Occidental Petroleum Corporation
Q3 2016 Earnings Call Transcript

Published: 1 Nov 2016

[Operator:]

Good morning and welcome to the Occidental Petroleum Corporation third quarter 2016 earnings conference call. Please note, this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead.

[Christopher M. Degner:]

Thank you, Kate. Good morning and thank you for participating in Occidental Petroleum's third quarter 2016 conference call. On the call with us today are

[Vicki A. Hollub:]

Thank you, Chris, and good morning, everyone. I'll begin by summarizing our key accomplishments in the third quarter. First, cost reduction efficiencies combined with improvement in new well productivity and better base management have enabled us to further reduce our total spend per barrel of production this year compared to 2015. Second, we again increased year-over-year production in our core areas, and we're on target to exceed the higher end of our guidance for 2016. Third, we remain prudent with our capital allocation as we focus on returns and maintain disciplined to stay within our $3 billion capital budget. Fourth, to further increase our low-decline production and improve efficiencies, we have acquired additional working interest in enhanced oil recovery projects and unconventional acreage in the Permian. Last, our aggressive appraisal and development efforts in our Permian Resources business have resulted in an improvement in the number and quality of wells in our inventory. As I've previously mentioned, our total spend per barrel of production metric includes our overhead, operating and capital cost per barrel of production. This metric is designed to drive cost reduction, increased well productivity and optimize base production. To align employees with this metric, we have linked this to incentive compensation. Our efforts to focus on efficiency and capital discipline are paying off, as we continued to lower our total spend per barrel of production. We averaged close to $62 per barrel in 2014, about $40 per barrel in 2015, and have targeted $28.50 per barrel in 2016. Year to date, we've beaten our target, with average total spend of about $27.50 per barrel. In the third quarter, total company production from our ongoing operations was about 605,000 BOE per day, an increase of 5% year over year driven by Al Hosn gas in Abu Dhabi, a new gas project in Oman and resilient base production in Permian Resources. The performance of the Al Hosn team continues to exceed our expectations as they optimize deliverability. They have again achieved record production of 74,000 BOE per day for the quarter. It's even more impressive that the plant operated well during the summer months, where temperatures can reach 120 degrees. We're optimistic that the plant can continue to deliver from 65,000 BOE per day to 75,000 BOE per day, depending on seasonal maintenance. We have commenced engineering studies for a potential expansion of the plant and expect to reach an investment decision in the second half of 2017. Permian Resources production this quarter was 121,000 BOE per day, representing year-over-year growth of 4%. As per our original development plans, Permian Resources production will decline slightly in the fourth quarter. We are adding rigs now to stabilize production and restart growth in early 2017. We continue to see improvements in well productivity in all of our areas. The increases in production from Al Hosn, Oman's Block 62, along with strong year-over-year production growth from Permian Resources will help us exceed the higher end of our production growth guidance for 2016. As we look forward to 2017, we expect to deliver 5% to 8% production growth, with the variance subject to our activity levels in the Permian. Longer term, we have a deep inventory of well locations in the Permian with the capability to drive direction growth above this range. Additionally, we have focused our international business on the core four areas

[Christopher G. Stavros:]

Thanks, Vicki, and good morning, everyone. Today I'll focus on the following items

[Jody Elliott:]

Thank you, Chris. Today, I will provide a review of our domestic operations during the third quarter, guidance on our program in the fourth quarter and an outlook for the start of 2017. For this year, our Permian Resources business achieved significant improvement in well economics across our Permian leading acreage position through step change advancements in well productivity and field development design. We believe this improvement in value starts with our subsurface characterization, where we are leveraging our geology, petrophysics and geochemistry expertise to achieve breakthroughs in our multi-bench appraisal, stimulation and other key subsurface design factors. We expect to quickly deliver a new series of breakthroughs in 2017 as we advance our seismic-based characterization and second phase of geoscience analytics. On the cost structure front, we continue to lower our capital and operating cost structure through faster drilling, leveraging engineering innovation and integrated planning to optimize execution and logistics. We expect these efforts, when combined in our field development plans, will ensure Oxy is a leader in realizing maximum value per acre by optimizing recovery and capitalization. Our unconventional business is well positioned to provide a competitive return in a low-cost environment and achieve significant growth in an improved price environment. As a result, during the third quarter we added a drilling rig in Permian Resources plus another at the beginning of the fourth quarter and have capacity and locations on standby to respond to improved pricing in 2017. Turning to the performance of Permian Resources. In the third quarter, we achieved daily production of 121,000 BOE per day, a 4% increase versus the prior year. Oil production declined modestly due to lower capital spending, with nine wells put online versus 54 wells in the third quarter of 2015. Improved well productivity and our emphasis on base management mitigated some of the base decline on the horizontal wells. In the second and third quarters, we completed gas processing and compression facilities, allowing for the capture and sales of more gas and NGLs. As we announced yesterday, we acquired producing properties and non-producing leasehold acreage in the Permian. In Permian Resources, we acquired 35,000 net acres in southern Reeves and Pecos Counties, where we currently operate and have a working interest. The properties will include approximately 7,000 BOE per day of net production, with 72% oil from 68 horizontal wells. On key portions of the acreage, we gained operatorship where we had existing non-operated interest, and most of the acreage is already held by production. Development will initially target the Wolfcamp A, Wolfcamp B and Bone Spring. Simply put, we know the acreage very well. It's very competitive with our existing inventory. We expect to drill longer laterals, execute multi-bench development and leverage our existing infrastructure in the area, notably the joint venture gas processing plant completed this summer. This transaction brings our overall position in the leasehold area to 59,000 net acres, with an aggregate acquisition cost under $2 billion. We plan on allocating approximately $200 million in capital in 2017 to the acquired acreage, utilizing one to two drilling rigs. Turning to our activities in our core development areas. Much of the focus of the drilling program in the second and third quarters was to appraise the potential for multi-bench development in southern Reeves, Eddy, Howard, Glasscock, and northern Reagan County. In southeast New Mexico, we drilled and completed two Cedar Canyon Third Bone Spring wells and one Cedar Canyon Wolfcamp A well in Eddy County. All of the wells had 30-day peak IPs over 1,000 BO per day. In southern Reeves County, we brought the Roan State 24 51H Second Bone Spring well online at a peak rate of 944 BOE per day and a 30-day rate of 702 BOE per day and a 90% oil cut. The well had a 4,500-foot lateral and increases our confidence in the potential for multi-bench development for our acreage in the area. We're on the learning curve in developing this bench and expect well productivity to improve as we apply our experience in drilling and completion technology and further integrate our subsurface analysis. In Glasscock County, we brought the appraisal well, Powell 1720 1H, online with a 7,500-foot lateral, which targeted the Spraberry formation with a 30-day rate of 931 BOE per day. As cited last quarter, we now compare and benchmark our well cost on a cost per 1,000-feet of lateral basis as we continue to increase our lateral lengths. Slide 23 illustrates our demonstrated improvement in well cost, which has declined roughly 38% from 2015. Similarly, our 1,000 foot of lateral per rig per quarter has also improved from 25.2 per rig in 2015 to 35.4 per rig in the third quarter. We believe that a significant percentage of these improvements in efficiency are driven by structural changes in how we drill and complete wells and expect to continue to improve these efficiencies as we add drilling rigs. In the Delaware Basin, we're aggressively appraising new benches while maintaining focus on improving well recoveries in our development benches. In southeast New Mexico, we tested a new Second Bone Spring slickwater frac design on the Cedar Canyon 27 Fed 5H with 2,000 pounds per foot and 50-foot cluster spacing. The cumulative production results from the new design have exceeded the first half 2016 design, and we expect to see continued improvement in future results. We're targeting an average well cost of $7.1 million for the Second Bone Spring and $8.3 million for the Third Bone Spring with 7,500-foot laterals and the increased completion size. Overall, we're very encouraged by the development and appraisal results in southeast New Mexico and we expect to increase activity in Q4 and throughout 2017. In the Texas Delaware, we drilled one well and turned one appraisal well to production. The reduction in activity in the area is consistent with the overall balance of activity shift between Texas and New Mexico, and we plan to increase activity in this area in the fourth quarter. Our upcoming wells in the fourth quarter will test new completion designs and drilling technology that we believe will drive step change value addition across all of our development areas. We expect to increase our average lateral length from approximately 5,200 feet in 2016 to over 9,000 feet in 2017. Shifting our results to the East Midland Basin, in the third quarter we drilled eight wells, brought four wells online, three of which have not reached peak production rates. We had multiple record drilling and completion achievements during the quarter. For example, we drilled a Wolfcamp B 7,500-foot lateral in 12.5 days rig release to rig release. We completed 10 frac stages in one day, and we drilled and completed two Wolfcamp A horizontals for $4.6 million and $4.9 million. Well productivity measured by the initial production rates per thousand foot of lateral continues to improve. In the Permian Resources as a whole, we achieved another quarter of lower quarter-over-quarter field operating expenses, due mainly to improved surface operations with optimized water handling, lower workover expenses, and better downhole performance. Since the second quarter of 2015, we've reduced our operating cost per barrel by 28%, continue to work additional cost reduction and efficiency improvements. As stated earlier, our focus on maximizing production from existing wells has been central to reducing declines in the business. We expect that our average annual uplift for our investment will be approximately 6,000 net BOE per day. This is another example of leveraging our decades of base management expertise in the EOR business to our Resources business. As previously stated, we expect to increase our drilling activity in the fourth quarter of 2016 and bring on approximately 20 wells. We expect production to be about 120,000 BOE per day in the fourth quarter and be growing as we exit the year. With over 115 wells planned for 2017, we expect to achieve double-digit production growth in Permian Resources. In addition to the recent acreage acquisition, we've been actively trading and swapping acreage in order to core up our position. We've traded approximately 10,000 acres, which will enable longer lateral development. So for 2017, we expect to drill more wells with more than double the total lateral length drilled in 2016. Now I'd like to shift to our Permian EOR business. We continue to take advantage of lower drilling cost and manage the operations to run our gas processing facilities at full capacity. Permian EOR had another quarter of free cash flow generation. Drilling costs are running 22% below our benchmark target, and we've lowered cash operating expenses by 20% since the fourth quarter of 2014 and 7% year over year, driven mainly by lower downhole maintenance and injectant costs. In similar fashion to our Resources business, the capital savings achieved by the EOR team will be reinvested into additional wells and CO2 flood expansions. As we've mentioned in previous calls, the residual oil zone development, or ROZ, is a vertical expansion of the CO2 flooded interval. The ROZ underlies most of our major EOR properties and can be developed between $3 and $7 per barrel. Year to date, we've completed 94 well deepenings and recompletions along with 36 new wells in the ROZ developments. We anticipate an additional 50 deepenings and recompletions and 10 new wells in ROZ developments in the fourth quarter of 2016. Yesterday, we announced acquisitions of working interest in 11 producing oil and gas properties and related infrastructure. The acquisition increases our ownership in several properties where we currently operate or are an existing working interest partner. These properties have production of approximately 4,000 barrels of equivalent per day at 80% oil, with estimated net crude developed producing reserves of approximately 25 million BOE and total proved reserves of approximately 41 million BOE. To summarize, our domestic business will provide competitive returns in a low-cost environment and achieve significant growth in an improved price environment. We believe our Permian business is uniquely positioned to leverage our subsurface innovation in unconventional and leadership in enhanced oil recovery to maximize the value per acre across our entire 2.4-million-acre portfolio. We plan to exit this year running eight drilling rigs on our operated acreage plus another 1.5 to 2 net rigs on our non-operated development acreage. We're pleased with the strides our teams have made in subsurface characterization, execution, and performance thus far in 2016 and look forward to continuing breakthroughs in 2017. Thank you, and I'll now hand it back to Chris Degner.

[Christopher M. Degner:]

Thank you, Jody. We'll now open up the call for questions.

[Operator:]

The first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

[Doug Leggate:]

Thanks. Good morning, everybody. I've got two questions. Vicki, I wonder if I could kick off with the acquisition last night. You've shown before the relative priority for the use of cash, and you've also shown us that you've got a fairly deep inventory of existing assets. I'm just trying to understand the rationale as to why $2 billion is the right use of cash versus a step up in activity on your existing acreage. If you could, just help us understand the rationale a little better and maybe some of the nuances about working interest changes, what it brings to you by way of operating capability and so on. Just help us understand the numbers a wee bit.

[Vicki A. Hollub:]

Doug, we've been looking at this. We've had ownership in this area for a while now. And what made us very attracted to this is the fact that it has the potential for five-bench development and the fact that it's so close to our Barilla Draw area where we've already installed infrastructure. We believe that the infrastructure in Barilla Draw combined with the infrastructure that was installed by a very prudent and efficient operator will enable us to combine the two and provide those synergies around that infrastructure to share that. The five benches, the shared infrastructure, and the operational efficiencies that we'll gain by combining these two areas and becoming operator of it where we can manage the development to maximize the net present value we believe was the best use of our cash at this point. This inventory fits within the less than $50 per barrel breakeven price for us or the price that generates positive NPV of $10 for us, so that we think is very prospective. We like how it fits. We believe that we can further develop Barilla Draw. It will help with the economics there. So the combination of the two of them provides us quite a bit of net present value.

[Doug Leggate:]

Vicki, I don't want to belabor the point, but I think Jody suggested one to two rigs in this area. I guess what I'm really trying to understand is, to justify the NPV – understand the NPV of the incremental wells, but to justify the NPV of the incremental wells plus the $2 billion acquisition cost, one would imagine you have to run at a pretty healthy pace above what you were going to do on your existing portfolio. So again, can you help us – guide us to where the activity level on this acreage goes to justify the $2 billion price tag?

[Vicki A. Hollub:]

The one to two rigs would be the initial starting point for us on this acreage. We expect to spend about $200 million in 2017. But in 2017, remember now, we're still trying to balance cash with what our expectations are around oil prices. We do expect improving prices in 2018, which is where we expect to really launch into a much more aggressive development of both Barilla Draw and this new area. So we expect that we're going to be very aggressive with the development on this once we get into 2018, where at that point we expect the supply gap to narrow such that the prices will warrant a much higher level of activity.

[Doug Leggate:]

Okay, and a very, very last one for me, a very quick one on Chemicals. Given the cracker starts up at the beginning of next year, can you just give us some guide on the free cash flow delta on that project as you move from 2016 into 2017? And I'll leave it there, thanks.

[Vicki A. Hollub:]

Okay.

[Robert Lee Peterson:]

Hi, this is Rob Peterson. So we'll just continue the spending of capital. We'll carry a small amount for commissioning the startup into 2017, and then we'll stop spending that and start generating cash from it. So it will be a several hundred million dollar flip between spending capital and generating cash out of the cracker, depending on the ramp-up time.

[Christopher G. Stavros:]

The swing, Doug, is actually about $300 million in terms of spending versus the contribution. So that's the delta, if you will, spending to cash flow.

[Doug Leggate:]

I just wanted to check order of magnitude. That sounds great, guys. Thanks so much.

[Operator:]

The next question is from Phil Gresh of JPMorgan. Please go ahead.

[Philip M. Gresh:]

Hey, good morning. I just want to follow up on the cash flow side of things. Chris, you mentioned $4.5 billion of CFO at $50. And if we use the CapEx, call it $3.5 billion, that would be $1 billion of free cash flow versus a dividend of $2.3 billion. So I guess what I was wondering is how you planned on funding that gap if oil is $50 or even if it's $55. Would you be looking to add debt to the balance sheet? Would you be looking to sell assets? And generally, Chris, just how are you thinking about target leverage following this acquisition?

[Christopher G. Stavros:]

Phil, it's a good question. It's going to come from a combination of a number of different sources for the cash. Without being completely or terribly specific about any given thing that we're going to do at any given moment, what I would say is obviously it's going to depend on commodity prices. I mentioned the sensitivity around our cash flow to commodity prices. But should the need arise, we would expect to monetize some non-core non-strategic assets that would more than, we believe, cover our needs and when including our expectations for next year's cash from operations. So I don't anticipate or expect us to fall short or have any issue with that. We've got multiple levers that we can pull on in terms of filling any gap, certainly to the extent that you just did the arithmetic around, and more should need be. And the capital remains very flexible, certainly within the range, depending on commodity prices.

[Philip M. Gresh:]

And on the target leverage side of things, post this deal, Vicki, you mentioned maybe even looking at additional bolt-on deals. How do you think about target leverage and the size of what bolt-on would mean relative to the acquisitions you've just done?

[Christopher G. Stavros:]

The leverage amounts, we're comfortable with that within our ratings right now. We'll obviously, depending on what the acquisition looks like, if we do acquisitions, it depends on what it looks like in terms of how we're going to look to fund it. And so some acquisitions are better sourced through leverage, some through other means. So we'll just have to look at it. It depends on what the acquisition looks like, the composition of the cash flows around the acquisition, the composition of the production in terms of determining how much leverage you're comfortable with for any given type of activity or specific acquisition. So the answer is it really depends.

[Philip M. Gresh:]

Okay.

[Vicki A. Hollub:]

And, Phil, with respect to the bolt-on acquisitions, we look at a lot of things in the Permian. And this is the first thing that we've seen in a while that really fits well with our current operations and really made sense from a long-term development standpoint. You may have heard our name associated with some things in here recently that – those are things we didn't bid on. We look at a lot of things, but what we always want to do is make sure that it's a good fit. and as Doug had alluded to, that our net present value of what we expect our development to be is going to cover the cost of the acquisition. And so that rules out a lot of things for us.

[Philip M. Gresh:]

Okay, thanks.

[Operator:]

The next question is from Ryan Todd of Deutsche Bank. Please go ahead.

[Ryan Todd:]

Great. Thanks. Maybe another follow-up – I know you referenced the addition of rigs into the fourth quarter in the Permian. But what level of activity is implied in the Permian in the $3.3 billion to $3.8 billion budget for 2017? And how much of that budget is allocated to Permian Resources?

[Jody Elliott:]

Ryan, this is Jody. The activity level currently planned for 2017 would be about six rigs in the Permian Resources area and three rigs in EOR. And then depending on what that final capital number is, we can scale that up, scale it down, again, depending on commodity prices or where that final direction is on the capital budget.

[Vicki A. Hollub:]

And we've said previously, although it's not final yet, that our capital spend would probably be in the range of $1.3 billion to $1.4 billion for Resources.

[Jody Elliott:]

And, Ryan, the other point I want to make is all the work that we've done this year around our characterization, around our field development planning, the upsizing and optimization of our stimulation has created this ability with very low capital intensity to generate a lot of production. So that inventory mix in 2017 will be optimized where we can grow production significantly with a fairly modest rig count.

[Ryan Todd:]

Thanks. And then maybe as a follow-up to that, can you talk a little bit about your infrastructure position in the Basin, how you feel like you're positioned to be able to ramp activity in terms of the flexibility you have over the next few years, whether you see yourselves, or the Basin in general, the industry in general, having any bottlenecks? Anything there would be great.

[Jody Elliott:]

Ryan, I think as far as our field development planning, that's one of the key things is that we try to get ahead of the game, whether it's water disposal, frac water movement, gas takeaway, oil takeaway. We try to plan those things in advance and build out ahead of when that need is going to be. So whether it's southeast New Mexico, we announced the startup of the joint venture gas plant recently in the Delaware. Those are all things to stay ahead of the infrastructure game. The new acquisition has considerable infrastructure, fresh water, salt water infrastructure, 4 million barrels of frac storage, 40 miles of distribution line. It has produced water treatment systems, 15 SWD wells, gas compression. So all those things that have been done extremely well in this acquisition are the same things we do on our own assets. And maybe Vicki or Chris will want to address the greater Permian infrastructure takeaway.

[Vicki A. Hollub:]

Ryan, I would just say that with respect to our takeaway capacity out of the Permian, we're very well positioned there. We have excess capacity above and beyond what we expect our growth to be. That's been a little bit of a drag on our Midstream business here recently, but we expect that to be a real benefit to us going forward.

[Ryan Todd:]

Great. Thanks.

[Operator:]

The next question is from Roger Read of Wells Fargo. Please go ahead.

[Roger D. Read:]

Thanks. Good morning. I guess maybe to come back to expectations in the fourth quarter here. How should we think about the acquired volumes coming in as part of the guidance of the 120,000 BOE per day for Permian Resources? Does that imply that Permian Resources is actually declining here in the fourth quarter and that adds on? Or how should we think about the exit rate you indicated would be higher?

[Jody Elliott:]

Roger, the 120,000 BOE per day includes our estimate of the acquisition. So there's some modest decline in the base core business pre-acquisition. Again, the activity level is ramping up. As you know, when you're doing multi-well multi-pad development with zipper fracking, the production comes lumpy. So a lot of that activity happens in the fourth quarter and the production will come very early in the first quarter of 2017.

[Roger D. Read:]

Okay. So potential for a little bit of – if things go really well, we can see it in December, otherwise thinking about it as a 2017 event?

[Jody Elliott:]

That's correct.

[Roger D. Read:]

Okay. And then can you walk us through with the acquisition here a little bit? The 700 locations obviously indicate potential for significant upside, some of which clearly will be price-driven and some of which is going to be based on drilling. How did you come to the 700? And what's an idea of how we should think at say maybe $60 oil in 2018 where that 700 locations could go?

[Christopher G. Stavros:]

Roger, the 700 locations is based on our conservative nature with assessing our developmental properties. So that's the minimum location count in the Wolfcamp A, the Wolfcamp B, Second Bone Spring. We're very optimistic about the two additional benches in the Bone Spring and in the Wolfcamp debris flow, which sits between the Wolfcamp A and Wolfcamp B. At $60, again, that inventory just continues to grow, whether it's tighter spacing. The other aspect is we continue to improve both well performance and our execution results. I mentioned that we have some technology things working in the drilling area, which we believe can be a step change in multi-well, multi-pad development. And so as we test those in the fourth quarter and in the first quarter of 2017, we'll be more able to talk about some of those details. But we think that would generate even more bench activity, not just in the acquisition, but on all of our core areas.

[Roger D. Read:]

Okay. Great. And just a final question. You mentioned this acreage was fairly HBP. Is there a percentage you can give us that maybe isn't? Give us an idea of maybe where the one to two rigs initially have to be focused.

[Christopher G. Stavros:]

I think it's north of 80%. And a lot of those are just clock drilling obligations as opposed to expiry issues.

[Roger D. Read:]

Okay. Great. Thank you.

[Operator:]

The next question is from Brian Singer of Goldman Sachs. Please go ahead.

[Brian Singer:]

Thank you. Good morning. I wanted to go back to the comments with regards to the CapEx cash flow for 2017. And if we take the acquisition side of things away and just look at the strategy with regards to growth versus free cash flow versus dividend, I think in the past you talked about wanting to try to cover that dividend with free cash flow. And perhaps $50 is just the low end of your oil range and will ultimately go higher, but I wanted to see if there's any change in your strategic thinking about the importance of covering the dividend with free cash flow, recognizing that Oxy is unique in even having free cash flow of this magnitude in the first place.

[Vicki A. Hollub:]

I'll tell you, Brian, we consider that, covering our dividend with cash flow, to be a priority for us. It's very critical. But we do view 2017 as a transition year. We don't expect prices to get to the point where it's reasonable for us to cover our dividend with cash flow until 2018. That's why we're ensuring that all the decisions that we make will enable us to get through the transition year of 2017. We have other levers we need to pull if that supply/demand balance doesn't narrow in 2018, so there are other things that we can do. But we're certainly expecting an oil price that is certainly closer to our cash flow neutral standpoint.

[Brian Singer:]

Great, thanks. And then shifting to the Permian, the acreage position as you highlighted it is very vast. Can you talk to whether you see your interest and the need for additional acquisitions to achieve the type of scale that you desire as you're doing with this acquisition here to be competitive to or more competitive with others in the basin that have contiguous acreage positions?

[Vicki A. Hollub:]

We viewed this acquisition as a very unique opportunity because of the reasons I've described. We don't see any need to acquire any additional acreage unless it's smaller bolt-ons that do provide us the efficiency to develop what we currently have, and those are the types of things that we would target going forward. Our inventory is huge, and we still haven't fully appraised the inventory we have. So what we view this to have done is in the greater Barilla Draw area, what it's done for us is just, in addition to the 59,000 acres associated with the acquisition, we have in that general area around 100,000 acres. So that gives us a really sizable position that's bigger than most positions, and that's why this was so important to us. It was a special case because, as you've noticed, we haven't really acquired anything in the last couple years. And this is the reason, we're looking for those things that provide us a unique opportunity to do something that's what we consider to be really a step change in a given area. Looking at the rest of our acreage, we're spending quite a bit of time and effort to appraise the rest of what we have and to rank it in terms of development. So now we feel very comfortable with the Greater Barilla Draw area. Southeast New Mexico is in prime position for aggressive development, and we have some areas in the Midland Basin as well. What we have to do now is we've got our appraisal team working on those parts of our acreage that are outside of those areas.

[Brian Singer:]

Great. Could you characterize the sum of the acreage that you believe now is developable and to the comment you just made?

[Jody Elliott:]

I think we'll update the full inventory picture in the fourth quarter. To give you a little bit of color, with all the appraisal work and all the subsurface work we're doing, we've changed the landscape of that inventory. We've doubled the lateral miles of inventory. The NPV on that existing inventory is up over 66%. We have 27 rig years of inventory at less than $40 a barrel, so we've really grown the existing inventory. This asset, it's really – the acquisition asset is really about just taking ownership in an already derisked core area with incredible infrastructure. So that's going to allow us, when you think about sand, when you think about water, when you think about logistics, people, supply chain leverage, it really allows us to hit all of those key drivers that lower F&D cost and keep our OpEx costs really low.

[Brian Singer:]

Thank you very much. I really appreciate it.

[Operator:]

The next question is from Evan Calio of Morgan Stanley. Please go ahead.

[Evan Calio:]

Hey, good morning, guys. You significantly beat Permian Resources volumes guidance for the second time in three quarters. And if I shift to the guidance, what are the ranges on the 2017 fuzzy bars for Permian Resources on slide 22? I'm just trying to square the circle here of whether that range reflects the enhanced completions, longer laterals, and increased wells drilled in the presentation, or if it's based on 2015 year-end technology, as are the location counts? It just looks low versus the commentary.

[Jody Elliott:]

Evan, that forecast is based on what we know today. So it's the latest version of our completion designs and our expansion. The fuzziness is really a function of what's the final capital budget going to be that year. But we're not forecasting enhancements or improvements that have not been demonstrated at this point in time. So those are all upside opportunities.

[Vicki A. Hollub:]

And, Evan, let me add to that that Jody and his team along with the support of the subsurface characterization team have beaten their forecast for about what, eight quarters in a row or so?

[Evan Calio:]

Any numbers on the high end of that? It looks like 135,000 BOE per day. Is that right?

[Vicki A. Hollub:]

It's a little bit higher than that.

[Evan Calio:]

Okay, maybe a second one, if I could, on the acquisition. Could you say how much of the acquisition was allocated to Permian Resources versus EOR? It looks close to $21,000 an acre versus the $43,000 an acre headline for Permian Resources, if we back out what you paid for J. Cleo using that cost basis metric. Is that right? And then on the other side of I guess Singer's question is with a larger Tier 1 footprint, will that increase for high-grading your portfolio or potential asset sales? I'll leave it there.

[Vicki A. Hollub:]

I would say that on the net value per acre, we were in the upper $20,000s on what we calculated for that. And with respect to the tiering of the acreage, this certainly gets us what I believe is going to be Tier 1 for us. I believe that this area will certainly be comparable with our best area, which is southeast New Mexico. The fact is that the opportunity to have five benches is going to make the infrastructure cost so minimal on a per BOE basis that I do believe that this is just going to continue to improve.

[Evan Calio:]

And drive – since it would take capital, would there be another high-grading on the back of that?

[Vicki A. Hollub:]

There could be. It really depends on product prices for 2017. We'll continue to balance our capital with our cash flow needs and the balance sheet.

[Evan Calio:]

Great. I appreciate it, guys.

[Vicki A. Hollub:]

Thanks.

[Operator:]

And the next question is from Matt Portillo of TPH. Please go ahead.

[Matthew Merrel Portillo:]

Good morning. Just starting off on the Permian Resources side, I was curious if you could provide any incremental color or commentary around the base design that you're currently utilizing in the Texas Delaware Basin and what you may be testing on a leading-edge basis that may be giving you some incremental excitement in terms of increased productivity on the wells.

[Jody Elliott:]

Matt, it's really basin. It's sub-basin specific, almost field specific in those designs. But in general, it is tighter cluster spacing and higher sand concentrations, and then doing trials to understand where you've hit diminishing returns. But in general, more sand, tighter cluster spacing is generating better results. But combining that with longer laterals has really been the key for us. And as you look at the numbers I talked about on extending lateral length, that's another real benefit for us. In New Mexico, this year we'll average around 5,000-foot laterals. We'll go almost to 7,000 feet next year. In the Texas Delaware, it's a little over 5,000-foot laterals. Next year it will be closer – this is effective lateral length – over 9,000 feet. And in East Midland Basin, we probably averaged – we'll average around 7,800-foot laterals in 2016, and in 2017 that will be over 9,000 feet. So the combination of extended lateral giving us really better EURs, better decline profiles combined with this continued integration of our geoscience with the stimulation design. The drilling technology piece is something that we'll talk a little bit more about in future quarters, but it's really an innovative way to access multiple benches and again leveraging your infrastructure across multiple benches with minimizing your facility cost.

[Matthew Merrel Portillo:]

And just a quick follow-up there, is there any color you can provide I guess just on what the base design looks like today? I'm just trying to reference point in the Texas part of the play specifically where your proppant loading is and where your fluid volumes are and maybe...

[Jody Elliott:]

It's in the 1,750 to 2,000 pounds per foot range, but we've trialed and will trial higher.

[Matthew Merrel Portillo:]

Great, and then just a follow-up question. On the New Mexico side of the border, it looks like you've started to delineate some of your acreage in Eddy County. I'm just curious. As you guys look at additional resource potential across New Mexico, what interest you have in, I guess moving into 2017, in terms of focusing on some incremental zone delineation in the Wolfcamp and Avalon horizons.

[Jody Elliott:]

So New Mexico will be one of the key places we operate in 2017. This year we've spent quite a bit of effort in the appraisal mode in New Mexico, testing the Third Bone Spring, testing the XY, Wolfcamp D. So we will continue as part of our development plans to appraise those other benches. Again, we believe New Mexico has many bench opportunities beyond what we've talked about previously in our inventory.

[Matthew Merrel Portillo:]

And last question from me. I just wanted to follow up on a previous question from an infrastructure perspective. So just to clarify there, I think there's some industry concern that as Permian growth accelerates over the next few years that the main infrastructure bottleneck may become the pipe capacity out of the basin. And so I wanted to just make sure that I understood your comments that you guys feel comfortable over the next few years that there are no pipe constraints or you have solutions in the work that can essentially debottleneck that.

[Vicki A. Hollub:]

I suspect there are going to be pipeline constraints for others, but I can tell you, we have plenty of capacity tied up and we'll be able to actually still contract and take third-party volumes to Houston. We have quite a bit of capacity, so we feel very comfortable with where we are.

[Matthew Merrel Portillo:]

Thank you very much. I appreciate it.

[Operator:]

That concludes our question-and-answer session. I would like to turn the conference back over to Chris Degner for closing remarks.

[Christopher M. Degner:]

Thank you, Kate. And thank you, everyone, for joining us on the call today.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.