Nov 5, 2015
Executives
Michael G. Edwards - Senior Director-Investor Relations Barton R.
Brookman - President & Chief Executive Officer Gysle R. Shellum - Chief Financial Officer Scott J.
Reasoner - Senior Vice President-Operations Lance A. Lauck - Executive Vice President Corporate Development and Strategy
Analysts
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Jason Smith - Bank of America Merrill Lynch Leo Mariani - RBC Capital Markets LLC Ipsit Mohanty - GMP Securities LLC Irene Oiyin Haas - Wunderlich Securities, Inc. Brian Corales - Howard Weil Michael A.
Hall - Heikkinen Energy Advisors Pavan P. Hoskote - Goldman Sachs & Co.
Mike Kelly - Seaport Global Securities LLC Welles W. Fitzpatrick - Johnson Rice & Co.
LLC David R. Tameron - Wells Fargo Securities LLC Jeffrey Richard Connolly - Clarkson Capital Markets LLC David Earl Beard - Coker & Palmer, Inc.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Operator
Greetings, and welcome to the PDC Energy 2015 Third Quarter Conference Call. At this time, all participants are in a listen-only mode.
A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host for today's call. Mr.
Michael Edwards, Senior Director-Investor Relations. Mr.
Edwards, please go ahead.
Michael G. Edwards - Senior Director-Investor Relations
Good morning, everyone, and welcome. On the call this morning, we have Bart Brookman, President and CEO; Gysle Shellum, CFO; Lance Lauck, Executive Vice President; and Scott Reasoner, Senior Vice President-Operations.
We've posted a slide presentation that accompanies our remarks today on the Investor Relations page of our website, which is pdce.com. I'd like to call your attention to the forward-looking statements on slide two of that presentation.
We will present some non-GAAP financial numbers on the call today, so I'd also like to call your attention to the appendix slides and the reconciliation of non-GAAP financial measures. We also filed our 10-Q this morning with the SEC.
With that, we can get started. I'd like to turn the call over to Bart Brookman, our CEO.
Bart?
Barton R. Brookman - President & Chief Executive Officer
Thank you, Mike, and good morning, everyone. First, I'd like to thank our operating teams for delivering some of the most impressive operating results I have seen in my 30 years in the industry.
For the quarter, the company achieved record production volumes. We continued to improve on our drilling efficiencies, our per well costs in the Wattenberg, as Scott will cover in a moment, improved an additional 5% from last quarter and our operating costs are dramatically improved and our technical innovations, particularly in the Wattenberg Field continued to deliver value.
Most importantly, we achieved all of these operational improvements, while honoring the balance sheet. We strengthened the balance sheet in the third quarter and will continue to do so in the fourth quarter.
Now, let me cover some of the highlights for the quarter. Production increased to 47,000 barrels of oil equivalent per day.
That is a 27% increase from the second quarter of 2015 and an 84% increase from the third quarter of 2014. Scott will give a lot more detail on production performance in a moment.
Nearly, 47% of the production for the company was oil. We expect continued growth in our production, as we finish up the fourth quarter, and we now expect total 2015 production to meet or slightly exceed the top end of our guidance range of 15 million barrels of oil equivalent.
The drilling times for the company improved from last quarter by approximately 10%. The plug-n-perf completions in the Wattenberg are quickly becoming the standard completion practice.
And our operating teams continue to test a variety of completion methods, which are enhancing our current production and will be key in our 2016 plan. Let me hit some financial highlights.
Adjusted cash flow for the quarter was $123 million. The company is on target for a capital spend of approximately $535 million as reflected in our 2015 guidance.
The company maintains nearly $650 million in liquidity, giving us tremendous financial and operational flexibility, and our debt-to-cap at quarter-end was 34%. Again, we expect continued strengthening of the balance sheet in the fourth quarter and will exit 2015 with a debt-to-EBITDAX ratio of approximately 1.5 times.
Overall, we're extremely pleased with the cost structure of the company. We continue to work on G&A and operating costs and are seeing ongoing improvement in productivity as reflected in our 37% year-over-year decrease in our lifting costs to $2.87 per barrel of oil equivalent.
In closing, let me give a little flavor on where the company is going in the fourth quarter and in 2016. You can expect peer-leading production growth.
Our drilling will be focused primarily in the inner and middle core portions of the Wattenberg Field. We anticipate continued improvement in our drill times.
Right now, we plan on running four rigs in the Wattenberg with ongoing focus on completion technology to improve our production base. We anticipate DCP, our primary mid-stream provider in the Wattenberg will have ample gathering and processing capacity through 2016.
From a financial perspective, we will continue to honor the balance sheet. We foresee the fourth quarter and 2016 to be cash flow neutral or slightly cash flow positive.
Lastly, the company will maintain ample liquidity to execute our business plan and operational flexibility to speed up or slow down based on market conditions. With that, I will turn the call over to Gysle for a financial overview.
Gysle R. Shellum - Chief Financial Officer
Thanks, Bart. Good morning, everyone.
As always, my comments will be high level, so for a more complete analysis of our third quarter, please see our 10-Q and press release that was filed earlier this morning. As you've heard, our first nine months of 2015 had a lot of activity in the Wattenberg, as well as steady production from our Utica operations.
Production for the third quarter was 4.3 million barrels of oil equivalent and that was above our expectations. Our third quarter reflects continued success of the Wattenberg program, which again had record production as well as the Utica wells performing in line with our expectations.
Despite much lower commodity prices, we still had substantial growth year-over-year and adjusted cash flow from operations and adjusted EBITDA aided by our large hedge position with $68 million in realized hedge gains in the quarter. You can find the reconciliation to adjusted EBITDA in the appendix to this press release.
That's the high level. Now, let's look at some of the metrics for the third quarter on slide six.
Again, this quarter, year-over-year production increased over 84%, while our third quarter oil and gas sales were down 13%, compared to third quarter 2014. Oil, natural gas and NGL prices all declined year-over-year and quarter-over-quarter.
Crude oil prices for the third quarter 2015 averaged $38.98, down 54% from the third quarter 2014. Average natural gas prices were down 41% from the third quarter 2014 and natural gas liquids were down 65%.
When we factor in our realized hedges, however, total sales plus realized hedges were up approximately 49% over the same period last year. The net realized hedge gain of $68 million in this quarter, compares to a net realized loss of $4.5 million in the third quarter of 2014, and a net gain of $44.1 million in the second quarter of 2015.
Production costs on a per unit measure were down about 39% year-over-year. For the third quarter 2015, we averaged $5.89 per BOE, down from $9.67 per BOE compared to the same quarter last year.
Production costs include lease operating expense, production taxes, overhead and some transportation and processing costs. Transportation costs almost doubled compared to the third quarter 2014 due to initial sales on the White Cliffs pipeline.
Transportation costs on the pipeline are paid by PDC and the resulting accounting reclassifies the costs previously reduced – previously that reduced the sale price per barrel to transportation costs. The result is higher sales price per barrel offset by transportation costs with no net impact to margins.
You can expect to see the transportation line item to continue to increase as we shift more sales to White Cliffs, and beginning in the fourth quarter of 2015 for the Saddle Butte pipeline. Gross margins were 76% of sales for the third quarter of 2015, down only slightly from 81% in the third quarter of 2014, reflecting the decrease in commodity prices nearly offset by a strong decrease in total production costs.
DD&A includes depreciation of fixed assets and depletion of oil and gas properties. Per barrel DD&A in the third quarter 2015 decreased 11% compared to the last quarter – compared to last quarter of – compared to the third quarter of 2014, down to $18.71.
The decrease is due primarily to last year's fourth quarter impairment in our Utica assets. Per unit depletion rates on just oil and gas properties for the third quarter was $18.44 per barrel equivalent compared to $20.70 per barrel equivalent in the third quarter of 2014.
We expect these rates will continue to decrease with lower drilling and completion costs. G&A decreased in the third quarter of 2015 compared to the third quarter of 2014 largely due to a $16.2 million litigation charge in the quarter last year.
G&A, excluding the litigation charge, decreased 45% on a per unit basis to $4.28 per barrel oil equivalent in the third quarter from $7.83 per barrel oil equivalent in the third quarter of 2014. Net loss for the quarter and for the nine months ended September 30 include a pre-tax impairment of $150 million related to Utica assets.
The after-tax impact of the impairment is $91 million. Moving to slide seven, we show our non-GAAP metrics.
Our adjusted net loss of $75.9 million in the third quarter compares to a $5.7 million loss in the same quarter in 2014. More about that in a minute.
Adjusted cash flow from operations is defined as cash flow from operations, excluding changes in working capital. Adjusted cash flow for the third quarter was $122.7 million, or $3.06 per diluted share, compared to $55 million, or $1.51 per diluted share for the third quarter 2014.
Adjusted EBITDA in the current quarter of $128.6 million was up significantly compared to the third quarter 2014 where it was $62.6 million. Adjusted EBITDA per diluted share of $3.21 was also up significantly year-over-year from $1.70 in the third quarter 2014.
At the bottom of the slide, we presented adjusted net income excluded – excluding the impairment on the Utica assets. When we adjust for the $150 million impairment in the quarter, we would have had net income of $15.4 million for the quarter and $33.6 million for the nine months ended September 31, 2015.
The table in slide eight reflects PDC borrowings. Our borrowing base was reaffirmed in September at $700 million and we kept our commitment level at $450 million.
With the redetermination, we also extended our credit facility for two years to maturing in March of 2020. We were slightly cash flow positive in the third quarter and expect the same in the fourth quarter.
We expect to exit the year drawn less than $50 million. Our trailing 12 month debt-to-EBITDAX as of September 30 was approximately 1.6 times and as Bart mentioned, we expect to end the year closer to 1.5 times.
With the $700 million borrowing base, net of $12 million letter of credit and a small cash balance, we have $642 million of liquidity as of the end of the quarter. Our $115 million convertible bond matures in May of 2016.
Our decision isn't official for another ten days, however, in our outlook, we've modeled retiring the face amount in cash and using common stock for anything above the $42.40 conversion price. Turning to slide nine, our hedge positions for the balance of 2015 and for 2016 and 2017 are shown on here.
As of September 30, our net hedges are valued at $278 million. For the fourth quarter, we have about 69% of our expected crude oil volumes hedged at a weighted average hedge price of $88.99.
On gas, we have about 70% of our expected volumes protected at a weighted average floor of about $3.74 per MMBtu. For 2016, we have 4.1 million barrels hedged and weighted average floors of $84.99 per barrel.
For natural gas, we have 29.8 billion cubic feet hedged at a weighted average price of $3.67 per MMBtu. We have some good hedge volumes for natural gas for 2017 and have about 1.4 million barrels of oil hedged in 2017.
Now, I'll turn this call over to Scott for an update on operations.
Scott J. Reasoner - Senior Vice President-Operations
Thank you, Gysle, and good morning, everyone. As both Bart and Gysle mentioned, we're very pleased with the third quarter.
Production totaled 47,000 barrels of oil equivalent per day, an 84% increase from the third quarter of 2014 and a 27% increase sequentially. We did a great job of not only meeting, but exceeding our internal targets and now expect to finish the year at the top end or slightly above our full-year guidance of 15 million barrels of oil equivalent.
Towards this end, I want to thank our EHS, land, and operations teams for continued focus on doing more for less and all their hard work in general. You can see here graphically on slide 12 just how strong our third quarter was.
Also note that oil accounted for nearly 40% -- 47% of our third quarter production and we were 65% liquid. There are several factors that were critical in the large jump in production we saw over last quarter.
We averaged nine days to spud-to-spud in the quarter, which is an improvement from the second quarter and is representative of the accelerated turned-in-line schedule we've experienced throughout the year. Line pressures in the Wattenberg have been substantially reduced, thanks to Lucerne 2, and our legacy vertical wells, as well as some of our older horizontal wells have really benefited greatly.
And lastly, we continue to gain confidence in our new completion technologies and are reaping the benefits of enhanced early production volumes. Moving on to our drilling and completion activity on slide 13, you can see we spud 53 wells and turned-in-line 33 wells in the third quarter.
We expect the fourth quarter turned-in-line number to be in the same range as the third quarter. As I mentioned earlier, our average spud-to-spud was down to nine days, a 10% improvement from the second quarter, and we do continue to see downward pressure on that number.
Also of note, as we discussed on the call last quarter, we plan to drop our fifth drilling rig in the next week or so and will operate four rigs in the Wattenberg and expect to spud between 40 and 50 wells in the fourth quarter. CapEx for the quarter came in just shy of $105 million, and we fully expect to fall within our previously guided range of $520 million to $550 million when all is said and done.
Our average well cost for a standard length lateral was $2.9 million during the quarter, and we saw costs move down on extended reach laterals to $3.9 million. As proud as we are of the production growth experienced this quarter, the fact that we were able to do so in such an efficient manner from a capital standpoint is what's really exciting.
Moving to slide 15, our lease operating expense for the quarter is also trending in the right direction, coming in below $3, at $2.87 per Boe. We expect this trend to continue and full year LOE to fall in comfortably within our guided range on the right hand side of the graph.
As Gysle mentioned, we have been able to nearly maintain our pre-hedged margins from last year, thanks to our production costs per Boe following similar trends seen here. On slide 16, you can see a snapshot of our drilling activity in the Wattenberg Field.
All of these projects, aside from the Becker Ranch downspacing project, are currently online. As a reminder, the Becker Ranch project is testing 22 well-equivalent spacing and is currently being turned to sales, with the expectation of all wells being online by the end of November.
Also of note, the Rieder project contains three wells with both AccessFrac and plug-and-perf completions. We won't know any definitive results for some time, but we'll update the market as we know more.
A little closer look at our results from the Chesnut downspacing test on slide 17. As a reminder, all 10 of these wells are extended reach laterals drilled on 20 well per section equivalent spacing.
Only one of these 10 wells contains plug-and-perf. The graph shown here is indicative of the results we're seeing from both our downspacing and extended reach lateral wells.
As you can see quite clearly on the graph, the wells are tracking either on or above our 600,000 barrel EUR type curve through nearly 150 days. We are encouraged by these early results and will continue to monitor and provide updates accordingly.
As far as plug-and-perf, we continue to see a sizable uplift in these wells. We will provide more details and specifics when we release our 2016 budget, but we have gained the confidence needed to include this completion design on the majority of our drilling program.
To date, we have performed 31 plug-and-perf completions and expect to have 10 additional plug-and-perf wells turned-in-line in the fourth quarter. Moving to midstream on slide 19, as we've mentioned several times, the alleviation of high line pressures throughout the field really provided a benefit to our legacy wells throughout the quarter.
As expected, the field-wide system currently has excess capacity that we expect to remain through 2016. In addition to the work that DCP has done with its Lucerne 2 plant, we've also benefited greatly from the Aka system, as the majority of our extended reach lateral wells flow through their facilities, which we've added to the map for context.
In the Utica, the coal and dynamite pads continue to show strong performance. These wells have increased our confidence in the play and we are excited to get back to work.
Lastly, without getting into much detail, I want to reiterate a couple of key takeaways related to our full year guidance. We anticipate production to meet or slightly exceed the top end of our guidance range; LOE is anticipated to come in at the low-end of our guidance range; and capital expenditures should also fall within our guidance range.
With that, I'll turn the call back over to the moderator for the Q&A.
Operator
Thank you. Our first question comes from Neal Dingmann of SunTrust.
Your line is open.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Good morning, guys. Bart, I know it's still relatively early as far as in that second tier that you guys have been drilling in, but just wondering again, when you look at EUR estimates that are out there on that, how that will differ or, number one, are you still comfortable or are things trending above that is my first question?
Barton R. Brookman - President & Chief Executive Officer
Neal, can you provide some clarity on second tier?
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Well, you guys call them – let's call it the middle core?
Barton R. Brookman - President & Chief Executive Officer
Middle core, okay.
Scott J. Reasoner - Senior Vice President-Operations
Yes. I think, Neal, the way we're looking at that right now, and obviously, the uplift that we're seeing from the plug-and-perf particularly is not in our type curve, so that's the number one point.
We're looking at that very carefully as we speak, going into next year's budget, to see what that looks like, and our plug-and-perf estimate on that first batch of wells, which was that – we showed the maxi (22:27), I believe, at the last quarter – we actually have seen that number come down a little bit. We're not seeing in the 30% to 35% range, but more near 20% is probably a better number, maybe 15% to 25%, something in that range, would be a good estimate.
How that affects our type curves, we have yet to determine, but we are looking at that as we speak to make those final determinations for our budget for 2016. And as far as the impact overall, obviously, that would definitely benefit the year and make a difference in the productivity.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Okay. You mentioned the plug-and-perf; that was where I was going with my second question.
What about any of the uplift you're seeing with the AccessFrac to BioVert? Are you -- again, nothing of that is – number one, what kind of uplift, or are you continuing to see more uplift with that versus the plug-and-perf, and is that too not included yet?
Scott J. Reasoner - Senior Vice President-Operations
You're absolutely right. It is not included.
The AccessFrac is not included in any of our type curves, so it's something that we're still working through the estimates for that for our budget for next year. But in terms of what we're seeing, we continue to see that 5% to 10% uplift in productivity.
And it's something that we've – as I indicated, we've done it on the Rieder pad, in addition to the plug-and-perf, and we're waiting to see the results of that, something that obviously would be tremendously beneficial if it works. And don't really have enough data to even make a good comment on that at this point, but both could impact, obviously, what we're seeing in 2016 from a budget and hopefully from an outcome perspective.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Okay. And then just one last one, if I could.
Looking at that slide, you show the 2015 downspacing projects. Again, my question is when you get a little bit north of the Chesnut and look at some of that, will those continue?
How do you look at downspacing on that? I know on the Chesnut, you were mentioning here, the 480-acre unit versus the 320-acre on the Becker Ranch and 320-acre on the Rieder.
So just my thoughts, is it everything to the north of Chesnut is going to have that same spacing or how do you think about that in general?
Scott J. Reasoner - Senior Vice President-Operations
We're still not completely sure on the answer to that question and that's part of what we continue to gain information from as we look at these tests that we're doing. I would say, as we move out of the middle core into the outer core – my early thoughts, and we obviously don't have any tests to this effect yet.
But my early thoughts are that we'll actually see the wells perform very well because there are fewer wells in the area. So really that's the one comment I have.
But again, that's something that we really need to test as we move forward.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
All right. Thanks, guys.
Another nice quarter.
Operator
Thank you. Our next question comes from Jason Smith of Bank of America.
Your line is open.
Jason Smith - Bank of America Merrill Lynch
Hey, good morning, everyone, and congrats.
Barton R. Brookman - President & Chief Executive Officer
Thanks, Jason.
Jason Smith - Bank of America Merrill Lynch
So, Scott, just picking up on something you just said. Last quarter, in your guidance you guys only had three Utica spuds set between now and 2017.
You just mentioned you're excited to get back to work there. So can you maybe provide some color around that comment and I'm just curious if your plans have changed at all?
Scott J. Reasoner - Senior Vice President-Operations
Our plans really haven't changed. We're still in the process of determining what we're going to do in 2016 and reaching out even beyond there.
Part of what we've said all along is that pad to the south in between really the Garvin and the Palmer wells we're – I can give you a name, it's called the Mason pad. We're actually looking at that pad to help us understand the value in that southern acreage, as the testing we've done thus far has been really in the northern acreage.
So that's the thought process we've been through to this point. But again, we're still looking at the budget for 2016 to determine exactly what that's going to look like.
Jason Smith - Bank of America Merrill Lynch
Got it. Okay, thanks.
Maybe one for Bart, just a higher level question just around M&A and what you guys are seeing around bid-ask spreads and maybe just curious on your buying interest both within the DJ Basin, obviously you guys passed on the Encana package, but interest within the basin, what you're seeing, and then any interest potentially outside of the basin?
Barton R. Brookman - President & Chief Executive Officer
Yeah. Let me start and I'll flip this over to Lance for some more color.
But we're definitely seeing some activity on asset deals pick up. Lance and his team are active in that.
We're being very finicky on our assessment and evaluation of the deals right now. I think we've been in the market saying we will give consideration to adding some assets to the company.
We've got the balance sheet to do that, but we will be very, very selective in that evaluation and decision-making. So we're starting to see things pick up.
I don't know if I can say right now we're seeing the bid-ask narrow that much. There just hasn't been that many deals that have transacted to really define that.
But that's going to happen, as we go into next year, I can assure you, because our forecast and I think everybody in the market right now feel like this oil price environment and definitely this natural gas environment is probably here to stay through the end of next year. So that's kind of the high level.
Lance, do you want to add anything?
Lance A. Lauck - Executive Vice President Corporate Development and Strategy
Yeah. The only thing, Jason, I'll add to that is that clearly the company is in a tremendous position with regard to our inventory in the core Wattenberg Field and a field that delivers tremendous rates of return, that's very consistent, and the teams continue to utilize technology to even enhance those production technologies and the production from the wells.
So, as we look at the world, we are in a great position with regard to – do we need to go out and pursue acquisitions? That said, when we see opportunities that come through, for example, the core Wattenberg Field, we typically always look at those and assess how they fit within our overall portfolio and overall drilling plans.
And so we always take a look at that. In addition to that, we are pursuing a basin study in several basins here in the U.S.
onshore, looking for those basins that can deliver that same type of return from our Wattenberg Field. And so that includes a lot of technical work.
It's a ground level up. So it includes a lot of reservoir, geologic, commercial work and they're really getting our arms around the aspects of that and what that could mean to the company going forward.
So we technically are going to pursue those opportunities that make sense to us. But at the end of the day, we've got a pretty high threshold to overcome when you look at the returns in our Wattenberg Field.
Jason Smith - Bank of America Merrill Lynch
Thanks, guys. I really appreciate the detailed response.
I'll let someone else jump on.
Operator
Thank you. Our next question comes from Leo Mariani of RBC.
Your line is open.
Leo Mariani - RBC Capital Markets LLC
Hey, guys. Obviously very strong production here in the quarter.
I was hoping to see if you guys could quantify how much of that was driven by the impact of Lucerne 2 and better midstream infrastructure this quarter?
Scott J. Reasoner - Senior Vice President-Operations
Hey, Leo, we are absolutely pleased with what we've seen out there. And actually this has exceeded our expectations fairly dramatically.
When you look at the quarter, we really looked at something near 200,000 barrels of oil equivalent above our expectations. And that's a credit to the line pressure out there, the guys getting the wells back online, and a whole bunch of different factors.
But in addition, DCP's line pressure was extremely high right in those last two months of the second quarter. So that jump-up was somewhat anticipated.
But it sure helped us through the quarter, and we expect that to continue through the end of the year and into next year. So we like what we see and continue to benefit from it.
Leo Mariani - RBC Capital Markets LLC
Okay. What I'm trying to get at is, is there an impact here where you think that the midstream drove the 200,000-barrel increase above your guide or is it more just really strong well performance?
Trying to differentiate between the two here, if you guys could?
Scott J. Reasoner - Senior Vice President-Operations
It's really a balance of the three factors, I think that I would point to that really are – it's a combination of the three. It's the lower line pressure, it's the technology that's driving the completions and the uplift of the plug-and-perf and AccessFrac, and the third piece, really being the pace at which we're drilling and the acceleration of the work that's happening out there.
So when I say evenly distributed, maybe something in that range, but each one of them contributed significantly.
Leo Mariani - RBC Capital Markets LLC
Okay. That's helpful.
And I guess in terms of the rig activity, obviously you guys are dropping a Wattenberg rig next week. In terms of run rate activity, you talked about, 40 wells to 50 wells in the fourth quarter.
The fourth quarter is benefiting from a period where that fifth rig is running. Should we assume as you roll into next year that 40 wells per quarter drilled is a run rate for now?
Scott J. Reasoner - Senior Vice President-Operations
We're probably looking at a number that's there or slightly higher or maybe 150 to – I'm sorry, 130 wells to 150 wells would be a good range for the entire year, next year.
Leo Mariani - RBC Capital Markets LLC
Okay. That's helpful.
And any material non-operated activity that's been happening or is expected to happen or has a lot of that dropped off?
Scott J. Reasoner - Senior Vice President-Operations
The non-operated activity actually picked up just a little bit in the second half of the year. And we are looking at that saying a lot of that's because of where the different companies are drilling.
And we are expecting – I would say we're expecting that to continue through the second year, or all of next year. But it's something that's up and down with some predictability, but it's still difficult to figure all that out because we really don't know the budgets of many of our peer companies out there yet, or I haven't seen all the drilling schedules yet.
Leo Mariani - RBC Capital Markets LLC
All right.
Barton R. Brookman - President & Chief Executive Officer
I want to add to that Leo, we're not anticipating next year that we will have the non-consent. Most of our partners, I think, have given us at least signaled that they're going to be participating in our drilling projects.
Leo Mariani - RBC Capital Markets LLC
All right. That's really helpful color.
Thank you.
Operator
Thank you. Our next question comes from Ipsit Mohanty of GMP.
Your line is open.
Ipsit Mohanty - GMP Securities LLC
Yeah. Good morning, folks.
Barton R. Brookman - President & Chief Executive Officer
Hi, Ipsit.
Ipsit Mohanty - GMP Securities LLC
Hi, Bart. How are you?
You've mentioned before – you called the core Wattenberg as a blanket play, so I'm curious that are all improvements in your EUR and type curves going to come from the D&C technique now? Is there any surprise to be expected from the geology at all?
Scott J. Reasoner - Senior Vice President-Operations
Ipsit, I don't think we're going to see a lot of variability over what we are expecting at this point. And when you start talking about the technologies, we've been doing them primarily in the middle core, but I don't see a lot of downside when we move to the outer core, to that type of – to the type of technology we're using.
Really what we're doing is contacting more rock with the fracs that we're doing. And in fact, when you move that technology, you could speculate around it actually being more effective when you're trying to move the liquid through the rocks.
The more connect – more rock that you've contacted because you're moving more oil through that rock should make it more beneficial. That's yet to be determined.
We haven't run those tests yet, but it's something that – if you're asking me my opinion on that, I would think it would look like something we could repeat out into the outer core, and obviously the middle core is pretty well tested.
Ipsit Mohanty - GMP Securities LLC
Okay. And then this is jumping the gun a little bit, but when you think about your results in the Chesnut section, 20 well-equivalent, and then you now go and test out the 22 well-equivalent and 26 well-equivalent.
Just interested in your strategy. Let's say that at some point, you hit interference, would you favor advancing the MPV (35:17) by drilling more despite the interference or would you just stop and maximize your EURs?
Just your thoughts on that?
Scott J. Reasoner - Senior Vice President-Operations
That's an interesting question that we're still trying to balance in our minds as we speak to that. We're obviously very much rate-of-return-driven, present value-driven, and so the reserves are important, but truly the making money on these projects is what we're here to do.
So it would be pointed that direction, but there would be a lot of assessment going on, on what does that mean in terms of both sets of numbers, I would say. We haven't seen that yet, the impact of one well on another from a productivity perspective, and showing you some of that data as we move along here.
But when we do, we'll have to have that discussion and, like I said, it will point us more toward making money than it would toward recovering reserves and how that balances out is yet to be determined.
Barton R. Brookman - President & Chief Executive Officer
Ipsit, I can add this. Philosophically, I don't think we want to pursue, I'll call it, an over-drilling plan because, obviously, landowner impacts, the number of wellheads, the capital required.
So finding that point of diminishing returns is a first goal. And then when we find that, we will define the number of wells per section and the market will be very clear on that and we will communicate effectively on that.
And then our teams will continue to try to enhance the recovery factors through all the other means; AccessFrac, stage lengths, frac designs, the other things that we're working on. So I think we'll be more conservative to not over-drill, is my point just because it's the most capital intensive way to grab reserves and there are impacts as far as the number of – the amount of surface use right now in Colorado.
Ipsit Mohanty - GMP Securities LLC
Okay. And then one last one, really more on the near-term.
When I look at the middle core, is it safe to assume that predominantly it will be all extended laterals in 2016 and, also, the working interests across the three core if you remind?
Scott J. Reasoner - Senior Vice President-Operations
If you look at it from our perspective at this point, we're moving more and more toward longer laterals. We'll probably drill some 2-milers in 2016 and so the balance between those three is yet to be determined, but we're definitely moving toward longer laterals as a greater portion of our project list.
When you look at the distribution of those, there will be a few in the inner core and a few in the outer core and the bulk – the remainder will really be in the middle core, so we're really focusing our efforts on the middle core.
Ipsit Mohanty - GMP Securities LLC
Okay. Okay.
All right. Great.
Thank you, guys. Great quarter.
Operator
Thank you. Our next question comes from Irene Haas of Wunderlich.
Your line is open.
Irene Oiyin Haas - Wunderlich Securities, Inc.
Yes. I have a question on basically plug-and-perf.
Right now, based on standard lateral, it looks good, and I'm interested in finding out what is the delta, how much more it costs and how much time it takes, and how do you think it will work with your longer laterals? And then ultimately, you guys are doing a whole lot of stuff in the Wattenberg Field, drilling more wells with less rigs and such.
Should we expect a pretty nice inventory update, end of the year or maybe by endless time if you choose to throw one of those meetings let's see, next year?
Scott J. Reasoner - Senior Vice President-Operations
Irene, I hope I hit all these – the questions you asked there, so if I don't, please remind me after I finish up, but as far as plug-and-perf is concerned, we are looking at that, as I mentioned, a 15% to 25% uplift in our standard length laterals. We don't have as good a measurement yet in terms of our extended laterals, so our expectations are, I would say, are tempered a little bit there yet.
But that's probably something that you would expect from us. We hope that it's similar numbers, but you have to look at those wells and say some of that work on the extended reach laterals, when we look at our peer companies out there, many of the wells they were doing were already with plug-and-perf, so our data set is somewhat skewed when we start looking at type curves, that kind of thing, toward maybe more plug-and-perfs in that data set.
Hopefully that's clear on what I'm saying there. So I'm not sure that we would expect the same uplift here yet, and we'll see what that looks like over time.
We are doing that work in extended reach laterals, and in fact, it's more effective than trying to run casing in, in our mind, with all of the sliding sleeve equipment on the outside, is some of the reason that, that makes more sense. So as we get to longer laterals, you'll see plug-and-perf be more of the standard and across the board more of the standard based on what we're seeing in terms of the uplift.
It really comes down to we think that the uplift, along with the operations, and the guys in the field are doing a tremendous job making this all work because it is more complex, as you pointed out, but we see that all as beneficial. In terms of the additional cost, you're talking between $100,000 and $200,000, depending on whether it's a standard lateral or the 2-mile type lateral.
And when you go to how much additional time it takes, because of the way they're cycling through these wells, we don't complete an entire well – and I think pretty much everybody understands that – but we complete a series of wells, so you frac one well, frac another well in stages, and then while you're fracking the next well in line, you're putting the plug in and perforating behind it. So it's a fairly efficient operation.
May take a little more time in a pad, but it's not significant.
Barton R. Brookman - President & Chief Executive Officer
Irene, on the last question that you had with regard to the inventory, as you probably know, our 2P inventory and the basis of our well count in the Wattenberg Field is based on 20 horizontal wells per section. Scott mentioned earlier in the fourth quarter here, we'll have turned on the Becker Ranch and the Rieder areas that are 22 and 26 well-equivalent tests.
So from a reservoir standpoint, we probably need that four to six months' worth of data to see how the wells are performing; then we'll be in a better position to say how that could potentially impact our overall inventory. So that will be something, Irene, that takes us well into next year with that data and that performance to see the impact on the inventory.
Irene Oiyin Haas - Wunderlich Securities, Inc.
Okay, great. Thank you.
Operator
Thank you. Our next question comes from Brian Corales of Howard Weil.
Your line is open.
Brian Corales - Howard Weil
Hey, guys. Most of my questions have been answered, but maybe just a question for Scott.
Based on what you've seen and maybe some of your peers, what do you think, where you sit today, how many wells do you think you can put in a section?
Scott J. Reasoner - Senior Vice President-Operations
At this point, I feel fairly comfortable at the 20, and that's our 2P number. And again, we're starting to get substantial data there, where we don't see that our production is deteriorating over time associated with that.
The Rieder and Becker will be really interesting data, and I really – I know at some point we're going to reach that point where you're looking at that decline that's more steep, and the question of Ipsit being, at what point do you make that decision, which way you're going to go. But the unfortunate part of this whole thing, Brian, is that it really takes time to get that data on the projects like the Becker and the Rieder and that is because it really doesn't necessarily occur early in the life of the well.
So, I guess, to answer your question, comfortable at 20, liking the idea that we're getting the Rieder and Beckers online. And I think it will be 180 days, maybe to a full year before we really know what that looks like, and I think that's the best answer I can give you at this point.
Brian Corales - Howard Weil
No, that's fair. And, Scott, if you – if there's a zone that you think has – that could surprise you to the upside, is it just the Niobrara B or is it another zone?
Scott J. Reasoner - Senior Vice President-Operations
That's another one of those things that I think we're still learning more and more about. It really comes down to the spacing of the wells between the different zones.
The A is definitely the weakest in most of the areas that we're in and we've not focused on it much this year and don't have many intentions to do that going forward. So it really comes down to how you place wells between the B, the C, and the Codell that becomes critical with an understanding of the number of wells that are already in the Codell vertical, in the acreage from the Codell vertical perspective, that becomes critical.
And it's something our teams are working on constantly, adjusting the number of wells they're putting in each one of those zones. We don't see a lot of difference between the B and the C, and obviously, you see the difference between the Niobrara and the Codell in many of our plots, so I think you can see there are places where the Codell doesn't perform quite up to the Niobrara standards early, although over time it seems like they flatten out and pick up – the volumes pick up on that.
So that's the way I see it, and as far as any one of those zones, particularly, like I said, I think the B, C, or Codell are pretty much in our sights as equally effective in terms of the rates of return.
Brian Corales - Howard Weil
Thanks, guys.
Operator
Thank you. Our next question comes from Michael Hall of Heikkinen Energy.
Your line is open.
Michael A. Hall - Heikkinen Energy Advisors
Thanks. Just curious, it seems you're building a bit of a backlog.
Wondering what the philosophy is around that and how many of those wells that you expected to drill next year you think you'll get on production?
Scott J. Reasoner - Senior Vice President-Operations
In terms of the carry-out of 2015 into 2016, our plans are at this point to put a second frac crew on right around the first of the year, and some of that is an efficiency project. Once we get that crew running, we really like to keep it running.
Our teams out in the field, both our internal teams and external teams being the service companies tend to get to working together and get more efficient when we do it that way. So rather than kicking that in, I think you could start any time here, but rather than kicking that in right now, we're really waiting so we can keep that frac crew busy through a good portion of the first half of next year.
And in terms of carry out into the next year, I think it will probably be a similar number as to what we're carrying in, although I don't have an exact number. That's kind of what I would expect on the pace at which we're drilling, the way we drill those wells, that can vary somewhat because what we try to do is frac wells that are neighboring wells all at one time.
And that's why we did the Chesnut Churchills the way we did it. And we'll continue to do it – take that approach as we go forward into the future.
Michael A. Hall - Heikkinen Energy Advisors
Okay. And just to be clear then, what is the current backlog or what do you expect the carry-over into 2016 to look like?
Scott J. Reasoner - Senior Vice President-Operations
Yeah. We're – I think we've said in the past that we're looking in that number at around a 60, carry into 2016, which we'll work off, like I said, in the first half of the year.
That number is very rough because the guys are constantly completing wells and we're drilling at different pace than what we expected, as we've said, that we continue to see downward pressure on the drilling. So it may be a few more, a few less.
Michael A. Hall - Heikkinen Energy Advisors
But you think that that 60 plus or minus level relative to a four-rig program is pretty close to a normalized level, it sounds like, as you think about running through the course of 2016 towards the end of the year?
Scott J. Reasoner - Senior Vice President-Operations
Yeah. That feels pretty comfortable to me.
Again, it could vary some, like I said, because of the way these packages are drilled. And it's not a single pad, it's a series of pads and how that all fits together is yet to be determined, really, toward the end of next year.
Michael A. Hall - Heikkinen Energy Advisors
Okay.
Scott J. Reasoner - Senior Vice President-Operations
But 60's a good number.
Michael A. Hall - Heikkinen Energy Advisors
That's helpful. I appreciate it.
And I guess, I was also curious, on the basin study you guys have talked about – you've talked about that in the past as well – I'm just wondering how has that evolved and what other characteristics outside of just raw rate of return, what other sorts of things are important as you think about basins from a strategic standpoint?
Barton R. Brookman - President & Chief Executive Officer
Yeah, Michael, so some of the key attributes we look for in a basin study is first off to have great rocks. I mean, you've got to have rocks that are capable of holding a tremendous amount of resource per section.
And – which leads you to places that have fixed sections as well as a lot of different intervals within those sections with which to target. Clearly, the technology and the advancements that Scott and the teams are doing to deliver more recovery per well is a great place to utilize that technology somewhere where you've got a lot of great resource that's in the ground.
So that's really fundamental to us from that standpoint and it's also got to be an area that we believe can deliver a multitude of downspacing projects. So it's more than just a few numbers of wells per section.
It's got to be a place that we can deliver a lot of wells that we can recover the volumes of oil and gas from that section. And we want something to be material to the company over time.
It's got to be something that if we were to add a new basin, something that we could add a significant amount of capital to and be impactful to the company over time. So, all those things, Michael, together are what we look at and assess and we do a lot of work, both from a reservoir and geologic standpoint to make sure that it fits and works, and then those projects need to compete with Wattenberg.
So, everything we look at has to come in and compete with Wattenberg. So, once we do that work and we have to lay it across our economics for the inner, middle and outer core areas of the Wattenberg and do a comparison with something that comes in and competes with that.
So, all those types of things together, all the while managing for a very strong balance sheet post-deal if that were something that we were to pursue in the future, we would do it in a way that obviously it really honors the balance sheet and that's accretive to the company. So, that – all those financial measures, the accretion, the strong balance sheet, all those things are things that we would look at and we would make a determination today that it adds value to the company going forward.
So, that's the types of things that we think about.
Michael A. Hall - Heikkinen Energy Advisors
Great. I appreciate the color.
It's helpful.
Operator
Thank you. Our next question comes from Pavan Hoskote of Goldman Sachs.
Your line is open.
Pavan P. Hoskote - Goldman Sachs & Co.
Thank you. Good morning, guys.
Scott J. Reasoner - Senior Vice President-Operations
Good morning.
Barton R. Brookman - President & Chief Executive Officer
Good morning, Pavan
Pavan P. Hoskote - Goldman Sachs & Co.
My first question is related to your comments that you're continuing to see improved well productivity using plug-and-perf and other completion techniques. To the extent that these benefits continue into 2016, would you choose to keep the full rigs and grow more or would you rather spend less to hit your current growth objective?
I'm really trying to understand whether you're solving for growth, spending, or free cash?
Barton R. Brookman - President & Chief Executive Officer
Pavan, let me see if I can tackle this one. Our first objective as we're looking at next year's plan will be targeting that cash flow neutral objective and – or slightly cash flow positive.
So, we're starting with our pricing forecasts, first and foremost honoring the balance sheet and then we layer in all of our activity, rig efficiencies, completion, designs and output with all of that after we determine that we're cash flow neutral, our production continues to be enhanced and our returns continue to improve based on some of the things that Scott has covered. So, we will first and foremost honor the balance sheet and then output will be production growth.
Will we slow down and go to a – let's say a strong cash flow positive position? I think that's what you're hinting at.
I think we would give that some consideration, but I don't know if that's our primary objective, to slow it down and there's a key reason in all of this is when we look at our 2016 budget right now, we're – early forecasts going to have peer leading growth in production, but we also want to make sure we're laying a very solid foundation for 2017. So, if we slow down too much, depending on, the rig counts and more importantly turned-in-line and spud counts, we can impact 2017.
We can have really strong growth in 2016, but 2017, we can enter 2017 in a trend that will make it more difficult for us to grow. So we've got multiple factors that we're looking at.
Last, I should note, if the market deteriorates even more or if the market comes back, we maintain a lot of flexibility to move this. And we maintain a lot of flexibility, if some of these enhancements continue as we go through 2016 we can always change our plans.
So, Scott, do you have anything you want to add on this?
Scott J. Reasoner - Senior Vice President-Operations
I think that was good. I don't, Barton.
Barton R. Brookman - President & Chief Executive Officer
Okay. Hopefully I answered your question.
Pavan P. Hoskote - Goldman Sachs & Co.
Great. Yes, that was a really helpful answer.
And then on an unrelated point, can you tell us what you're seeing in terms of operating and capital costs in the DJ Basin and how much room do you see for service costs to fall further?
Scott J. Reasoner - Senior Vice President-Operations
Pavan, my comments, we're seeing the cost of those standard lateral at $2.9 million and the extended reach lateral at $3.9 million and I don't – there's still downward pressure, but it's not nearly as much as it's been in the past and much of what we're seeing is still some efficiency that's coming into the drilling side when you talk about the changes that we've experienced here in the last several months and maybe a little bit of price reduction. We're hoping that we can continue to get more efficient.
Obviously drill pace continues. Every day you drop off, that's a rig day of expense as well as all the associated services with that.
So really our downward trend is still there, but I don't think we're going to see substantial adjustments from here. It will have to be technology that drives a significant portion of it.
That doesn't mean we're not still pushing. We are.
But we're getting pushed back at the same time.
Pavan P. Hoskote - Goldman Sachs & Co.
Got it. Thanks a lot.
Scott J. Reasoner - Senior Vice President-Operations
Yes. Thanks.
Operator
Thank you. Our next question comes from Mike Kelly of Seaport Global.
Your line is open.
Mike Kelly - Seaport Global Securities LLC
Hey, guys, good morning.
Barton R. Brookman - President & Chief Executive Officer
Good morning.
Scott J. Reasoner - Senior Vice President-Operations
Good morning.
Mike Kelly - Seaport Global Securities LLC
I was just hoping to get maybe some added color going into Q4 here. And you grew 27% sequentially Q3.
Only looks like you need a 2% sequential growth to hit that 15 million BOE annual number. I'm just curious, should we expect a more of a subdued growth quarter or could this be the second best quarter of Bart's life here?
Gysle R. Shellum - Chief Financial Officer
I'm always hoping to deliver more for Bart, I guess, is the answer to that. Mike I think what you're really looking at, in the third quarter is the benefit of a bunch of turned-in-lines that occurred late in the second quarter.
And third quarter turned-in-lines have been, I would say, we're at about three quarters of what we turned-in-line in the second quarter that we turned-in-line in the third quarter. So we are going to see some flattening of that growth.
As we've said, we're really looking at something that takes us to the top end of that 15 million barrels of oil equivalent, maybe slightly above it. And so that gives you a good flavor for where we're headed.
It really is a function of those turned-in-lines as to the growth that we see and with that slowing down a bit in the third quarter, it's going to at least flatten us out slightly, but not completely. Hopefully we see a little bit of growth and we can deliver that to Bart, another one of his best performances in his life.
Mike Kelly - Seaport Global Securities LLC
Perfect. That's all I've got, guys.
Thanks a lot. Great quarter.
Gysle R. Shellum - Chief Financial Officer
Thanks.
Barton R. Brookman - President & Chief Executive Officer
Thanks, Mike.
Operator
Thank you. Our next question comes from Welles Fitzpatrick of Johnson Rice.
Your line is open.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Hi, guys, good morning.
Barton R. Brookman - President & Chief Executive Officer
Hey, Welles. Good morning.
Gysle R. Shellum - Chief Financial Officer
Hey, Welles
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
You guys have talked about a lot of confidence from the Sunmark (57:41) and Chesnut on the 20-acre spacing. Is that what you guys are actually permitting for development mode in 2016 or is it not quite there yet?
Scott J. Reasoner - Senior Vice President-Operations
We're very near that number. I would say, the best thing to do is give a range.
We're really in the 16 to 20 range and it depends a lot on the circumstances that we're faced with in terms of the existing development, the amount of – and by that I mean, well development and the amount of surface area that we can occupy if there happens to be some limits because of the surface owner, then we'd have to look at that, but really looking in that 16 to 20 range.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Okay. Perfect.
And then I know you guys have talked about it in broad strokes, but are there any plans to test out that elimination of a string of casing that we've seen some of your compatriots in the basin do?
Scott J. Reasoner - Senior Vice President-Operations
We have done three wells and had good success doing them. In terms of the economic benefit, we're not there yet in understanding all of that.
We're looking at the numbers. They're still rolling in.
They've been done just recently. I think they finished the last one in the last couple – maybe in the last week even.
We do plan to do a number of those through the rest of this year I think six to eight is what we have on slate. So you can tell we had good success and we're going forward with it, oftentimes called the monobore, but we've had good results.
The first three didn't face a lot of issues that we didn't expect and we're hoping that we're able to continue that and there's obviously eliminating a string of casing, the associated cement, the well heads, et cetera, there's some benefit there to be had if we can get good at it and not create a bunch of problems for ourselves.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
That's great. And then lastly, Gysle, I know you've got some time left, but I just want to say congrats on the retirement and it's been a pleasure getting to know you.
Gysle R. Shellum - Chief Financial Officer
Thank you, Welles and thank you for your kind note and your research report last week.
Operator
Thank you. Our next question comes from David Tameron of Wells Fargo.
Your line is open.
David R. Tameron - Wells Fargo Securities LLC
Yes, Gysle, likewise. Welles beat me to it, but congrats on the retirement.
I've still got a few questions left, believe it or not. Have you guys given us a current return, and maybe you gave it during the call and I missed it, but can you tell us what you're currently getting out in the DJ, average well, however you want to phrase it?
Barton R. Brookman - President & Chief Executive Officer
(60:22)
Gysle R. Shellum - Chief Financial Officer
You want drilling returns, David?
David R. Tameron - Wells Fargo Securities LLC
Yes, yes, drilling returns. Yes, just...
Gysle R. Shellum - Chief Financial Officer
Yes, I don't think we've given an update on our current market. Obviously, Scott has announced that there's a modest decrease in our capital and we are currently in the evaluation mode of all these production enhancements.
The question around type curves and all of that. So I don't think we've updated anything.
But obviously with the price here the last few months been in this mid-$40s and low to gas environment, the most recent market presentation I would expect there to be some enhancements in those numbers.
David R. Tameron - Wells Fargo Securities LLC
Okay.
Gysle R. Shellum - Chief Financial Officer
The level of enhancements, we're still working through that as we work through the 2016 budget.
David R. Tameron - Wells Fargo Securities LLC
Okay. And, Bart, I don't know if this is you or Lance or whoever, but takeaway differentials, can you just talk about – I know you had the language in the press release about the reclassification, but can you talk about what you'd expect differentials to be ex that classification going forward?
Barton R. Brookman - President & Chief Executive Officer
Yeah, David. So, third quarter, we delivered an all in differential of $8.75 a barrel and that is from NYMEX all the way back to the well head.
In August at our second quarter, we had projected a $9 all in differential, so we're about a quarter inside of that. Our oil marketing teams are doing a tremendous job going out and securing short-term oil contracts that are inside at $8.75 per barrel number, so they're doing a good job continuing to bring that number down.
So, I think the trend is for the long-term oil differentials to continue to decline some and we'll have a better handle on that as we look at our December announcement of our budget for 2016.
David R. Tameron - Wells Fargo Securities LLC
Good. And Lance, how much do you have that's locked?
What percent of however you want to define it, call it current production as locked down or has the Firm defined how much is floating, if you will?
Lance A. Lauck - Executive Vice President Corporate Development and Strategy
So good question, David. So, we have 6,600 barrels a day that is going to White Cliffs.
So, it's going all the way to Cushing, Oklahoma in that pipeline. That is a long-term contract.
Other than that, the rest of our oil is anywhere from month-to-month or as much as six-month type contracts and there are a few that are maybe closer to a year. But the majority of our oil contracts are, I would classify as short-term and we're really then being able to utilize this continued reduction in differentials.
We're able to take advantage of that as we see more and more opportunities for tighter differentials. So, it's a good trend for the company.
David R. Tameron - Wells Fargo Securities LLC
Okay. That's helpful.
And then last question, and whoever wants to take this, maybe Scott or Bart, if I think about reserve bookings, and I'm just trying to figure out, if I think about a year ago, what were you given credit for as far as – or what would the typical well look like as far as completion or lateral length? I'm just trying to get a better handle on – I assume you're going to get an uplift this year.
I'm just trying to figure out where they were a year ago and where they're headed?
Lance A. Lauck - Executive Vice President Corporate Development and Strategy
Let me start a bit on, David, and I can turn it over to Scott to share more insight on it as well. For – the reserve booking methodology on approved reserve basis had a location count of about 10 wells per section.
David R. Tameron - Wells Fargo Securities LLC
Okay.
Lance A. Lauck - Executive Vice President Corporate Development and Strategy
So, that would be eight in the Niobrara and two in the Codell. And you can see – and the type curves that we've had for that in the past, and the EURs for the past, we've talked a lot about that at our Analyst Day and stuff with that.
As we look towards year end 2015, I mean clearly we have inventory here that is very resilient to these lower prices and we envision a drilling plan and development plan over the next several years, that is going to be a strong drilling plan and very consistent with what we've had in the past. So, we feel in general that we feel very good about our – the volumes for our year-end 2015 reserves from approved basis.
That said, we're still a few months away from fully finalizing all of those numbers and then we'll have to weigh in the facts and circumstances at that time to see how that looks. But we feel pretty good about where we sit now with our volumes for 2015 year-end reserves.
Barton R. Brookman - President & Chief Executive Officer
And just to clarify, David, all of the completion techniques that we're talking about, the plug-and-perf, AccessFrac, none of that was built into any of our type curves; and our reserve report, I believe, was generated on standard laterals only. So longer laterals, plug-n-perf, AccessFrac and any other technical advancements, including the downspacing Lance is talking about, are all upsides in our reserve report.
And Ryder Scott right now is gaining a lot of data. Scott just answered the question, what are we drilling now 2016 to 2020.
So everything we're bringing on line is supporting downspacing that Lance talked about. So I believe Ryder Scott will have enough data to really make a good assessment of downspacing opportunities and then all of these production or completion enhancements will take time, because Ryder Scott is going to want enough data to fully justify any type of uptick in the type curve.
I do know last year our type curves were adjusted upward, and if I remember correctly, about 10%, and that primarily was due to shorter stage lengths, and I think we announced that at Analyst Day. So expect probably – expect some of the same.
I obviously can't announce we're upgrading type curves, but we have some forces in the company right now that I would say on a reserve basis are very positive.
David R. Tameron - Wells Fargo Securities LLC
Okay. No.
That's helpful color. I appreciate it.
Again, congrats on the good quarter.
Operator
Thank you. Our next question comes from Jeffrey Connolly of Clarkson.
Your line is open.
Jeffrey Richard Connolly - Clarkson Capital Markets LLC
Hi, guys. You touched on the benefits of the lower line pressures on the legacy vertical wells and some of the older horizontals.
Do you think the lower line pressures are having an impact on initial production from new horizontal wells or since you used the choke management program, it doesn't really matter and could it have an impact on 90-day, 180-day, or even 365-day production?
Barton R. Brookman - President & Chief Executive Officer
I think when you look at those overall, the impact is really on those older wells. The newer wells have a tremendous amount of pressure and can overcome that line pressure and so the benefits are minimal if any.
It does obviously make our guys in the field, their lives easier to deal with less line pressure irrespective of what type of well it is. But the wells can overcome it.
And it's exactly as you described, that choke management really keeps that pressure on it longer. Does it start to impact them at the 180 days?
I would say very little. But at 365 days, particularly if they're in a lower GOR environment, you would see some – maybe some slight benefits, again, making it easier just to run the wells.
But generally that first year, and particularly since we're working mostly in the middle and inner core, there would be little impact from the new wells.
Jeffrey Richard Connolly - Clarkson Capital Markets LLC
Okay. Got it.
And then going forward and the three-year outlook, extended reach laterals, the results look good, obviously becoming a bigger proportion of the overall drilling program. Can you guys help us think about what percentage of that or how that might increase over time?
Scott J. Reasoner - Senior Vice President-Operations
In terms of that, I think, it's – you're asking about how many are we going to do? Is that kind of your question?
Jeffrey Richard Connolly - Clarkson Capital Markets LLC
Right. Or just like a rough percentage, something for us to think about going forward?
Scott J. Reasoner - Senior Vice President-Operations
We're still working on that. Like I said, we'll probably have a reasonable number of 2-milers, which we have not done in the past; and the actual numbers I don't really have to give you, but if I were guessing at this point, I would split them probably 50% standard and maybe evenly split between the extended reach and the 2-milers.
And that's a really rough estimate at this point.
Jeffrey Richard Connolly - Clarkson Capital Markets LLC
Okay, got it. Thanks.
Thank you very much.
Operator
Thank you. Our next question comes from David Beard of Coker Palmer.
Your line is open.
David Earl Beard - Coker & Palmer, Inc.
Good morning, gentlemen. Thanks for running a little bit over.
Just two questions. When you look out, what percent of your wells do you think could be plug-and-perf or could you use BioVert?
And then you used to give a percent production from vertical. I wondered if you had that number and would you consider spending some money on the vertical wells to increase production?
Thank you.
Scott J. Reasoner - Senior Vice President-Operations
In terms of the possibility of using plug-and-perf, I think – well, based on what we see right now, we're going to be doing most of our wells next year using plug-and-perf. We will have a few that carry in from this year into next year that were drilled over the last several months, but we'll have the sliding sleeve technology in them.
So you'll see us, I think, convert over probably completely. I don't want to say 100% that way, but for next year after we get those worked through the system.
When you talk about access brackets, it's an interesting dynamic in some wells that process goes very easily and our guys in the field can kind of tell when it's going to go easy and when it's going to be more complex. So we're really making that decision on the fly, as to which wells are going to get AccessFrac, and which wells are not going to get that; and a lot of it is the complexity or the difficulty with which they have fracking the well.
And so, really, I don't have a good number yet for AccessFrac and probably won't even going into the budget season and the discussions that we'll have around budget here in the next couple of months. So it's such that that's a more complex issue and the good thing about it, though, is you don't redesign the wellbores.
So we can make the decision as we're fracking the wells as to whether or not we're going to implement AccessFrac in the process. In terms of the percentage of the older vertical wells, we – I guess, the best indication I can give you is in the – on the final page of the operational highlights, page – slide 21, you can calculate it from that series of equations, or series of numbers that we give you there, where 82% horizontal is what it is, so the remainder, the 18% would be vertical.
David Earl Beard - Coker & Palmer, Inc.
Okay, great. Thank you.
Operator
Thank you. Our next question comes from Dan McSpirit of BMO Capital Markets.
Your line is open.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Thank you, and good morning. How much are you willing to change the financial risk profile of the company to permanently finance an acquisition?
That is, how much are you willing to lever up considering the low level of leverage today?
Gysle R. Shellum - Chief Financial Officer
This is Gysle, Dan. It's a pretty open-ended question.
I guess I'd answer that by saying our leverage now is, as we've said, we expect to end the year at 1.5 times. We've got kind of a soft ceiling at 2 times.
If we did come across the acquisition that we couldn't say no to, we might be willing to go a little bit north of that as long as we had line of sight in pretty short timeframe that we could dip back down below that 2 number, assuming the market is soft like it is today. If things get better, that soft 2 ceiling could increase, but right now we don't see that.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Okay. Great.
And are there any stones unturned in the DJ Basin? That is, is there acreage available for acquisition that could compete with returns generated from drilling inner and middle core Wattenberg wells?
Lance A. Lauck - Executive Vice President Corporate Development and Strategy
You know, Dan, it's Lance. We see, you know, a few packages here and there that typically are fairly small on the actual acreage count that's within sort of that core area that we've really highlighted.
So there's not too many opportunities to pick up acreage in the area. There's only really a few number of operators in general and the field has been drilled predominantly vertically for a tremendous number of years.
And so it's all HBP, so it's not all acreage needing to move because it's primary term. So from that standpoint, there's not a tremendous number of opportunities that come into that basin that really sort of competes with what we have in place already.
So – but we look; we'll continue to look, and if opportunities come by, we'll make sure that we take a good look at it.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Okay. Great.
And just one last one, final one here. Could you remind us when you drill the last inner core Wattenberg well, assuming the current pace of drilling?
Barton R. Brookman - President & Chief Executive Officer
When we drill the last in our inventory, Dan?
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Yeah, that's right.
Barton R. Brookman - President & Chief Executive Officer
I think it's 2017.
Scott J. Reasoner - Senior Vice President-Operations
I believe that's correct. Although that doesn't necessarily mean that as we consolidate acreage, and we still have small pieces of acreage out there, that we still may end up drilling a few wells in the inner core.
But I think that – over the next year, year and a half, really we'll use up the inventory that we have of inner core. Like I said, though, there will be some that show up here off and on as we move to develop those smaller parcels that we have.
Barton R. Brookman - President & Chief Executive Officer
And the other thing, too, Dan, I'll just share on that just as a reminder. Our focus on drilling in the Wattenberg is inner and middle core and all along we've only had approximately 100 locations in the inner core area.
So all of the economics that drive the outlook projections that we have are predominantly middle core. So we have a substantial inventory there and that's the source of our growth for many, many years going forward.
Daniel Eugene McSpirit - BMO Capital Markets (United States)
Very good. Have a great day.
Thank you.
Barton R. Brookman - President & Chief Executive Officer
Thanks, Dan.
Operator
Thank you. That ends our Q&A session for today.
I'm going to go ahead and turn the call back over to Mr. Brookman for closing remarks.
Barton R. Brookman - President & Chief Executive Officer
Well, thank you, Ashley, and thank you, everyone. Thank you for sticking with us here for an hour and 20 minutes and your ongoing support.
Expect more on 2016 by the end of this year. I believe we've got an announcement at least planned around our budget sometime in mid-December.
So again, thank you for your time.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program.
You may all disconnect. Everyone, have a wonderful day.