximately 565 barrels of oil equivalent per day for the initial 90 days. This performance equates to a per-well average of approximately 50,000 barrels of oil equivalent in their first three months of production, which places this performance above our current 575,000 barrels of oil equivalent per day type curve, thus providing additional opportunity for higher EURs in the future.

Moving to more specifics around second-quarter activity, we drilled six gross wells and completed nine gross wells. Three lower Wolfcamp B wells were placed on production at our Taylor Draw field in Reagan County, with an average completed lateral length of 4,965 feet and an average 24-hour peak rate of 866 barrels of oil equivalent per day.

These wells, which include the Weatherby [four, five, and six], have been producing under natural flowing pressure since mid-May. We're pleased to see this type of well performance and producing pressure in a somewhat shallower portion of the basin and believe that our larger frac designs are a key contributing factor.

At our Carpe Diem build in Midland County, two Wolfcamp B wells returned to production with average completed lateral lengths of 6,574 feet. The Kendra Kristin 1121 and the Kendra Kristin 1122 had recent 24-hour IP rates of 1,163 barrels of oil equivalent per day and 1,176 barrels of oil equivalent per day, respectively, after being put on sub pump. This supports our positive views in this field's potential, especially since we are still producing these wells at somewhat restricted rates, due to gas curtailment issues that we are in the process of resolving.

A two-well pad was brought online at our Garrison Draw field in Reagan County, with stacked development of the Lower Wolfcamp B and Wolfcamp A. These wells continue to flow back under natural pressure after 40 days.

The Wolfcamp A well, the University 15AH was our third well targeting this formation, with the other two being drilled in Upton County at our East Bloxom field. Based on our experience with these wells, we have established an initial type curve assumption of 400,000 to 500,000 barrels of oil equivalent for this zone in the Southern Midland Basin, with an associated well cost of $7.7 million for a 7,500-foot drilled and completed lateral.

As we look out the remainder of the year, we plan to complete an additional 15 horizontal wells, which is a modest increase over our original plan, due to operational efficiencies and a change in the working interest composition associated with our targeted wells. These completions will be focused on two levels of the Wolfcamp B.

In addition, we are currently drilling our first horizontal well outside of the Wolfcamp Shale, targeting the Lower Spraberry at Carpe Diem in Midland County, which will be completed later this year. We're progressing initiatives to expand our program development model to two additional fields, we're currently drilling a 9,400-feet Wolfcamp B well with a partner operator at our recently acquired Opal field in Upton County, and we are permitting two horizontal wells at Pecan Acres in Midland County, targeting the Wolfcamp B and Lower Spraberry zones.

That brings me to my final topic. On previous calls, I've talked about the outstanding team we've assembled to shape and drive our development program. I'm eager to leverage their expertise, along with the infrastructure capacity we have established in each of our development areas, with a plan to accelerate activity later this year with the addition of a third dedicated rig supporting horizontal development.

The rig is a high-capability vertical rig that will be used to set intermediate casing in front of our two horizontal rigs, which will then drill the curves and the laterals. We expect to take delivery of the rig in October and anticipate seeing the impact of increased production in 2015, with the planned drilling and completion of almost 40 operated wells, a 33% increase, compared to 30 wells in 2014. This development model allows more efficient use of the two horizontal rigs to drill the curve in the lateral sections of the well and provides the opportunity to drive incremental capital savings.

It is certainly a busy time for the team, but we have been preparing for the acceleration in our activity for several months and are positioned to hit the ground running later this year, both in terms of infrastructure and operational execution.

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

Thank you, Gary, and thanks to everyone on the call for taking the time to join us.

Our reported net income for the quarter, on a GAAP presentation, was $2.8 million, or $0.07 per diluted share. This figure included the impact of the following items on a pretax basis -- non-cash unsettled losses of $3 million, related to a mark-to-market of our hedging portfolio; non-cash expense of $4.6 million, related to the mark-to-market valuation of performance-based incentive compensation awards; and a gain of $3.2 million, related to the early retirement of our Senior Notes. Excluding these items and the related income tax impacts, adjusted net income was $5.7 million, or $0.14 per diluted share.

Adjusted EBITDA for the second quarter was $27.8 million, a sequential increase of 27% over the first quarter, and equates to an adjusted EBITDA margin of 69%. An additional measure of our strong operating margin is our total cash margin after cash interest costs, which stood at just over $55 per BOE produced in the first six months of 2014.

Discretionary cash flow for the three months ended June 30, 2014, totaled $23.5 million, or $0.57 per diluted share. This number includes $1.4 million of payments related to an asset retirement obligation we retained for an operated platform related to offshore oil and gas property sold in late 2013. Excluding these payments, our discretionary cash flow from continuing operations was $24.9 million, or $0.60 per diluted share.

I'll also note that our effective book tax rate was 45% for the second quarter of 2014, due to nondeductible compensation expenses and state income tax. Importantly, we do not anticipate any related past tax payments this year or for the foreseeable future.

In terms of income statement detail, operating revenues for the three months ended June 30, 2014, include oil and natural gas sales of $40.5 million, from an average production of 5,280 BOE per day on a two-stream basis. As noted earlier, this represents a sequential increase of 21% over our first-quarter production. Oil production in the quarter represented 84% of our total production, on a volume basis, and contributed to 92% of our total revenues.

As discussed last quarter, our proportion of oil production remained elevated, due to near-term gas curtailment in Midland County. We have seen curtailments in this area fall over the last few weeks, as capacity constraints get resolved, and we expect that our mix of oil will decline slightly, going forward, as a result of increased natural gas sales.

Our average realized commodity prices for the first quarter were $93.10 per barrel of oil and $6.17 per Mcf of natural gas, including BTU adjustments for NGLs. On a barrel of oil equivalent basis, this equates to $84.30 per BOE produced in the quarter.

We did experience inflated Midland oil basin differentials of approximately $8.37 per barrel on average in the quarter, which we expect to decrease in the coming months, as long-haul pipelines and associated gathering infrastructure enter into service.

Moving to expenses, our total LOE, including workovers, was $9.08 per BOE for the quarter, which shows a trending decrease over the first quarter and is within our provided guidance of $9, $10 per BOE. The decrease is largely attributable to an increasing proportion of horizontal production in our total production mix, which currently stands at roughly 80%.

Adjusted G&A expense, which excludes the impact of non-cash mark-to-market items, was $4.9 million in the second quarter of 2014, a modest increase compared to the $4.5 million adjusted expense in the first quarter of 2014. And this is primarily attributable to state franchise taxes of approximately $300,000.

Interest expense incurred in the quarter was $1.8 million and amounts to an approximate 6.3% cash interest rate on average debt balances for the quarter. This metric includes a few weeks of interest in the quarter associated with our now fully retired 13% Senior Notes, which were redeemed in April. Over the past two quarters, our cash interest rate has declined by over 50%.

I will now discuss capital expenditures and our outlook for the coming quarters. Our total operational capital expenditures, excluding capitalized expenses for the second quarter, were $57.7 million on a cash basis. Second-quarter cash expenditures included the drilling of six gross horizontal wells, with an average working interest of 94%, and the completion of nine gross horizontal wells, with an average working interest of 88%.

Looking out at the remainder of the year, we expect our total operational capital budget to approximate $215 million, inclusive of the following changes from our initial budget established in early 2014 -- the impact of larger completion designs as discussed earlier, and the addition of non-operated wells at our Opal Field that was acquired in January, 2014. Both of these items were previously discussed on our first-quarter call. In addition, we increased our drilling activity plans to include two additional net completions this year and the drilling of the vertical sections for seven horizontal wells as part of the three-rig program we expect to commence in October.

At the end of the quarter, our liquidity position was approximately $115 million, based on our current borrowing base and total availability under our second lien facility. Our next borrowing base determination is scheduled for September, providing the opportunity to add to our liquidity position.

From a long-term capital standpoint, we continue to maintain a solid debt-to-annualized adjusted EBITDA of 1.5 times, which provides the flexibility to fund our acceleration initiatives, heading into 2015. This flexibility is enhanced by the ability to call our existing second lien facility any time and access term debt markets on an expanded basis.

In terms of hedging for the balance of 2014, we currently have approximately 57% of our forecasted oil production and 29% of our forecasted natural gas production hedged under swap agreements tied to NYMEX prices. Our 2014 oil hedge agreements provide for weighted average swap price of $95.10 for the balance of the year.

For next year, we recently entered into hedging agreements for 1,750 barrels of oil per day, in the first half of 2015, and 1,500 barrels a day for the second half. The structure of these 2015 agreements provides a put price protection at $90 per barrel, with varying degrees of upward price participation.

As part of the press release issued yesterday, we established third-quarter guidance with production in the range of 5,450 to 5,650 BOE per day. And an estimated oil contribution of 79% to 81%. LOE, including workovers, in a range of $9 to $10 per BOE. And adjusted G&A in a range of $9.25 to $10.25 per BOE.

We also updated our full-year 2014 production guidance to 5,250 to 5,350 BOE per day for the year, which implies a fourth-quarter guidance midpoint of just over 6,000 BOE per day and also represents an increased annual guidance of 50 barrels of oil equivalent per day. With the additional rig entering program development in October of this year, we expect to see the production impact of this accelerated drilling program in early 2015.

With that, I will turn the call back over to Fred.

Thank you, Joe. We'll now open the call to questions.

(Operator Instructions)

Will Green, Stephens.

I wonder if we could start on the optimized completion techniques you guys are using? It sounds like you've spent a little bit up front on the first part of the year. Sounds like early signs are encouraging, that the wells are going to be above the type curve. And you guys are committed to spending that incremental dollar on the remaining wells this year.

Is that the way to think about that -- that CapEx dedicated to the higher-volume jobs?

Will, this is Gary.

That is precisely how you should think about that. Again, it's early times, but we're encouraged with primarily higher pressures with our wells, more energy as they're flowing back. And that's encouraging enough for us to say that it's probably worth the investment. I'd hate to pass up the opportunity.

The other part of that completion design, of course, is how we're flowing them back. And so there are certain wells that we're actually restricting more than others so that we can actually, over the long-term, over the next six months, try to figure out what the optimum flow back or controlled flow back position might be.

So, yes. I would think about the bigger fracs. We're encouraged with that.

And whether we go with controlled flow back over longer period of time is still yet to be seen, because we're truly testing that concept in a pretty big way at our Weatherbys 3, 4, and 5 wells.

One of those wells is on gas lift, one of those wells is on a [sub] pump, and we restrict the flow back of both of those wells. And we think they're performing quite nicely.

Great.

And you guys are -- so at this point, you're encouraged by the flow rates above the 575 type curve. At this point, are you guys still running the 575 type curve through the guidance? Is that how we should think about the way the guidance works?

Yes. We haven't change our methodology, Will. We're still -- that range of 475 to 505 are the basis for our type curves, which change by lateral length and where we are in the basin. So there has been no change that.

Great.

And so if the trend continues to these updated completion designs and you continue to outperform that curve, then ultimately, you guys might look at reassessing that at some point in the future?

Certainly. I think that follows in with Gary's remarks and some of the details we have in our new IR presentation we have up on the website.

We like to have room to move on the upside. We don't want to be wrong and have to move the other way. So over time, we like to have that [bias], but it does take time for us to get to that point, when we do update our type curve after seeing some long-term performance.

Absolutely. That sounds good.

And one last one for me -- did I hear you guys say that this extra rig you guys would expect to see about a 50% production growth number next year? Did I hear that correct in the prepared remarks?

That's correct. Yes. Year-over-year -- 50%, 2015 versus 2014.

Great. Thanks, guys. That's all I had.

Tim Rezvan, Sterne Agee.

Hi. Good afternoon, folks. Had a couple of quick ones for you.

First, I think, bigger picture on the inventory side. I know there was some debate last quarter on your willingness to add a third rig without bolting on some more properties. I know you made a smaller acquisition -- about 600 acres -- but should we see this third rig as some kind of signal that you do have visibility on both your (inaudible) properties?

Tim, I see this third rig as an opportunity bring our current inventory forward. As we looked hard -- the team and I looked hard -- at what we could do with our current inventory, we've got capacity today to go faster. And my view that certainly prepares us, as we continue to work multiple deals all the time, we're constantly looking for opportunities to actually expand the use of that rig to other properties.

Okay, fair enough.

And then -- I may be slicing the bologna a little thin here -- but I noticed on your guidance, it's skewing a little bit gassier. Is there anything we should read into on that?

No. Again, I think we talked about -- at least, on the last call and over the last couple of months -- we did have some gas off take constraints, primarily in Midland County. Earlier this year, we had some in Upton County, but we're slowly resolving that.

So I think we're at a, probably, artificially high oil contribution, pushing 85%, which is well above, I think, anyone you see out there. So what we talked about, as those constraints get resolved, we would normalize back down into the low 80s%. And that's where we're guiding down to. So--

Okay.

The flip side is we're able to sell more gas. So that's a good thing.

Sure. Okay.

And then, one more, if I could ask Joe on. What was your liquidity position at quarter end? I didn't catch that number -- your capacity?

$115 million (multiple speakers) between our two credit facilities. Yes.

Okay. Thank you.

Ryan Oatman, SunTrust.

Hi, good afternoon.

I appreciate you all discussing the potential growth outlook for 2015. What type of capital program should we associate with that three-rig program, considering that it is a vertical rig as opposed to horizontal rig?

We're certainly in the final throes of scheduling out. [And Gary could talk to you].

Looking at specific wells that we're drilling, which have an impact on working interest and such, in general, we're running at a pretty high working interest. So right now, broad brush, we'd be looking for operational capital in the $270 million range. So that does reflect a little bit of savings from running a vertical rig versus a horizontal rig, if you were just grossing up where we are this year.

That's probably as good of a ballpark estimate that we'll be working on over the next quarter to refine that and give you a little bit more specifics. But for planning purposes, that's probably a good number for you to be thinking about.

Thank you. That's helpful.

Strategy wise, in terms of talking about acreage acquisitions, you've got some big peers around you always, especially recently. Can you speak to how the leasehold acquisition strategy or environment has changed around you with some of the new entrants to the play?

I think we've talked about it several times. We've got a couple of different strategies.

One, being a smaller Company, the bolt-on acquisitions are a big part of our strategy. And I get that may not be exciting, day to day. But suffice it to say, we have a lot of work going on in the Midland basin, in and around our current positions, looking at the opportunities to either [farm in] joint venture, add acreage. And admittedly, those will be smaller bolt-on acquisitions. And we continue to do some. And we'll continue to be able to do that, and some of them may be a little bigger than others.

And we think that's an area where, maybe, we don't have as much competition doing that. Being smaller, that we obviously focus on some of the transactions that aren't as large that, as you mentioned, several of the larger peers for us, out here in the Permian basin.

At the same time, we do think that in the areas we're operating in, we feel like our technical expertise and our knowledge of the areas gives us a very competitive advantage. And so we feel like that we can be competitive in those areas. Clearly, maybe, we're not spending a lot of time focused on the largest of those transactions out there.

But we do continue to look at some transactions, maybe, larger transactions, larger than, certainly, some of our bolt-ons. And we think it's reasonable to think that if we keep at it, that we'll be able to make one of those happen.

That's helpful.

And then one final one for me -- the northern Midland basin acreage. Can you describe how that fits into the remaining development plan? And any longer-term plans for that?

Yes, Ryan.

The program we talked about, even the focus on our accelerated program in 2015, it's all focused around our core acreage in the central and southern Midland area. We've done a lot of work, a lot of evaluation, and, really, a lot of disappointing results from our northern Midland acreage. And we have no plans to do much more with it.

Has there been any market interest in that acreage, given its [non-core] to you guys?

Oh, we'd certainly entertain anyone's interest, but I'm not aware of any.

Okay, that's it for me. I'll hop back in queue. Thanks.

Ron Mills, Johnson Rice.

Good afternoon.

I'll start with the drilling inventory. Relative to your last update, the inventory went up about 80 wells or so. It looks like a lot of those are in the Joe Mill, the Wolfcamp B, and even some down in the Cline and middle Spraberry.

You're testing for those zones this year. What drove the increase, particularly in, say, the Wolfcamp B there? And also, what drove the increase in the zones that you won't be testing yourself until next year?

Ron, on that, you're right. It does cover a lot of the zones. And most of that increase, I'd say the majority, comes from the addition of Pecan Acres into the mix, now that we've come up with a development plan, and Gary can talk more, too.

But we started a permitting process there. That was a field that, historically, we've been developing vertically to hold acreage. And now, have turned the corner and want to turn that into a horizontal development program.

That was really the addition -- until we had some firm plans around that, we were holding back some of that from the inventory. But now we have a little bit more visibility. We've added the Pecan Acres locations to the mix, and, certainly, in that part of Midland County, there are, certainly, multiple benches that have been de-risked and others [in our perspective].

Gary, do you want to add to Pecan Acres, there?

Yes, certainly. The whole inventory -- the addition of Pecan Acres wells, that's -- everyone knows about Diamondback's success in the area. It's the [leading NGL fitting] Pecan Acres.

We're going to go after some of those same types of results. We can get those wells permitted and drilled and into some infrastructure that's coming the direction. That infrastructure will be in, in just another couple of months. So it's an opportune time, now, to crank up the activity in that area.

And frankly, we will be jointly developing some of that area with our offset Partners. We're in discussions with both Diamondback and RSP about extended laterals from one of the sections into their areas, north and south. So I think that's a great opportunity for all of us to work jointly together -- in the city of Midland, as well as outside the city Midland Pecan Acres.

I think the other inventory came in when we actually acquired some more acreage west of Garrison Draw -- added a few more wells there. Again, these bolt-on acquisitions, though they may not be headlines, they certainly make a huge difference in inventory. Three levels, seven wells a level over another section, is a significant number when it comes to our inventory position. So, yes. We've got lots to work on.

The other confidence level that we've certainly gained is, we're very confident with the results of both the upper B and the lower B. We see that as, certainly, applicable across the entire southern basin. And so we're happy with that.

We've certainly de-risked, significantly, the Wolfcamp A, now, at the southern basin. We know Diamondback has now drilled a very successful Lower Spraberry well immediately west of our East Bloxom area, Ron. So we now have the Lower Spraberry well scheduled the next time we go down to Bloxom field in Upton County. And we're in the process, right now, of drilling our first Lower Spraberry in Carpe Diem.

So across our acreage, we're de-risking these wells as others have de-risked around us. And we're very encouraged with the results in the industry that others are delivering in areas like the Cline or like the Joe Mill or even with a lot of work that RSP has been doing in the middle Spraberry. So we're happy to be surrounded by the successful Partners that we have there.

And by the way, thanks for the new presentation. I think it has a lot of good information.

But the slide 10 of the new presentation, where you talk about emerging zones -- and there's a call out showing, really, Pecan Acres. It looks like more Wolfcamp B around Pecan Acres. Is that going to be the focus of your activity in that area?

Yes. It will be the Wolfcamp B and the Lower Spraberry. We certainly are excited about results like Diamondback's getting out of Gridiron. That's a mile away, or less than a mile away, from Section 23.

So that Wolfcamp B will certainly be a focused. And then, we're very excited about the Spraberry results that are coming around that area. So, Wolfcamp B and Spraberry -- Lower Spraberry, Ron.

Okay.

And then, you talked about being towards the upper end of your original E-type curve, and/or even moving above it in some recent wells. But when I look at slide 11 of your presentation, what's driving the -- it looks to me -- improved performance as you move out along this spectrum, closer to 90 days than, say, day 30? You really pinch up towards the upper end of that curve.

Is that just number of wells, fewer wells with more production, or is there something going on operationally to drive that improvement, as the wells produce longer?

Again, several of these wells -- they've kind of curtailed them in the early time flow back, Ron. And that's probably why you see that gap early time. And as we get the pressure off of them, and we open them up a little bit more, trying to baby them along, we get further along on that type curve.

So I think it's really our operating strategy. And we may delay a little bit of early time performance, but over the long-term, I think it's helping us.

And is the 6,900 or 7,000-foot type curve what your average is targeting this year? And if you look to next year on those 40 wells, is it going to stay around that level, or do you think you'll be able to even extend that out, based on the lease footprint?

I'd say it still depends on where we are. The level of confidence that we have on all of these benches -- we're still somewhat taking it as -- move it up as we see it approach. And so we're between those two levels, 475 to 575, is the way I would answer that question.

Yes. And we'll have, Ron -- [pick up] laterals. Through the next quarter, we'll have a little bit more visibility on exact locations and be able to provide a little bit more color on average lateral lengths for next year. We probably don't have that detail right now.

Okay. Alright, guys, thank you so much.

Thanks, Ron.

Phillips Johnston, Capital One.

Hey, guys.

Just a follow-up on Tim's question on the oil mix trending down to the low 80s% in the back half of the year. Is that the kind of mix we should be thinking about, looking out into next year and even, perhaps, beyond that?

And then, maybe, as a related follow-up, now that you've got some decent history with about 36 completions under your belt, are you seeing any meaningful changes in the GOR as the wells mature?

We've seen minor changes in different areas of the basin for GOR, Philip, but not meaningful changes as the well matures at this point, yet. So, we're still very comfortable with the GOR mix that we see.

And yes, we would suggest that you target the lower 80s% on oil.

Okay.

And as you think about the 40 operated wells planned for next year, can you give us any color what the mix might look like, in terms of Southern Midland versus Central? And also, perhaps, what the mix might be on the various formations that are listed on slide 10?

Yes. The primary focus for next year, again -- the primary zones of focus -- will be, again, that Wolfcamp B level. And until we see exceptional results somewhere else, our approach is to build up -- from the bottom up. And so coming up, we would be starting with B, the A, the Lower Spraberry, and et cetera.

So our focus is on the B, with mixes of Spraberry and Lower Spraberry and A, to get that lower level completely developed out. As far as the mix goes, we would expect to move these rigs throughout all of our asset bases. So it would be a mix between 7,500-foot wells at East Bloxom and Southern Midland.

We're going to be pushing some, potentially, 10,000-foot wells at Garrison Draw, shortly. We'll be looking at a mix of 7,500 and 5,000-foot wells at Taylor Draw, all in Southern Midland.

We're anxious to see the results of this first joint-operated well in our Opal acquisition, that will become available, here, in the next couple of months. Down in southern -- just below our Bloxom area.

And certainly, we're really excited about all the opportunity in Central Midland. The wells that we're seen it Carpe Diem are exceptional wells. And so those will always been the mix as we rotate the rig in and out. And once we get started at Pecan Acres, and we see those types of results that we're expecting, that would be a big part of our focus.

Okay, great, thank you.

Andrew Smith, Global Hunter Securities.

Good afternoon, guys.

Can you talk about what the accelerated drilling program 2015 -- how you plan to fund that?

Sure. I'll make a few points on -- I think where we start out is, certainly, the strong cash margins that we're seeing in the business. Talk about $55 per BOE produced, which, obviously, has positive implications for our operating cash flow, which continues to grow. And also, the cash flow that's running through our reserve reports and having impact on the borrowing base.

So certainly, we expect the borrowing base to continue to grow as an important source of liquidity. We have the re-determination next month. And if you, theoretically, looked out, we could manage a program of draws on our borrowing base as that increases and some of the liquidity in our second lien. But that's not the intention. I mean, that's fine for theoretical math.

But certainly, we look at the balance sheet strength that we have today from the long-term capital perspective at 1.5 times debt to EBITDA, as I talked about. We certainly have the opportunity to take up leverage a bit, from that point, with some term debt, certainly as our asset base continues to grow with long-lived reserves and production to match those assets and liabilities up. Certainly, with the de-risked drilling focus that we have, from a risk perspective, that helps too, with us taking up leverage a little bit.

Rough numbers -- to give you a sense, just to ballpark it -- again, this is really directional but could be helpful if you think about things. If you looked at our second-quarter 2014 EBITDA, annualize that, and said, we're comfortable with 2.5 times leverage on that, which is basically what we've been talking -- 2 to 2.5 times range. With that type of debt capacity, about $280 million of debt capacity today. If you then said, alright, we'll repay all the debt we have today on the balance sheet, that remaining cash of $115 million plus we would have undrawn borrowing base facility of $155 million, that's $270 million of liquidity today.

Again, these are very directional type of numbers, but it gives you a sense of what we think, from a term debt perspective, what we can put on the balance sheet today, given where the asset base has grown. And certainly, with the 50% production rate we're targeting -- growth rate we're targeting next year, have opportunities to reduce the leverage on a debt to EBITDA basis, down over time. And also, with reserve, as we anticipate, certainly, continue to build the borrowing base and enhance liquidity through that.

Now, that handles this program quite comfortably, we think. But we're always looking for other opportunities for incremental liquidity, and whether we need that for acquisitions or to handle some of the efficiencies we see in the drilling program. For instance, this year, we drilled a couple more -- or had a couple more completions than we anticipated because some of the efficiencies we're seen in the program. There's a good likelihood will must see additional efficiencies adding this third rig and would need capital to tackle attractive projects.

We always keep our eyes on improving our liquidity over time. And that can take a wide range of options. But for this program, we've laid out, as Fred mentioned, we've taken a pretty measured approach to this. We've been asked the question the last few quarters of when we're going to accelerate activity, and we weren't going to do until we were ready from the operational side and, certainly, from the financial side. And we're, certainly, squarely there, and we have a good plan to tackle that.

Great, thanks.

For some of these longer lateral wells, the 9,000, 10,000-foot laterals, what are the well costs for those?

I think we're at $8.5 million for our 9,000-foot laterals at Carpe Diem -- maybe $8.6 million. The 10,000-foot lateral that's currently being jointly drilled by us and another company is right around -- it's got some [science] in, it's got a [pilot hole] and things like that -- but it's right around $10 million. That's a -- what number did I say on the--

$8.6 million.

$8.6 million, yes -- for the 9,000. (inaudible) But yes. Those are the types of numbers we're talking about. Well worth the investment for the types of wells we're delivering.

Thanks, guys.

Thank you.

Ladies and gentlemen, this will conclude the question-and-answer portion of today's conference. I would now like to turn the call back over to Fred Callon for closing remarks.

Thanks. Again, we appreciate everyone taking the time to call in this afternoon. If you have any additional questions, don't hesitate to give us a call. Thanks so much.

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