Feb 11, 2015
Executives
Scott Douglas Sheffield – Chairman of the Board & Chief Executive Officer Timothy L. Dove – President, Chief Operating Officer & Director Richard P.
Dealy – Chief Financial Officer & Executive Vice President Frank Hopkins – Vice President Investor Relations
Analysts
Doug Leggate – Bank of America Merrill Lynch Arun Jayaram – Credit Suisse Charles Meade – Johnson & Rice Company, LLC Brian Singer – Goldman Sachs Leo Mariani – RBC Capital Markets David W. Kistler – Simmons & Company International Matthew Portillo – Tudor, Pickering, Holt & Co.
[Unidentified Analyst] – Capital One Michael A. Hall – Heikkinen Energy Advisors Jeffrey Campbell – Tuohy Brothers Investment Research Philip Genworth – BMO Capital Markets Ryan Oatman – SunTrust Robinson Humphrey Harry Mateer – Barclays Capital
Operator
Welcome to Pioneer Natural Resources’ fourth quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations.
Pioneer has prepared PowerPoint slides to supplement their comments today. These Slides can be accessed over the Internet at www.PXD.com.
Again, the Internet site to access 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 28th.
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 result in future periods to differ materially from the forward-looking statements.
These risks and uncertainties are described in Pioneer’s news release on Page Two of the slide presentation and in Pioneer’s public filings made with the Securities & 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.
Frank Hopkins
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’s fair to say that Pioneer had another great year as evidenced by our strong production growth, impressive horizontal well performance, and solid yearend 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 follow 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. After that, we’ll open up the call for your questions.
With that, I’ll turn the call over to Scott.
Scott Douglas Sheffield
Obviously, a lot has happened over the last three months since our last call. We’ll start off on Page Three, 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 a Barnett Shale and Hugoton divestures 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’s 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 divestures as 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 ’13. 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 costs 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 with $1 billion in cash, net-to-debt operating cash flow less than one, and debt-to-book of 16%. Pioneer has one of the strongest balance sheets of anybody in the US today.
Slide Number Four; focusing more on our results, Northern Spraberry/Wolfcamp horizontal drilling, we placed 36 Wolfcamp shale wells, a combination of A, B, and D on production. For each of those intervals the fourth quarter wells are outperforming the average of all previously drilled wells in that interval.
We’re 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 down spacing. In addition, we exported 10,000 barrels of oil per day 3,500 barrels a day net to Pioneer of Eagle Ford shale condensate.
During the second half of ’14 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 as committed for all of 2015 under two contracts primarily going to Asia.
You’ll have read articles recently over the last three or four weeks that condensate sales have slowed down by other companies’ attempts, but what’s going to happen is 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 and also in [Cushing]. Going to Slide Number 15 and our ’15 outlook.
In response to the low oil price environment reducing margins, we have significantly reduced spending. We’re focusing obviously, on returns, we think is 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 an additional 30% to 40%, as we add additional rigs, whether it’s beginning July 1, 2015 or whether it’s by the end of the year, by getting an additional 10% cost reduction.
Seeing oil prices restored 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’s smart to keep our balance sheet strong.
We have the flexibility when to start the rig, get our [indiscernible] down 20%, start the rigs back up sometime mid ’15 or late 2015 going into ’16. But currently, we are reducing our horizontal drilling activity in the Spraberry/Wolfcamp and Eagle Ford shale to 16 rigs by the end of February, 50% reduction.
Six in the north. If you look on the cap ex Slide later obviously, the north is our biggest area.
That’s where most of our 10 billion barrels of resource potential is, but it’s going to get 65% of the cap ex. Remember, they’re 100% work interest wells in the north where the other two areas our JVs in the south where we still have our carry.
Throughout ’15 our carry will be extended into ’16 now and six rigs in the Eagle Ford again, with our JV we have reduced working interest. Most of the cap ex 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’ll see there’s a small portion in the cap ex for the first really two months of 2015. We’re essentially on our last well now and it turns out it’s a disposal well to a brackish water zone.
Also, with our infrastructure projects we’ll be slowed down both in our water systems and our expansion in 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 ’14. $1.6 billion for drilling, $250 million for infrastructure.
Operating cash flow today at $1.7 billion. Cash on hand $1 billion.
We expect to dip into our cash on hand roughly about $100 million to $150 million. Slide Number Six, we’re forecasting annual production growth from continuing operations of 10% plus based on that budget.
We significantly high graded the program. Obviously, you’ll hear from Tim that we’re drilling in our best areas in the 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.
We’re forecasting oil growth at 20% plus. Margins are improving through efficiency gains and cost reductions.
We’re already realizing a 10% decrease. This has happened so fast.
We’ve already realized a 10% decrease, we expect to get to 20% by year end ’15. We are prepared, as I mentioned earlier, to add more rigs by July 1st in response to reduced cost and improved price environment.
Based on how fast this has happened, I do expect total US production to flatten second half of ’15 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 ’16.
We’re very well hedged as we have mentioned. 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 as well positioned as well as anybody to weather this storm whether it’s 12 months, 24 months, six months. We’re ready to ramp up activity when things improve.
Slide Seven; cap ex $1.85 billion. Our drilling capital $1.6 billion again, most of it is 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. As you can see, looking on the rainbow chart, you can pick your price but at $55 oil and $3 gas with very well hedged position, we’ll be overspending roughly about $100 million to $150 million.
Slide Number Eight going into our growth profile. We’ve had a great year in ’14, 48% oil.
18% oil growth from ’13 to ’14. Ended the year at 201, the highest production in the company’s history.
Going into ’15 we’ll still be growing our oil growth significantly. Fourth quarter ’14 fourth quarter ’15 will essentially be flat.
We did ethane rejection and downtime from the ice storm obviously, in the first quarter. Ethane rejection we’re assuming it will 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.
Timothy L. Dove
As Scott already alluded to, despite the downdrafts in commodity prices that we’ve seen, 2014 was an exceptionally strong year for us operationally and as I’ll talk about, that success is carried into the fourth quarter. Turning to Slide Nine, first let’s talk about the map here.
This map shows where all of the Spraberry/Wolfcamp wells were completed as well as some other zones including the Middle Spraberry, Lower Spraberry and Jo Mill. It’s color coded by zone to give you an idea of where all 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.
Scott alluded to this in his comments, but the really important message here is for each of the intervals we drilled in the Wolfcamp, wells we put on production in the fourth quarter were outperforming the average of all 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 grade 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.
The strong EURs that we’ve seen in the north have been very consistent. You can see them in more detail on Slide 10 where we show a depiction of the average of all of the Wolfcamp wells that we’ve drilled.
Note, this is all wells drilled not just the best wells. Focusing first on the Wolfcamp A you can see we added to our data considerably where we had only drilled 12 prior wells, we added 11 in the fourth quarter and you can see that those wells are tracking well in excess of a million boe.
Those are very encouraging results. They’re 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 a 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 dataset 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 of the last 20 wells put on production, a little bit longer laterals but well exceeding a million boe.
Look at the bottom left part of the graph of Wolfcamp B, we have obviously a smaller sample size here with only five wells having been put on production, but they still are tracking in the range between 800,000 boe and a million boe. 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 the Wolfcamp zones. In terms of the Wolfcamp A and B results you see so far on these graphs, I think they will be representative of what we’ll be drilling in ’15.
That is to say, a high graded program just focused on those two zones. I think we’ll see a lot of benefits, a lot of efficiencies owing to the fact that we’ll only be concentrating the drilling in the Wolfcamp and in the Spraberry trend area to those two zones in 2015.
Turning to Slide 11, that’s just more granularity as to the northern campaign for this year. As Scott has already mentioned, we’re reducing the rig count as we speak down to about six rigs.
The activity, as you can see on the right hand graph, is spread in a couple of counties in this case. We plan to spud 60 wells in 2015 again, focused on two and three 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, as I look back at our past data where 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.
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 that in doing so that we’re 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 we already have existing facilities. 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 carryover of wells that were drilled but not completed in 2014, so you’ll also see more well results in the first and second quarter from other zones other than the Wolfcamp B & A, including the Wolfcamp D and the Lower Spraberry shale.
For 2015 for roughly an average 9,000 foot lateral, we’re 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 owning to cost reductions on the one hand but also efficiency gains.
With that 900,000 boes 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 IRRs up to 55% at current strip prices. The average probably being more in the neighborhood of 35% to 40% on all those wells.
As Scott mentioned, we have one last rig that’ll be stacked in about a week or so, the last of the Mohicans when I comes to vertical drilling in the Spraberry trend area. We’re 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 the same way we did in the earlier Slide, 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 again, all in 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’re a little bit shallower so we have about 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 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 they are 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 that activity last year was excellent production growth.
We had production of 115,000 boe in the fourth quarter. We placed 69 wells in production from the horizontal standpoint and 30 vertical wells.
Production was up dramatically, about 12,000 barrels a day compared to the third quarter. Oil production up about 10,000 barrels a day.
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 again, 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. A lot 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’d have an exit rate that we’d expect to be flat fourth quarter to fourth quarter. We were affected in the fourth 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 week as well owing to a relatively warm winter.
The combination of those have us rejecting ethane which is going to affect 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 and so we’ve 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.
For example, last year we built 20 new tank batteries, 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 there.
We’re dialing back and spending money as minimally as we can and 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 that is planned in Martin County, it’s 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. 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 needed for maintaining the facilities while we wait on that expansion. Turning to Slide 15, we’re 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 that 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 offtake 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.
Basically, at today’s activity level we have plenty of infrastructure, and water, and sand, and so the punchline 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 six and focusing, as Scott mentioned, in Karnes and DeWitt Counties where we have been drilling the most productive wells in the area. 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. We’re proud of that, we’re proud of our Eagle Ford team for having delivered those kinds of results.
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 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. We generate here returns good or better than we do around the company with the strong average EURs of these wells of 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 result to become some of the best economics in the company. Turning to 17 then, shows the results of all that activity.
It’s a ramp up continuing in the Eagle Ford shale to 49,000 barrels a day in the fourth quarter. It was effected 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 effecting 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 fiscal full year 2015 production is also being reduced somewhat, as I mentioned, on the Permian due to ethane rejection. It’s exactly the same situation where 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.
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 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 [indiscernible], 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 fluid, and profit. We’re continuing those.
It’s 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 dataset to be able to discuss where we’re going to move forward in terms of optimization around the same concepts that work well in the Eagle Ford shale. 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.
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 coil tubing drill outs after the fracks are done.
Again, a potential for significant savings. I can say definitively we’ve already realized about a 10% reduction in 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. 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.
With that, I’m going to pass it to Rich for his analysis of the fourth quarter financials and first quarter outlook.
Richard P. Dealy
I’m going to start on Slide 19. We reported net income attributable to common stockholders 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 drive by the decline in the oil prices and to a lesser extent gas prices which had the effect of increasing the value of our derivative portfolio. Also, as you’ll notice 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 declining 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 all within guidance other than G&A which was slightly over, but nothing significant.
Turning to Slide 20 on price realization, on these we did come out in late January and announced 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 declining 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 BFS 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 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 whole year just given where the ethane supplies are relative to demand.
A couple of 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 pud locations that we had in West Texas as we switch to the higher rate of return horizontal drilling out there so that’ll impact reserves and impact DD&A.
Then as you are aware, given that pricing for reserves are done on a 12 month lag, the impact of the fallen commodity prices will be seen as 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 saving items that we’re working on.
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. With that, why don’t I stop there and we’ll go ahead and open up the call for questions.
Operator
[Operator Instructions] Your first question comes from Doug Leggate – Bank of America Merrill Lynch.
Doug Leggate
On the realizations this quarter, before we get into the kind of 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 is a lot lower in December than it was for the average?
Scott Douglas Sheffield
If you look at 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’re back weighted so realizations to the extent they were worse in December definitely hurt us.
Doug Leggate
My two follow ups are kind of related I guess. Firstly, on the 20% plus growth I’m wondering if you could just help us with the plus, and that’s for oil obviously, what the variables are?
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?
Timothy L. Dove
Obviously we’re focused on Wolfcamp B are averaging 75% to 78% oil. When you start focusing on 900,000 to a 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, ethane rejection has something 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.
Doug Leggate
I guess what I’m getting at is when you sure 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?
Frank Hopkins
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, and I think it’s fair to say going into the year we tend to be conservative and that will play into it as well.
Doug Leggate
My last one is just very quickly hopefully, the slowdown in spending can you help us a little bit with how that impacts the third tax calculation in terms of what percentage of current would be?
Richard P. Dealy
I think 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.
Operator
Your next question comes from Arun Jayaram – Credit Suisse.
Arun Jayaram
My first question is related to a comment by one of your peers Scott, and at Anadarko they mentioned they thought 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?
Scott Douglas Sheffield
The first answer to Anadarko’s statement is that you probably could get similar returns in a $90 environment if you got 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.
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 ’16, ’17, and ’18 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.
It all depends on what happens going into ’16, ’17, and ’18. In my opinion, the bigger picture is that the US has been growing a million barrels per day a year.
The world on the demand side, most people agree, will be adding 1.2 million barrels a day. The Saudi’s want to find a price, a long term price, that will keep US growth somewhere down between 300,000 and 500,000 barrels a day until demand significantly picks up and so long term I feel like we’re in a $60 to $80 price world instead of an $80 to $100 price world.
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.
Arun Jayaram
My follow up is really regarding the Midstream sale. I was wondering if you could talk about if the pull back in commodity prices have any impact do you think, on that sale?
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?
Scott Douglas Sheffield
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 tremendous interest in the package and so we don’t see that affecting this transaction.
If we are successful in announcing and in closing and can get up to $2 billion of cash for instance, then we may take a more aggressive stance and start up some rigs earlier than I said earlier, maybe earlier than July 1st. If you have $2 billion in cash and 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 1st.
Arun Jayaram
Just to clarify, you’re thinking $2 billion in proceeds potentially from this transaction which is quite a bit higher than I thought you mentioned before?
Scott Douglas Sheffield
We already have a billion in cash on the balance sheet and most expectations are around $1 billion for our share of the asset base. I think most analysis have around 10 times cash flow which is about $100 million per year cash flow net to Pioneer.
Operator
Your next question comes from Charles Meade – Johnson & Rice Company, LLC.
Charles Meade
I wonder if I could pick up on that same theme a bit and maybe approach it a little bit differently? You have the cash on your balance sheet because you prefunded a lot of this cap ex.
It was in a different world and it makes sense that circumstances have changed here, but you’re planning to spend roughly [indiscernible] for ’15, what are the circumstances as you look at ’16 that would lead you to want to go ahead and spend more than cash flow? Right now the strip for ’16 as I’m looking at it is about $60 for oil, would that be sufficient or is it really more on the services costs front?
Scott Douglas Sheffield
It’s a combination of all. We’ve got to get our cost down 20% plus, we’ve got to feel confident and have successful [indiscernible] 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.
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. We’re being cautious just to make sure that ’16 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 the US companies and to start declining by late ’15 in general.
Charles Meade
If I could pick up a bit on the cost reduction and efficiency side, you’ve talked about your 10% cost reductions 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, is you’ve also identified some efficiencies whether through well design or more effective frack placement, or selection of frack stages, that sort of thing, should we think about those two things as additive or perhaps multiplicative when we’re thinking about your productivity in terms of F&D or dollars spent per new barrel brought on and so should we be looking for really more than 20% when you add in the efficiencies too?
Timothy L. Dove
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’s actually the net effect of drilling essentially all B wells in the same exact areas with the same exact rigs. We’ve seen an example of that in Eagle Ford, of course, where we were drilling one or two zones and the efficiencies were dramatic.
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 just sort of the net cost of wells just getting cost reductions in place. It will incorporate 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 is more low hanging fruit.
Charles Meade
On that front it seems to me that going to existing pads with existing tank batteries and that sort of thing, sets you up or at least the logical question to ask, whether you’re going to be doing some down spacing tests in the B, in the Wolfcamp B? Is that part of your plans for 2015?
Timothy L. Dove
Yes. As you know, we’ve been doing some down spacing tests through time, we will be doing some of that again in 2015.
It’s a really important thing to get our arms around for the future so we’re not going to short trip that at all. We will be down spacing testing 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 the B3 in the south and 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 of the other wells in the area. All of this activity is part of essentially this whole optimization planning that we’re doing.
Operator
Your next question comes from Brian Singer – Goldman Sachs.
Brian Singer
I had two questions on the cost front, the first is actually a follow up to 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?
Timothy L. Dove
I think first of all, I mentioned this actually in my comments, 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 guar 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 and 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. 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. Notwithstanding all of that of course, we’re getting really significant improvement from the standpoint of reduced diesel costs.
There’s a pretty big utilization of diesel when it comes to fracture stimulating a well and we’ve seen diesel costs come down probably 45%. I think on all those fronts we would say we can be competitive with third parties and we’ll continue to do so.
Today we’re using only Pioneer green fleets.
Brian Singer
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 cap ex that you’re deferring and do you see the ultimate cost 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?
Timothy L. Dove
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.
Look at the sand mine for instance, when we need more sand – in fact, the expansion of the sand mine I don’t expect cost to come down to expand the sand mind they’ll probably be essentially the same if and when we pull the trigger to do that. I think that is 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 part of a large capital plan, in fact, early stages we were talking about $500 million in 2015, that got reduced to $300 million and 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 it sort of is what it is, 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.
Brian Singer
Just a follow up on that, the sand mine and the gas processing you said you ultimately don’t expect cost 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?
Timothy L. Dove
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 prices we have some direct competition with chemical plants and those are, as you know, going up like crazy in the light of today’s low energy costs in the United States so I don’t see any inflationary costs associated with building essentially plant facilities.
Operator
Your next question comes from Leo Mariani – RBC Capital Markets.
Leo Mariani
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 was some benefit of longer laterals. Could you maybe talk about some of the other things 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?
Timothy L. Dove
I think you’re right, as you mentioned – actually, it was on Slide 10 that we had in most cases 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, is 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 is just so much easier to get the wells drilled when you know what to expect from a down hole standpoint.
But looking forward, there are 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, [indiscernible], fluids, those are all being tested and we’re seeing marginal gains on all of that. You look at Eagle Ford as an example, we’re now five years into the Eagle Ford shall and we’ve seen dramatic reductions in drilling costs and completion costs just owing to the fact that we’ve been there so long and we’re now just in the process of starting to generation those types of improvements in the Permian Basin.
We’re a little ahead in the southern Wolfcamp area here we’re drilling wells generally speaking, in only a couple of zones. In the northern area we’ve been drilling wells across the basin, as I showed on the earlier map and 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 and we’ll have more to say as soon as we start to get some well results from this year’s campaign.
Leo Mariani
Is it safe to say that that’s not really in the guidance here in 2015?
Timothy L. Dove
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 operational or efficiencies associated with essentially what amounts to drilling in the same areas where we’re drilling with the same rigs, in the same zones, in the same area.
We are accounting for the situation I mentioned where we’re not drilling a lot of wells outside of existing infrastructure. We are factoring that in but not efficiency gains from drilling.
Leo Mariani
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 in the Eagle Ford and Midstream proceeds. It sounds like the rigs can come back rather quickly.
Obviously, guys are deferring some significant infrastructure expense here in 2015. [Indiscernible] that the rigs start coming back do you start accelerating some of the infrastructure spend as well?
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 midyear when can we start to see some of the inflection in terms of back in in production growth mode and are there going to be any impediments on the infrastructure side that prevent that?
Timothy L. Dove
I think the way to think about that is in general, as you know, we’re drilling two and three well pads, that will push out spud pop dates depending on where you are and what you’re drilling 130 to 150 days and so let’s just use the scenario we pull the trigger, have rigs raised as of let’s say July 1st. 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 five 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.
Operator
Your next question comes from David W. Kistler – Simmons & Company International.
David W. Kistler
Real quickly, when we think about the I guess, for lack of 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 ’16 and lower service costs? It would seem like that would be a prudent thing to do on a PV basis and would prevent the potential decline of production that you’re seeing in Q3 and Q4 for the company in aggregate?
Timothy L. Dove
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 [indiscernible] 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.
We’re going to see the cost reductions but they’ll just be generated through time. I mean, it’s 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.
That’s the objective, keeping our fleets busy for the time being.
David W. Kistler
Thinking to 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 think 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?
Richard P. Dealy
The bigger picture is that we have to – nobody knows what the price of oil is going to be in ’16, ’17, ’18, and ’19 and we have to wait and see what happens when things bottom out this year whether it’s $40 or whether it is $44 a few weeks ago, and we’re hedged so we’re not too concern about how low it will go. Personally, I’d rather it go lower and just recorrect itself and have the supply side turn down.
The world is still very, very tight, there’s only two 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 declining, this scenario is just not going to play out very long, it can’t and so we’re more optimistic that prices are going to come back in ’16. If for some reason, like you said, 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 to $60 world for the next several years that’s a whole different ballgame, it’s a whole different story and we’ve just got to plan it accordingly.
But right now we’re just not thinking that scenario is going to play out.
Operator
Your next question comes from Matthew Portillo – Tudor, Pickering, Holt & Co.
Matthew Portillo
Two quick questions for me. I guess around the midstream side of the business I wanted to see if you could provide some incremental context.
Under your current plans to potentially reaccelerate some of the drilling program with lower service costs in the back half of this year, how should we think about that growth midstream cap ex of $250 this year, how should that trend into 2016 from a spinning perspective?
Timothy L. Dove
If you take a look at one of the plants cost, they cost roughly probably $150 million $160 million something like that [indiscernible], 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 run our old growth plan we were putting a new plan 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.
Matthew Portillo
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 ’17 and beyond, how should we factor in or layer that into our thoughts around your 2016 expenditure program with a slight acceleration case on the rig count?
A - Timothy L. Dove
If we’re flat from where we are today for that scenario where 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. Our water projects, and for that matter you can look at this as associated with gas prices as well, they’re all optional.
They all provide optionality for us to deal with accelerated cases and so none of that really needs to be spent except to the extent wherein 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. That’s why it’s hard to answer your question definitively.
Matthew Portillo
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 kind of the $70 to $80 world, what sort of outspend would you be potentially targeting given kind of the balance sheet strength you have or how should we kind of think about the growth trajectory going into 2016?
Scott Douglas Sheffield
The big factor is how much – we have a billion of cash on the balance sheet, how much do we get on a successful EFS, that’ll determine – we don’t [indiscernible] spending when we have cash on the balance sheet and returns are good and 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 cap ex so we would increase our cap ex at that point in time.
Also, what’s not in there is we hope that we’ll move towards 20% closer by the end of the year. So we’re only assuming a 10% reduction, we think we’ll get closer to 15% into 20% before the end of the year and that’s also not built in.
Operator
Your next question comes from [Unidentified Analyst] – Capital One.
[Unidentified Analyst]
Slide Eight shows your quarterly production peaking in the second quarter as you worked 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 ’15 cap rate is held throughout the year and continues into ’16, would you expect your production to decline slightly in 2016 on a year-over-year basis?
Scott Douglas Sheffield
It’ll be basically flat going into ’16 if we don’t add any rigs at all or spend any of the capital that we have on the balance sheet. That scenario will occur if oil prices stay in the $50 range.
We do have strong hedges. If you go back into our hedge position, we’ve converted a lot of our $10 [indiscernible] hedges to $40 by $65 by $75 and so we feel very confident we’re going to get $65 plus oil on most of our oil going into ’16 which also helps.
[Unidentified Analyst]
Just as a follow up to the last statement there on the cap ex cost reductions, I think you said it does not assume 20% reductions towards the end of the year. If you did realize that how much lower do you think the $1.6 billion would actually be?
Scott Douglas Sheffield
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’s more likely to be at least 15% occur through the average of the year sliding towards 20% at the end of the year so you’d take off another 5%.
Operator
Your next question comes from Michael A. Hall – Heikkinen Energy Advisors.
Michael A. Hall
Kind of following on that last question, but looking at the shape of the 2015 activity, are all those completion carry overs from 2014 coming on or expected to come on in the first half of ’15 and then does that quarterly completion rate in the back half for the northern Permian program look about 17 or so wells per quarter? Is that enough to keep things flat in the northern Permian in ’16 if you kept that up or what level of quarterly completions is needed to keep that program flat?
Timothy L. Dove
I would just touch on it like this, if you look at approximate numbers as to what we’re expecting most of this is related to the carry over and just the way the pop 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 and second quarter because of the carry overs and just the drilling campaign ending in the end of ’14, there were probably 80 or so pops each of the first two quarters.
Then that falls off as that inventory is cleaned up and you get more to 50 and 60 in the last two quarters and so that’s really why the curve looks like they do. Of course, that would change to the extent we ramp up drilling and particularly it would affect the fourth quarter.
Michael A. Hall
Then on the vertical program, what would you put the PDP decline at maybe fourth quarter ’15 fourth quarter ’14 as you lay that down? I’m just curious what that looks like?
Timothy L. Dove
Vertical drilling? You mean production from vertical wells?
Michael A. Hall
Yes, the overall vertical production wedge, what’s that PDP decline look like?
Timothy L. Dove
It’s no more than 10% because 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 and 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 has provided here in the bottom part of the curve being darker vertical wells and you sort of have to interpolate but it looks like probably a total of 10% decline year-on-year.
Michael A. Hall
How much carry are you expecting to utilize in the southern JV in 2015 and then what does that look like?
Richard P. Dealy
There’s $575 million left and we’ll use probably about 75% of it in ’15.
Michael A. Hall
You used 75% of the $575 million?
Richard P. Dealy
Correct.
Operator
Your next question comes from Jeffrey Campbell – Tuohy Brothers Investment Research.
Jeffrey Campbell
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?
Timothy L. Dove
We have taken quite an extensive effort to work with a 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 low so they’ve been very cooperative. In many cases these deferrals have been done costless to Pioneer because of our long standing relationships with the owners and at some points in time they’ve cost 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.
We will have minimal land implications of the current slowdown.
Jeffrey Campbell
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?
Timothy L. Dove
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 commodity price environment where we’re drilling more wells we will need a certain amount of drilling for continuous drilling obligations and it may be there’s a handful of vertical 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.
Jeffrey Campbell
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 somebody with results with this technology and it seemed to be aligned with the relative reservoir pressures where it was being implemented.
Timothy L. Dove
We’ve actually be doing this for some time. It takes several different forms including dissolvable plug seats and so on, but we’ve mostly used large bore plugs in the Permian and the Eagle Ford and the only issue 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 plugs.
It can take five days of operation and so it’s 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.
Operator
Your next question comes from Philip Genworth – BMO Capital Markets.
Philip Genworth
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 view 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 [indiscernible] full project rates of return also be pretty similar between the two areas?
Timothy L. Dove
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, they’re at about 9,000 feet.
One thing we are doing, as Frank mentioned and I think we mentioned on our slides, we’re using a relatively conservative EUR average in the north and the south we had more well control in the south, we’re probably more on the number in terms of what the south can do. 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 early in its life.
Philip Genworth
With longer production history in some of the down spacing 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 have compared to initial expectations and how this has shaped your view of full field development in this area?
Timothy L. Dove
That’s certainly one area. We had one particular test in the Giddings area where we tested quite a large number of down space 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 you’re 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’re drilling As and Bs, to go ahead and complete all 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 cleaning 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, in our program this year and we’ll also be testing some spacing less than that.
Philip Genworth
Last question, how should we think about any Eagle Ford Midstream sale just in terms of the impact to the reported cost structure? It sounds like $100 million of EBITDA is still good to estimate even though it’s reduced activities.
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?
Richard P. Dealy
It is reflected in the LOE guidance. It’ll be in future quarters and there would be an increase in LOE and I don’t have the exact number here, but for Eagle Ford it’s $1 or $2 of boe.
Frank Hopkins
The last estimate was around $0.50 for the entire company.
Operator
Your next question comes from Ryan Oatman – SunTrust Robinson Humphrey.
Ryan Oatman
You work with partners in the Eagle Ford in 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?
Scott Douglas Sheffield
There hasn’t been a joint venture in almost two years in the US. 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 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 – the best way to do it so we’re not even thinking about another joint venture at this point in time.
Ryan Oatman
Does it sound like there would be a potential for asset sales as a way to bring value forward or obviously, would you just prefer the organic capital route?
Scott Douglas Sheffield
We’ll have to look at all the options. I mean right now we have a billion in cash on the balance sheet, we hope to get another billion so that’s something that’s way down the road.
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’ve 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.
Operator
Your next question comes from Harry Mateer – Barclays Capital.
Harry Mateer
The first question, it sounds like you’re saying the drilling cap ex you’re targeting this year is essentially maintenance cap ex given that production would be roughly flat if you keep spending at that level. Is that the right way to think about it as being maintenance cap ex?
Scott Douglas Sheffield
It’s not focused on maintenance cap ex. 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’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.
Harry Mateer
But the 4Q to 4Q production looks roughly flat, is that right?
Scott Douglas Sheffield
Yes. That wasn’t the overall reason we came out with this budget is where I’m going.
Harry Mateer
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 cap ex budget gets you roughly flat production 4Q over 4Q and 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 derisk the balance sheet even further by [indiscernible] liquidity and just pay that down instead of assuming you might refinance it?
Scott Douglas Sheffield
Well no, I think we could still issue 10 year money in the low 4% range so the ’16, ’17, ’18 maturities that are coming up we’ll be looking at going to the markets at the right point in time. We’re not going to use our billion to buy that back in, it’s not cost effective.
Harry Mateer
Then just the last one, on the potential EFS sales, your current thinking is you’d look to provide minimum volume commitments for a period of time after that sale?
Scott Douglas Sheffield
That all depends on negotiations with the buyer.
Operator
There are no further questions at this time. I’d like to turn it back to our speakers for any additional or closing remarks.
A - Scott Douglas Sheffield
Again, thank you everybody for participating, great questions. Hopefully we’ll see a little bit higher oil price next time we see everybody the next three months.
Thank you all.
Operator
This concludes today’s conference. Thank you for your participation.