先鋒自然資源 (PXD) 2014 Q4 法說會逐字稿

Good day, and 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 these slides related to today's call is www.PXD.com. At the website, select Investors and then select Earnings and Webcasts.

This call is being recorded. A replay of the call will be archived on the Internet site through February 28.

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.

Good day, everyone, and thank you for joining us. I'm going to briefly review the agenda for today's call.

Scott will be the first speaker. He'll provide the financial and operating highlights for the fourth quarter of 2014 and quickly review our key accomplishments for the year. I think it is fair to say that Pioneer had another great year, as evidenced by our strong production growth, impressive horizontal well performance, and solid year-end balance sheet. Scott will then review our plans for 2015, in the face of the current weak commodity price environment.

After Scott concludes his remarks, Tim will review our fourth-quarter horizontal drilling results in the Spraberry/Wolfcamp and the Eagle Ford shale. He'll also provide details regarding our high-graded 2015 drilling programs for both of those areas. And then followed by -- he'll give you the latest plans for our Spraberry/Wolfcamp infrastructure projects and an overview of our initiatives to cut costs and improve efficiencies.

Rich will then cover the fourth quarter financials in more detail and provide earnings guidance for the first quarter. And after that, we'll open up the call for your questions.

So with that, I'll turn the call over to Scott.

Thanks, Frank. Good morning. Obviously, a lot has happened over the last three months since our last call.

We'll start off on page 3, our financial and operating highlights. We had fourth-quarter adjusted income of $116 million, or $0.80 per diluted share.

We had fourth-quarter production, a little over 201,000 barrels a day from continuing operations. It reflects the fact that we did divest of Barnett Shale and Hugoton divestitures as discontinued operations.

Increased 15,000 barrels a day equivalent, or 8%, versus the third quarter. Oil production up 12,000 barrels a day, or 13%, versus third quarter. Obviously, the growth is being driven by our world-class source rocks in the Spraberry/Wolfcamp field and the drilling program there.

For our full-year production, we averaged 182,000 barrels a day equivalent. Again, reflects adding Alaska to the Barnett Shale and Hugoton divestitures and discontinued operations.

We increased 28,000 barrels a day equivalent, or 18%, versus 2013. Oil production was up 18,000 barrels of oil per day, or 25%, versus 2013. Again, strong growth from our successful Spraberry/Wolfcamp program and our Eagle Ford shale program.

We delivered great drill bit reserve replacement -- 177 million barrels of oil equivalent in 2014, at a finding cost of $19.65 per BOE. When you look at and break out just our horizontal drill bit F&D cost, it was $15.51.

What's more important -- we ended the year with a balance sheet of $1 billion in cash, net to debt operating cash flow of less than 1, and debt to book of 16%. Pioneer has one of the strongest balance sheets of anybody in the US today.

Slide number 4 -- focusing more on our results. Northern Spraberry/Wolfcamp horizontal drilling -- we placed 36 Wolfcamp Shale wells, a combination of A, B, & D on production. For each of those intervals, the fourth quarter wells are outperforming the average of all previously drilled wells in that interval.

Continuing to have great results -- very positive results -- from Upper Eagle Ford, both on going after the upper targets in the Upper Eagle Ford and also continued downspacing. In addition, we exported 10,000 barrels of oil per day at 3,500 barrels a day net to Pioneer of Eagle Ford Shale condensate.

During the second half of 2014, we significantly improved pricing to domestic condensate sales. We're taking that improved pricing, drilling more wells, reinvesting it back in the Eagle Ford program. It's the benefit of exports, allowing exports to Asia or to Europe.

In addition, we signed contracts of 20,000 barrels a day, 7,000 net, to Pioneer of condensate. That's committed for all of 2015 under two contracts, primarily going to Asia.

You all have read articles recently, over the last three, four weeks, that condensate sales have slowed down by other companies' attempts. But what's going to happen -- when the differential is widened to $6, between Brent and WTI, I do expect more companies to begin exports both to Europe and to Asia, with that differential at $6, and potentially expect it to go higher, with storage high in pad three and also in Cushing.

Going to slide number 5 and our 2015 outlook -- in response to the low oil price environment and reduced margins, we have significantly reduced spending. We're focusing, obviously, on returns. We think it's the most important item to really focus on -- capital efficiency -- and we're high-grading all of our key areas.

You can see later, when Tim talks, that we're delivering great returns, both in Eagle Ford, up to 70%, and both in the south and the north in our Spraberry/Wolfcamp areas, up to 55%. By delaying the returns in rigs, we could see an improvement of additional 30% to 40% as we add additional rigs -- whether it is beginning July 1, of 2015, or whether it is by the end of the year -- by getting an additional 10% cost reduction.

Seeing oil prices restore back to at least $70 a barrel in 2016. We'll see a 30% to 40% increase in returns over and above what I just mentioned today. We think that it's smart to keep our balance sheet strong.

We have the flexibility when to start the rigs to get our well costs down 20%. Start the rigs back up sometime mid-2015 or late-2015, going into 2016.

But currently we are reducing our horizontal drilling activity in the Spraberry/Wolfcamp and the Eagle Ford Shale to 16 rigs by the end of February -- 50% reduction, 6 in the north. If you look on the CapEx slide later, obviously, the north is our biggest area. It's where most of our 10 billion barrels of resource potential is, but it's going to get 65% of the CapEx.

Remember, they are 100% working interest wells in the north, where the other two areas are JVs in the south, where we still have our carry throughout 2015. Our carry will be extended into 2016 now. And six rigs in the Eagle Ford, again with our JV, we have reduced working interest. So most of CapEx will be in the north when we get to that.

We're essentially shutting down all vertical drilling programs. In Spraberry/Wolfcamp, we're on our last well now. You see there's a small portion in the CapEx for the first, really, two months of 2015.

Essentially, we're on our last well now. It turns out it is a disposal well to a brackish water zone.

Also with our infrastructure projects, we will be slowed down, both on our water system and our expansion of the Brady sand mine. Tim will go into more detail later.

Our total expenditures for 2015 will be $1.85 billion, which is a 45% reduction from 2014, $1.6 billion for drilling, $250 million for infrastructure. Operating cash flow today, at $1.7 billion. Cash on hand at $1 billion. We expect to dip into our cash on hand, roughly, about $100 million to $150 million.

Slide number 6. We're forecasting annual production growth from continuing operations of 10% plus, based on that budget. We have significantly high-graded the program.

Obviously, you'll hear from Tim that we're drilling in our best areas in Eagle Ford -- in the Karnes and DeWitt areas in the Eagle Ford. And we're upgrading drilling more to the north -- in our Sinochem joint venture -- in our best areas there. And we're drilling in our best areas in the north, primarily focused on the Wolfcamp B.

Forecasting oil growth of 20% plus. Margins are improving through efficiency gains and cost reductions. We're already realizing a 10% decrease. This has happened so fast. We have already realized a 10% decrease; we expect to get to 20% by year-end 2015.

We are prepared, as I mentioned earlier, to add more rigs by July 1, in response to reduced costs and improved price environment. Based on how fast this has happened, I do expect total US production to flatten second half of 2015 and start declining. That's why I'm optimistic about oil prices coming back in 2016.

We are also still pursuing our divestment of the EFS Midstream, our Eagle Ford gathering system. We expect bids over the next couple of weeks, so we're still optimistic there.

And we would like to have $1.5 billion to $2 billion in cash sometime by the end of 2015 to be able to jump start our program, with several more rigs going into 2016. We are very well hedged, as we have mentioned.

And finally, I think we have some of the best source rocks in the US, or in the world. We probably have one of the best balance sheets. So Pioneer is probably well-positioned as well as anybody to weather this storm, whether it is 12 months, 24 months, 6 months. We're ready to ramp up activity when things improve.

Slide 7. CapEx -- $1.85 billion. Our drilling capital -- $1.6 billion. Again, most of it's in the north -- 65%.

$120 million in the south, in our joint venture area, with Sinochem. $390 million in Eagle Ford. Other capital -- about $250 million.

And you can see, looking on the rainbow chart, you can pick your price. But at $55 oil and $3 gas, with a very well hedged position, we'll be over-spending, roughly, about $100 million, $150 million.

Slide number 8. Going into our growth profile, we've had a great year in 2014. 48% oil, 18% oil growth from 2013 to 2014. Ended the year at 201 million, the highest production in the Company's history.

Going into 2015, we'll still be growing our oil growth significantly. Fourth quarter 2014, fourth quarter 2015, essentially will be flat.

We did have downtime, and also ethane rejection and downtime from the ice storm, obviously, in the first quarter. Ethane rejection -- we're assuming it'll occur throughout all of 2015. We'll be up to 53% oil in 2015 -- up from 48%.

Let me turn it over to Tim to get more detail on our asset base.

Thanks, Scott.

And as he has already alluded to, despite the downdrafts of commodity prices that we've seen, 2014 was an exceptionally strong year for us operationally. And as I'll talk about, that success has carried into the fourth quarter.

Turning to slide 9. First, let's talk about the map, here. This map shows where all of the Wolfcamp, Spraberry/Wolfcamp wells were completed, as well as some other zones, including the Middle Spraberry, Lower Spraberry, and Jo Mill.

It is color coded by zone to give you an idea where all of the drilling and completions were occurring in 2014. Suffice it to say, there were a total of 43 wells put on production in all of these zones. On the left, you can see that 36 of those were within Wolfcamp Shale intervals, of which, the vast majority was in the Wolfcamp B.

And Scott alluded to this in his comments, but the really important message here is, for each of the intervals we drilled in the Wolfcamp, the wells we put on production in the fourth quarter are outperforming the average of all of the prior wells. And that's a very positive statement, when it comes to improving the contribution and productivity from future wells as well.

We did put four Lower Spraberry Shale wells on production. The data from those wells, you'll see, looks similar to that which we had drilled prior.

We did place a Jo mill well on production in the fourth quarter, as well as two Middle Spraberry Shale wells. The Jo Mill well was really a big positive as it had our highest 24-hour peak rate of any Jo Mill well we've drilled to date, of over 900 barrels a day.

The two Middle Spraberry Shale wells averaged about 400 barrels per day, BOE based. And of course, it's still considered to be relatively marginal, especially in today's oil price.

So the strong EURs that we've seen in the north have been very consistent. You can see them more in detail on slide 10, where we show a depiction of the average of all of the Wolfcamp wells that we've drilled. Note that this is all wells drilled, not just the best wells.

So focusing first on the Wolfcamp A, you can see we added to our data set considerably, where we had only drilled 12 prior wells. And we added 11 in the fourth quarter. And you can see that those wells are tracking well in excess of 1 million BOE.

Those are very encouraging results. They are partially explained by the fact that -- you see in the boxes -- that we're drilling longer laterals during the fourth quarter. But still, with this curve significantly above 1 million BOE, it gives us a lot of confidence in that zone.

Turning to the Wolfcamp B, on the right part of slide 10. You can see that we now have a very large data set on Wolfcamp B. That's why it gives us a lot of confidence, as we focus on 2015 drilling, to do so within the Wolfcamp B. Here, you see similar results as to past wells, but really exceeding -- in the sense for the last 20 wells put on production -- a little bit longer laterals, but well exceeding 1 million BOE.

Looking at the bottom left part of the graph, the Wolfcamp D. And we have, obviously, a smaller sample size here, with only 5 wells having been put on production. But they still are tracking in the range between 800,000 BOE and 1 million BOE. So we consider these to be very positive results, and they help us focus now on where the drilling is going to occur in 2015.

These graphs, of course, are not normalized. So when we talk about 2015 drilling, we're going to be averaging 900,000 BOE. But I think that will end up being conservative in all of the Wolfcamp zones.

In terms of the Wolfcamp A and B results you see so far on these graphs, I think that will be representative of what we will be drilling in 2015. That is to say, a high-graded program just focused on those two zones. So I think we will see a lot of benefits, a lot of efficiencies, owing to the fact we'll only be concentrating the drilling in the Wolfcamp and the Spraberry trend area to those two zones in 2015.

Turning to slide 11, this is more granularity as to the northern campaign for this year. As Scott has already mentioned, we are reducing the rig count, as we speak, down to about 6 rigs. The activity, as you can see on the right-hand graph, is spread in only a couple of counties in this case.

We plan to spud 60 wells in 2015. Again, focused on 2- and 3-well pads. The vast majority of those being in the Wolfcamp B, with some Wolfcamp A drilling.

That gives us tremendous efficiencies. And I see this -- when I look back at our past data, when we have a certain rig drilling repetitive wells in the same zone in the same area, we see dramatic improvement in time on wells and cost efficiencies. And that's exactly what we ought to see in 2015, as we really are focusing primarily on one zone, that being the Wolfcamp B, with a smattering of Wolfcamp A wells.

But it gives us a lot of confidence, in doing so, that we are high-grading. We're drilling wells in areas where we have the highest EURs, the highest net revenue interest. We've seen the best results in these areas; they're areas where we already have existing facilities. So that combination gives us a lot of confidence that we're going to have very strong economics in the 2015 campaign, despite the downturn.

We will, actually, put on production 85 to 90 wells this year, compared to 97 last year. That's due to the carry-over of wells that were drilled but not completed in 2014. So you will also see more well results in the first and second quarter from other zones, other than the Wolfcamp B and A, including the Wolfcamp D and the lower Spraberry Shale.

For 2015, for roughly an average 9,000 foot lateral, we are assuming about a $9 million cost. I think that will come down through time. That's based on an average 10% cost reduction, compared to 2014. We expect to be at 20% by year end, or more, and so I see those numbers coming down, owing to cost reductions on the one hand, but also efficiency gains.

So with that 900,000 BOE, as I mentioned, which I think will eventually be conservative -- it seems to be conservative, based on our historical results from the same zones -- we'd be generating EURs up to 55% at current strip prices. The average probably being more in the neighborhood of 35% to 40% on all of those wells.

As Scott mentioned, we have one last rig that will be stacked in about a week or so -- the last of the Mohicans, when it comes to vertical drilling in the Spraberry trend area. So we are really looking forward to the high-grading activity in 2015, as shown on slide 11.

Turning to Slide 12. This is the southern area. You see, on the graph to the right -- starting in the same way we did in the earlier slide -- that the drilling is moving to the north, in areas where we have higher EURs. And we'll be focusing the 45 wells that are spud, essentially almost, again, all on the Wolfcamp B. It, once again, gives us significant efficiencies, when it comes to drilling and cost reductions.

High-grading will be identical. That is to say, drilling the wells where we have the highest returns, highest EURs, highest NRIs, and where we have existing facilities. This is essentially the same objectives we're pushing towards in our northern campaign.

Again, we have some wells carried over into 2015, from last year. So in actuality, we will place 75 to 80 wells on production, and 75% of those will be B wells, the remainder being the other Wolfcamp zones.

Here in the southern acreage, we are a little bit shallower, so we have about an approximately $8 million well cost -- again, I think that can be reduced through time -- again, averaging about 9,000 feet. And so I think we have a lot of room to even to improve, when it comes to those numbers.

In the south, we generate a similar set of returns, simply because they're shallower. And such that they're shallower, the well costs are cheaper. And so their economics compare favorably with the returns in the north.

Turning to slide 13 then. The result of all of that activity last year was excellent production growth. Had production of 115,000 BOE in the fourth quarter, placed 69 wells on production, from the horizontal standpoint, and 30 vertical wells. And production was up dramatically, about 12,000-barrels a day, compared to the third quarter. And oil production up about 10,000-barrels a day. So really, really a strong result.

We pointed out earlier last year, we were going to see back-weighted production growth. And we certainly saw that in spades, looking at the fourth quarter.

Looking forward to 2015 -- and these numbers are predicated on the current rig count and not assuming any increases in the rig count for the time being -- but we would increase production about 20% with the growth, principally, first-half weighted. None of that is due to carry-overs from 2014. Based on the current rig count -- that is, adding no new rigs, let's say, middle of the year or later in the year -- we have an exit rate to exit rate that we expect to be flat, fourth quarter to fourth quarter.

We were affected in the first quarter, as we mentioned in the press release, earlier this quarter, we had a pretty severe ice storm -- not as bad as last year, but nonetheless, we didn't have all the wells back on production until very near the end of January. And so, as a result of that, we lost production, in addition to the fact that we lost production due to ethane rejection.

You've had ethane fall to, today, about $7.50 per barrel, which when you net out transportation and fractionation, really doesn't even make it economic to produce and sell. And that's been further exacerbated by the fact that propane prices have been weak as well, owing to a relatively warm winter. So the combination of those have us rejecting ethane, which is going to affect the first quarter production by about 3,000 barrels a day, counting the weather effects.

Now, turning to slide 14. We started out, of course, in the early planning, in the fall, with an extensive capital plan to prepare for the accelerated program of drilling that we had planned. And that has, obviously, not materialized in the current environment.

So we scaled many of those infrastructure projects back to the minimum that makes sense in the current commodity price environment we find ourselves. That includes tank batteries and gas processing, the Brady sand mine, and the water projects.

We are, as I mentioned in our optimized plan, drilling in areas where we have existing facilities. So for example, last year, we built 20 new tank batteries. And this year, we're planning to build eight.

Similarly, last year, we drilled 16 salt water disposal wells. This year, we're going to drill three. So we are dialing back and spending money as minimally as we can, drilling wells near existing infrastructure.

We have worked with Atlas, our partner in the Permian Basin, to delay some gas-processing infrastructure. The 200 million cubic feet a day plant that's planned in Martin County -- it is referred to as the Buffalo plant -- has been deferred from the summer of this year, when we had it originally planned when we thought we were in an accelerated growth mode, to somewhere in the third quarter or after of 2016. And the additional plant that we had planned for 2016 has now been deferred until the price environment improves and our activity levels are clarified. The 2015 capital program does include costs for the beginnings of the Buffalo plant expenditure, as well as investments for system upgrades in our existing facilities.

As a result of our activity reduction as well, we can easily postpone the expansion of our Brady plant. We had planned to expand it from 750,000 tons per year, to 2.1 million tons. We can defer that, now, until 2016 or after. There's, of course, a small amount of capital still needed for maintaining the facilities, while we wait on that expansion.

Turning to slide 15, and talking, specifically, on this slide about water. We're also slowing down our water projects, as well.

Our original plans had quite a large amount of capital to put in place a field-wide transport system. It was contemplating the substantial acceleration of drilling. But as a result of the slowdown, we're now expecting to spend only about $100 million with substantially less expenditures than we had planned prior, with the activity basically being associated with constructing the feeder line, as shown on the map coming from an existing third-party brackish water source to our Southern Wolfcamp area, that reduces the well costs there about $150,000 per well.

We have been working with the cities of Odessa and Midland. Both cities have been very constructive and cooperative in working through the downturn with us. We're working with the city of Odessa to defer the off-take of some of their effluent water, and we continue to work with the city of Midland to push out some of our purchases of water there, until drilling increases, in terms of activity.

So basically, at today's activity level, we have plenty of infrastructure in water and sand. And so the punch line is, as activity increases, as we look forward, we'll be ready to expedite these projects to be ready for future success.

I'll turn now to the Eagle Ford -- slide 16. Once again, in this area, just like we are in the Permian Basin, we're high-grading our drilling activities in south Texas; reducing the rig count to 6; and focusing, as Scott mentioned, in Karnes and DeWitt counties, where we have been drilling the most productive wells in the area.

I'll turn, now, to the graph on the bottom right. This is a third-party analysis that shows that Pioneer has drilled the very best wells, on average, in the play, measured by the 150-day cumulative production of the wells. And we're proud of that; we're proud of our Eagle Ford team for having delivered those kind of results. And that level of production results and efficiencies should continue or improve as we high-grade, going into 2015.

We did put 128 wells on production last year. 50 of those were in the Upper targets, which continue to show very good results. We'll have a large Upper program, as well, out of the total of the 2015 campaign, where we have about 100 wells that we'll put on production.

Well costs have been dramatically reduced in the Eagle Ford, as we have a lot of history under our belt, in terms of cost reductions -- $7 million to $8 million average, 5,000-foot laterals. And we generate, here, returns as good or better than we do around the Company, with the strong average EURs of these wells at 1.3 million BOE -- returns up to 70% and averaging 50% or so, based on current commodity prices. The wells are cheaper after so much experience, and the shorter laterals help us, and the EURs push the results to become some of the best economics in the Company.

Turning to 17 then -- it shows the results of all of that activity, and it's a ramp-up continuing in the Eagle Ford Shale to 49,000-barrels a day in the fourth quarter. It was affected negatively by the fact we had some production downtime, and we had greater-than-anticipated shut-in of offset wells. As we're fracking wells, we need to shut in the offset wells to protect their future production. And the timing of that ends up affecting, of course, that quarter's production.

We look for production to increase about 9% this year -- basically flat through the year -- based on the effects of the timing of POPs. The FY15 and full-year 2015 production is also being reduced similar to what I mentioned on Permian, due to ethane rejection. It's exactly the same situation. We don't really think it makes economic sense to produce and sell ethane at current market prices.

Then turning to slide 18, we have a large amount of activity going. We're really turning over every rock when it comes to optimizing returns on these wells. And in fact, 2015 gives us a chance to focus on optimization, on continuous improvement, and on cost reductions -- essentially improving our margins and reducing our breakeven economics further.

In the basins where we are, our breakeven economics are some of the lowest in the industry, but for the industry, this is probably an unintended consequence of OPEC's pricing policies, that they are forcing us to further reduce our breakeven economics. And we'll be the beneficiary of that, as an industry, as we move forward.

We are aggressively soliciting cost reductions. You can see a list of those on slide 18. Some of those are applicable cost reductions for our pumping services fleet, such as chemicals and guar and so on.

We continue to spend money and drill wells and complete those with a focus on optimization testing. We've discussed this quite a bit in the past, in terms of increasing clusters per stage, pumping different volumes of fluids, and profit. We're continuing those.

A little bit early to really say, yet, how those results are going to turn out. We think, probably, by the mid-year, we'll have a pretty good data set to be able to discuss where we are going to move forward, in terms of optimization, around the same concepts that work well in the Eagle Ford Shale.

And then in addition, we're working on modified three string and two string casing designs in the south, in the Wolfcamp zones, that have the potential for very large savings -- 500,000 to 1 million barrels per well. And we're even looking towards utilizing some of those same concepts in the north.

We continue to push the envelope, in terms of using new technologies, including dissolvable plug technologies that enables us to eliminate the coil tubing drill-outs after the fracs are done. Again, a potential for significant savings.

So I can say, definitively, we've already realized about a 10% reduction of our drilling costs. I think it will be at least 20% by the end of this year, compared to 2014. And we're pushing even further from there.

So let me conclude simply by saying 2015 is a year that we're focused on doing the optimal things very efficiently. And that, I think, will be borne out, as we look at our operational results for the year.

And with that, I am going to pass it to Rich for his analysis of the fourth-quarter financials and first-quarter outlook.

Thanks, Tim. And good morning.

I am going to start on Slide 19, where we reported net income attributable to common stock holders of $431 million, or $2.91 after tax. That did include non-cash mark-to-market derivative gains -- after tax of $364 million, or $2.45 -- primarily driven by the decline in oil prices and, to a lesser extent, gas prices, which had the effect of increasing the value of our derivative portfolio.

Also, as you note on the slide, we had unusual items totaling $49 million or $0.34 after tax. That was principally related to the impairment of acreage in our Black Fox prospect in southeastern Colorado and for drilling rig early termination fees, both of which were affected by the decline in commodity prices.

If you look at the bottom of slide 19, where we show results compared to guidance, you'll see that each of those items are, for the most part, are all within guidance -- other than G&A, which was slightly over, but nothing significant.

Turning to Slide 20, on price realizations. And on these, we did come out in late January and announce our price realizations. As you can see here, oil prices were down 27%, to $66.64; NGL prices were down 35%, to $18.50. And as Tim mentioned, the biggest decline was in ethane and propane prices, which led us to start rejecting ethane beginning January of 2015. Gas prices were down 5%, as you can see.

And then at the bottom of the slide, you'll see the positive impact we had from our derivative position during the fourth quarter. And as Scott mentioned, we are well hedged into 2015, at 90% of oil and gas, both at very attractive prices.

Turning to slide 21, looking at production costs. You'll see that they're fairly consistent throughout the year -- in that $13 to $14 range. In the fourth quarter, we were up 3%, principally related to LOE, which is the timing of invoices. That was offset some by the decline in commodity prices reducing production taxes.

Turning to Slide 22, looking at the balance sheet. Our net debt was $1.6 billion at the end of the year. That did include $1 billion of cash on the balance sheet. We've got $1.5 billion undrawn credit facility.

So as you can see, excellent financial position, with plenty of liquidity. That will, obviously, be strengthened further if the planned sale of EFS Midstream is successful. So all in all, a great balance sheet in today's commodity price environment, as Scott mentioned.

Turning to Slide 23 and switching to first-quarter guidance. You can see here, daily production at 192,000 to 197,000 BOEs per day. This does reflect the 3,000 barrels a day of weather-related downtime that we had in January -- so that's taken into account -- plus, the 4,000-barrels a day of ethane rejection that we predict in the first quarter and expect for the full year, just given where the ethane supplies are, relative to demand.

A couple other items of note to point out, here, is our DD&A guidance has gone up -- that is really two-fold. One, is the removal of the remaining vertical [spud] locations that we had in West Texas, as we switched to the higher rate of return horizontal drilling out there. So that will impact the reserves and impact DD&A. And then, as are you aware, given that pricing for reserves are done on a 12-month lag, the impact of the fallen commodity prices will be seen as we move through the year, and so that will have a slight increase in our DD&A rate.

The other item, there, is G&A. It is lower than previous guidance, as we've initiated a few cost-savings items that we're working on. And then, in other expense, that range is a little bit higher, as it includes stacked rig charges that we'll have in the first quarter, of $7 million to $11 million.

So with that, why don't I stop there. And we'll -- Kayla, we'll go ahead and open up the call for questions.

Thank you.

(Operator Instructions)

We will take our first from Doug Leggate with Bank of America Merrill Lynch.

Thanks. Good morning, everybody. I'm going to try a couple, if I may, in no particular order.

I guess, on the realizations this quarter -- before we get into the drilling program -- can you give us an idea of how many of your completions were skewed towards the back end of the quarter? Because obviously, the price was a lot lower in December than it was for the average. And I've got a couple follow-ups, please.

Yes, Doug. If you look at just our POP results for fourth quarter, you're exactly right. We're skewed towards December.

We had 41 of our total POPs in December, while we had 30 in November and 28 in October. So you can see we are back-weighted. So realizations, to the extent they were worse in December, definitely hurt us.

Okay. That makes some sense. I'm trying to understand why it was a little weaker than normal.

And just my two follow-ups are related, I guess. Firstly, on the 20% plus growth, I'm wondering if you can just help us with the plus -- that's for oil, obviously -- what the variables are. And I guess, specific to that, when you talk about the inventory of 900,000 barrel wells in the Spraberry/Wolfcamp.

When you look at the average you had in the fourth quarter, they seemed to have been -- at least in the A -- to be significantly above the million mark. So, how do you get to the 900,000, and what are the variables that could influence the plus on the 20% plus?

Yes, Doug. Obviously, we're focused on -- the Wolfcamp Bs are averaging 75% to 78% oil. When you start focusing on 900,000 to 1 million barrel-type wells or even greater, obviously, our gas production is declining in our other asset areas. So it just shows that we can continue to grow the oil side of the business.

NGLs, of course, with ethane rejection, has something though to do with it, also. But the focus is strictly on the best oil projects that we have. And that's why you're seeing that type of growth rate.

But I guess, what I'm getting at is, when you show the type of wells that you drilled in the fourth quarter, they were substantially above that 900,000. So what I'm trying to understand is, how do you get to the 900,000 if you're focused on the best parts of the play? You see what I mean?

Hey, Doug. This is Frank. Let me try to help you with that.

We do have some carry-over wells from the fourth quarter. You've got some Lower Spraberry Shale wells. You've got some Wolfcamp D wells.

I think it is fair to say, going into the year, we tend to be conservative. And that will play into it as well.

Okay. Thanks, Frank.

My last one, then, is, just very quickly, hopefully. The slowdown in the spending -- can you help us a little bit as to how that impacts the deferred tax calculation, in terms of what might be -- what the percentage of current would be?

And I'll leave it there. Thanks.

Yes. I think that our current will be teeny, or very tiny. It will just be AMT, if anything. So I don't expect much, in the way of current taxes for 2015, based on the current commodity price environment.

All right. Thanks, everybody. Appreciate it.

We will go next to Arun Jayaram with Credit Suisse.

Good morning.

My first question is related to a comment by one of your peers, Scott. And at Anadarko, they mentioned that they thought that they could get similar returns at $70 oil versus $90, if you saw 20% type cost deflation.

I was wondering if you agree with that statement. And if you were to see 20% cost deflation at $70, what type of growth do you think that Pioneer could generate, from a longer-term perspective?

Yes. The first answer to Anadarko's statement is that you probably could get to similar returns in a $90 environment, if you get a 20% at $70. Each company is going to have a lot lower margins. They're going to have a lot lower growth rate. So you're not going to get the same growth rate at $90 versus $70.

In regard to at this point in time, we're running out 10-year models. And it all depends on the oil price long-term. And so, I could not even speculate, but I do know that we're set up to grow significantly in 2016, 2017, 2018, continually, based on the strip price, as we see it today, with a 20% plus reduction.

If the oil prices stay lower, we'll probably see more than 20% cost reduction. So it all depends on what happens, going into 2016, 2017, 2018.

In my opinion, the bigger picture is, that the US has been growing 1 million barrels a day per year. The world, on the demand side, most people will agree, will be adding 1.2 million barrels a day. The Saudi's want to find a price -- long-term price -- that will keep US growth somewhere down between 300,000 and 500,000 barrels a day, until demand significantly picks up.

So long-term, I feel like we are in a $60 to $80 price world, instead of an $80 to $100 price world. So we are probably -- once this thing settles out -- we're probably going to be in the $60 to $80 for a while, until we see conflicts in the Middle East, or see demand pick up significantly.

That's helpful, Scott. Appreciate that.

My follow-up is really regarding the Midstream sales. Wondering if you could just talk about if the pull-back in commodity prices have any impact, you think, on that sale.

And I think you guys had talked about potential proceeds of $1 billion. If you were able to reach some proceeds in 2015, can you talk about, potentially, redeploying that capital, in terms of spending, and how that could impact 2016?

Yes. Obviously, it's a big swing factor, in regard to that. The large MLPs have not been -- their stocks, or units -- have not been affected as much as the US independent sector. And so we see no lack of interest -- or there's tremendous interest in the package. And so we don't see that affecting this transaction.

If we are successful in announcing and closing and can get up to $2 billion of cash, for instance, then we may take a more aggressive stance in start-ups and rigs earlier than I said earlier -- maybe earlier than July 1. If we have $2 billion in cash, we can get our well costs down 20% quicker, which we might be able to, then we could see starting up rigs even quicker than July 1.

Just to clarify, Scott. So you're thinking $2 billion in proceeds, potentially, from this transaction, which is quite a bit higher than I thought you had mentioned before.

No. We already have $1 billion in cash on the balance sheet. So most expectations are around $1 billion for our share of the asset base.

Okay.

I think most analysts have around 10 times cash flow, which is about $100 million per year cash flow, net to Pioneer.

Okay. Thank you very much.

We will go next to Charles Meade with Johnson Rice.

Good morning, to everyone there.

Scott, I wondered if I could just pick up a bit on that same theme a bit, and maybe approach it a little bit differently. What -- you have the cash on your balance sheet because you pre-funded a lot of this CapEx. It was in a different world, and it makes sense that circumstances have changed here.

But, you're planning to spend, roughly, with the cash flow for 2015 -- what are the circumstances, as you look at 2016, that would lead you to want to go ahead and spend more than cash flow? I mean right now, the strip for 2016, as I'm looking at it, is about $60 for oil. Would that be sufficient, or is it really more on the services cost front?

Yes. It's a combination of all. We've got to get our costs down 20% plus. We've got to feel confident and have successful EFS Midstream divestiture. And then we have to be confident that oil prices have bottomed and are trending up, and that demand in the world is picking up, also.

So it's really a combination of all three to four factors, and we will gain confidence and start the rigs back up as soon as we have confidence. We don't need to be confident in all four factors -- maybe at least three of them -- but we've got to feel confident, especially about the oil price.

We've heard comments that this scenario that Saudi Arabia has played out -- it could be a six-month scenario; it could be a two-year scenario. So we're being cautious just to make sure that 2016 isn't another $50 oil price world. Based on people's forecasts, I do expect production to flatten much sooner than people expect among all of the US companies and to start declining by late 2015, in general.

Got it. So that would certainly happen. That's really helpful, Scott.

Then, if I could pick up a bit, on the cost reduction and efficiency side. So you've talked about -- you had 10% cost reductions are what you're seeing now. You think you can get to 20%. But in addition to that, you've also -- or what appears in addition to that -- you've also identified some efficiencies that you're going to, whether it's through well design or more effective frac placement or selection of frac stages, that sort of thing.

Should we think about those two things as additive or, perhaps, multiplicative, when we're really thinking about your productivity, in terms of F&D or dollars spent per new barrel brought on? So should we be looking for, really, more than 20%, when you add in efficiencies, too?

Charles, let me take a shot at that one.

I think, I already touched on a couple of the efficiency areas we're working on. But the one area where we're really holding back on is, what actually is the net effect of drilling all -- essentially, all B wells in the same exact areas, with the same exact rigs?

We've seen an example of that in the Eagle Ford -- of course, we were drilling principally one or two zones -- and the efficiencies are dramatic. I mean, you're talking about several days reduction in well drilling and substantial cost savings there.

We are pushing the envelope on new technologies. And so I think we're going to pare away at it. The 20%, the way I look at it, is the net cost of wells just getting cost reductions put in place. It incorporates some of the things I mentioned, such as dissolvable plug technologies, and this kind of thing.

But we're not, today, building in any efficiencies in those numbers that have to do with, basically, improved optimization regarding well drilling and completions. And that's where there's more low-hanging fruit.

Got it. Got it. That's good.

And I'll just sneak in one more, if I may, Tim, on that front. It seems to me that, going to existing pads with existing tank batteries, that sort of thing, sets you up -- or at least, it's a logical question to ask -- whether you're going to be some downspacing tests in the B, in the Wolfcamp B. Is that part of your plans for 2015?

Yes. As you know, we've been doing some downspacing tests through time. We will be doing some of that again, in 2015. It is a very important thing to get our arms around for the future, so we're not going to short-shrift that at all.

We will be downspacing tests, and also testing different approaches to completions. As you know, we have As and Bs, and we have actually two zones in the B -- the B2 and B3 in the south.

So we're studying ways to stagger these wells. How to stack the wells. How to complete the wells so as to not have offsetting negative effects from the other wells in the area. And so all of this activity is part of, essentially, this whole optimization planning that we're doing.

Got it. Thanks a lot, Tim.

You bet.

We'll go next to Brian Singer with Goldman Sachs.

Thank you. Good morning.

Had two questions on the cost front. The first is actually a follow-up to a question, Tim, I think you tackled a month ago, which is -- when you look at Pioneer's vertical integration, do you see that providing a greater challenge or opportunity for cost cutting, versus leaning on the services companies? And what differences are you seeing in the cost of wells that you self-source, versus those where you have third parties?

I think first of all, I mentioned this, actually, in my comments, Brian, that we are actively pursuing cost savings for our pumping services group. And that incorporates a couple of different fronts.

One is, obviously, things like water and chemicals. We do buy a substantial amount of third-party sand, and so we're working on sand supply cost reductions, as well.

We're looking at different ways to utilize our fleets, in terms of reducing things like overtime, and improving efficiencies surrounding the utilization of equipment. So I think those are all possibilities for pretty substantial cost reductions.

Ultimately, I know we can compete with our brethren, who also pressure pump wells in the industry. And for right now, I think that will suffice, because essentially, what we're seeing, in terms of third-party quotations, is that these pressure pumping companies are offering their services, essentially, at cash breakeven costs. We know we can compete with those costs.

So, notwithstanding all of that, of course, we're getting really significant improvement, from the standpoint of reduced diesel costs. It is a pretty big utilization of diesel, when it comes to pressure stimulating a well. And we have seen diesel costs come down probably 45%.

So I think it's -- on all of those fronts, we would say we can be competitive with the third parties. And we'll continue to do so. Today, we're using only Pioneer grain fleets.

Got it. Thanks.

Then, a follow-up. When you look at some of the infrastructure projects that you're deferring -- the sand expansion, the processing plant, and pieces of the water disposal system -- what's the cumulative CapEx that you're deferring? And do you see the ultimate costs of these projects coming down over the next year, or do you view these as just a pure dollar-for-dollar deferral pushing them down the road?

Yes. I think, if you recall when we were talking about this exact topic at the time of the equity raise, we were talking about $1.2 billion, $1.3 billion worth of infrastructure needs. I think, what you have to look at is, what exactly will be the needs, going forward, when it comes to the activity levels?

So look at the sand mine, for instance. Where we need more sand, we will effect the expansion of the sand mine. I don't expect costs to come down to expand the sand mine, they'll probably be essentially the same, if and when we pull the trigger to do that.

I think that's true on gas processing, as well. And, for that matter, other infrastructure projects.

On the water front, as you know, we really talked about, as a part of a large capital plan, in fact, the early stages, we were talking about $500 million in 2015. That got reduced to $300 million, now to $100 million. And at the time, we were talking about putting in the big mainline backbone system for the entire north/south areas of the field. And that doesn't make a lot of sense in today's world, with activity levels.

As I mentioned, we have plenty of water today -- at today's activity levels. But when we decide to pull the trigger on that, it will be a large capital dollar amount. And there probably, sort of is what it is. And it's going to take that kind of money to put the project in place in the fullness of time, to the extent we are in that accelerated growth campaign in the industry.

Thanks.

And just to follow up on that. The sand mine and the gas processing, you said, you ultimately don't expect costs to come down. Is that because you've locked them in already, or you just don't see deflationary pressures in what goes into those expansions?

Yes. I mean, this is all industrial equipment. It's not necessarily particular to mining.

In fact, you might look at it the other way -- when we're doing gas processing, that's in direct competition with chemical plants. And those are, as you know, going up like crazy, in light of today's low energy cost in the United States. So I don't see any deflationary costs associated with building, essentially, plant facilities.

Great. Thank you.

We will go next to Leo Mariani with RBC.

Hi, guys.

I was hoping you could talk a little bit to your well results in the fourth quarter in the Permian. They certainly looked to be rather strong. I think, Tim, you referenced there were some benefit of longer laterals.

Could you maybe talk about some of the other things that you might have done in the fourth quarter, which have led to better performance? And I guess, just how far down the road do you think you guys are, in terms of optimizing some of these horizontal wells, at this point?

Leo, I think you're right. As I mentioned, it was actually on slide 10, that we have, in most cases, had average lateral lengths longer than we had on average, prior to that.

But we are working through, as I mentioned, quite a number of areas where we're trying to improve through time. And one of the major areas is, as I mentioned, as we continue to focus mostly on Wolfcamp B wells, we'll simply see the benefits associated with operating in the same zone, with the same well, in the same area. And it's just so much easier to get the wells drilled, when you know what to expect from a down hole stands point.

But looking forward, there's a lot of different things we're working on, as we speak. And a lot of that has to do with the optimization -- things I mentioned earlier -- when it comes to how the wells are completed, proppant, fluids. Those are all being tested, and we're seeing marginal gains on all that.

You look at Eagle Ford, as an example, we're now five years into the Eagle Ford Shale. We've seen dramatic reductions in drilling costs and completion costs, just owing to the fact we've been there so long. And we're now just in process of starting to generate those types of improvements in the Permian Basin.

We're a little ahead in the southern Wolfcamp area, where we're drilling wells, generally speaking, in only a couple zones. In the northern area, we've been drilling wells across the basin, as I showed on the earlier map, in various zones.

So it's hard to get efficiencies out of that because you've got new rigs working on new zones, and so on. But I think, moving forward, you're really going to see a dramatic improvement in that, and we'll have more to say, as soon as we start to get some well results from this year's campaign.

Okay. Is it safe to say that's not really in the guidance, here, in 2015?

That's right. That's what I mentioned to Charles, when he asked the same question, essentially, which is, we're not factoring in improvement operationally or efficiencies associated with, essentially, what amounts to drilling in the same areas, where we're drilling this with the same rigs, in the same zone, in the same area.

We are accounting for the situation I mentioned. We're not drilling a lot of wells outside of existing infrastructure. We are factoring that in. But not efficiency gains from drilling.

Okay.

I guess, obviously, you guys spoke in length about, deceleration case being prepared to go, as soon as the next handful of months, if you get the service cost reduction and the Eagle Ford Midstream proceeds. It sounds like the rigs can come back rather quickly.

Obviously, guys are deferring some significant infrastructure expense here, in 2015. I mean, to the extent that the rigs start coming back, do you start accelerating some of the infrastructure spend, as well? And in terms of your ability to accelerate production, can that, at all, be impacted by some of the deferral of infrastructure that we're seeing here, in 2015?

I guess what I'm really trying to get at is, if you did start adding the rigs back mid-year, when can we start to see some of the inflection, in terms of back end, in production growth mode? And are there going to be any impediments on the infrastructure side that may prevent that?

Thanks, Leo. I think, the way to think about that is, in general, as you know, we're drilling on two and three-well pads. That will push out spud POP dates, depending upon where you are and what you're drilling, 130 to 150 days.

So let's just use the scenario -- we pull the trigger, have rigs raised, as of, let's say, July 1. You start to see the production effects of that, the end of the year, essentially, let's just say fourth quarter. And accordingly, we have plenty of infrastructure today to deal with the new production that comes from those wells.

We were really, of course, focused on, at the time of building that infrastructure, using the north as an example, we had 16 rigs running, planning to add 5 to 10 per year. Right now, we have 16 rigs that are going to be running in the entire Company, only 10 in the Permian Basin, horizontally. So we've got a long way to go before we're taxing infrastructure, in terms of acceleration.

Okay. That's really helpful. Thanks, guys.

We will go next to Dave Kistler with Simmons & Co.

Good morning, guys.

Real quickly, when we think about the, I guess, for lack of a better word, backlog of drilled uncompleted wells in the Permian, that are leading to a nice production uptick in Q1 and Q2, why not defer the completion of those with your outlook for improving commodity prices heading into 2016, and lower service costs? It would seem like that would be a prudent thing to do on a PD basis, and would prevent the potential decline of production that you're seeing in Q3 and Q4 for the Company, in aggregate?

Well, I think, the easiest way to analyze that is to say we have our own green Pioneer fleets out there. They're working every day; they're tackling this [frag] bank as we speak. And so, to the extent we get cost reductions, those will be generated and will flow through our completion costs through the Pioneer Pumping Services fleets.

And so we are going to see the cost reductions, but they'll just be generated through time. I mean, it is really a matter, more, of keeping our fleets busy, keeping our people busy, with the idea that we have a very good probability of some sort of an upturn. And we want to be ready for that. And so that's the objective of keeping our fleets busy, for the time being.

Okay.

And so, thinking through that, then, let's say this low commodity price environment continues to exist for a bit; demand isn't necessarily picking up. So two of the four items you highlighted for accelerating may not come to fruition. You're laying down 50% of the rigs; you're using your fleets to complete everything and drill everything.

At that juncture, your backlog falls off. Do you then, potentially, look at laying off people to reduce costs, as well? Where do we stand, on that kind of an outlook, in terms of big cuts on the actual equipment, but not necessarily big cuts on G&A, that could correspond to that?

Yes, Dave. The bigger picture is that we have to -- nobody knows what the price of oil is going to be in 2016, 2017, 2018, 2019. And we have to wait to see what happens when things bottom out this year, whether it's $40, or whether it is $44 a few weeks ago.

We're hedged, so we are not too concerned about how low it goes. Personally, I'd rather it go lower and just re-correct itself, and have the supply side turn down.

The world is still very tight. There's only 2 million barrels a day excess capacity in the world. That's going to be used up in the next two years, easily. If you couple that with US production decline, the scenario is just not going to play out very long. It can't.

So we're more optimistic that prices are going to come back in 2016. For some reason, like you said, if they don't, then we'll have to -- the whole industry will have to look at what to do if prices are going to stay in the $50, $60 world for the next several years.

That's a whole different ball game, it is a whole different story, and we've just got to plan accordingly. But right now, we're just not thinking that scenario is going to play out.

Okay. Appreciate that added color. Thank you so much.

We'll go next to Matt Portillo with TPH.

Good morning, all.

Matt.

Two quick questions for me. I guess, around the Midstream side of the business -- wanted to see if you could provide some incremental context. So under your current plans to, potentially, re-accelerate some of the drilling program with lower service costs in the back half of this year, how should we think about that growth Midstream CapEx of $250 million this year? How should that trend into 2016, from a spending perspective?

Well, if you take a look at what one of these plants cost, they cost roughly, probably, $150 million, $160 million, something like that -- [8/8], which our share is 27%. And so it's not really a substantial amount of capital.

The question is, is it capital that hits every year? In other words, when we were in our old growth plan, we were putting a new plant out there every 12 months. And so it gets material after five years, when you put that many new plants on.

I think, right now, it's sort of wait and see. But the amount of capital you're talking about there, because of our low working interest, is relatively small.

I guess, from a bigger-picture perspective, as we roll-in the water expansion and some of the other projects that will, most likely, be necessary for 2017 and beyond, how should we factor in or layer that into our thoughts around your 2016 expenditure program, with the slight acceleration case on the rig count?

Yes. Well, if we're flat from where we are today, and for that scenario, let's just say commodity prices are low; we're flat on our rig count through all of this year, we do not need any excess water at that point in time. So our water projects, and for that matter, you can look at this associated with gas processing as well, are all optional. They all provide optionality for us to deal with accelerated cases.

So none of that really needs to be spent, except to the extent where, in an accelerated case, we want to supply our own needs. And so you have to look at this and say, it's 100% dependent upon, what it is we are facing, in terms of an accelerated drilling campaign. So that's why it's hard to answer your question definitively.

Great.

Then just the second question, quickly, here, on your guidance from a spending perspective for 2015, of $1.6 billion on drilling. Does that assume any of the rig adds that, potentially, could come in the back half of the year? Will that be incremental to your program?

Then, as we think about the 2016 outlook, could you provide some high-level color? If we think about the crude world and a $70 to $80 world, what sort of outspend would you be, potentially, targeting, given the balance sheet strength you have? Or how should we think about the growth trajectory, going into 2016?

Yes. I mean, the big factor is, how much do we -- we have $1 billion in cash on the balance sheet. How much do we get on a successful EFS? That will determine -- we don't mind out-spending when we have a bunch of cash on the balance sheet and returns are good; well costs are down.

We have not built in -- if we add rigs in July, or any time this year, over and above the current 16 rigs, that is not in our CapEx. So we would increase our CapEx, at that point in time.

Also, what's not in there is, that we hope that we'll get -- move toward 20% closer than by the end of the year. So we're only assuming a 10% reduction. We think we'll get closer to 15% and to 20%, before the end of the year. That's also not built in.

Thank you very much.

We'll go next to Phillips Johnston with Capital One.

Hi, guys. Thanks.

Slide 8 shows your quarterly production peaking in the second quarter, as you work your completion inventory off. And then, there's a very mild decline in Q3 and Q4.

My question is a bit theoretical. But if the current 2015 CapEx run rate is held throughout the year and continues into 2016, would you expect your production to decline slightly in 2016, on a year-over-year basis?

It will be basically flat, going into 2016, if we don't spend any -- if we don't add any rigs at all, or spend any of the capital that we have on the balance sheet. So, under that -- that scenario will occur if oil prices stay in the $50 range.

We do have strong hedges. We have, if you go back into our hedge position, we've converted a lot of our $10, 3-way hedges to [$40 by $65 by $75]. We feel very confident we are going to get $65 plus dollar oil on most of our oil, going into 2016, which also helps.

Okay.

Just as a follow-up to the last statement, there, on the CapEx cost reductions. I think, you said that it does not assume 20% reductions toward the end of the year. If you did realize that, how much lower do you think the $1.6 billion would actually be?

We can just take another -- you can take 15 -- it's easy math. Just take another 5% off the $1.6 billion, or take another 10% off the $1.6 billion if we get it quicker, like next week. But, it is more likely to be at least 15% occur, through the average of the year, sliding toward 20% at the end of the year. So you could take off another 5%.

Okay. Makes sense. Thanks.

We'll go next to Michael Hall with Heikkinen Energy Advisors.

Thanks. Appreciate the time. A lot of mine have been asked and answered.

But I guess, just looking at the -- kind of following on the last question, but looking at the shape of the 2015 activity, are all of those completion carry-overs from 2014 coming on, or expected to come on in the first half of 2015? And then does that quarterly completion rate in the back half for the northern Permian program look like about, I don't know, 17 or so wells per quarter?

Is that enough to keep things flat in the northern Permian in 2016, if you kept that up? Or what level of quarterly completions is needed to keep that program flat?

Well, I'll just touch on it like this. If you look at approximate numbers as to what we're expect, mostly, this is related to the carry-over, and just the way the schedule works. We've got more POPs at the end of the first quarter than we do early in the first quarter.

But overall, if you look at the first quarter and second quarter, because of the carry-overs, and just the drilling campaign ending at the end of 2014, so about probably, 80 or so POPs each, for the first two quarters. Then that falls off, as that inventory is cleaned up, and you get more at 50 and 60 in the last two quarters. So that's really why the curves look like they do.

Of course, that would change to the extent we ramp up drilling. And particularly, it would affect the fourth quarter.

Okay. Yes. That's helpful. Makes sense.

Then on the vertical program, what would you put the PDP decline at, maybe fourth-quarter 2015, fourth-quarter 2014, as you could lay that down? Just curious what that looks like.

Vertical drilling? You mean the production from the vertical wells?

Yes. The overall vertical production wedge, what does that PDP decline look like for 4Q 2015, 4Q 2014?

I think it's probably -- yes. It's no more than 10%, you have a very -- you have 7,000 wells that are declining 5%. So it's a relatively low decline rate. But the new wells, of course, are declining faster. So that's how you get something approaching 10%.

You can actually see that, if you go to slide 13. And it's sort of faded into what Frank's provided here, in the bottom part of the curve, meaning the darker vertical wells. You sort of have to interpolate, but it looks like, probably, a total 10% decline, year on year.

Yes. Okay.

Then, how much carrier are you expecting to utilize in the southern JV in 2015? And then what does that look like in--

Yes. 75% of it. There's a $575 million left, and we'll use, probably, about 75% of it in 2015.

You'll use 75% of the $575 million?

Correct.

Okay. Great. That's all I have. Appreciate it, guys.

We'll go next to Jeffrey Campbell with Tuohy Brothers Investment Research.

Good morning.

Slide 11 says that the northern vertical program ceases in February. Will you let any leases expire as a result, or can you pay lease extensions to hold acreage less expensively than drilling?

Yes, Jeffrey. We have taken quite extensive effort to work with a the lot of the mineral owners to, basically, what amounts to defer continuous drilling obligations. And as you might expect, there's a lot of mineral owners who don't necessarily want wells drilled on their property when prices are this slow. So they've been very cooperative.

In many cases, these deferral's have been done costless to Pioneer, because of our long-standing relationships with the owners. And at some points in time, it costs some minimal amount of money, but nothing compared to what it would take to drill a well, which would otherwise be needed to hold the land. So we will have minimal land implications of the current slowdown.

Okay. That's helpful.

As a follow-on to that, do you expect to resume the vertical program when prices improve, or does this downturn, essentially, accelerate the cessation of vertical drilling?

Well, I think it has, also, to do with how many horizontal wells we drill. That's always going to be the variable because, once we get back into a higher price commodity -- higher commodity price environment where we're drilling more wells, we will need a certain amount of drilling for continuous drilling obligations.

It may be that there's a handful of vertical wells that might be needed -- rigs that might be needed to do that. It's just too early to say, because it's all predicated on how many horizontal rigs we raise.

Okay.

If I could sneak one last one in, because I found it interesting -- how far along are you on this dissolvable plug testing stuff? Because we've actually seen some uneven results of this technology, and it seemed to be aligned with the relative reservoir pressures where it was being implemented.

Yes. Well, we've actually been doing this for some time. It takes several different forms, including dissolvable plug seats and so on.

But we've mostly used the large bore plugs in the Permian and the Eagle Ford. And the only issues we've seen is, if you don't get a proper dissolving of the plug, you may need to, otherwise, manually drill them out. But in our case, there's no real risk associated with having to go in manually and drill them out.

They can save a substantial amount of money. As I mentioned, $300,000 per well is a possibility. When you take out this need to drill out plugs, it can take five days of operation.

So it is definitely worth pursuing the technology. And, I think, it does have a little bit of moving parts, in terms of needing to improve the technology. But we're one of the operators who are willing to take the risk to do it.

Great. That's really good color. Thank you. I appreciate it.

We'll go next to Phillip Jungwirth with BMO.

Good morning.

I was wondering if you could expand on the comment about 2015 IRRs being similar in the north as in the south, just because I always viewed the north as being a higher-return area. Beyond just being shallower with lower [DNC], is this a function of greater high-grading in the south in 2015, and efficiencies yet to be realized in the north? Or a full project rates of return also be pretty similar between the two areas?

Part of it is the fact that it is shallower in the south. We're drilling similar, in terms of horizontal lengths, so there's really no difference there, at about 9,000 feet.

One thing we are doing is, as Frank mentioned and, I think, we mentioned on our slides, we're using a relatively conserve EUR average in the north. And the south -- we have more well control in the south. We're probably more on the number, in terms of what the south can do.

So, I think it may be a combination of those things. You'll notice, in the south, we're averaging 750,000 BOE. That's probably about what we can expect.

In the north, when we use 900,000, I think it can be higher than that. So we're trying to be conservative in the north because we're, really, earlier in its life.

Okay. Great.

Then, with longer production history in some of the downspacing tests in the southern JV area, where I think, you were testing anywhere from 310 to 720 foot inter-lateral spacing and staggering wells in the Upper and Lower Wolfcamp B, can you just talk about how the results, as compared to initial expectations, and how this has shaped your view of full field development in this area?

Yes. Well, that's certainly one area. We had one particular test in the Giddings area, where we tested quite a large number of downspaced horizontal wells. We're doing that in quite a few other areas of the field.

As I mentioned, one of the objectives, here, is to -- especially, let's just say, when we are drilling offset As and Bs, or when you're drilling offset B2s and B3s in the south, or staggered I should say -- staggered and offset, what's the proper distances to be used? And also, how should the wells be completed?

I think, we're getting further down the road, in terms of the notion of, when we are drilling As and Bs, to go ahead and complete all of the Bs first and then come back and complete the As, as the most optimal way to make sure we don't have any negative effect on the As. So we are gleaning some information from this.

But I'd just say it's still pretty early days. I still think we're going to be, probably, out in the 800 feet to 1,000-foot distances between B wells, as an example, on our program this year. And we'll also be testing some spacing less than that.

Great.

Then, last question. How should we think about any Eagle Ford Midstream sales, in terms of the impact of the reported cost structure? It sounds like $100 million of EBITDA is still a good estimate, even with reduced activity.

Will there be a future P&L hit from selling the assets? And if so, is this already reflected in the LOE guidance, or where would this be realized?

It is reflected in the LOE guidance. It'll be in future quarters, where that would be. And there would be an increase in LOE. I don't have the exact number here, but it's -- for Eagle Ford, it is $1 or $2 of BOE.

Great. Thanks, guys.

(inaudible)

Pardon me?

More like $0.50 for the Company.

For the Company, yes.

The Company, yes. The last estimate was around $0.50.

For the entire Company.

Right.

Thanks a lot.

We'll go next to Ryan Oatman with SunTrust.

Thanks for taking my question.

You work with partners in the Eagle Ford and southern Midland Basin, where you benefit from drilling carries. With this down-shift in commodity prices and now, capital spending, could you speak to if and how your thoughts have changed, regarding a potential joint venture for the northern Midland Basin?

Yes. There hasn't been a, I guess in early 2013, there hasn't been a joint venture in almost two years, in the US. So I think joint ventures have gone by the wayside, as a way.

Now the question is, what's going to happen, and what price environment are we going to have? And so long-term, we have to look at our long-term growth rate -- how to bring our northern acreage forward.

But I think we're a long way from that, as the best way to do it. So we're not even thinking about another joint venture, at this point in time.

Okay. Makes sense.

Does it sound like, there will be a potential for asset sales as a way to bring value forward, or obviously, would you just prefer the organic capital route?

We'll have to look at all the options. I mean, right now, we have $1 billion in cash on the balance sheet. We hope to get another $1 billion. So that's something that's way down the road.

In Pioneer's history is that we use all options, assets, divestitures, balance sheet. We have, of course, gone to the equity markets, like we did recently. We've sold portions of our acreage in the north, like we did last year. We've done JVs.

So we have done a combination of all four or five, trying to bring our NAV forward. And we'll continue to look at the same, over the next several years.

Great. Thanks for the color.

We'll go next to Harry Mateer with Barclays.

Hi, good morning.

First question. So, it sounds like you're saying the drilling CapEx you're targeting this year is, essentially, maintenance CapEx, given that production will be roughly flat if you keep spending at that level. Is that the right way to think about it -- as being maintenance CapEx?

It's not focused on maintenance CapEx. We're focused on delivering a growth rate of 10% plus. That growth rate can increase, depending on when we start up new rigs. They've got to be great projects -- great returns.

We've got to bring our NAV forward. That's how we -- we've got to keep a great balance sheet. So we don't focus on maintenance capital. That's not the guide, as to what we came out with our program.

Okay. But the 4Q to 4Q production looks roughly flat, is that right?

Right. Yes. That's right.

Okay.

And then --

That wasn't the overall reason we came out with this budget. That's where I'm going.

Got it. Okay.

Then, how do you think about -- obviously, you're in a great balance sheet position and liquidity position today, but hedges don't last forever. So, if someone is a bit more bearish on energy prices for a longer period of time, how do you think of balancing that risk, versus the fact that the current CapEx budget gets you roughly flat production, 4Q over 4Q?

Do you think, when you look out -- I know it's preliminary -- but you do have a bond maturity in mid-2016. Do you think it's conceivable you might want to de-risk the balance sheet even further, by warehousing liquidity -- just pay that down instead of assuming that you might refinance it?

Well, no. I think, we could still issue 10-year money in the 4% range, low 4%s. So the 2016, 2017, 2018, maturities that are coming up, we'll be looking at going to the markets at the right point in time. So we're not going to use our $1 billion to buy that back in. It is not cost effective.

Okay, great.

The last one, on the potential EFS sales, your current thinking that you would think to provide a minimum volume commitments for a period of time after that sale?

That all depends on negotiations with the buyer.

Okay. Thank you.

There are no further questions at this time. I would like to turn it back to our speakers for any additional or closing remarks.

Again, thank you, everybody, for participating. Great questions.

Hopefully, we'll see a little bit higher oil price the next time we see everybody -- in the next three months. Thank you.

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