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Executives

Scott Sheffield - Chairman & CEO

Tim Dove - President & COO

Rich Dealy - EVP & CFO

Frank Hopkins - SVP, IR

Analysts

Leo Mariani - RBC Capital Markets

Ryan Oatman - SunTrust Robinson Humphrey

Brian Singer - Goldman Sachs

Matt Portillo - Tudor, Pickering, Holt

Will Green - Stephens

Jeffrey Campbell - Tuohy Brother Investment Research

Amir Arif - Stifel Nicolaus

Charles Meade - Johnson Rice & Company

Dave Kistler - Simmons & Company

Gil Yang - DISCERN

John Freeman - Raymond James

Joe Allman - JPMorgan Chase

Brian Corales - Howard Weil

Michael Hall - Heikkinen Energy Advisors

Mike Kelly - Global Hunter Securities

Pioneer Natural Resources Company (PXD) Q4 2013 Earnings Conference Call February 11, 2013 10:00 AM ET

Operator

Welcome to Pioneer Natural Resources Fourth Quarter Conference Call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Earnings and Webcast.

This call is being recorded and a replay of the call will be archived on the Internet site through March 8th.

The company's comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on Page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Frank Hopkins

Good day everyone and thank you for joining us. I’m going to briefly review the agenda for today’s call, Scott will be up first. He will provide the financial and operating highlights for the fourth quarter of 2013 and go over several of our key accomplishments that took place during last year. I will then review our capital program for 2014, our production growth forecast for 2014 through 2018 and our increase in resource base is being delivered by our successful horizontal drilling programs Spraberry/Wolfcamp and Eagle Ford shale.

After Scott concludes his remarks Tim will discuss our recent horizontal drilling results in the Northern Spraberry/Wolfcamp and drilling plans for this year. We will also comment drilling plans in the Southern Wolfcamp joint venture area and Eagle Ford shale as well as some of the downspacing activity that’s underway in these areas. Rich will then cover the fourth quarter financials in more detail and he will provide earnings guidance for the first quarter and after that we will open up the call for your questions. With that I will turn the call over to Scott.

Scott Sheffield

Thanks Frank. Good morning. On slide number 3 opening up with our adjusted income for the fourth quarter of a 140 million or a $1 per diluted share that does exclude our non-cash impairment on our Raton asset due to the significant drop in the 15 year strip which we primarily use from 540 to 460 by 12/31 [ph] to 15% drop and then we had a 27% drop in the gas price that the strip went to, it went to 730 before and it's drop down to 530. So a 27% drop obviously the value of our PUDs that impacts them significantly when you go from a 540 to a 460 15 year strip, again it was non-cash.

Fourth quarter production 164,000 barrels a day equivalent from continuing operations. This does exclude our announced sale of Alaska and also our plan to divest the Barnett shale assets. Fourth quarter reduction including Barnett consisting with our January 29th press release it was 173,000 barrels a day as you remember we had significant curtailed operations primarily in West Texas of 6000 barrels a day due to the two ice storms during the November, December. We did have record Eagle Ford shale production net of 40,000 barrels a day equivalent in the fourth quarter.

For the year we averaged a 161,000 barrels of oil day equivalent backing out Alaska and Barnett through reflected in discontinued ops so up 12% from full year of 2012. At tremendous strong production growth related to our successful Spraberry/Wolfcamp program up 19% and the Eagle Ford shale program up 35%. Overall oil growth up 22%, also we had an excellent year in regard to drill bit reserve replacement 211%, 141 million barrels of oil equivalent added at a drill bit finding cost of 19.70 per BOE. We did make the decision to move most of our vertical Spraberry/Wolfcamp, vertical PUDs from proved undeveloped to the horizontal resource which we will discuss later. We will be moving to 12 vertical rigs eventually moving down to five vertical rigs and eventually down to zero over the next several years.

Going to slide number 4, we’re forecasting 2014 annual production growth from continuing operations of 14% to 19% based on planned drilling capital expenditures about $3 billion. We’re increasing our horizontal rig count from five rigs at year-end 2013 to remember we started in ’13 to one went to five. We added five rigs by the end of January so most of them started at the end of January. We’re adding another six by the end of March so we will be up to 16, if you remember it takes roughly 5 to 6 months to see first production on these wells from these new rigs and that’s why we see most of our growth in the second half of the year for 2014.

We’re targeting 16% to 21% compounded annual growth rate from continuing operations from the ‘14 to ‘16 period and we easily expect to more than double production by 2018 compared to 2013. We have a great set of hedges in place for 2014 protecting at $93 on the downside with upside to $114.

We completed our merger of PXD and Pioneer Southwest Energy Partners. In addition we have progressing asset divestures which will allow us to reallocate capital back into our excellent returns to the Spraberry/Wolfcamp drilling program. We did announce the Alaska sale last quarter, we’re now announcing reduced proceeds of 350 primarily due to ongoing due diligence. It remains subject to receiving governmental and other third party approvals. In addition we think it's important to go ahead and reallocate capital from the Barnett shale assets.

We have had expressions of interest over the last several weeks. We anticipate planning to sell those over the next few weeks to months and in addition we expect to receive another $100 million from other asset divestures. We entered the year with a strong balance sheet of $400 million of cash on hand, net debt to operating cash flow of 1.1 using the current strip it's less than one and net debt to book capitalization of 25%.

Going to slide number 5, a quick update, Tim will go into more detail on our highlights. We have production data from our first 10 Wolfcamp A, B and D wells which have been on for extended period of time. It supports the following EURs and returns for wells at 7000 lateral lengths. We feel like Midland County is our best sweet spot for Wolfcamp B. We feel very good about going to a 1 million barrels of oil equivalent, 100% type returns. The Wolfcamp A in Midland County remember we only have one well now we have several wells scheduled for ’14. In addition to the Wolfcamp B in Martin County we’re assigning 800,000 barrels of oil equivalent over a 100% plus returns and the Wolfcamp D both in Midland and Martin and Andrews County, 650,000 to 800,000 barrels of oil equivalent, it returns between 45% to 95%.

We’re placing four additional wells in the B in fourth quarter we did place and early production from these wells support the same EURs and those are the two Hutt wells and maybe the Scharbauer Ranch well. We will place our first Wolfcamp B interval in Glasscock County on production in early February with an IP of 60 barrels of oil equivalent per day and going to slide number 6 I think which is probably one of the major highlights of the program is that Chris Cheatwood and Tom Spalding, our geologists has been telling us about the lower Spraberry shale is probably one of their most all rich intervals in the entire Spraberry/Wolfcamp play but we’re seeing tremendous results. We have placed five new lower Spraberry shale wells and Andrews, Glasscock, Martin and Midland counties is pretty much throughout our entire sweet spot.

To the North the early production data suggests lower Spraberry shale EURs will range from 575,000 to 800,000 I think you do have upside to that as you can see when Tim goes over the tight curves. With IRRs ranging from 45% to 100% and what’s also interesting was we’re getting 84% oil content so gas oil ratios are about half as they are in the Wolfcamp so we’re hitting 75% to 76% oil on the Wolfcamp, we’re getting 84% in the Spraberry. I won't go over the table but you can see the indications that Tim will go over the tight curves.

Last point we hit down space to 50-60 acres down in the South JV area and all the wells are exhibiting similar production performance. The Eagle Ford on slide 7 again moving forward lot of great news, the downspacing is working. The upper Eagle Ford is working; a lot of additional wells were drilled at the end of the fourth quarter of 2013. We see 45 upper Eagle Ford wells being drilled in 2014 and continue to optimize generating tremendous returns in the Eagle Ford and continue to grow significantly.

And also what’s important I think is taking our resource base up from 8 billion barrels of oil equivalent to over 10 billion barrels of oil equivalent. When you take proved reserves plus net resources we’re greater than 11.

Going on slide 8 into our CapEx budget very similar to 2013 and the amount obviously more and more capital is being focused on the Spraberry/Wolfcamp interval. This year if you remember we’re getting a full carry in the South where we did not in the South during 2013. We’re spending roughly 2.2 billion. In the North only 200 million, in the South again Eagle Ford program is very similar about 545 million, and 100 million scattered with other assets.

Capital, 285 million about half of that are buildings in West Texas which will be completed in 2014 so we expect that number to come down obviously significantly going into ’15 and ’16. Operating cash flow this is based on 90 flat and $4 gas flat at 2.3 billion. If you look at current prices and the strip or really the strip going forward we’re at $2.5 billion on cash flow. Funding it, we have 400 million in cash on hand in addition to the 2.3 billion to 2.5 billion in cash flow and then proceeds from divestures. So we expect year-end ’14 to be about the same debt levels as of end of 2013.

Going to slide 9, in regard to forecasting production growth, as over the next three years we averaged 161,000 again up 12% versus ’12 forecasting a 14% to 19% production growth. If you remember we’re losing roughly about 11,000 barrels a day equivalent from Barnett. For 2014 we’re losing about 1000 barrels a day from other divestures or the $100 million is coming from approximately, so a little to about 12 of what the street has in 2014.

Again we’re second half loaded due to the effect of the 11 more rigs moving into the North. Over the next three years 16% to 21% growth rate will be moving to 8% liquids in 2014 climbing on up to 75% of liquids in 2016 and as I stated earlier we expect to more than double our current production from 2013 to 2018.

Going to our resource potential on slide 10 and 11. On slide number 10 again this really just exhibits the major change by moving off almost 300 million barrels in the Spraberry vertical program and the Spraberry water club program into horizontal Spraberry/Wolfcamp we get an increase of 2.3 billion barrels of oil equivalent. You can see that we’re totally changing the makeup of what we will be going after over the next several years. We do go up to 50 rigs by 2018. When you look at the number of locations and assuming roughly 10 wells per rig but essentially we will have 40 years of inventory with this amount. We’re still only own a 100 acre spacing, we’re drilling most of our wells on a 100 to 110 acres spacing now anyway. So you got substantial improvement in this number for downspacing and also as foot noted in number six. A lot of other zones have not be tested such as the Clearfork, the Middle Spraberry shale, the Atoka, the Woodford, and other zones.

So again but I think the focus instead of continuing to add significant resource it's all about execution on production growth which Tim will go over.

Final slide on number 11, just summarizing the total resource potential. We’re over 11 billion barrels of oil equivalent over 22,000 horizontal drilling locations. The only other change that I’ve not mentioned here is the increase in the Eagle Ford shale which primarily we’re downspacing and then also the upper Eagle Ford and some additional lean condensate locations. We've added a number of locations and the resource potential in Eagle Ford shale and also by removing the Spraberry/Wolfcamp PUDs we expect to add 600 million barrels of oil equivalent just in the Spraberry/Wolfcamp horizontal reserves from ‘14 to 2016.

I’m going to stop there and let Tim talk about the quarter and going forward on executing it.

Tim Dove

Thanks Scott. Turning to slide 12, 2013 was a year in which we accomplished quite a lot in terms of our understanding of the various zones in the Wolfcamp basin. As the graph shows we’re really targeting six different horizontal shale zones each of which has substantial oil in place. So what I will be talking about now is really what I think we’ve accomplished in those very prolific zones in our 2013 campaign and that begins on slide 13. It's really a recap of what the Northern drilling campaign achieved during last year. Scott already mentioned this but it is important to point out we were running exactly one rig a year ago and of course that just points out the significance of going to, there will 16 rigs by the end of this quarter.

We were successful last year in placing 21 horizontal wells on production. You can see the table the different zones where those wells were landed. In summary we had really quite outstanding well results some of the top wells in the Midland Basin. The concentration of the wells was really in the Wolfcamp B where we have the most data, saw very consistent and strong results there.

Some of the news that we’re talking about today surrounds the lower Spraberry shale early results and you can see we actually have five of those on production. They are relatively early days in their production. They do show a different sort of tight curve than we see in the Wolfcamp. So it's not just about IP when it comes to lower Spraberry shales, there is a lot of water production that’s to be gotten off of wells. The oil rate builds through times and I’ve got a later slide to show you the early type well concepts that we should expect in the lower Spraberry shale wells.

But we do list a couple Jo Mill shale wells both are relatively lower rate and each of those two had a mechanical problem generally related to having to do with faulty plugs which we’re remediating. So I would say the jury is still out when it comes to Jo Mill looking forward until we get some more well results. But suffice to say we have successfully appraised four of these six stacked intervals that were target for 2013. Importantly a lot of results have confirmed our geologic maps, our geology and geophysics teams in combination with engineering have produced really quite excellent maps and our drilling to-date is essence have confirmed those maps.

What we’re not talking about today is Middle Spraberry shale intervals yet because that appraisal is still underway. I think those wells would be expected to perform more like lower Spraberry wells but we will have more data on that shortly. It will be some time before we have definitive data because we will be just putting our first wells on production shortly.

Importantly 2013 was a year in which we had a quite bit of science, you will see those numbers going down in science expenditures in 2014. So turning to slide 14, some specifics on the tight curves for the first six Wolfcamp A and B wells these wells of course have what we kind of think would be adequate history to get a feel for the tight curves in the longer term. As you can see really these are tremendous results across the boards. IPs are one thing that we’re focused on but I would call your attention to the fumes that were shown in these colored boxes and as an example look at the lowest on the graph the blue DL Hutt that’s our first well in the DL Hutt area, it's now (indiscernible) to 190,000 barrels not even a year on production. I recall and we’re drilling the vertical campaigns years ago those wells are produced 140,000 barrels in 30 years.

So it gives you the idea of the capital efficiency associated with horizontal drilling in these formations is a substantial benefit and also shown here in the coral color is our first Wolfcamp campaign well it's now being on production quite a long time as well, gives us an idea that it's going to be quite an outstanding zone as well.

And these graphs give us the confidence to support what Scott was referring to in terms of where we think the EURs would be for 7000 foot laterals so about a 1 million BOE for Wolfcamp D wells and 800,000 for Wolfcamp A wells in Midland County and about 800,000 BOE for B wells in Martin County. But really tremendous result so far and particularly related to our wells that are longest on production.

Turning to slide 15, this shows data on the newest Wolfcamp B since our last report and without going through the details once again they show very solid results and particularly now in both Midland and Martin county but now is Glasscock County. You see our first well the Flanagan 14, this was a very solid horizontal well that encourages the Glasscock in addition to the other counties we have been doing drilling. It is going to be prolific for the Wolfcamp D as well and again this data we see here in terms of results further supports the notion that these Wolfcamp B intervals are very prolific in all of these counties and support the numbers I mentioned on the prior slide. On slide 16, now I’m going to be switching to the Wolfcamp D wells in the North of which we have four that we’re reporting here.

You can see actually they are in several different counties, they are in three different counties and they are in fact exhibiting very strong tight curves in their own right in the D in those three counties and in addition to which the fumes [ph] are very strong as well and this data here gives us a lot of confidence that the remember Scott was referring to early on EURs the Wolfcamp D wells would range from 650,000 to 800,000 BOE in Midland, Martin and Andrews for 7000 foot lateral.

So all in all the results of these wells in the Wolfcamp particularly B and D and A for that matter are really living up to the hype and living up to the potential.

Slide 17 is turning to the results of our five lower Spraberry shale wells in the North and you will notice we have a lot less production data, production history because the longest of these wells is being on only about 90 days. I mentioned this little bit earlier but just the nature of these wells are such that you would expect a different type curve than you would expect in the Wolfcamp in addition to which you will also notice that these wells we’re drilling in four different counties. So to give us a view from far in terms of the breadth of lower Spraberry shale which our geos would tell us it's the highest oil in place of any of the zones that we’re speaking. But if you take a look at the type curves they do look very different than the Wolfcamp well. They have a slower oil rate in terms of an IP but that builds through time as the load water is returned and builds to very solid rates in the fullness of time and they appear to be actually relatively flatter trajectory as they get into their full production mode.

So this gives us a lot of confidence to lower Spraberry shale is in fact one of the prolific zone and the early production data would allow us to say it's like the range would be 575,000 to 800,000 on these wells. It is range; it's relatively early days but suffice to say the results look very encouraging. I would point out that we’re still in the process of entertaining the idea of what’s the proper way to get the load water off of these wells as fast as possible. You will notice that the Flanagan well shown in the magenta color where we installed an ESP only about three weeks into the flow back and starting to see really substantial improvements in flattening of production. So we’re testing really across these areas a combination of gas lift, jet pumps, rod pumps but particularly ESPs are showing a lot of benefit. We continue into looking ways to optimize the early production in these wells and essentially getting the water of the system as fast as possible in order to build oil rates.

On slide 18, this simply summarizes the horizontal drilling economics in the Northern campaign. As Scott mentioned a lot of this earlier but suffice to say based on the EURs that we discussed a moment ago and our B and C cost for 7000 foot laterals that are shown in the table we get excellent returns from all four zones and this course is based on 90 and 4 case [ph]. So this gives us a lot of confidence the capital that we’re putting to place in all these zones is being efficiently employed. Let me turn now to slide 19 and that’s related to this year 2014s plan in the North and as we already alluded we’re transitioning from horizontal appraisal program in 2013 it was really about resource capture to 2014 we’re really into more development and growing production. Of course it will take time as we’re just building the rig count but you will see that happen through the next series of quarters.

As it was mentioned by Scott and I the horizontal rig count is substantially increasing, it will be at 16 rigs by the end of the first quarter. The last of those rigs is in the final stages of contracting; do not see any issues getting those rigs out there running by the end of the quarter. We do plan to start about a 140 wells in the North average lateral length about 8200 feet.

Right now the plan is to focus the drilling on the Wolfcamp A, B and D where we have much more production history and data as I mentioned when I was showing you the tight curves. Right now only about 10% of those wells are scheduled for the various Spraberry shale. So however if we continue to see really strong lower Spraberry shale results and for that matter when we start to see Middle Spraberry shale results and we clarified Jo Mill we could easily just switch this up and from a higher percentage of Spraberry shale well. So stay tuned on that as we evaluate and tweak the program depending on the results that we see.

We will be reducing science expenses as you can imagine now that we’re more in a development campaign science becomes less of a priority. Most of these wells if not all of them will be drilled basis three well pads, yield they start to pop time of about 145 days and so the results of this will be when we’re doing pad drilling and we’re only adding rigs as we get them in through the quarter we’re going to have a second half weighted production growth and the example is if we get a rig out there in March, spuds the well in March we won't see production basically until September of this year. So you could see that’s kind of the nature of the beast when it comes to the combination of pad drilling and just getting these rigs out here in the first cost.

Cost is like 8.5 million to 9 million well as we are increasing average lateral length. We’re reducing the vertical recount in the fullness of time and it will be substantially reduced to zero but we do need a certain number of rigs on that to meet our continuous drilling obligations on certain of our leasehold.

Going now to slide 20, this is now a focus on the Southern JV area and just like in the North the focus is on production in 2014 we will be spending about a 115 wells compared to a 100 last year, lateral length is increasing some 13% to 9400 feet and again utilizing almost all three well pads. In the South the focus is Wolfcamp about 2/3rds will be in the Wolfcamp B and the remaining in the other three Wolfcamp intervals, A, C and D. Right now the focus is on some of our higher return areas. We know as we get into Northern Upton and in Reagan Counties specifically up in the Giddings and University Block 2 area. You see better results as we’re deeper into the basin going that direction. And so we’re going to focus in our best areas first and that’s what you will see as a focus for our 2014 campaign. Cost look like they are about 8 million for the South on average at the lateral link projected.

Slide 21, we did have a successful downspacing test we felt like I had mentioned in our third quarter call in the Giddings area. We recall we began testing downspacing down to about 720 feet to 480 feet that’s moving down from a 160 acres basin to about 77 acres basin. We’re testing those 12 wells and continuing to look at their performance and the important note is that the performance of wells that are 480 feet in terms of spacing the production is compared to the 720 spaced offset wells were essentially identical which is really what you’re looking for. So we will continue to monitor those wells and make some evaluations begin of this year including the possibility of looking at further downspacing to perhaps down to 50 acre spacing.

At the end of the day slide 22 shows that the result of all the activity in this production growth and with the predominance of it at least in terms of 2014 weighted to the second half of the year. We’ve very good fourth quarter other than for the fact it was flattish due to the losing about 5000 barrels a day due to the severe winter weather in the end of November and in December. Importantly our horizontal production did grow substantially from 8000 to 14,000 barrels a day; you can see that in the graph where the lighter green wedge is starting to overtake the darker which represents a vertical drilling. Overall campaign included in North and South about 250 wells and also the remaining number of vertical wells. The number of wells expected to be put on production this quarter in the Permian is about 32 with less going on in terms of some of the delays most of those will come on towards the second half of this quarter. It turns out the majority of the pops are going to be in the JV area and the results there is a lot of the incremental production from this activities will be mostly realized not in the first quarter but rather in the second quarter.

So in summary 2014 is a really big year, as we transform the drilling program from appraisal and resource capture to development and production growth in the Permian basin.

Now let’s turn to slide 23 regarding the Eagle Ford, we also talked about downspacing efforts in our upper Eagle Ford test in our third quarter goal on Eagle Ford the call we initially for some time has been downspacing from a 1000 to 500 feet between wells in our liquids rich areas. Recently we have been doing the further downspacing to about 300 feet a staggering the wells and the wells is at 300 feet downspacing seem to be performing in line with those of the 500 feet and that’s extremely encouraging and we’re actually looking now and drilling to test that space even further to 175 feet spacing and these areas will in some cases include both lower and upper Eagle Ford wells. They will add potentially sustainable number of locations in Eagle Ford. The activity will be performed in the three boxes that are shown on the map.

Turning to slide 24 for more detail on the upper Eagle Ford test. You can actually see the graph on the bottom right it's really the top two lines showing production one is for upper Eagle Ford zone and then two offset lower Eagle Ford zones. They are essentially tracking with really no distinction between the upper and lower results which is exactly what we’re looking for. So we think about 25% of our acreage prospective for upper Eagle Ford shale wells and toward that end we will be drilling about 45 of them this year as a part of the program.

Optimization has always been if you turn to slide 25 in the shale plays they all require continuous improvement and the Eagle Ford is no different and over the past two years we have been actively involved in doing just that working on continuous completion design and there are several things that we have been doing one is to reduce cluster spacing so we’re moving cluster spacing in general 70 feet between per clusters to 50 feet, increasing amount of sand, we’re pumping [ph] generally increasing that from 800 pounds per foot up about 50% to 1200 per foot. So we’re significantly increasing profit concentration and also increasing the amount of barrels of fluids pumped per minute to act more efficiently fracture stimulate the rock. So far, we're seeing really quite excellent results 20% to 30% EUR increases with very low amounts of increases in capital which yields returns of about a 100% on the incremental capital spend. There is a couple of graphs down here we will be able to give you some confidence that this is occurring so in the one to the bottom left we have original offset well shown in the blue curve and then above those is the incremental production coming from the test we’re actually increasing the barrels per minute pump and reducing cluster spacing. So you can see about a 20% EUR bump for only a 4% capital increment.

And similarly on the bottom right curve you see a situation in which we are increasing the amount of profit per foot and at the same time decreasing cluster spacing and here you see a case where EUR is up 30% but capital is up only 12%.

So these are good examples of our focus on technical excellence in Eagle Ford and those will continue. Finally on slide 26, Eagle Ford really had a great fourth quarter and I think ’14 will be a strong product growth year once again. Scott mentioned the fact that Eagle Ford had record production in the fourth quarter having put 41 wells on production in the fourth quarter after having to play less number in the third quarter and those are primarily the ways into the first half of the first quarter. The plan is to drill 110 wells out here increasing lateral length by about 21% going to about 61 to 100 feet average laterals. As was mentioned earlier essentially a 100% pad drilling 3 and 4 well pads for the most part which will have the effect of moving spud to pop days in the neighborhood of a 120 to a 150 days for the three and four well pads respectively. We will put about 26 wells on production in the first quarter and anticipate that the result of that will be most of the impact will be in the second half of the quarter and most of the production impact heavily realized in the second quarter.

So in summary we expect big things from our key drilling areas in 2014 and with that I will pass it over to Rich for the discussion of the fourth quarter financials and outlook for 2014.

Rich Dealy

Thanks Tim. I’m going to start on slide 27 where we had a net loss through common stockholders of $1.4 billion, or $9.82. It did include mark to market derivative losses of 28 million or $0.20 after tax and a number of unusual items the first of which was reducing our carrying value of the Alaska, Barnett shale assets down to their estimated value and that was for 507 million or $3.64 per diluted share. As Scott talked about we did reduce and taken an impairment on our Raton gas properties for 957 million or $6.87 and we had 15 million related to reducing our inventory tubular goods as a result of our reduced vertical drilling program.

Looking at the middle of the page where we talk about guidance relative to our fourth quarter results. I’m going to focus on the middle column which is comparable to the guidance we gave out. As Scott and Tim both mentioned you know production was down to the weather related issues that we have previously talked about. The other item there that’s worth noting is our G&A expenses and it's higher than the guidance we provided principally related to performance based compensation given the Company’s significant accomplishments during 2013.

The other items are consistent with guidance so I will skip over those. Turning to slide 28 looking at realized prices, you can see in the green bar there that oil was down 11% during the fourth quarter and if you look at NGLs and gas prices they were relatively flat quarter-on-quarter and then at the bottom of this slide if you look at our deposit impact of our derivatives you can see the strong derivative portfolio we have in the benefits those added during the quarter.

Turning to slide 29 talk about production cost for the quarter they were down 6% relative to the third quarter, the significant components of that being LOE which was up due to the onetime repair cost that we had during the quarter associated with the severe winter weather. Those were offset by a reduction in third party transportation principally related to some adjustments from the third quarter that we recognized in the fourth quarter related to Eagle Ford shale production and then if you look at the production and ad valorem taxes, those were down also primarily as ad valorem taxes come in, in the fourth quarter, those were below our estimates.

Turning to slide 30, liquidity position, the Company is in excellent financial condition with no near term maturities. You can see from the schedule there. We do have $393 million of cash from the balance sheet plus 1.5 billion undrawn credit facility so plenty of liquidity. So all in all a very good financial position that we sit into the year.

Turning to slide 31, let’s talk about first quarter guidance it's important to remind everybody that this excludes Alaska and Barnett shale, they will be included in discontinued operations. Looking at first quarter production we do anticipate a 166,000 to a 171,000 BOEs per day. the sales reflect as Tim talked about our first quarter ramp up in rigs and given the effective pad drilling on our production our growth will be weighted towards the second half of the year.

The other items here, the only other item worth noting is DD&A expense is lower than it has been in the past. The results of the Raton impairment with the other items being consistent with prior quarters. So with that I will stop there and we will open to call for questions.

Question-and-Answer Session

Operator

(Operator Instructions). And we will take our first question from Leo Mariani with RBC.

Leo Mariani - RBC Capital Markets

Question about the longer-term horizontal rig ramp that you guys have spoken about. I think in the prepared comments you guys talked about 50 rigs in 2018. I know you're going to 16 rigs here in the Northern Midland by the end of the quarter. Just curious is that 50 rigs for the entire Midland basin? Does that include the South as well and where would that rig number be by the end of 1Q? I’m not sure exactly how many have in the South is that circa 25 total and can you talk to that increase from roughly 25 to 50 by 2018 is that pretty steady over time where you add X number of rigs per annum? How should we think about that?

Scott Sheffield

Leo, I think obviously there's a lot more acreage to the North, 600,000 to 700,000 acres compared to the South so you're going to see the North probably carry more rigs in the South we’re going to be adding about two to three rigs per year. We're not increasing really the rigs in 2014 in the South primarily because we're increasing the lateral length significantly, but we'll pick back up more rigs in the South going into ’15 but the North was going to be weighted more and more rigs over the next five years because of the better wells and also the acreage position.

Leo Mariani - RBC Capital Markets

Okay. I guess just looking at EURs that you guys put out here I guess in the Wolfcamp. It looks like for the most part decently wide range, better ones are the 1 million barrels allotted kind of 800,000 barrels and some it's sort of 650 to 800. Just curious in terms of those EURs I guess at this point are those you know Pioneer numbers? Are those kind of third party engineered numbers, are there any substantial differences what was booked at the year-end reserve report versus what you guys think the estimates are there?

Scott Sheffield

We still obviously it takes us a good 2-3 years internally to get to those numbers. So this is what the type curves are exhibiting and drilling it takes us 2-3 years to get up to that number internally and then we use Netherland Sewell and within that 2 or 3 time frame they get within 2% - 3% of that number also. You just need more history and if you look at the pie charts and the resource potential even though I did not emphasize when I went over those pie charts. We are not using a 1 million barrels for instance in those pie charts, we’re using 800,000 for most of the counties and we’re using 575 for lower Spraberry shales. So there is still lot of potential increase in those resource pie chart. So these are strong indications based on the type cures is our main point in Midland and Martin county on the various intervals.

Leo Mariani - RBC Capital Markets

Can you relate that to your three-year production guidance as well? Are you using those lower numbers to get to that three-year CAGR as well?

Scott Sheffield

Yes. We're using the numbers in the resource pie chart in our production growth. Same numbers. 575 and 800,000, 650,000 for Wolfcamp B.

Operator

And we will take our next question from Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey

In the South it looks like you tested about 11 wells across the unit in the upper and lower Wolfcamp B. How do you look at spacing and where that moves in the North versus your Southern acreage as well?

Tim Dove

Right now just to give you a clarification the only spacing test we have done of significance is actually in the Giddings area which is in the South. Of course the Giddings area is in the northern part of the South. So what we’re doing is we’re watching the Giddings results, trying to get a handle on the history on those wells and right now we’re in the second quarter of their production. And we’re making assessment later I think the what Scott mentioned to you earlier right now the whole northern drilling campaign is predicated on in terms of where you’re, a 110 to 140 acre spacing. So it's very, very likely that our learning’s from the South get translated to the North and then ultimately is a substantial amount of the northern acreage which is brought down to more potentially spaced wells. So let’s say 80 acres but we’re not going to jump into downspacing ever to North till we really have this pilot understood so we then can extrapolate into the North.

Ryan Oatman - SunTrust Robinson Humphrey

Got you. That 80-acre spacing would correspond to eight wells across, let's say. Then in the South, it does look like it's a predominantly Wolfcamp B program. Can you speak to the other intervals that you plan to test including the Wolfcamp A, C and D? Maybe remind us of your historical activity in those other zones and perhaps more detail on your 2014 plans? In those other zones, A, C, and D?

Tim Dove

First of all we have drilled some Wolfcamp A wells in the South. Some of those wells have actually encountered issues such as being drilled too close to faults, and so on and so I don’t know that we would say in the South we have a real statistically sampling of wells that we thought were completed properly. But that said when you look forward about 2/3rds of the wells will be drilling in Wolfcamp B. We will be drilling our first wells in the Wolfcamp C so that will be very interesting to see how those results come out and then the balance of course being A and B wells. So I think really it's just a matter of, we’re going to be testing some of these zones in some newer areas and evaluating them particularly with news on the Wolfcamp C.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. Then finally I noticed that you didn't mention any Spraberry or drill mill wells planned in the South. Can you just remind us on how you're thinking about those zones in the Southern acreage versus what you're seeing in Wolfcamp B, C, A, and D?

Scott Sheffield

Yes in the South with the we had tremendous support from the from the Texas Railroad Commission on what we call Rule 40 in allocation which got approved in December. So that’s going to allow us to go ahead and move forward on the program to test the Spraberry shales and drill more wells in the South. So we do have some wells planned in the various Spraberry shale intervals in the South also as to the North.

Operator

And we will take our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

As you think about the second-half ramp-up, as your rig count rises and as you're three well pads get into place, can you talk about the key midstream facility milestones for oil, gas, and NGL's that are needed in progress so far?

Scott Sheffield

Yes we’ve two joint ventures pretty much in the entire 900,000 acres ones with Atlas and one is with WTG [ph] as primarily with Atlas. So went on a mission about 18 months ago to educated Atlas the fact that we need a gas processing plant about every 18 months and so we’re on track to bring on a plant about every 18 months, the size of that plant is about 200 million a day. So the next one is in ‘14 and then we got one schedule for ’15 and probably you will need another one about every 18 months moving forward. So both NGL takeaways we see no issues on dry gas, we really see no issues. We have takeaways on that and so at this point in time even though it's fairly tied on crude oil right now we do have a major pipeline bridge that’s coming on this summer and then you will have Cactus and then also Energy Transfer crude pipeline coming on. So you’re adding another 700,000 – 800,000 barrels a day in the Permian in the next probably 12 to 15 months Brian, so even though it's a little tighten now on crude oil we don’t see any issues for next 4 or 5 months with us because of our agreements and then that being relieved on crude oil.

So we don’t really see any major issues in regard to we did build it into our forecast this year, some downtime potentially on there is going to be potentially be a bottleneck in regard to the Atlas plan coming on about four months and the continued ramp up and the Spraberry/Wolfcamp program by third parties. We could fill out these gas processing plant by June or July. So we have built in some down time in our forecast as about a four month delay of reducing ethane production at that point in time.

Brian Singer - Goldman Sachs

Great. Thank you. Then secondly, your proved develop percentage rose at year-end because you took the vertical PUDs off. Was there any debate about putting more horizontal PUDs and how should we expect your PUD percentage to change going forward if at all?

Scott Sheffield

Obviously if you can just take that 600 million barrels of adds the next three years so that gets us back up and we’re going to be move out significant amount of production obviously in the next three years too. It's important not to be aggressive to be within the guidelines so we generally tend to be more conservative, we decided to go ahead and setup and get very aggressive on the vertical PUD removal. We could have done it over a couple year of period but since we’re pretty much made the decision to get down to five rigs or zero, it's hard to justify leaving an vertical PUDs on the books. So we had just took most of them off, there is very little left to add there. So we tend to be conservative on adds in regard to horizontal Wolfcamp and we’ve a forecast that will add somewhere in the neighborhood of 600 million barrels over the next three years of horizontal Wolfcamp.

Brian Singer - Goldman Sachs

Great and there was no disagreement with regards to the timing of this horizontal bookings between yourselves and your reserve engineers or auditors?

Tim Dove

I think Brian you need to realize that in the early stages of these wells number one we’re only going to be able to book a certain amount of the early production owing to the fact you don’t have much data. Secondly you only generate you will be limited to 1 or 2 offsets to the wells. As you get through time you’ve a substantial amount more opportunity to use more statistical methods to evaluate the reserves but you also have to be able to get to the wells in five years pursuant to the drilling rules within the five year plans. So all of those things are governors to actual bookings that as I said we pretty much have visibility on this 600 million BOE adds going forward.

Operator

And we will take our next question from Matt Portillo with TPH.

Matt Portillo - Tudor, Pickering, Holt

Two quick questions for me. Just one quick follow-up on the production guidance over the next three years I was curious if you could provide a little bit more context around the range from 16% to 21%. Is that predicated on any sort of fluctuation in crude price and ramp to your rig count? And then I have a quick follow-up question to that.

Scott Sheffield

Yes it's pretty much run on a $90 flat case so obviously if the actually it's on a strip price range and so the strip over the next three years gets down to about $83. So in ’16 gets down to about $83, the crude prices are much stronger than that than the numbers can be higher because we would add more rigs obviously into the Spraberry/Wolfcamp program. And gas prices are pretty much in the 400 to 450 range in the strip in the next three year. So I would say the big change could be crude, (indiscernible) and continues to move forward which it has and obviously even with this year free up another 200 million in cash is potentially later in the year we could add more rigs if the price continues to average $98, $99, a $100 per barrel per WTI. So what’s the second part of your question?

Matt Portillo - Tudor, Pickering, Holt

And just in regards to low end of that guidance range is that predicated on potentially a slower ramp in the rig count or is that just variability around your type curve expectations?

Scott Sheffield

Well that’s obviously the first year, when you take the midpoint of the first year of ’14 to ’19 it's at the lower end of the 16 to 21 and so it points toward much higher production to get to 16 to 21 or even to double over five years more than double over five years. It points to much higher production growth rates in ’15 – ’16.

Matt Portillo - Tudor, Pickering, Holt

Great and then second question just in regards to some of your northern acreage you guys have had pretty successful wells in kind of the central part of Andrews and Martin. I was curious if you’ve any color on kind of the potential for the northern part of those counties and if you plan to test any part of your northern acreage over the next 6 to 12 months.

Scott Sheffield

We have generally have tested we’re drilling a few more University wells but in Andrews we may go a little bit further North than the University wells where we have drilled a D and a Lower Spraberry shale both very successful. So we will probably go to the North end. We don’t see testing anything in Gaines or Dawson. We will probably test the North Eastern end and Martin County at some point in time. So we pretty have gone, we’re probably within 5 to 7 miles as far North as we have been.

Operator

And we will take our next question from Will Green with Stephens.

Will Green - Stephens

You guys mentioned a few months before we get first production on these additional rigs and I guess that makes sense on the lag effect you see. You’re drilling some longer laterals, but I assume you guys are also getting quicker with how you get these to sales. Can you give us an idea of once these rigs get up and running and humming along like they should be, what a good spud the sales number is at that point for these rigs?

Tim Dove

I think if you look at it there is always continuous improvement, what we’re already seeing these reductions in days on drilling, realizing in a lot of cases we’re using three and four string plans to make sure that we have adequate cement jobs on these wells which puts you up in more than mid-20s in terms of the number of days in some of these horizontals but overall if you think of spud to top times we still think we’re probably able to reduce substantially more we’re today so let’s just say we’re averaging a 170 days in 2013 spud to top. I think we can probably get that down to 150. So you’re probably lower than in the future. So I think there is going to be substantial improvements, every hour counts, is what it amounts to.

Will Green - Stephens

That is an average assuming that you're continually getting this pretty big rig ramp going and realizing that you're going to have a lot of those rigs that are lower than the average, correct?

Tim Dove

Well we’re going to have situations where we are bringing on new rigs and we want those rigs to be hopefully coming out of areas where they are already hot. We don’t have much risk that they are going to have delays or issues.

Will Green - Stephens

And then, how should we think about Company owned pumping at this point in time? Do you guys plan to add any more? How do you guys think about the percentage of the Spraberry or Eagle Ford which is going to be serviced from vertical integration this year?

Tim Dove

When we got into vertical integration when it comes to pumping services as we only intend to be say no more than 2/3rds vertically integrated. We dropped the vertical rig count so substantially we had gotten ourselves to the point where essentially 100% pumping our own wells. As you look at the current situation now that we have added the horizontal wells going into 2014 and really last year as well. What we can say now is that in essence we’re pumping all of our own horizontal completions in the Permian. We have a couple of third parties we’re pumping the vertical completions in Permian. In the Eagle Ford we have two pioneer fleets working in one third party fleet. So we’re heading much more to a model I think that starts bringing in third parties. Obviously margins have been significantly reduced over the last year or two in response to the big influx of supply of pumping equipment and I would think at that point of time we would rather bring in third parties to pump the wells rather than doing it ourselves. So we do not have any plan to acquire additional fleets at this time, that said we’re always basically tweaking our horsepower, bringing in some new pumps for replacement purposes and so on and so it's relatively small amount of our capital budget but it is something we have to do just to maintain the equipment.

Operator

We will take our next question from Jeffrey Campbell with Tuohy Brother Investment Research.

Jeffrey Campbell - Tuohy Brother Investment Research

First question I wanted to ask was I noticed on your slide 18 the IRRs reflected single well drilling costs. I was wondering what cost reductions might be feasible from synergies on pad?

Tim Dove

If you take a look at the pad drilling we’re now extensively utilizing that across each of our areas and this includes Eagle Ford, Southern Wolfcamp, and Northern Wolfcamp. Our average would be about 500,000 per well if you are incorporating pad drilling savings compared to single well economics. That’s the other way to look at this, so as if you look at that same slide we’re using 7000 foot laterals and right now almost all of our laterals are well above 7000 feet. So there is offsetting factors as well.

Jeffrey Campbell - Tuohy Brother Investment Research

My next question was with regard to Glasscock. You mentioned your enthusiasm for Glasscock based on the recent Flanagan well. And looking at the well results in the county seems as if the pattern is generally lower IP's but also lower decline rates. I was just wondering you also drilled I believe you drilled a Spraberry well on Glasscock as well so after your recent results what are you thinking about Glasscock how it will fit into your drilling plans?

Tim Dove

I think so far along the lines of what you said, our Glasscock well in the lower Spraberry shale exhibits basically the same sort of trajectory that you see on slide 17 and the rest of our lower Spraberry shales. However having put an ESP on that well pretty early. It seemed really pretty strong IP rate for this style of well. In fact right now they were attractive over the 1 million type curve so that’s pretty encouraging but of course it's only early days you got a month worth of production on the well. So that would have to give you encouragement about Glasscock at least when it comes to lower Spraberry shale areas and I wouldn’t be too concerned about the IP rates there as much as I would be what’s the trajectory of the wells look like as you de-water or basically get the load water off the well through the time as you can and really you will be looking at the fullness of time on these curves and as I said on slide 17 they look pretty interesting and they look pretty positive to me.

Scott Sheffield

I would just add that if you look at the results of some of the other operators over there that have been drilling there certainly longer than first couple of wells we have put on, I think it supports what Tim said.

Jeffrey Campbell - Tuohy Brother Investment Research

Okay. My last question is shifting to Eagle Ford. It looks like the results really continue to impress. When we look at the returns to your posting in Eagle Ford, they seem to match the best returns in the Permian. When you guys were at our conference last August, it seems like selling Eagle Ford was a foregone conclusion. I'm wondering if this is still the forward look or has this got a chance to stay in the portfolio?

Scott Sheffield

No, Eagle Ford, obviously our policy at the Board level is that all assets will sell at the right price. Eagle Ford is a tremendous growth vehicle and it's moving forward significantly, we just increased the resource potential significantly in which results at this point in time with the top of returns that Tim talked about in the Spraberry/Wolfcamp they self-fund themselves and so the program to achieve these 16% to 21% growth rates is essentially self-funding. So we just don’t anticipate that at this point in time.

Operator

We will take our next question from Amir Arif with Stifel Nicolaus.

Amir Arif - Stifel Nicolaus

First quick question is just can you just highlight some of the factors and parameters you're thinking about in terms of how fast you want to be shifting from vertical to horizontals and just the pace of horizontal rig count over the next two, three years? Is it just capital or is it facilities or what else you’re thinking about there?

Tim Dove

I think the basic premise is that we have to drill a certain number of wells on the areas we’ve continuous drilling obligation clauses and some of the big ranches in the Permian basin. That’s the way that’s been done through time is using vertical drilling especially in a scenario which we did not have enough horizontal activity, not enough horizontal rigs to fulfill those obligations. As you look forward and as you kind of think about the rig ramp going from 1 to 5 to 10 to 16 and then eventually 25-30 rigs, it can easily be the case where let’s just say three years from now you’ve enough horizontal activity such that you can use horizontal drilling to fulfill those obligations as opposed to verticals. So I would be thinking about this in connection with 3-4 years from now it's basically a situation where you have got a horizontal campaign and a fleet out there that’s big enough to all of a sudden replace your needs to have vertical rigs. Notwithstanding all that the horizontal capital efficiencies are so much higher than that makes economic sense as well.

Amir Arif - Stifel Nicolaus

Okay. So what would stop you from getting up to the 25 rigs at a faster pace and letting go of the vertical rigs at a faster pace?

Tim Dove

Well, I think there's obviously a few governors. We don't want to put is out there so fast we're going to have diminishing returns, i.e. costs go up. We think there's a way to do this on it's a stepwise basis that makes sense that doesn't tax all of the different service providers, it doesn't tax our needs for things like water and electricity and people, and throughput and off take and so on. We're going to get there as going to get there as fast as we can. I can't tell you the exact date we're going to be there but we're definitely moving smartly in that direction having gone from one rig this time a year ago to 16 here in about three months.

Amir Arif - Stifel Nicolaus

It sounds goods and then in terms of lower Spraberry the productions that you show on page 17, is that just the December 31 or is that all the current production you’ve available right now?

Tim Dove

That’s current data.

Scott Sheffield

Yeah within the last couple of days.

Amir Arif - Stifel Nicolaus

Okay. Then if EURs continue hold up the way that they might be, at what point would you start shifting from less Wolfcamp vertical or less Wolfcamp B zones and then doing some more Spraberry shale?

Tim Dove

I think the real question is going to be does this now mean we complete four different zones versus the way you’re thinking about it. So does this now mean if you can prove the Wolfcamp A, B and D are prolific in this area and in the lower Spraberry shale that has other zones as well then you’re now looking at a serious of stack laterals that’s the way I would be thinking about it.

Amir Arif - Stifel Nicolaus

Okay. Final question, when can we expect some results on the middle Spraberry?

Tim Dove

I think it will into the second quarter before we have wells producing enough days given the fact they should exhibit similar production trajectories that I showed you on the slide 17 lower Spraberry shale type curves, it just takes a couple 2 -3 months before you have gotten the load water back and can establish the increasing rate. So I think we will know a lot more in the second quarter. We will have to see when we have data that we’re able to explain.

Operator

And we will take our next question from Charles Meade with Johnson Rice & Company.

Charles Meade - Johnson Rice & Company

I'd like to ask a few more questions on the lower Spraberry shale. Then I'm kind of surprised that over now we're just getting to it but I was wondering if I think we all have in our mind that you're Wolfcamp prospectivity map but can you talk a bit about your current thinking on how the prospectivity for how that math would look for the Spraberry shale versus the Wolfcamp? I think there's some other operators who said that perhaps the Spraberry shale is more perspective further North or maybe the sweet spot will be for the North.

Tim Dove

I think if you look at and Charles you had a chance to see some of these maps in some of our road show materials but if you take a look at the in general the Spraberry shales they are very much ubiquitous across the acreage. In fact very similar thickness North South and East West which makes them different in the Wolfcamp. Some of the Wolfcamp zones they are in one direction or another. So I think the way to think about it is the lower Spraberry shales is probably as extensive as any of the zones that we’re even talking about in terms of it's lateral continuity and the maintenance of thickness across the basin.

Charles Meade - Johnson Rice & Company

Got it. And then I was wondering if you could just talk a bit more about the way these wells are coming online, and the way they're exhibiting the shallow decline, and maybe set the stage for us for how to interpret that slide 17 as it gets updated with more data as time goes by?

Scott Sheffield

Yeah Charles you just don’t have the pressure like you do and there is a pressure regime change when you get in the Wolfcamp and so the Wolfcamp wells come on. They peak within three days, we’re generally using gas lift, so they make a lot more gas and the Spraberry shale wells produce less gas and so with less gas available for gas lift and during the winter you can see when Tim went over the curve you can see the ups and downs of all the lower Spraberry shale wells so that’s why we’re highly encouraged by the two wells we fit on ESPs and so the flat curve it essentially had no down time and so we got to continue to move the water off to get the oil flowing. So it's less pressure and so…

Charles Meade - Johnson Rice & Company

That water is that formation water or is that frac load?

Scott Sheffield

It's frac load, the frac needs well 200,000 barrels of water. So it's going to take several months to get the water off. So you got to realize you’re in a less pressure, less gas, it's 84% - 85% oil so it just takes time to get the oil off, I mean the water off.

Tim Dove

It's not having as much energy in the system to get that load back without help.

Operator

And we will take our next question from Dave Kistler with Simmons & Company.

Dave Kistler - Simmons & Company

Real quickly, thinking about CapEx for 2015 and 2016, you outlined production very nicely for us. How should we think about CapEx creeping higher and more specifically edging out rigs more specifically how should we think about that CapEx mix on the Northern side of the acreage in Spraberry/Wolfcamp horizontals versus verticals?

Scott Sheffield

Yeah we’re obviously I think we will be keeping verticals flat for a couple of years at around 12 before we start declining and I said all the way down to five a five year time frame. On the North we’re adding about three rigs per year on our production growth. In the South we’re adding about three rigs per year but if you remember we’re carried, so I don’t see much increase at all in ’15 in the South. In the North you will see a slight CapEx increase with more rigs in north but cash flow will be up significantly going into 2015. 2016 I think the carry runs out towards the end of ’15? Okay so ’16 you will see a bigger increase in the South in the CapEx in regard to the South because the (indiscernible) runs out going into ’16.

Dave Kistler - Simmons & Company

So just as we think about progression is it fair to maybe bake in 5% growth in total CapEx spending between ‘14 to ’15, ‘15 to ‘16, or am I too aggressive?

Scott Sheffield

Yeah probably 10% plus.

Dave Kistler - Simmons & Company

Okay, 10% plus. I appreciate that. And then kind of just switching over to vertical integration, and the service environment, are there any areas where you're seeing pressure? You mentioned that you haven't had any problems contracting rigs but are people trying to get you to lock down longer-term contracts? Are pricing creeping up at all on those high-end horizontal rigs? How should we think about factoring in any service costs increase over the next couple of years?

Tim Dove

Really Dave if you take a look at the new contracts that we’re signing, there is very little upward price pressure on those. In fact most of it purveyors of drilling will basically look at any sort of different ranges of time frames on contracts and are flexible on that so I think we’re still in sort of an equilibrium mode when it comes to the cost. We have seen other things that have fallen so dramatically for example. Some of our chemical cost have come down dramatically. So, there are some markets where you’re actually seeing some reductions. Our electricity cost are coming down in the Permian basin for instance but there is not a lot of areas where we’re feeling that the other side of the equation is hitting. We’re not seeing a lot of push in terms of cost creep at all and I think that’s due to the fact we have been in this whatever it is $90 to $100 oil case here for year and half and so it was pretty clear that we’re in the equilibrium mode. We’re not seeing a whole lot of creep [ph].

Dave Kistler - Simmons & Company

And then switching over to something that may seem a little unusual but obviously gas prices have gotten better. Is there a gas price that makes potentially the gas window of the Eagle Ford more interesting to you guys? Do you consider moving rigs over there? Or do rates return on the balance of the portfolio prohibit you guys from doing that?

Scott Sheffield

We still have when you get up to a consistent strip of $5.50 to $6 before we start considering it obviously I have stated in the first part of the call that the 15 year strip has dropped significantly examine the 4.60 range. I think what’s going to happen obviously, gas demand is increasing significantly over the next five years with LNG exports dementing in late ’15 early ’16. It is going to take mostly gas price throughout the U.S. except for the Marcellus and Utica. It is going to take the gas price $5.50 - $6 to start rigs back up. So that’s how we look at the Eagle Ford, that’s how we look at Raton but we need to get up in the $5.50 - $6 range.

Dave Kistler - Simmons & Company

One last one, just looking at the number of wells your drilling on pads right now, averaging, call it, three wells per pad. I would imagine that that number actually creeps up over time which extends that popped time even though you're having efficiencies at the drill bit. And am I thinking about that the right way? Is that going to continue to result in lumpy production? Just looking at your charts, it looks like 4Q ‘14 versus 4Q ‘13 is a 30% growth rate, but is that big chop on year-over-year quarterly basis going to continue? Are you planning on moving to more wells per pad over time?

Tim Dove

Yes Dave we’re as you know growing phenomenon’s of the wells this year on three well pad. That said we’re doing some on four well pads as well so we have a lot better feel for what’s the impact of basically the third increase in the number of wells on pad even this year but you had to believe this is our efficiency associated with this. Our tendency would be go to more wells per pad from time that said that would make more sense in a scenario, we got a large base of production from large number of wells so that the lumpiness that would come from I would say increasing from 3 to 4 well pads becomes basically immaterial in the sense of production forecasting. It's just right now when we’re in a situation you’ve such a low base to start from that one pad coming on heavily skews the numbers upward the day it comes on and at the same time it was delayed it holds your numbers back. I think in time you will see more wells per pad and in time as the days of production is solidified by few years of drilling you’re not going to see this kind of lumpiness but for the time being we got to deal with it.

Operator

And we will take our next question from Gil Yang with DISCERN.

Gil Yang - DISCERN

You've got such a variety of acreage in different counties different zones in each of these counties and you've clearly talked about Wolfcamp in Midland as being probably the better area. As you head out towards longer-term development, do you see that you'll be targeting how do you high-grade the assets versus the other obligations and versus the synergies of having a lot of activity concentrated in one area? So what's the longer-term development look like? Is it all Midland Wolfcamp B first and then the other assets or is it drilling all over the place with many different zones being completed at the same time in certain areas?

Scott Sheffield

I think what we’re hoping happens is that we get up the lower Spraberry shale will continue to move up at a higher end of the range that we said. So let’s say the lower Spraberry shale is 800,000 and the D wells, it looks like they are trending higher towards maybe 800,000 and so hopefully we will get in a range of 800,000 to a million BOEs for all four of these zones and if we do then that points towards similar development drilling 800,000 to a million on similar paths and just drill as Tim said earlier four zones. And so they are all a 100% type returns plus there is a difference between a million and 575 and obviously we’re going to stay away from more 575s but right now the trending is for the 800,000s to the millions and if we can get that consistently in Glasscock, Martin, Midland and Andrews in the North then we’re going to develop all four zones overtime?

Gil Yang - DISCERN

Related to that, the follow-up is how do you think about the payout time changing as you drill off of these pads with the intention of the cost savings versus the delay for the pop? Is the payout in the sense of when you spud versus the payout, is it a longer or shorter? Drilling off of the pads?

Tim Dove

I think it's interesting question, obviously you’ve a PV effect of the 150 days if you will there is that and so you don’t start getting paid back to the wells put on production. So you’ve to think it's a little bit longer in terms of payout but the results of that the results are going to be improved cost and so I think there is your trade-off.

Gil Yang - DISCERN

And so is the return higher or lower with that popped delay?

Tim Dove

Well I think the only reason we do is it will be higher.

Operator

We will take our next question from John Freeman with Raymond James.

John Freeman - Raymond James

Just two questions. Following up on the spud to pop times if I look towards the Eagle Ford where you're doing three well pods that are 90 to 120 days, four wells that are 120 to 150 regardless of what you end up doing on the number of wells for padding in the North and South and Permian can at least directionally over the next several years think that that's the trend heading closer to what you're doing in the deferred?

Tim Dove

I think the learning’s are important to apply to Eagle Ford realizing Eagle Ford our lateral lengths aren’t nearly as long. I think we’re averaging 6100 feet Eagle Ford in 2014 and we’re in the 8s to 9s [ph]. So you sort my definition we’re adding more time associated with that but I mean directionally Eagle Ford is a great model for us to try to attain on Permian it's just that Permian we’re dealing with longer laterals than more stages and so on. So we’re always going to have that uphill battle but directionally we certainly had a team in our Eagle Ford group that we can look at what they have accomplished and apply the same learning’s.

John Freeman - Raymond James

Okay. Just last question for me, when I think about the longer laterals, 7000 foot plus in the North, just ballpark, what percentage of your Northern acreage is capable of the longer laterals either because you can't do it because of lease line issues or previous vertical drilling or whatever. Just ballpark how much of it do you think is capable of being drilled at that sort of a lateral length or longer?

Scott Sheffield

John essentially all of it is 7000 feet. Our large portion will to (indiscernible) probably in the 30% range but almost all of it on the 7000 feet. We do have some tracks when you look at our map that we intended to do drilling deals or trades or make sure that we did 7000 plus but in lot of our acreage tracks we can’t get 7000 we will go out and do a trade or farm out in regard to or buy the acreage to make sure we hit 7000 plus.

Tim Dove

And just to give you a frame of reference John for 2014, 89% of the wells will be drilled 7500 feet and more. That gives you an idea that our leasehold's pretty extensive and as Scott said the main thing is you drill out, we’re going to be able to amass a land team trying to get out to where we cobble together acreage so as to get out to 10,000.

Operator

And we will take our next question from Joe Allman with JPMorgan Chase.

Joe Allman - JPMorgan Chase

Question on the EURs, you listed in your press release and in your presentation in the Midland basin. What's your assumption in terms of into lateral spacing there? And what do you think the impact would be if you tried the downspacing in the North as you're trying in the South?

Scott Sheffield

As we stated in the foot notes on our 100 acre spacing, essentially we’re drilling most of our 7000 foot laterals on a 110 acre space. So there is no downspacing essentially being in put into the resource potential slide at this point in time. I have been associated with this due diligence out for the long time period. We took it down from 160s when I started down to 20 acre spacing, Christie [ph] would tell me we would probably go down to 5 acre spacing on verticals at some point in time so this rock is tight. So seeing what’s happened in another shale plays throughout the U.S. and Eagle Ford success. I see downspacing easily working in this play.

Joe Allman - JPMorgan Chase

And Scott, do think we'll see some degradation on EUR's so for example on the Wolfcamp B you’re saying that the well so far you think they're going to yield 1 million BOE as you down space you think that number is lower or do you think your best guess at this point based on the wells you've got is that that's a good number for even downspacing somewhat?

Scott Sheffield

I would guess we saw that in verticals but it wasn’t we saw changes downward from 160 going down to 20s overtime but it's due to pressure depletion. We never saw the offset wells affected at all and so if you down space in 10 or 15 years from now after developing for instance the Wolfcamp B the 50 acre spacing or the 30 acre spacing I would tend to say that you’re going to see with pressure depletion you will see a little bit less than a million barrels.

Joe Allman - JPMorgan Chase

When we look at these EURs that you’re listing, should we think these EUR's as your best guess at the EURs for each of these intervals? Or do they just represent what you drilled so far and they're not necessarily representative of the play going forward?

Tim Dove

We’re not cherry picking any wells either all the wells so you can interpret for yourself I mean it is what it is and it is that.

Joe Allman - JPMorgan Chase

Is there any reason to think…

Scott Sheffield

We can say on the resource potential we’re still being more conservative than what we’re saying on the type curves. So as the type curves get more and more performance we will translate that into the resource pie that we showed.

Joe Allman - JPMorgan Chase

Got you. Is there any reason to think that the results going forward will be different than what you've seen so far? Any geological reason or other reason?

Scott Sheffield

Not too much no. We’ve pretty good scattering of wells in those zones already, pretty good history. For Spraberry shale, we still need more time.

Tim Dove

And it's true also in Middle Spraberry shale and John I will just add I mean if you look around at what some of the others are drilling I mean that adds to the confidence because they are seeing some of our results, some of our peers.

Joe Allman - JPMorgan Chase

Got it. And so thinking about the Southern Midland basin what's your best EUR estimate now for the South and then with the downspacing you've done and the planned testing over the next 12 months or so, would you expect to see that number to go down, the EUR number?

Scott Sheffield

We’re still, we have not changed it from last year to this year, it's still 75. For downspacing we could add resource potential there too.

Joe Allman - JPMorgan Chase

Okay. But so far your downspacing so far you've seen no degradation in that EUR per well?

Scott Sheffield

No.

Operator

And we will take our next question from Brian Corales with Howard Weil.

Brian Corales - Howard Weil

Just one on the Eagle Ford, I see you all testing the three different areas for that upper Eagle Ford. Do you think this could exist over your entire acreage block?

Tim Dove

I think if you look at it personally you’ve various thicknesses of the Eagle Ford and so by definition of it thickness changes going from 200 to 300 feet [ph], you could have situation where you simply don’t have enough thickness on the one hand. The other thing that occurs as you’ve very geology changes which occur up and down the basin and so we really looked at it to say we think these are going to be sweet spots where we can apply this downspacing and it wouldn’t necessarily be, it would be all over the acreage.

Brian Corales - Howard Weil

And then kind of one big picture question, getting to 50 rigs in the Northern part of the Midland by 2018, what's the biggest impediment? Is it people? Is it rigs? Is it take away? What do you think the biggest impediment is and how can you prevent or how can you help that from not having?

Tim Dove

I think we have 50 rigs today it would immediately quickly fill up some of your capacity’s processes and so there is that but as Scott mentioned few minutes ago we’re looking at it in a piecemeal basis, we need a new gas plant every say year and half or so. So we’re right in that process of adding the next one, as we mentioned later this year and other following year. So we’re sort of keeping two years ahead of the issue that said with the growth in the basin we’re seeing some issues where we have some tightness but overall I think we have well in hand but to operate 50 rigs compared to where we’re today which is basically in the neighborhood of come up on 25 rigs, it's double rig count means the double the water we need to put in place, we’re doing a lot of work there to make sure we have water supplies that are adequate for the fracs. We got to get twice as much sand out of Brady sand mine which we can do either from current supply or from an expansion. We have the need for more people needless to say. I think we’re the biggest employer of all of the upstream companies. So we’re the company of choice and so I don’t feel they have got a big issue there. Electricity needs to build out to some of these areas where we’re dealing with more remote drilling campaigns. So it's really kind of an all the above strategy, all of those things need to be dealt with that’s why we can’t sort of instantaneously step on the accelerator and go from 25 to 50 tomorrow. We need to do it through the time and logically and piecemeal.

Operator

We will take our next question from Michael Hall with Heikkinen Energy Advisors.

Michael Hall - Heikkinen Energy Advisors

A lot of mine have been answered, but one question I was wondering on the 8000 wells you provide in the North, how would you allocate those to the various EUR buckets that you provided in the release and slides?

Tim Dove

What was it, 8,000 wells? What was it now? The resource potential? I tell you what, Michael, I looked at this that last night. Quick high-level and we can look at it closer but I would say maybe 25% would be the Spraberry shales. Remembering that there is a lot more verticals that have been drilled in the Spraberry shales over the years and then the rest I think is split relatively evenly between the A, B, and D.

Michael Hall - Heikkinen Energy Advisors

And then just to be clear in the CAGR guidance you provided what part of EURs are you assuming in those assuming you already provided or are you cutting those?

Tim Dove

Yes. Same ones we provided.

Michael Hall - Heikkinen Energy Advisors

In terms of go-forward infrastructure spend, you outlined kind of what third parties are doing but how does your infrastructure spend in the field progress as we move through ‘15, ‘16? What are the key items you're spending?

Tim Dove

If you take a look at slide 8 again you will notice that we have quite amount of capital that’s direct towards infrastructure spending both in the North and the South and particularly you notice in the North and that’s because whenever we’re out in the new areas we’re going to build tank batteries that can handle 64 wells and these are relatively expensive propositions and to the extent we’re putting one or two wells on production into the tank battery, we’re spending the capital for all of that tank battery day one but you’re not getting the effect of spreading that capital over a large number of wells until well into the project. That said all these tank batteries are being built modularly such we increase or decrease their size and so accordingly that’s what you’re seeing here in 2014.

As you look at ’15 we’re kind in the same mode where we got to be adding tank batteries in some of our new areas, not just tank batteries of course, salt water disposal facilities and so on. And I think over the next couple of years you will see a substantial amount of capital just like this until we have essentially built out the areas at which point you’re done with that capital to a great extent and then relative capital to tie in any new wells relatively limited and but it's going to be a couple of two or three years before we’re there. Similarly we’re going to be putting in place large water handling systems both with regard to bringing water to location for drilling and completions as well as handling produce water. So we’ve a very large contingent of people working on our water management facilities and then through time you will see more capital on that project going through the next few years as well.

Michael Hall - Heikkinen Energy Advisors

And then last on my end just the in the various areas you outlined in the North, South and the Eagle Ford, how many wells do you actually expect to put on production in each of those? Just in terms of spud count that you provided? How should we think about that?

Frank Hopkins

Michael this is Frank, I will have to get back to you on that I mean we basically what you've got in all the materials we gave out is what the spud count is.

Operator

We will take our next question rom Mike Kelly with Global Hunter Securities.

Mike Kelly - Global Hunter Securities

Quick one’s for you. One, just following up on all this spud to spud, spud to pop conversation here, I want to make sure I fully understand what you're saying in terms of the 150 day spud to pop for a three well pads. I'm interested if how long the rig is actually tied up in this 150 days, if it's there for all 150 days or it's done after 90 and it could start drilling the next three well pads? Thanks.

Tim Dove

Yeah generally the rig is moved and in lot of cases we’re using walking rigs and so it's very short load time and it's off the well in about between 25 and 30 days in the average. So that rig can then be released to go to the next well.

Mike Kelly - Global Hunter Securities

That's important in my model at least. Thanks. Also for CapEx you talked about, Scott, I think you mentioned 10% increase at least going out ‘15, ‘16. If I'm running numbers throughout my model, looks like a pretty decent sized funding gap for ‘15 as well. What's kind the if you go down the list of options here, how do you expect to fill that?

Scott Sheffield

I'd say that we've got productions growing pretty significantly so our cash flow growth is pretty substantial as well so it covers a big chunk of it. And then we'll have to look at whether we put it on the credit facility to the extent there's any extra or look at other alternatives.

Mike Kelly - Global Hunter Securities

Okay appreciate it and maybe one more if can sneak in just the Alaska looks like the sales expectations, proceeds declined a bit here maybe if you can just give any color on that? Thanks.

Tim Dove

Well basically the deal has been renegotiated from Pioneer standpoint. We have stated that Alaska is a non-core asset and strategically we have got a buyer that’s interested in progressing the transaction. So we’re moving forward with it.

Operator

And that concludes today’s question and answer session. At this time I would like to turn the conference over to Mr. Scott Sheffield for any additional or closing remarks.

Frank Hopkins

This is Frank. Scott had to go to another meeting but we want to thank everybody for being on the call today. We’re going to be out on the road quite a bit here over the next couple of months and we hope to see you all. Thanks a lot for listening.

Operator

And this concludes today’s conference. We thank you for your participation.

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