先鋒自然資源 (PXD) 2013 Q4 法說會逐字稿

Welcome to the 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 Webcasts. This call is being recorded, and a replay of the call will be archived on the internet site through March 8.

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 new 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.

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'll provide the financial and operating highlights for the fourth quarter of 2013, and he'll go over several of our key accomplishments that took place during last year. He'll then view our capital program for 2014, our production growth forecast for 2014 through 2018, and our increasing resource base that's being delivered by our successful horizontal drilling programs in the Spraberry/Wolfcamp and the 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. He'll also comment on drilling plans in the Southern Wolfcamp joint venture area and the 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'll provide earnings guidance for the first quarter, and after that, we'll open up the call for your questions. With that, I'll turn the call over to Scott.

Thanks, Frank. Good morning. On slide number 3, I'm opening up with our adjusted income for the fourth quarter of $140 million or $1 per diluted share. That does exclude the non-cash impairment on our Raton asset, due to the significant drop in the 15-year strip, which we primarily used from $5.40 to $4.60 by December 31.

It's a 15% drop and then we had a 27% drop in the gas price that the strip went to. It went to $7.30 before, and it's dropped down to $5.30, so a 27% drop. Obviously, the value of our PUDs, it impacts them significantly when you go from a $5.40 down to a $4.60 15-year strip. Again, it was non-cash.

Fourth quarter production was 164,000 barrels a day equivalent from continuing operations. This does exclude our announced sale of Alaska and also our plan to divest of the Barnett Shale assets. Fourth quarter production including Barnett, consistent with our January 20 press release was 173,000 barrels a day. As you remember we had significant curtailed operations, primarily in West Texas of 6,000 barrels a day due to the two ice storms, during November and 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 161,000 barrels of oil a day equivalent, backing out Alaska and Barnett, which were reflected in discontinued ops, so up 12% from full-year 2012. We had tremendous strong production growth related to our successful Spraberry/Wolfcamp program, up 19% and the Eagle Ford shale program up 35%. We had overall oil growth of 22%.

We had an excellent year in regard to drill bit reserve replacement, 211%. 141 million barrels of oil equivalent was 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'll discuss later. We'll be moving to 12 vertical rigs, eventually moving down to 5 vertical rigs and eventually down to zero over the next several years.

Going to slide number 4, we are forecasting 2014 annual production growth from continuing operations of 14% to 19% based on planned drilling capital expenditures of about $3 billion. We're increasing our horizontal rig count from 5 rigs at year-end 2013. Remember, we started the year in 2013 of 1, went to 5. We've added 5 rigs by the end of January, so most of them started at the end of January. We're adding another 6 by the end of March, so we'll be up to 16. If you remember, it takes roughly five to six months to see first production on these wells from these new rigs. 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 2014 to 2016 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 divestitures which will allow us to reallocate capital back into our excellent returns in the Spraberry/Wolfcamp drilling program.

We did announce the Alaska sale last quarter. We're now announcing reduced proceeds of $350 million, 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've had expressions of interest over the last several weeks.

We anticipate planning to sell those over the next few weeks to months. In addition, we expect to receive another $100 million from other asset divestitures. We ended the year with a strong balance sheet of $400 million in cash on hand. Net debt to operating cash flow is 1.1. Using the current strip it's less than 1. 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 an extended period of time. It supports the following EURs and returns for wells at 7,000 lateral lengths. We feel like in 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 and Midland County, remember, only have one well now. We have several wells scheduled for 2014.

In addition to the Wolfcamp B in Martin County, we're assigning 800,000 barrels of oil equivalent, over 100%-plus returns. The Wolfcamp D both in Midland, Martin, and Andrews County, we're assigning 650,000 to 800,000 barrels of oil equivalent with returns between 45% to 95%. We're placing four additional wells in the B -- in fourth quarter, we did place. Early production from these wells support the same EURs Those are the two Hutt wells, the Mabee, and the Scharbauer Ranch well. We placed our first Wolfcamp B interval in Glasscock County on production in early February, with an IP of 1,460 barrels of oil equivalent per day.

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 have been telling us the Lower Spraberry shale is probably one of the most oil-rich intervals in the entire Spraberry/Wolfcamp play. We're seeing tremendous results. We've placed five new Lower Spraberry shale wells in Andrews, Glasscock, Martin, and Midland Counties, 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 type curves with IRRs ranging from 45% to 100%. What's also interesting was we're getting 84% oil content, so gas-oil ratios are about half as they are in the Wolfcamp. Where we're getting 75% to 76% oil in 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 type curves. Last point, we did 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, a lot of great news. The downspacing is working. The upper Eagle Ford is working. A lot of additional wells were drilled the end of the fourth quarter of 2013. We see 45 Upper Eagle Ford wells being drilled in 2014 and continuing to optimize, generating tremendous returns in Eagle Ford and continue to grow significantly. Also what's most 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 resource, we're greater than 11 billion.

Going on slide 8 into our CapEx budget, it's very similar to 2013 in the amount. Obviously more and more capital's 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, but spending roughly $2.2 billion in the North, and only $200 million in the South. Again, the Eagle Ford program is very similar -- about $545 million, then $100 million scattered with other assets.

Capital is $285 million. About half of that are buildings in West Texas which will be completed in 2014. We expect that number to come down obviously significantly going into 2015 and 2016.

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 -- 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 of cash flow and then proceeds from divestitures. We expect year-end 2014 to be about the same debt levels as end of 2013.

Going to slide 9, in regard to the forecasting production growth, again over the next three years, we average 161,000, again up 12% versus 2012, forecasting of 14% to 19% production growth. If you remember we are losing roughly about 11,000 barrels a day equivalent from Barnett for 2014. We're losing about 1,000 barrels a day from other divestitures whereas $100 million is coming from approximately -- so we're losing about [12] off what the Street has in 2014.

Again, we're second-half loaded due to the effect of 11 more rigs moving into the North. Over the next three years, 16% to 21% growth rate. We'll be moving to 68% liquids in 2014, climbing on up to 75% liquids in 2016. Then as I stated earlier, we're expected 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 waterflood program into horizontal Spraberry/Wolfcamp. We get an increase of 2.3 billion barrels of oil equivalent, you can see, so we're totally changing the make-up of what we'll 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, essentially we'll have 40 years of inventory with this amount. We're still only on 100-acre spacing. We're drilling most of our wells on 100- to 110-acre spacing now anyway. You've got substantial improvement in this number 4 downspacing.

Also as footnoted in number 6, a lot of other zones have not been tested such as the Clearfork, the Middle Spraberry shale, the Atoka, the Woodford, and other zones. Again, 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 have not mentioned here is the increase in the Eagle Ford shale. It's primarily with downspacing, and also the upper Eagle Ford and some additional lean condensate locations.

We've added a number of locations in the resource potential in Eagle Ford. 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 2014 to 2016. I'm going to stop there, and let Tim talk about the quarter and going forward on executing.

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. What I'll be talking about now is really what I think we've accomplished in those very prolific zones in our 2013 campaign. 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 1 rig a year ago and of course that just points out the significance of going to what will be 16 rigs here by the end of this quarter. We were successful last year in placing 21 horizontal wells on production. You can see the table in the different zones where those wells were landed.

In summary, we had a 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 really have the most data. We saw very consistent and strong results there. Some of the news that we're talking about today surrounds the lower Spraberry shale early results. You can see we actually have put five of those on production.

They're relatively early days in their production. They do show a different sort of type curve than we see in the Wolfcamp. It's not just about IP when it comes to Lower Spraberry shales. There's a lot of water production that has to be gotten off the wells. The oil rate builds through time, and I've got a later slide to show you the early type well concepts that we should expect in Lower Spraberry shale wells.

We do you list a couple Jo Mill shale wells. Both have 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. I'd say the jury is still out when it comes to Jo Mill looking forward until we get some more well results.

Suffice it to say, we have successfully appraised 4 of the 6 stacked intervals that were our target for 2013. Importantly, a lot of the 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 in essence 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 shale wells, but we'll have more data on that shortly. It will be sometime before we have definitive data because we'd just be putting our first wells on production here shortly.

Importantly, 2013 was a year in which we had quite a bit of science. You'll see those numbers going down in terms of science expenditures in 2014. Turning to slide 14, some specifics on the type 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 type curves in the longer-term. You can see really these are tremendous results across the board.

IPs are one thing that we're focused on, but I'd call your attention to the cums that are shown in these colored boxes. 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 cumed 190,000 barrels and not even a year on production. Recall when we're drilling the vertical campaigns years ago, those wells would produce 140,000 barrels in 30 years, so it gives you the idea that the capital efficiency associated with horizontal drilling in these formations is a substantial benefit.

Also shown here in the coral color is our first Wolfcamp A well. It's now been on production quite a long time as well. It gives us an idea that it's going to be quite an outstanding zone as well. These graphs give us the confidence to support what Scott was referring to in terms of where we think the EURs would be for 7,000-foot laterals. So about 1 million BOE for Wolfcamp D wells, and 800,000 for Wolfcamp A wells in Midland County, and about 800,000 BOE for D wells in Martin County. They're really tremendous results so far, in particular related to our wells that are the longest on production.

Turning to slide 15, this shows data on the newest Wolfcamp B wells since our last report. Without going through the details of these, once again they show very solid results and particularly now in both Midland and Martin County, but now in 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've been doing drilling, is going to be prolific for the Wolfcamp B as well. Again, this data we see here in terms of results further supports the notion that these Wolfcamp B intervals are very prolific in all 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're in several different counties. They're in three different counties. They are in fact exhibiting very strong type curves in their own right, in the D in those three counties. In addition to which the cums are very strong as well.

This data here gives us a lot of confidence that the number Scott was referring to earlier on EURs for Wolfcamp D wells would range from 650,000 to 800,000 BOE in Midland, Martin, and Andrews for 7,000-foot laterals. 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 then is turning to the results of our five Lower Spraberry shale wells in the North. You'll notice we have a lot less production data -- production history because the longest of these wells has been on only about 90 days. I mentioned this a little bit earlier but just the nature of these wells is such that you'd expect a different type curve than you would expect in the Wolfcamp.

In addition to which, you'll also notice that these wells were drilled in four different counties. So they give us a view from afar in terms of the breadth of Lower Spraberry shale which our geos would tell us is the highest oil in place of any of the zones that we're speaking of. 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. They appear to be actually on a relatively flatter trajectory as they get into their full production. This gives us a lot of confidence the Lower Spraberry shale is in fact going to be a prolific zone. The early production data would allow us to say it looks like the range would be 575,000 to 800,000 on these wells. It is a range. It's relatively early days but suffice it 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 these wells as fast as possible? You'll notice that the Flanagan well shown in the magenta color where we installed an ESP only about three weeks into the flowback and starting to see really substantial improvements and flattening in production. We are testing really across these areas a combination of gas lift, jet pumps, rod pumps but particularly ESPs are showing a lot of benefit. We'll be continuing to look at ways to optimize the early production from these wells and essentially getting the water out of the system as fast as possible in order to build the oil rate.

On slide 18, this simply summarizes the horizontal drilling economics in the Northern campaign. Scott mentioned a lot of this earlier. Suffice it to say, based on the EURs that we discussed a moment ago, in our B and C costs for 7,000-foot laterals that are shown in the table, we get excellent returns from all four zones, and this of course is based on a $90 and $4 case. This gives us a lot of confidence that the capital that we're putting in place in all these zones is being efficiently employed.

Let me turn now to slide 19, and that's related to this year's 2014 plan in the North. And as we've already alluded to, we're transitioning from a horizontal appraisal program in 2013 that 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 building the rig count but you'll see that happen through next series of quarters.

As was mentioned by both Scott and I, the horizontal rig count is substantially increasing. We had 16 rigs by the end of the first quarter. The last of those rigs is in the final stages of contracting. I do not see any issue getting those rigs out there and running by the end of the quarter.

We do plan to spud about 140 wells in the North, average lateral length about 8,200 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 type curves. Right now, only about 10% of those wells are scheduled for the various Spraberry shale zones.

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 clarify Jo Mill, we could easily just switch this up and drill a higher percentage of Spraberry shale wells. Stay tuned on that as we evaluate and tweak the program depending upon the results that we see. We will be reducing science expenses, as you can imagine. Now that we're more in the development campaign, science becomes less of a priority.

Most of these wells, if not all of them, will be drilled basis three-well pads. Three-well pads yield a spud-to-POP time of about 145 days, so the results of this will be when we're doing pad drilling and we're only adding rigs as we get through the quarter, we're going to have a second-half weighted production growth. 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.

You can see that's the nature of the beast when it comes to combination of pad drilling and getting these rigs out here in the first quarter. Costs look like $8.5 million to $9 million per well as we are increasing the average lateral length. We are reducing the vertical rig count. In the fullness of time, it will be substantially reduced to zero. But we do need a certain number of rigs right now 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, it focuses on production. In 2014, it will be spudding about 115 wells, as compared to 100 last year. Lateral length increasing some 13% to 9,400 feet, and again utilizing almost all three-well pads. In the South, the focus is Wolfcamp. About two-thirds will be in 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, we see better results as we're deeper into the basin going that direction. We're going to focus on our best areas first, and that's what you'll see as a focus of our 2014 campaign. The costs look like they're about $8 million for the South on average at the lateral length 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, you recall we began testing downspacing down to about 720 feet. Sorry, from 720 feet to 480 feet. That's moving down from 116 -acre spacing to about 77-acre spacing.

We're testing those 12 wells and continuing to look at their performance, and the important note is that the performance of the wells that are 480 feet in terms of spacing, the production compared to the 720 spaced offset wells were essentially identical which is really what you're looking for. We'll continue to monitor those wells and make some evaluations as we get into 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 results all the activity is production growth, with the predominance of it, at least in terms of 2014, weighted to the second half of the year. We have a very good fourth quarter, other than for the fact that it looks flattish due to losing about 5,000 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 8,000 to 14,000 barrels a day. You can see that in the graph where the lighter green wedge is starting to overtake the darker wedge that represents vertical drilling. Overall campaign including the 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 what's going on in terms of some of the delays, most of those will come on toward the second half of this quarter.

It turns out a majority of the POPs are going to be in the JV area. The result is a lot of the incremental production from this activity will be mostly realized, not in the first quarter, but rather in the second quarter. 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 turn to slide 23, regarding the Eagle Ford, we also talked about downspacing efforts in our Upper Eagle Ford test, in our third quarter call on Eagle Ford. Recall we initially had for some time had been downspacing from 1,000 to 500 feet between wells in our liquids rich areas. Recently, we've been doing further downspacing to about 300 feet, staggering the wells. The wells at 300 feet downspacing seem to be performed in line with those of the 500 feet, and that's extremely encouraging.

We're actually looking now at drilling to test downspacing even further to 175 feet spacing. These areas will in some cases include both Lower and Upper Eagle Ford wells. That will add potentially a substantial number of locations to the 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 in the bottom right. It's really the top two lines showing production. One is for an Upper Eagle Ford zone, and then two offset Lower Eagle Ford zones. They're essentially tracking with really no distinction between the Upper and Lower results which is exactly what we're looking for. We think about 25% of our acreage is prospective for Upper Eagle Ford shale wells, and toward the end, we'll be drilling about 45 of them this year as a part of the program.

Optimization is always big, as we turn to slide 25 in the shale plays. They all require continuous improvement and the Eagle Ford is no different. Over the past two years, we've been actively involved in doing just that, working on continuous improvement in our completion design, and list several things that we've been doing. One is to reduce cluster spacing, so moving cluster spacing in general from 70 feet between per clusters to 50 feet; increasing the amount of sand or proppant we're pumping -- generally increasing that from 800 pounds per foot up to about 50% to 1,200 pounds per foot.

So significantly increasing proppant concentration. And also increasing the amount of barrels of fluids pumped per minute to act more effectively to fracture stimulate the rock. So far, we've seen really quite excellent results, 20% to 30% EUR increases with very low amounts of increases in capital, which yields returns of about 100% on the incremental capital spend.

There's a couple of graphs down here which will be able to give you some confidence that this is occurring. In the one to the bottom left, we have original offset wells shown in the blue curve. Then above those is the incremental production coming from a test where we're actually increasing the barrels per minute pumped, and reducing cluster spacing. You can see about a 20% EUR bump for only a 4% capital increment.

Similarly, on the bottom right curve you see a situation in which we're increasing the amount of profit per foot, and at the same time decreasing the cluster spacing. Here you see a case where EURs are at 30% while capital's up only 12%. 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 2014 will be a strong production 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 put less number of that in the third quarter. Those are primarily way 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 6,100 feet average laterals.

As was mentioned earlier, essentially 100% pad drilling, three- and four-well pads for the most part, which would have the effect of moving spud-to-POP days in the neighborhood of 120 to 150 days for the three- and four-well pads, respectively. We'll put about 26 wells on production in the first quarter, and anticipate that the results of that will be most of the impact will be in the second half of the quarter. Most of the production impact will be heavily realized in the second quarter.

In summary, we expect big things from our key drilling areas in 2014. With that, I'll pass it over to Rich for a discussion of the fourth quarter financials and outlook for 2014.

Thanks, Tim. I'm going to start on slide 27 where we had a net loss attributable to 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 Alaskan Barnett Shale asset down to their estimated value. That was for $507 million or $3.64 per diluted share.

As Scott talked about, we did reduce and take 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 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, production was down due to weather-related issues that we previously talked about. The other item there that's worth noting is our G&A expense. 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'll skip over those.

Turning to slide 28, looking at realized prices, you can see from the green bars there that oil was down 11% during the fourth quarter. If you look at NGLs and gas prices, they were relatively flat quarter-on-quarter. Then at the bottom of the slide, if you look at the positive impact of our derivatives, you can see the strong derivative portfolio we have and the benefits those added during the quarter.

Turning to slide 29, I'll talk about production costs 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 one-time repair costs that we had during the quarter associated with the severe winter weather. Those were offset by 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. 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's in excellent financial condition with no near-term maturities. You can see from the schedule there, we do have $393 million of cash on the balance sheet, plus $1.5 billion undrawn credit facility, so plenty of liquidity. All in all a very good financial position that we sit in at the end of the year.

Turning to slide 31, let's talk about first quarter guidance. It's important to remind everybody that does exclude Alaska and Barnett shale. They'll be concluded included in Discontinued Operations. Looking at first quarter production, we do anticipate 166,000 to 171,000 BOEs per day. T

This does reflect, as Tim talked about, our first quarter ramp up in rigs, and given the effect of 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. It is lower than it has been in the past, the result of the Raton impairment with the other items being consistent with prior quarters. With that, I'll stop there and we'll open up the call for questions.

(Operator Instructions)

Leo Mariani, RBC.

A 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? Where would that rig number be by the end of 1Q? I'm not sure exactly how many you have in the South. Is that maybe circa 25 total? 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?

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. Then 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. We'll pick back up more rigs in the South going into 2015. 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.

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

Obviously, it takes us a good two, three years internally to get to those numbers. This is what the type curves are exhibiting. Generally, it takes us two, three years to get up to that number internally. And then we use Netherland Sewell, and within that two-, three-year timeframe they get within 2%, 3% of that number also. We just need more history. 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're not using 1 million barrels, for instance, in those pie charts. We're using 800,000 for most of the counties, and we're using 575,000 for Lower Spraberry shales, so there's still a lot of potential increase in those resource pie charts. These are strong indications based on the type curves is our main point in Midland and Martin County on the various intervals.

Okay. 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?

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

Okay. Thanks, guys.

Ryan Oatman, SunTrust.

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?

Right now, just to give you clarification, the only spacing test that we've 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. What we're doing is we're watching the Giddings results, trying to get a handle on enough history on those wells, and right now we're in the second quarter of their production. We'll be making an assessment later. I think what Scott mentioned to you earlier is right now the whole Northern drilling campaign is predicated on, it depends on where you are, 110- to 140-acre spacing. It's very, very likely that our learnings from the South get translated to the North and that ultimately there's a substantial amount of the Northern acreage which is brought down to more potentially spaced wells. Let's say 80 acres, but we're not going to jump into a downspacing ever in the North until we have this pilot understood, so we then can extrapolate into the North.

Got you. That 80-acre spacing would correspond to 8 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?

First of all, we have drilled some Wolfcamp A wells in the South. Some of those wells actually encountered issues such as being drilled too close to faults, and so on. I don't know that we would say in the South we have a real statistical sampling of wells that we thought were completed properly. With that said, when you look forward about two-thirds of the wells will be drilled in the Wolfcamp B. We'll be drilling our first wells in the Wolfcamp C. That will be very interesting to see, how those results come out. The balance of course being A and [D] wells. It's a matter of we're going to be testing some of these zones in some newer areas and evaluating them, particularly with news on Wolfcamp C.

Okay. Then finally, I noticed didn't mention any Spraberry or Jo 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?

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

Great. That's it for me. Thank you.

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 NGLs that are needed and progress far?

Yes. We had two joint ventures pretty much in the entire 900,000 acres. One's with Atlas, and one's with the [WTG]. It's primarily with Atlas. We went on a mission about 18 months ago to educate Atlas the fact that we need a gas processing plant about 18 every months. We're on track to bring on a plant about every 18 months. The size of that plant's about 200 million a day, so the next one is in 2014. Then we've got one scheduled for 2015, and probably we'll need another one about every 18 months moving forward. Both NGL takeaways, we see no issues. On dry gas, we really see no issues. We have takeaways on that. At this point in time, even though it's fairly tight on crude oil right now, we do have a major pipeline bridge that's coming on this summer. Then you'll have Cactus and then also Energy Transfer Sun crude oil pipeline coming on. You're adding another 700,000, 800,000 barrels a day in the Permian in the next 12 to 15 months, Brian. Even though it's a little tight now on crude oil, we don't see any issues the next four or five months with us because our agreements, and then that being relieved on crude oil, so we don't really see any major issues.

We did built into our forecast this year some down time. There's going to potentially be a bottleneck in regard to the Atlas plant coming on in about four months, and the continued ramp-up in the Spraberry/Wolfcamp program by third parties. We could fill out these gas processing plant by June or July. We have built in some downtime in our forecast of about a four-month delay of reducing ethane production at that point in time.

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

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

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

I think, Brian, you have 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 generally would be limited to one or two offsets to the wells. As you get through time, you have 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 within five years, pursuant to the drilling rules within the five-year plan. All of those things are governors to actual bookings, but as I said, we pretty much have visibility on the 600 million BOE adds going forward.

Great. Thank you.

Matt Portillo, TPH.

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? Then I have a quick follow-up question to that.

Yes. It's pretty much run on a $90 flat case. Actually, it's on a strip price case, isn't it, Rich?

Yes.

More strip. The strip over the next three years gets down to about $83. In 2016, it gets down to about $83. If crude prices are much stronger than that, then the numbers can be higher because we would add more rigs obviously into the Spraberry/Wolfcamp program. Gas prices are pretty much in the $4 to $4.50 range in the strip in the next three years. I would say the big change could be crude. It's been in extreme [backward gradation] and continues to move forward which it has. Obviously, even with this year freeing up another $200 million in cash, potentially later in the year we could add more rigs if the price continues to average $98, $99, $100 a barrel for WTI. What was the second part of your question?

In regards to the 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?

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%. 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 2015, 2016.

Great. Then second question, just in regards to some of your Northern acreage, you guys have had some pretty successful wells in the central part of Andrews and Martin. I was curious if you have any color on 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?

We 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've drilled a D and a Lower Spraberry shale, both very successful. We'll probably go to the North end. We don't see testing anything in Gaines or Dawson. We'll probably test the Northeastern end of Martin County at some point in time. We pretty much have gone. We're probably within 5 to 7 miles as far North as we've been.

Thank you.

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. Your 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-to- sales number is at that point for these rigs?

I think if you look at it, there's always continuous improvement. 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 (inaudible) these wells which puts you out in more the mid-20s in terms of number of days on some of these horizontals. But overall, if you think of spud-to-POP times, we still think we're probably able to reduce substantially from where we are today. Let's just say we're averaging 170 days in 2013 in spud-to-POP. I think we could probably get that down to 150, and probably lower than that in the future. I think it's going to be substantial improvements and every hour counts, is what it amounts to.

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?

We're going to have situation where we're bringing on new rigs, and we'll want those rigs to be hopefully coming out of areas where they're already hot, where you don't have much risk that they're going to have delays or issues.

Got you. 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?

As you know, we at least got into vertical integration when it comes to pumping services, we only intended to be no more than two-thirds vertically integrated. We dropped the vertical rig count so substantially, we had gotten ourselves to the point where we are essentially 100% pumping our own wells. As you look at the current situation though, now that we've 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-party who are pumping the vertical completions in the Permian. In the Eagle Ford, we have two Pioneer fleets working and one third-party fleet. 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. I would think of that point in time, we would rather be bringing in third parties to pump the wells rather than doing it ourselves. We do not have any plans 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. It's a relatively small amount of our capital budget, but it is something we have to do just to maintain the equipment.

Great. I appreciate all the color, guys.

Jeffrey Campbell, Tuohy Brothers 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?

I think if you take a look at the pad drilling, we're now extensively utilizing that across each of our areas. This includes Eagle Ford, Southern Wolfcamp, and Northern Wolfcamp. Our average would be about 500,000 per well, if you are incorporating a pad drilling savings compared to single-well economics. That said, the other way to look at this though is, if you look at that same slide, we're using 7,000-foot laterals. Right now, almost all of our laterals are well above 7,000 feet. There's offsetting factors as well.

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

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, we've seen really pretty strong IP rate for this style of well. In fact, right now that well is tracking over the million barrel type curve, so that's pretty encouraging. But of course it's only early days. We've got a month worth of production on the well. That would have to give you encouragement about Glasscock at least when it comes to Lower Spraberry shale areas. 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 time as fast as you can? Really, you need to be looking at the fullness of time on these curves, and as I said on slide 17, it looks pretty interesting. They looked pretty positive to me.

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 the first couple of wells we put on, I think it supports what Tim said.

Okay. My last question is shifting to Eagle Ford. It looks like the results really continue to impress. When we look at the returns for 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 the 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?

No. Obviously, our policy at the Board level is that all assets for sale at the right price. Eagle Ford is a tremendous growth vehicle. It's moving forward significantly. We just increased the resource potential significantly with results. At this point in time, with the type of returns that Tim talked about in the Spraberry and Wolfcamp, they self-fund themselves. 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.

Great. Thanks a lot.

Amir Arif, Stifel Nicholas.

First, quick question is just can you just highlight some of the factors or parameters you're thinking about in terms of how fast you want to be shifting from verticals 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?

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

Okay. 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?

Well, I think there's obviously a few governors. We don't want to put rigs out there so fast we're going to have diminishing returns, ie, costs go up. We think there's a way to do this. 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 day we're going to be there, but we're definitely moving smartly in that direction having gone from 1 rig this time a year ago, to 16 here in about three months.

That sounds good. Then in terms of the Lower Spraberry, the production ratio on page 17, is that just to December 31? Or is that all the current production have available right now?

That's current data.

Within the last couple days.

Okay. Then if EURs continue to 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?

I think the real question's going to be, does this now mean we complete in four different zones versus the way you're thinking about it? Does this now mean if we can prove the Wolfcamp A, B, and D are prolific in this area, and in the Lower Spraberry shale, perhaps other zones as well, then you're now looking at a series of stacked laterals. That's the way I would be thinking about it.

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

I think it'll be 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 slide 17, Lower Spraberry shale type curves. It just takes a couple, two, three months before you have gotten the load water back and can establish the increasing rate. I think we'll know a lot more in the second quarter. We'll have to see when we have data that we're able to explain.

Thank you.

Gil Yang, Discern.

Charles Meade, Johnson Rice.

I'd like to ask a few more questions on the Lower Spraberry shale. I'm surprised that over now, we're just getting to it. I was wondering, I think we all have in our mind, you're Wolfcamp prospectivity map, but can you talk a bit about your current thinking on how the prospectivity for how that map 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 prospective further North, or maybe the sweet spot will be further North.

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

Got it. 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?

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

Got it, Scott. That water, is that formation water or is that frac load?

It's frac load. We're fracking these wells at 200,000 barrels of water, so it's going to take several months to get the water off. You've got to realize you're in a less pressure, less gas. It's 84% 85% oil. It just takes time to get the water off.

Just think about it as not having as much energy in the system to get that load back without help.

Got it. That's exactly the color I was looking for. Thank you.

Dave Kistler, Simmons and 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?

I think we'll be keeping verticals flat for a couple of years at about 12 before we start declining. I said all the way down to five in our five-year timeframe. 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 2015 in the South. The North, you'll see a slight CapEx increase with more rigs in the North, but cash flow will be up significantly going into 2015, and so 2016 I think to carry runs out towards the end of 2016 into 2015. Okay. 2016, you'll see a bigger increase in the South and the CapEx in regard to the South because the (inaudible) runs out going to 2016.

As we think about progression, is it fair to maybe bake in 5% growth in total CapEx spending between 2014 to 2015, 2015 to 2016, or am I too aggressive?

Probably 10% plus.

Okay, 10% plus. I appreciate that. Then 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. Are people trying to get you to lock down longer-term contracts? Is pricing creeping up at all on those high-end horizontal rigs? How should we think about factoring in any service costs creep over the next couple of years?

Really, Dave, if you take a look at the new contracts that we're signing, there's very little upward price pressure on those. In fact, most of the purveyors of drilling will basically look at any different ranges of time frames on contracts and are flexible on that. I think we're still in an equilibrium mode when it comes to the cost. We have seen other things that have fallen, so [guar] costs have come down dramatically, for example. Some of our chemical costs have come down dramatically. There are some markets where you are actually seeing some reductions. Our electricity costs are coming down in the Permian Basin, for instance. There are 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 right now. I think it has to do with the fact, we've been in this whatever it is, $90 to $100 oil case here for year-and-a-half, so it's pretty clear that we're just in an equilibrium mode. We're not seeing a whole lot of creep.

Okay. I appreciate that color. 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 of return on the balance of the portfolio prohibit you guys from doing that?

Yes. We feel like we need to get up to a consistent strip of $5.50 to $6 before we start considering it. Obviously, I stated in the first part of the call that a 15-year strip has dropped significantly, even though it's down in the $4.60 range. I think what's going to happen obviously, gas demand's increasing significantly over the next five years. With L&G exports commencing in late 2015, early 2016, it's going to take most of these gas plays throughout the US except for the Marcellus and Utica. It's going to take a gas price $5.50, $6 to start rigs back up. That's how we look at the Eagle Ford. That's how we look at Raton. We need to get up in the $5.50, $6 range.

Great. I appreciate that. One last one, just looking at the number of wells you're 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 POP time even though you're having efficiencies at the drill bit. 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 2014 versus 4Q 2013 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?

Dave, we are as you know drilling a predominance of the wells this year on three-well pads. That said, we are doing some on four-well pads as well. We'll have a lot better feel for what's the impact of basically a third increase in the number of wells on a pad even this year. You have to believe that since there are efficiencies associated with this that our tendency would be to go to more wells per pad through time. That said, that would make more sense in a scenario. We've got a large base of production from a large number of wells, so that the lumpiness that would come from let's say increasing from three- to four-well pads becomes basically immaterial, in the sense of production forecasting. It's just right now when we're in a situation you have such a low base to start from, that one pad, coming on heavily skews the numbers upward the day it comes on. At the same time, if it's delayed it holds your numbers back. I think in time you'll see more wells per pad, and in time as the base of production is solidified by a few years of drilling, you're not going to see this kind of lumpiness. For the time being, we've got to deal with it.

Okay. I appreciate the clarification, guys. Thanks so much.

Gil Yang, Discern.

Thanks for taking my question. You've got such a variety of acreage in different counties and in different zones in each of these counties. You've clearly talked about Wolfcamp 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? 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?

Gil, it's Scott. I think what we're hoping happens is that we get up the Lower Spraberry shale will continue to move up at the higher end of the range that we said. Let's say that Lower Spraberry shale is 800,000, and if the D wells, it look like there trending higher toward maybe 800,000, hopefully we'll get in the range of 800,000 to 1 million BOEs for all four of these zones. If we do, then that points toward similar development. We'll drill 800,000 to 1 million on similar paths and just drill, as Tim said earlier, four zones. They're all 100% type returns plus. If there's a difference between 1 million and 575,000, obviously were going to stay away from more 575,000s, but right now the trending is toward 800,000 to 1 million. If we can get that consistently in Glasscock, Martin, Midland, and Andrews in the North, then we're going to develop all four zones over time.

Okay. Great. Related to that, the follow-up is how do you think about the payouts 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 longer or shorter, drilling off of the pads?

I think that's an interesting question. Obviously, you have a [PV] effect of the 150 days if you will, there's that. You don't start getting paid back until the well is put on production, so you'd have to take it's a bit longer in terms of payout but the results of that is also going to be improved cost. I think there's your trade-off.

Is the return higher or lower with that POP delay?

I think it only reason we'd do it is it would be higher.

Okay. All right. Thank you.

John Freeman, Raymond James.

Just two questions. Following up on the spud-to-POP times, if I look at the Eagle Ford where you're doing three-well pads 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 per pad in the North and South and Permian, can I at least directionally in the next couple of years think that that's the trend, heading closer to what you're doing in the Eagle Ford?

I think the learnings that are important to apply to you are realizing Eagle Ford, our lateral lengths are nearly as long. I think we're averaging 6,100 feet in the Eagle Ford in 2014, and we're in the 8,000s to 9,000s. You by definition are adding more time associated with that, but I think directionally Eagle Ford is a great model for us to try to attain on Permian. It's just that in Permian, we're dealing with longer laterals and then more stages, and so on. We're always going to have that uphill battle, but directionally we certainly have a team in our Eagle Ford group that we can look at what they've accomplished and apply the same learnings.

Okay. Just last question for me, when I think about the longer laterals, 7,000-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?

John, essentially all of it at 7,000 feet. A large portion will be 9,000 to 10,000 feet, probably in the 30% range, but almost all of that on 7,000 feet. If not, we do have some tracts, when you look at our map, that we intend to do drilling deals or trades to make sure we get 7,000 plus. A lot of our acreage tracts, where we can't get 7,000, we'll go out and do a trade or a farm out in regard to or buy the acreage to make sure we get 7,000 plus.

Just to give you a frame of reference, John, for 2014, 89% of the wells will be drilled 7,500 feet and more. That gives you an idea that our leasehold's pretty extensive, and as Scott said, the main thing is to realize we're going to be able to amass a land team trying to get out to where we cobble together acreage so as we get up to 10,000.

That's very helpful. I appreciate it, guys. Thanks.

Joe Allman, JPMorgan.

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 inter-lateral spacing there? What do you think the impact would be if you tried the downspacing in the North as you're trying in the South?

(inaudible) As we stated in the footnotes on 100-acre spacing, essentially we're drilling more about 7,000-foot laterals on 110-acres spacing, so there's no downspacing essentially being put into the resource potential slide at this point in time.

How is it going to work in the North?

Downspacing. I've been associated with this field, Joe, as you know for a long time period. I won't state how long. We took it down from 160 when I started down to 20-acre spacing. (inaudible) would tell me we'd probably go down to 5-acre spacing on verticals at some point in time, so this rock is tight. Seeing what's happened in other shale plays throughout the US and Eagle Ford's success, I see downspacing easily working in this play over time.

Scott, do think we'll see some degradation on EURs you've listed? For example on the Wolfcamp B, your saying that the wells so far, you think they're going to yield 1 million BOE as you downspacing. Do you think that number is lower? Do you think your best guess at this point is based on the wells you've got? That's a good number for even downspacing somewhat?

I would guess that we saw that in vertical. We saw changes downward from 160 going down to 20s over time, but it's due to pressure depletion. We never saw the offset wells effected at all. If you downspace in 10 or 15 years now, after developing, for instance the Wolfcamp B, 50-acre spacing or the 30-acre spacing, I would tend to say that you're going to see with pressure depletion, you'll see a little bit less than a million barrels.

Got you.

(inaudible) economics.

Got you. When you look at these EURs that you're listing, should we think these EURs 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?

We not cherry picking any wells. These are all the wells. You can interpret fro yourself. It is what it is, in that data set.

Is there any reason to think --

I was going to say, on the resource potential, we're still being more conservative than what we're saying on the type curves. As the type curves get more and more performance, we'll translate that into the resource pie that we show.

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?

Not too much, no. We have a pretty good scattering of wells in those zones already, pretty good history.

Got you.

For Spraberry shale, we still need more time.

And that's true also in Middle Spraberry shale. Also just to add, if you look at around what some of the others are drilling, that adds to the confidence because they're seeing similar results, some of our peers.

Got it. Then thinking about the Southern Midland Basin, what's your best EUR estimate now for the South? 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?

We're still using it. We have not changed it from last year to this year. It's still at 575,000. Downspacing, we could add resource potential there too.

Okay. So far, with your downspacing, you've seen no degradation in that EUR per well?

No.

Great. All right. Very helpful. Thank you.

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?

I think not. I think if you look at it, first of all, you have various thicknesses of the Eagle Ford. By definition, thickness changes going from 200 feet to 300 feet, you could have a situation where you simply don't have enough thickness on the one hand. The other thing that occurs is you have various geology changes which occur up and down the Basin. We really looked at it to say we think these are going to be the sweet spots, where we can apply this downspacing, and it wouldn't necessarily be that it would be all over the acreage.

Okay. That's helpful. Then 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 takeaway? What do you think the biggest impediment is, and how can you help that from not having?

I think we had 50 rigs today. You would immediately quickly fill up some of your capacity to process, and so there's that. As Scott mentioned a few minutes ago, we're looking at that on a piecemeal basis where we need in gas plant every, say, year-and-a-half or so. We're right in that process of adding the next one, as we mentioned, later this year and another the following year. We're really keeping two years ahead of the issue. That said, with the growth in the Basin, we are seeing some issues where we have some tightness, but overall I think we have it well in hand.

To operate 50 rigs, compared to where we are today which is basically in the neighborhood of coming up on 25 rigs. If double the rig count means it doubles the water, we need to put it in place. We're doing a lot of work there to make sure we have water supplies that are adequate for the fracs. We've got to get twice as much sand out of the 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. We're the Company of choice, so I don't feel like that's a big issue there. Electricity needs to be built out to some of these areas where we're dealing with more remote drilling campaigns. It's really an all-of-the-above strategy. All of those things need to be dealt with. That's why we can't instantaneously step on the accelerator and go from 25 to 50 tomorrow. We need to do it through time and logically and piecemeal.

That was helpful. Thank you.

Michael Hall, Heikkinen Energy Advisors.

A lot of mine have been answered, but one question I was wondering. On the 8,000 wells you provide in the North, how would you allocate those to the various EUR buckets that you provided in the release and slides?

What was it, 8,000 wells? What was it now?

The resource potential?

The resource potential.

I tell you what, Michael. This is Frank. I looked at that last night. The quick high-level, and we can look at it closer but I'd say maybe 25% would be the Spraberry shales, remembering that there's a lot more verticals that have been drilled in the Spraberry shales over the years. Then the rest, I think is split relatively evenly between the A, B, and D.

Okay. That's helpful. Thank you. Just to be clear, in the CAGR guidance you provided, what [quarter] EURs are you assuming in those? Are those the same EURs you provided, or are you haircutting those?

Yes. Same ones we provided.

Same ones.

Okay. In terms of go-forward infrastructure spend, you outlined what third parties are doing, but how does your infrastructure spend in the field progress as we move through 2015, 2016? What are the key items you're spending on?

If you take a look at slide 8 again, you'll notice we have quite amount of capital that's directed toward infrastructure spending both in the North and the South. Particularly, you notice in the North, and that's because whenever we're out in new areas, we're going to build tank batteries that can handle 64 wells. 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 long number of wells until well into the project. That said, all of these tank batteries are being built modularly such as we increase or decrease their size. Accordingly, that's what you're seeing here in 2014.

As you look to 2015, we're in the same mode where we've 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. I think over the next couple of years, you'll 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 the relative capital to tie in any new well is relatively limited. It's going to be a couple, two, 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 produced water. We have a very large contingent of people working on our water management facilities, and through time you'll see more capital on that project going through the next few years as well.

Okay. That's helpful. Thank you. Then last on my end would be, in the various areas you outlined in the North, South, and Eagle Ford, how many wells do you actually expect to put on production in each of those? (inaudible) stark count that you provided? How should we think about that?

Michael, it's Frank. I'll have to get back to you on that. Basically, what you've got in all the materials we gave out is what the spud count is.

Fair enough. Thanks, guys.

Mike Kelly, Global Hunter Securities.

Quick ones 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, Frank, in terms of the 150 day spud-to-POP for a three-well pad. 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? It could start drilling the next three-well pad? Thanks.

Generally, the rig is moved, and in a lot of cases we're using walking rigs, so it's a very short [load] time. It's off the well in about between 25 and 30 days within the average, so that rig can then be released to go to the next well.

Okay. All right. That's important in my model at least. Thanks. Also for CapEx, Scott, I think you mentioned 10% increase at least going out 2015, 2016. If I'm running numbers through my model, it looks like a pretty decent sized funding gap for 2015 as well. If you go down the list of options here, how do you expect to fill that?

I'd say that we've got productions growing pretty significantly, so our cash flow growth is pretty substantial as well. It covers a big chunk of it. 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.

Okay. I appreciate it. One more if I could sneak in, Alaska looks like the sales expectations, the proceeds declined a bit here. Maybe if you could give any color on that? Thanks.

Basically, the deal has been renegotiated from Pioneer's standpoint. We have stated that Alaska's a non-core assets, and strategically, we've got a buyer that's interested in progressing the transaction, so we're moving forward with it.

Okay. All right. Thank you.

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.

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.

This concludes today's conference. We thank you for your participation.