PDC Energy Inc (PDCE) 2017 Q2 法說會逐字稿

Greetings, and welcome to the PDC Energy 2017 Second Quarter Conference Call. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Mike Edwards, Senior Director of Investor Relations. Mr. Edwards, you may begin.

Thank you. Good morning, everyone, and welcome. On the call this morning, we have Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; Scott Reasoner, Chief Operating Officer; and David Honeyfield, Senior Vice President and CFO.

We've posted a slide presentation that accompanies our remarks today on the Investor Relations Page of our website, pdce.com. I'd like to call your attention to our forward-looking statements on Slide 2 of that presentation. We will present some non-U. S. GAAP financial the numbers on today's call, so I'd also like to call your attention to the appendix slides of that presentation where you'll find the reconciliation of those non-U. S. GAAP financial measures.

With that, we can get started, and I'll turn the call over to Bart Brookman, our CEO. Bart?

Thanks, Mike, and I appreciate everyone joining the call today. A terrific quarter. Production just over 8 million barrels of oil equivalent, that is a 54% improvement from the same quarter last year. Let me start this call with some important takeaways for today. First, Wattenburg completion designs. They continue to drive improved well performance and a record production level in this basin. Second, drilling efficiencies in the Wattenberg have made another leap forward, helping push ongoing improvements in our capital efficiency and enabling us to drop to 3 rigs in the Wattenberg Field effective fourth quarter of this year. Third, Delaware completions are performing very well, giving us strong confidence in enhanced well performance, particularly in the eastern portion of the basin. Fourth, and one of our challenges, the Delaware cost structure. We continue to see upward pressure on a per-well basis. This is generally due to an across-the-board demand pull on services, and Scott will cover this more in a moment. Fifth, corporate operating costs continue to improve on a per BOE basis, setting all-time lows for the company. And last, in a 50-dollar oil, $3-natural gas world, PDC is positioned to deliver strong operating and financial outlook. As we wrap up 2017 and head into '18, we remain focused on maintaining our strong balance sheet, reducing 2018 overspend levels and pursuing cash flow neutrality in 2019, all while planning to deliver 3-year compounded annual production growth rate of approximately 35% through 2019. David, Scott and Lance will give more detail on these key themes later in the call.

Now let me hit some of the quarterly highlights. Again, production of approximately 88,000 barrels of oil equivalent per day in the quarter, we spud 49 wells and turned in line 38, and we executed on our operating plan without a single significant safety incident. As noted earlier, lifting costs for the quarter continued to improve to $2.50 per BOE for the company. Watttenberg lifting costs were $2.21 per BOE and the Delaware was -- is now under $5 at $4.88 per BOE. From a financial perspective, we ended the quarter with approximately $200 million cash on hand, giving us approximately $900 million in liquidity and a leverage ratio of 1.9x.

Our capital investment for the quarter, $219 million and adjusted cash flow, $143 million. Last, we continue to be very pleased with the overall cost structure of the company, both operating and G&A combined, right in line with our expectations and guidance.

Now let me give some color on how we plan to wrap up '17 and early outlook for '18. As I noted, as a direct reflection of the improvements in our drilling efficiencies, we plan to drop to 3 rigs in the Wattenberg in October of this year. Even with this operational move, our expected 2017 spud count for the Company now stands at 155 wells, that is up from 139 wells. With these extra spuds and our adjusted completion and turn-in-line schedules, we expect to carry additional uncompleted wells into 2018.

The extra spuds, along with higher working interests associated with a recently executed acreage swap in Wattenberg and the modest increases in our Delaware well costs result in our capital budget now targeting $800 million.

On the production side, we are sticking with our 32 million to 33 million barrels of oil equivalent range. But I would guide you to the lower end of this range given our modified turn-in-line schedules and elevated line pressures we are seeing in the Wattenberg Field particularly impacting our older vertical production.

Now on 2018 outlook. Expect our commitment to the balance sheet to remain our first priority as we enter next year. With 6 rigs running in '18, we anticipate our capital investment to be slightly above 2017 levels compared to our base case at Analyst Day, our 2018 CapEx projection represents a reduction of approximately 15% in capital spend from that base case level. We expect continued improvement in our leverage ratio, little or no draw on our credit facility as we exit next year, and from a production gross standpoint, depending on the final capital allocation, we anticipate somewhere between 20% and 30% production growth for 2018. In Wattenberg, expect us to focus on high working interest wells and longer lateral drilling, and in the Delaware, an enhanced focus in the Eastern area, where we are seeing tremendous results. And last, we maintain operational flexibility to add or drop rigs should market conditions materially change.

With that, I'm going to turn the call over to Scott for a more detailed look at our operations.

Thanks, Mark. Good morning, everyone. Operationally, we're extremely happy with the second quarter. Production of more than 88,000 barrels of oil equivalent per day represents a 54% growth compared to the second quarter of 2016 and a very impressive 19% growth from the first quarter of this year. Of note, production out of the Delaware increased by nearly 50% from the first quarter of the year, thanks to a series of successful turn-in-lines and PDP improvements that I will detail in a second. Production in this basin exceeded 10,000 barrels of oil equivalent per day in the second quarter.

Slide 8 goes into a little more detail on the liquids production for the quarter, which increased to 63% of total production. Of note, we grew oil volumes nearly 30% from the first quarter of this year and more than 60% compared to the second quarter of last year. Oil growth actually outpaced total BOE growth.

From an LOE standpoint, our team did a great job again this quarter. As Bart mentioned, we are now a record level for your company of $2.50 per BOE. Included in this quarter-over-quarter decrease in our LOE per BOE is the Delaware Basin improvement of approximately 25% from $6.48 to $4.88 per BOE.

Moving to Slide 9. As Bart highlighted earlier, we are now projecting a 2017 capital spend of approximately $800 million. There are several moving parts that we project will impact our capital program for the remainder of the year. In Wattenberg, we plan to drop to a 3-rig pace in the fourth quarter. We were able to do this, thanks to continued improvements in drilling efficiencies that we are realizing. We'll get into more detail on this on the next slide.

There are 3 main drivers of expected capital on production for the second half of the year. The first is the expected timing of completions and turn-in-lines in the Wattenberg Field. As a result of an acreage trade of approximately 4,000 net acres, which we expect to close in the second half of this year, we anticipate a net $5 million to $10 million increase in capital associated with drilling activity on acreage we are trading into. We are, therefore, deferring a few projects to 2018 to manage our 2017 capital spend levels. These changes have resulted in a less active fourth quarter than previously planned and a handful fewer turn-in-lines in 2017 than originally expected. As a reminder, this is very similar to our second half 2016 Wattenberg program and in our mind, a prudent move considering that the anticipated midstream expansion isn't scheduled to come online until the fourth quarter of 2018.

The second issue relates to line pressure. We've experienced a hot summer, and line pressures have increased in the field. While DCP added capacity with a bypass in July, the continued success from not only PDC but our operators in the basin, continues to bring incremental volumes onto their system. Generally, this higher line pressure was expected. However, we've slightly increased our estimated curtailment factors for the remainder of the year and believe that our updated full-year guidance captures the current environment.

The third item is in the Delaware, where we plan to operate 3 rigs for the remainder of the year. We are seeing some additional pressure on service costs that have been factored into our remaining drill and complete estimates for 2017, and we'll continue to manage at this as we move forward.

Something that is worth pointing out is that thanks to adding the third and fourth rigs earlier this year than originally planned, we have gained some flexibility to meet HBP initiatives through much of next year with just 2 rigs should the cost or price environment dictate.

Moving to Slide 10. Here, we provide a little more detail on our Wattenberg drilling efficiency gains. The charts on the bottom of the slide show not only the current spud to spud drill times we are realizing but also the improvements made over the past couple of years. As you can see, truly remarkable work from our team as we're drilling SRLs and MRLs twice as fast as only 1.5 years ago.

With current drill times of 6 days per an SRL, 8 days per an MRL, and 10 days for an XRL, we expect a 3-rig pace to deliver close to the same lateral footage as the 4-rig pace we showed at our Analyst Day in April. Lastly, the table on the right shows the impact this is having on our 2017 program. Our lateral feet drilled for the year is expected to increase by more than 15% despite dropping a rig for a full quarter.

In terms of completions, Slide 11, shows more detail of the tighter completion stage spacing in Wattenberg. We have been testing on both our SRL and XRL wells this year. As a reminder, for the SRLs, our previous type curve was based on 200- to 225-foot spacing, with the testing this year based on 170-foot spacing. As you can see, performance from the new design is slightly above the type curve. The graph on the right shows a comparison of extended reach laterals with 140-foot spacing to our type curve based on 170-foot spacing. The 140-foot spacing design clearly provides a production uplift through the first 120 days or so and with only a minor cost increase.

The economics are solid. A word of caution, before starting to bake this into any assumption, we've only performed this test on a handful of wells and only have a few months of data. The team is also working on tweaking the 170-foot completion design to replicate the results of the 140-foot design but at a lower cost.

Shifting gears to the Delaware Basin. We'll start with an overview of the quarter on Slide 12. Capital per well has been higher than first quarter due to increased service company costs and our continued efforts to gather science to further evaluate our 3 areas. We have 5 spuds and 6 turn-in-lines for the quarter, and as I mentioned earlier, increased production by nearly 50% to over 10,000 barrels of oil equivalent per day in the second quarter.

In our Western area, we turned in-line 2 Phillips State wells, that so far, have been disappointing and below our expectations. We continue -- we plan to continue monitoring these wells, and at this time, plan to use the data in part of a technical study and evaluation of the area. As it stands, there are no plans for drilling in this area for the remainder of 2017 or 2018, but we're confident that the team will figure it out as we continue improving operationally and monitor nearby results.

Our central and eastern areas are a different story. In the central, both Greenwich wells are exceeding type curves and oil mix expectations, and recent midstream investment has increased our PDP in the area. More on this in a minute.

In the Eastern area, our latest turn-in-lines continue to deliver exceptional results above our expectations. We are shifting our near-term focus to longer laterals in this area.

Taking a closer look at the Eastern area wells, you can see updated performance from all wells, including the Kenosha and Lost Saddle on Slide 13. I'd like to call your attention to the red dash line on the left-hand graph. This is the average cumulative production of the 6 wells shown. As you can see, at about 150 days it is nearly doubled that of an acquisition type curve.

On the right-hand side of the graph, we give more detail on the Kenosha well, our first 2-mile lateral or XRL in the basin. This well has a 30-day peak IP of approximately 2,300 barrels of oil equivalent per day but more impressively, has been producing above 2,000 barrels of oil equivalent per day for the past 100 days. Based on casing pressures and other data, we anticipate this well to continue on this flat trajectory for some time. We anticipate turning in line 6 additional XRLs in the Eastern area this year.

Moving to Slide 14. You can see the early results of our central area, including the 2 Greenwich wells; the Greenwich 4H, which is shown by the maroon line on the production plot, had a 30-day peak IP of over 1,400 barrels of oil equivalent per day or nearly 200 barrels of oil equivalent per day per 1,000 feet. This well has been reproducing 55% oil, which is above our expected range of 30% to 50% in the area. The Greenwich 3H, a Wolfcamp B well, had only 1,200 feet of lateral completed. But as you can see, it's performing extremely well on a normalized basis. Obviously, we wish we were able to complete the entire lateral, but we are very happy with this well in terms of a data point for the area.

The Liam and inherited HSS state wells are both below type curve. The Liam has seen seeing improving production since we pulled the tubing and returned it to production after a shut-in for an offset operator completing its well. With production this past week of 300 barrels per day of oil and 3 million cubic feet of gas per day, specific to the central area or the integration activities and midstream investments shown on Slide 15.

The graph shows we've been able to increase our PDP on this group of 7 wells in the area by almost 1,000 barrels of oil equivalent per day since we took ownership last December. We have been really pleased with the work of our production team to drive performance on the base PDP wells. This is a direct result of our upgrades that our operating team has made over that time, including upgrading poly lines to steel and increasing compression capacity.

In June, we doubled our compression capacity in preparation to add the 3 additional Greenwich wells we are currently drilling.

In recap, the second quarter was extremely strong from an operational perspective. Production increased 20% compared to the first quarter, with oil production increasing 30% over that same time. Our operating cost structure continues to improve with Wattenberg LOE down to $2.22 per BOE, and Delaware LOE, decreasing 25% from the first quarter.

We continue to make strides from a drilling efficiency standpoint in the Wattenberg and as we covered, are starting to build some solid momentum in terms of well results in the Delaware.

With that, I'll turn the call over to David Honeyfield to discuss the financial results for the quarter. David?

Thanks, Scott, and good morning. Slide 18 looks at the 3 and 6 month GAAP metrics for 2017 and 2016. I know that at times people tend to look past the immediate quarter results, and I hope that folks take a minute and try to put into perspective the significant uplifts in production and operational improvements that are driving our overall margin contribution. The pace of production growth, coupled with a strong and resilient balance sheet and flexibility in our operations, are key differentiators where PDC is delivered.

Our second quarter results this year clearly benefit from the 54% production increase and 25% increase in realized price for BOE over the second quarter of 2016. The commodity market improvement over the first half of '17 helped, and we've also continued to aggressively manage our oil sales in Wattenberg to produce and further improve net realized oil price.

Production cost and G&A on an absolute basis increased 72% and 25%, respectively between periods, but as I will show you on the following slide, our per-BOE metrics continue to trend in the right direction.

Net income for the quarter was $41.3 million compared to a net loss of $95.5 million in the second quarter of last year. The primary driver behind this improvement was the $103 million increase in crude oil, natural gas and NGL sales between periods, combined with the effect of the mark-to-market, or commodity-derivative instruments.

The last thing I'd like to call out is the production by basin chart on the bottom right-hand side of the slide where we show the strong growth for the company. We were able to continue a steady growth profile in Wattenberg while layering on a solid wedge of production associated with our Delaware assets that we highlighted earlier in the call.

Moving to Slide 19, we show a summary of our production costs both in terms of total dollars on the income statement on a per-BOE basis. As a reminder, when we discuss production costs, we include LOE, production taxes and transportation gathering and processing or TG&P.

As Scott touched on, our LOE cost per barrel of oil equivalent continued to improve from the first quarter. The sequential quarter comparison highlights the operating team's progression in the Delaware and the continued drive for operating efficiency across the company. What I find particularly relevant is remembering that the acquisition of the Delaware assets occurred at the end of 2016, meaning that the second quarter '16 results don't have any Delaware activity included. The fact that we incorporated brand-new LOE and TG&P dollars from the acquisitions, and we were still able to reduce our per-unit cost in these categories is a notable operational achievement.

Moving to Slide 20. We highlight our adjusted EBITDAX and adjusted cash flow from operations. Please see the appendix for the reconciliations of our non-GAAP metrics. Our adjusted EBITDAX shown on the right-hand side of the slide was $200 million for the quarter, just shy of the $218 million of capital investment. As a reminder, this adjusted EBITDAX calculation now includes noncash stock-based compensation as well as exploration and G&G costs.

Also included this quarter are the proceeds we received from the sale of our MK note of approximately $40 million. This was a solid transaction that provided a nice boost to our overall liquidity. Adjusted cash flow from operations increased 27% from the second quarter of last year to almost $143 million, driven largely by increased crude oil, natural gas and NGL sales and the net change in fair value of unsettled commodity derivatives.

Moving over to Slide 21, we take a look at our leverage, liquidity, and hedge positions. As of June 30, we had $202 million of cash, and when combined with our undrawn RBL facility, we had just over $900 million of liquidity. Our leverage ratio as defined in our revolving credit facility agreement, improved again on a sequential quarterly basis to 1.9x.

In terms of hedges, we're well-protected in the second half of '17 and have a solid foundation in place for 2018, something that adds to the operational flexibility we've highlighted.

We have approximately 70% of our expected second-half oil production hedged right at $50 per barrel, and 65% of our expected natural gas production hedged at $3.40 per MMBtu.

In terms of looking forward, we continue to execute a hedging strategy that considers the robust economics of our capital program that uses hedges to help insulate these returns. We've added some additional layers of hedges since our last update that are reflected in the table.

As we look at our 2018 coverage and our current thoughts on capital investment and production levels, we are at roughly 50% hedged for crude at over $50 per barrel, and nearly 60% hedged for natural gas at $3 per MMBtu. And this is based on the criteria that Lance will describe here in a minute. This strategy of layering and hedges is particularly useful when you consider the tremendous return profile of our overall capital program. Layering in the hedges is an effective mechanism to help maintain solid and relatively predictable near-term visibility into our cash flows.

We certainly are evaluating the details of how our capital program will look in 2018 and beyond and the growth profile we can deliver. We will be going through our budgeting process over the next few months to finalize our plans. The flexibility we've developed certainly provides a constructive view of being able to manage our outspend to tighter levels in 2018, with the ability to fund much of this with cash on the balance sheet, while decreasing our leverage ratio and delivering strong production growth.

A quick look at our updated production and financial guidance for the full year 2017 is on Page 22. Scott already addressed some of the moving pieces that affect our production and capital outlook for the year. We previously described being in the top third of our 30 million to 33 million-barrel of oil equivalent range in 2017. Given the adjustments for timing of completions and the higher line pressures in the Wattenberg gathering system reflected in recent months, we're probably weighted towards the lower end of the 32 million to 33 million BOE band.

The capital number of approximately $800 million includes a bit of additional capital from the acreage trade that Scott mentioned that we're looking to close before the end of the year and the adjustment to the per-well capital costs in the Delaware.

In terms of operating costs, we're now expecting to be in the bottom half of our LOE range of $2.65 to $3 per BOE, reflecting the continued growth of our production contribution from the Delaware.

To echo Bart and Scott, the second quarter was very strong, and we delivered on our growth profile and cost management objectives. The outlook on the commodity price continues to be volatile, yet we're in a select group of companies that have a solid liquidity profile, a very healthy leverage metric and the ability to continue to grow the company at a robust space while managing our capital investment program to deliver great returns.

With that, I'll turn the call over to Lance Lauck for a high-level look of the 2018 and '19 in a $50 and $3-dollar world.

Thanks, David. In this final slide of our second quarter call, we wanted to provide high-level scenario utilizing the price forecast close to the current strip. This case represents a reasonable scenario of how we would likely manage the business in a $50 and $3 price world. In this model based on several input assumptions from where we currently sit today. Also keep in mind this case is an early outlook for 2018, as our official 2018 budget is expected to be completed towards the end of the year.

As you'll recall from our April Analyst Day this year, the company provided 2 longer-term growth scenarios through 2020. The first was our base case that provided a higher growth outlook based upon oil increasing to $65 per barrel of oil in 2020. The second case was our resilient case that demonstrated the resilience of our portfolio and strength of our balance sheet if faced with a distressed $40 oil and $2.50 gas price world over the next few years. The key take away from this scenario we're presenting today is that it demonstrates the flexibility and optionality of our portfolio to drive capital efficiency in a $50 and $3 world.

Let's look first at some of the key input assumptions. This case utilizes just 6 total corporate rigs through 2019, which is equivalent to an approximate 7-rig case due to the increased efficiencies in Wattenberg that we talked about earlier. The rigs are held flat through year-end '19 and that compares to our base case at Analyst Day, which had ramped to an 11-rig case exiting 2019. This flat 6-rig case results in a reduction in capital spending of approximately $400 million over the 3-year timeframe ending 2019 versus out of our base case at Analyst Day, and it includes the higher per-well CapEx in Delaware.

Even with his reduced spending, we still model a 3-year production CAGR of approximately 35% from 2016 to 2019. In fact, our 2019 midpoint volumes projected in this $50 and $3 case are only 5% below our base case from Analyst Day. Importantly, we project cash flow neutrality in 2019, also similar to our base case from Analyst Day.

We also project a year-end 2019 leverage ratio of only 1.1x despite an $11 per barrel of oil price reduction in this case, compared to the 2019 oil price assumed at Analyst Day.

Finally, the table in the lower right provides a high range of output on a year-by-year basis through 2019 in our $50 and $3 case. First of all, our capital only increases about 10% per year. Our projected outspend of estimated cash flow decreases in each year from about 45% this year to 25% in 2018, to anticipated cash flow neutrality in 2019. Also note that a revolver is expected to be only minimally drawn in 2018 and 2019.

Our production profile is more back-end weighted versus our base case at Analyst Day, and that's due primarily to higher anticipated midstream curtailments through most of 2018 until new third party midstream facilities are operational in the Wattenberg Field. For 2018, we project a very solid 20% to 30% production growth. Our primary midstream provider in Wattenberg is working closely with PDC to plan for and build out additional midstream capacity from the basin. However, PDC and others on their system are experiencing very strong well performance from our horizontal programs, which we believe will elevate line pressures until plant 10 is in operation in late 2018.

For 2019, and again based upon our current estimates, we're projecting a strong corporate production growth of 30% to 40% due to the anticipated increase in Wattenberg midstream capacity, plus the completion of additional DUC wells in Wattenberg in that year.

So to summarize, this case demonstrates the flexibility the company has to drive capital efficiency in a $50 and $3 world. And more importantly, it serves our commitment to our balance sheet while still driving strong value-added production growth. So with that, I'd like to turn it over to the operator for Q&A.

(Operator Instructions) Our first question comes from the line of Brian Corales of Howard Will.

Just to start on the line pressures. Is that based -- is it -- PDC, is it basin-centric? And how much -- can you maybe quantify how much you think is going to be curtailed?

Yes, Brian. This is Scott. I think when you look at the overall picture, we're seeing line pressure elevated pretty much across the field on all of our wells. And it's obviously summer time right now and that's what we normally expect. And we've modeled that in through this summer and expect things this fall maybe to be a little higher than we had originally planned, but still see it -- as we roll out of the summer and into the fall, the cooling temperatures will help relieve some of that pressure. And then rolling into next year we'll obviously work on that as we get towards our budget numbers. But again, we think we've pretty well captured it in that number between 32 million to 33 million barrels of oil equivalent. And as far as percentages or actual numbers, I just don't have those at hand here.

I guess what I'm trying to get towards is, the guidance still looks a little conservative to state that you're going to be at the bottom end, and I'm just trying to get there because it's difficult to do that, I guess with the amount of completions you have going forward.

And again, that range is 32 to 33, we want to make sure that's clear. It's not 30 to 33 anymore. That's something I want to be sure we're clear on. But also, Brian, don't forget that we did delay completions at the end of this year. And that is part of what is rolling through the system as well. So elevated line pressure being a part of it and then the completion process being delayed until the first of next year really covers those 2 things. And that's why maybe that perspective you have is something that is more complex than just line pressure alone.

Brian, this is Dave Honeyfield, too. I think the other thing that we called out in our 10-Q that we filed earlier today is that we do expect a nice uplift again in Q3. And then with what Scott described, we'll probably be kind of flattish in Q4. Certainly there is some ability to see some upside there I think, if some things go better than as planned, but I think that gives you -- hopefully gives you a pretty good perspective of how things are managing out.

And then one last question. You talked about inflation in Delaware, basically everywhere. Can you just talk about what is the primary thing that's driving that outside -- I know that it's a very active basin, but is it on the completion side, the sand side, or -- and on top of that, what is the current well cost for a 2-mile lateral?

Yes. When we look at this overall, Brian, we're looking at about a 15% increase, maybe a little over that from the last numbers we published, and so that will give you a good idea of where we're at in terms of costs. When you talk about where that's coming from, it's coming from really across the board costs. It's drilling completion -- everything we do is just a little bit more money out there right now, and so that's what we're seeing happen. And I think it's pretty much a part of the Delaware process right now for all of the companies. We don't see any particular area where you'd go that -- that's the biggest movement in the capital cost if you want to look at it that way as well.

Our next question comes from Mike Scialla of Stifel.

Since you've had the Delaware properties now almost about a year and you've shown well performance versus your type curves, for the most part, outperforming. I just want to see if you could comment on the inventory versus your acquisition economics. Where have things gone better than expected? Obviously, the Western side is not working out as well so far as planned. If you can just make some general comments on the overall inventory versus what your original expectations were?

Sure, Mike, this is Lance. At the time of our acquisitions, we had 785 wells in inventory that were almost all 1-milers with the exception of the Western acreage block that we had 40 wells on that were 2-milers. From where we sit today, we are testing and plan to test downspacing in the eastern area that we'll look to hopefully increase that inventory count for the company. As you may recall, the Eastern side, we had a total of 12 wells per section in inventory, 8 in the Wolfcamp A, and 4 in the Wolfcamp B. And we're going to be testing tighter spacing than that later this year and on into next year. So we look to see an improvement in the inventory with the work that's being done on there today. In the central area, we continue to drill, for example, on this Greenwich area where we're drilling 3 wells there now and will with that have various thoughts around the different spaces between wells there also, so that will be a good opportunity in the central area with the Greenwich areas to look at some testing on the spacing there as we see it. And so that's something that'll be a focus on for the company as well. So from where we sit today, we haven't changed our view just yet on inventory, but what we're doing is gathering that key technical information, things that Scott talked about with some of the technical work that we're doing. We'll gather that information to have a better view on that going forward.

Mike, this is Bart. Let me just add a little more quantitative to what Lance. On Slide 12, if you look, we did call out the number of locations in the original acquisition model. And just to kind of restate what Lance just talked about, that Eastern side, we had 410 locations, those were 1 milers. Obviously, we're drilling a lot 1.5 and 2 milers, that's going to change that number, but overall, we feel like our spacing -- there's upside in that outside 410 from a net lateral feet. And then obviously, we want everyone to understand we have tremendous confidence in well performance in that area as far as the upside production performance per well. And then the central area was 335 -- and again I think we have a lot of confidence, particularly with some of the B results we've been seeing, that that number is going to grow with time. And then the only area we're scratching our head a little bit right now, but again, as Scott said, we'll figure it out, are the 40 locations over in the Western area.

That's helpful. Can you talk about what kind of things you're looking at on the Western side? And what do you think went wrong there? Any more detail on that?

Yes. Mike, this is Scott. And I guess when I look at that at this point, first of all, we're very early in those 2 wells' life, and there's a lot of things that we're looking at in terms of the productivity of those wells. Did we land them in the proper chunk of rock in the A section, or could we move those up or down? In addition, are they in the best area from a standpoint of the overall acreage position we're looking at? And then finally, we've got logs and some other data that we've gathered out there, but we're looking at other zones within that 3,000 feet of rock that we have out there, and still have confidence in finding that proper combination of lateral length and location within the rock to make that area work. There is a heck of a lot to learn there yet though. As everybody knows, when we looked at that, there were a limited number of wells out there, and there still are a limited number. We've added 2, but we are also watching the offset -- offset operators drill out there to understand what zones they're looking at. And we have another benefit in that we still have time and I think that's another thing that we can take some time here and really study what we've done.

Our next question comes from Mike Kelly of Seaport Global.

Just trying to understand the range of guidance that you gave in 2018, and really just pick your brain. What would cause you to come in at the low-end of that range -- the 20% to 30% range, and conversely, the high-end? My thought is that it's probably Wattenberg volumes. Maybe just give us a little more context of how volatile that could potentially be in '18 and what you've got factored into the guidance right now.

Mike, I'll take a stab on this and then turn it to some of the rest of the guys for some comments on it. So we look at 2018 with a 20% to 30% production growth, I would say the primary factor on the range of that is going to be around the line pressures in the Wattenberg Field. I mean clearly, it's a -- we look at additional curtailments there given the success of the program, given the success of what some of the other companies are doing with the success of their horizontal drilling programs and that's one of the key drivers for that range that we're talking about there with the 2018 numbers. Clearly, we continue to drill and watch the performance from our Eastern area, in the Delaware, where you have substantial outperformance in the Eastern Wolfcamp A wells. That's something that's very positive to us that we're watching and after 120, 150 days, very good performance. So we're watching that uplift and seeing how that continues over time, that could be a very good benefit to the company. Also in the Central area, with the additional midstream work that we've done and expansions there for Delaware, we look for opportunities there to improve line pressures, and be able to get our wells online and connected there for production in the Delaware Basin. So that's important to us as well. And also with this 4,000-acre trade in Wattenberg, again, we have various synergies that we look to get from that, that continues to drive capital efficiencies. We are very pleased with what's going on with the Kersey area block that we have. But those are some of, I think, the key drivers of the see for production guidance. And that's -- and Mike, just from where we sit today, we've got a lot of work to do, we'll continue to watch how line pressures move over the next couple of quarters. You'll have a better handle on this probably later towards the end of the year when we get down to our actual 2018 guidance and budget [talk].

Got it. Just following up on the line pressure. How much -- is this truly kind of a vertical -- an issue for your vertical production, or you can just see horizontals get clipped as well? And what is kind of a good estimate for your current production stemming from the legacy vertical wells?

Yes. Mike, this is Scott. As far as the overall production look we have right now, we're in that probably 5% to 7% and 5% to 8% of our production is from the vertical wells, and they'll be the most impacted by the higher line pressure. When you start to talk about what other wells will be impacted, obviously, the older wells will be -- the older horizontal wells will also be impacted by the line pressure, probably not as much because they do have energy to buck that pressure. So really, it will be a combination of all those. The newer wells will be pretty well able to move through the system, and that's part of our I guess blessing, when you look at we have a tremendous amount of new production that keeps coming online as a result of the drilling we're doing.

Okay. And just wrapping all that up, is this -- do we see this kind of ultimately getting figured out, in your opinion by the end of '18 into '19, or is this going to be kind of just something that is a thorn in your side potentially for years to come?

Mike, that's a great question. We spend a lot of time with our from primary midstream service provider out here, and we have a lot of confidence in the future of their facility expansions and our ability to put wells into their system and get back to normal line pressures. In fact, our primary midstream provider yesterday, approved the second plant to be installed in the Wattenberg area, which -- the first and second plant or they call it plant 10 and 11, now gets -- and will add another 400 million a day of capacity in the area. So we work real closely with them as far as our projections for drilling in the future. They look at all the volumes that is coming onto their system and they're doing a good job projecting that out. I think we think long-term about what all this could mean -- and we feel confident as we model out for many years in the future, looking at our gas volumes and what the capacities are going to look like for the midstream. So, no, I think this is something that is sort of a -- I would kind of classify it as a temporary elevated line pressure timeframe, but it's also something that we see clear line of sight to get the line pressures back to normal and back to a place that will continue to allow continued growth. And that's why when we look at 2019 versus 2018 growth, we're at 30% to 40% corporate growth in production in 2019, and that's because of the timing at that second plant is scheduled to come on midyear 2019. So a lot of additional capacity coming to the system at that point in time.

Our next question comes from Tim Rezvan of Mizuho.

I wanted to switch gears a bit and go to Slide 13 where you give that Kenosha well performance, not very typical of this flat decline that you've seen. Is that because the well was put on ESP or is there something else happening? And is that a production trajectory that you've seen from other wells in that area?

It's an interesting well in that it's a 2-mile lateral. And we don't have it on artificial lift, it's a flowing well. It's a very strong well. The pressures mirror up to the type of production profile you see. We're seeing very strong pressure response to the completion. And I think we're looking at a well here that has got a lot of horsepower behind it well into the future and when you combine that with the idea that we're still cleaning it up, if you want to call it that, in that we're still producing a substantial amount of water associated with the original completion, that well -- it just looks like it's going to be a phenomenal well to us. And it's got the right combination of I guess, bringing it online and not getting too excited about overproducing it early, and a really good combination of that coupled with good completion and the right idea about how to produce it into the future.

Is it fair to say this is a managed flowback?

It is a managed flowback, that's correct. And we do that across our wells in the Wattenberg and we're watching very carefully to make sure we don't overproduce them early. And if over time, and I'm saying over a long period of time, not over the next couple of wells, but we could probably get more aggressive with these wells if we see that it's not affecting them.

Okay. If I could go back to the Wattenberg, I noticed you gave your updated turn-in-line cadence for standard, your middle and then extended reach. The number of total turn-in-lines is down but I noticed the percent that are extended reach laterals is up pretty sharply, up 14 versus your prior estimate even though the total number turn-in-lines is down. Should we expect those are going to be late 2017 turn-in-lines? I'm just trying to mesh -- it looks like your total lateral feet completed is probably higher, and you have high line pressure issues. So can you help me kind of understand the different pieces there?

Yes. I'll do the best I can with that. When you look at our completions schedule, we're going to have these wells online, all up -- obviously, we'll be doing fracking in that middle of fourth quarter timeframe for the year. So these wells will all be online, not -- I guess I would say not necessarily later the year but through the rest of the third quarter and early part of the fourth quarter. And with that comes a combination of extended reach laterals and the SRLs, particularly. I guess when you look at how that's -- is that going to flow across the quarter and a half that we have left for completion purposes, I don't really have a feel for that so I guess that's the best description I can give you at this point.

Okay, that's fair enough. I can talk with Mike offline on that. And then, if I could just sneak one last one in?

And, Tim, one last point on Scott's comments there. Yes, the 2 milers and the pace as we go through the second half of the year, we're going to have a lot of long lateral wells coming online as we approach the beginning of next year, and then we obviously, I think over 20 turn-in-lines rolling over in the next year, along with our 6 -- potential 6 rigs. So we're going to have an incredibly strong -- similar to what happened last year, we're going to have an incredibly strong first quarter and second quarter of next year, in both basins but in particular, up in Wattenberg. And Scott and the team are really trying to just pace all these in that Kersey area so that we can kind of just spread it out over time related to some of the higher line pressures we're experiencing. So there's a method to some of this madness of what we're try to do spreading these out over time. But it is setting us up for a very strong first quarter of next year.

Sure, sure. If I could just sneak one last one in. Can you give a little more color on the trade that you did kind of on where in your footprint that the acreage was, and was there a cash outlay associated with that?

Yes. So the tray was actually 4,000 acres that we executed there in the Wattenberg Field. And basically, what it does is it just continues to pull acreage into more of sort of our key focus areas within the middle core that we have. And it allows us to enable us to drill the longer laterals and have some of that efficiency the same way. There's no cash that traded hands as part of the deal, but as part of that, we did pick up $5 million to $10 million of capital as part of that trade on increased working interest in wells that were drilled there. So a nice trade and very thankful to do it, and it's a win-win for both parties.

Our next question comes from Neal Dingmann of SunTrust.

Lance, maybe a question for you, potentially Scott. Just looking at -- you guys have been pretty ahead of the curve as far as just infrastructure buildout in most of your Delaware. Could you just talk about the magnitude that you'll have for the remainder of this year and into '18, and then how that fits into your cash flow neutrality estimates?

I'll start out, and talk more about this year, and then Lance, hopefully, you can fill in on the rest of the 2018 plan. At this point, we've got that $35 million that we budgeted for this year. And it looks like we'll spend most of that, Neal, as we move through the year mostly on well connects, but also we're continuing to add water wells, frack pits where needed, waterlines in all the different areas that we're working in. And I guess those have come in very handy, I guess. This early period, you can see some of that benefit of the increased production on those PDP walls, something we really weren't expecting, but we really are excited to have it. And we will continue to do those kinds of things as we see benefits. But more importantly, we're really just connecting the new wells, getting that setup. And oftentimes, I think that it's important to recognize, we're overdesigning the facilities that we're putting in place in order to prepare for the future. And I think that's part of what -- when we look at this, we're not putting in 4-inch pipe if we need a 4-inch pipe. We're putting in pipe that will benefit us over the long-term. It's something that is an obvious expenditure at this point, but it's greater than you want to spend but necessary for the distant future, and I mean, over the next 2, 3, 4, 5 years. Lance?

And Neal for 2018 and from a modeling standpoint, we're still just using an estimate of approximately 10% of the Delaware D&C CapEx to be equal to the Delaware midstream capital. And again the primary use of that is connecting the wells that will be drilled based upon the 3-rig schedule, and continue to work with various infrastructure, with water supply wells, water disposal wells, as part of that. Having the midstream ownership here requires additional integrated work between all of our teams to put it together. But at the end of the day, the ability to move water through the systems here and dispose into our disposal wells is a very efficient way to handle the water, and have control of our destiny from gas gathering type of services as well. So all this is in there to continue to help reduce our overall operating cost. And for the second quarter this year, we were below $5 a barrel equivalent. So very pleased with all the results that we have and our ability to be in control of our destiny as far as timing of well connects and managing the margins from the field.

Good color, Lance. And then just lastly, just on the -- I forget, Scott, if it was you or if Bart was talking about just the Delaware service costs, the variability. I'm just wondering what you sort of perceive, how you sort of see that exiting the year? And I know some others have locked in proppants, some others will lock in rigs longer-term, those sort of things. What are your thoughts around that?

Yes. We're still seeing costs move a little bit, Neal, but we're seeing them settle down. And obviously, it's all a function of rig count. As the rig count slows down or speeds up, that's really what drives the service costs. So I guess that's the best indicator, I -- that's available out there to me to understand where service costs are going. In terms of long-term commitments, we don't have very long-term commitments on our drilling rigs, and we don't have long-term commitments on frack, nor frack supplies. So we're subject to these shorter-term movements. But it does give us the flexibility to move up and down in terms of rig count if we need to do that and I guess that's the blessing that goes with that.

Our next question comes from Michael Hall of Heikkinen Energy.

I guess, I wanted to go back to that Slide 13. I'm just curious, to what extent have the completion designs changed over the -- I guess the time you've been completing wells out there and relative to how the prior operator was completing them as well.

Well, I guess the best way to describe it is we're in a fairly early understanding of the completion process, and the teams are working hard changing things that they think are appropriate. And we, based on these curves, you can see we feel like we're making really good headway. Some of the things that -- challenges that we've been faced with and thinking back about when we started, the smaller diameter casing was a limiting factor on the 2-mile wells, and particularly, I'll point toward the Liam well, where we did -- we weren't able to really effectively complete the [toe] of that. So changing the process over to put 5.5-inch casing in these wells is something that is making a difference particularly on the longer laterals. The shorter laterals we've stayed with the smaller casing. But all of that, coupled with design changes are appropriate, and at this point I'd -- to step through all of those is a complex matter, but at this point, we're pumping 2,400 pounds per foot of sand and we're pumping about 55 barrels per foot. And the perf clusters is something that they're working on, and so we keep changing that around and change rates, et cetera, to try to better contact rock as we're moving through that process. But it's increments of learning, I guess, is the best way to say it about what the team is doing. And I think as this point toward, we're making good headway doing it.

Okay. And I guess staying on the completion design topic. In the DJ, is there any reason from a technical perspective, why tighter stage spacing would work better in long lateral wells than the shorter wells?

That's a really good question, and the answer in my mind, Michael, is no. I would say at this point, we're seeing some of the benefits in the -- if you're looking at the standard reach laterals relative to the extended reach laterals that we have on Slide 11, you can see that 170-foot spacing isn't moving up quite as much as we'd like it. We feel like those wells particularly are being impacted by some of the line pressure issues that we've discussed already, and that may be limiting their capacity to produce. But really, I think overall, our teams are expecting those wells to get better. As -- going to 170-foot spacing expect them to get better, and I don't see any reason why they wouldn't. I will add, even within this project that we have going out there, constantly trying to improve, we're taking the 170-foot spacing and adjusting per schemes, et cetera in those wells to try to take the 170-foot spacing and make them perform like a 140-foot spacing without adding costs -- or with adding, I would say, limited costs.

Okay. And then I guess last on my end just on guidance. I've got 2 questions. Number 1, on 2018, do you expect oil volume growth to differ materially from the 20%, 30% range of overall volumes? And then second, in '17, on the new the completion counts, is there any change in working interest expected new versus old or is that static?

Well, I'll take the first part of that, Michael. As we look at over the next couple of years, yes, we're projecting sort of a very similar mix for oil, gas and then gels going forward for the next couple of years. So we're -- approximately, that 40% oil, a little over 20% in gels and the balance of that is natural gas based upon the modeling that we're doing today.

And Michael, I'd just put a warning out there because we've got -- obviously, we've got our Eastern Delaware. If we end up allocating more capital to that portion of our budget, that would drive the oil mix. If we go more towards the inner portion of the Kersey area, we would get gassier. We've had some phenomenal, phenomenal wells come online. So I just want to put a little warning, we've got a range there. A lot of flexibility depending on what's happening with commodity prices to move our selection of wells.

And just to answer your question working interest, and this is particular to Wattenberg, we did pick up some, as Lance pointed to, the $5 million to $10 million additional capital investment. That will push our working interest up a small amount, but I wouldn't think it's going to be a significant amount. I don't have specific numbers but that's the one thing that I would say is probably going to push it up just a little bit.

Everything else is about the same.

Our next question comes from Paul Grigel of Macquarie.

Maybe 1 for Lance, here. As you guys lay out the '18 and '19 plan on Slide 24, could you discuss what assumptions you're using on that Eastern Delaware Basin type curve within that modeling parameter, realizing it's not formal guidance, but trying to understand if that's the 1 million-barrel type curve or if it's closer to actual well results?

Sure. No, Paul, that's a good question. So for our Eastern area, the block 4 wells at the Wolfcamp A, we are using a 15% increase to the acquisition type curve, in that estimate. I think, as you can clearly see, as Scott showed earlier, it's performing in that average [although] it's performing well above that amount. But we've -- we feel at this juncture, for modeling purposes, 15% is a good representative increase over the acquisition type curve.

Okay, that's helpful. And then maybe one for David here. You guys have some Waha basis hedges on. Could you guys give the thoughts on adding those, and then maybe an update on the midstream view of what you see in Waha more so into '18 right now?

Sure. Paul, this -- on the Waha hedges per basis, really just part of our overall hedging program on that. As you've seen in the past, we've added some up against CIG and some in Waha. You know certainly, the Waha market has expanded certainly over the last 4 or 5 months. And don't see too many of those projects coming online really until the end of 2018. So really just trying to take some of that risk off the table as we try to project forward what sort of volumes we'll start seeing coming through the system. Hopefully that gives enough color on it.

Okay. And then is there any change in the operational outlook as you guys look through there and evacuating gas room from the basin?

I don't think so. Overall, I think we feel confident. We just recognize that it may get a little bit tighter and that's going to manifest itself through bases at points in time.

Our next question comes from John Nelson with Goldman Sachs.

Dave, I wanted to come back to something you said earlier to make sure I heard you right. Were you referring to Wattenberg volumes specifically or company-wide when I think you made the reference that 3Q production would be up sequentially and then we should think about 4Q being flat?

Sure. Yes, that's really a general company-wide statement overall, so we'll continue to see some nice growth in both the Wattenberg and in the Delaware, particularly into the third quarter, and then the management that we've talked about here in Q4, just estimate that will keep us pretty flat as a company.

Okay. That's helpful. And then I guess looking ahead to 2018 if we do run the 3 rigs in the Wattenberg, is that going to help you guys just keep production flat? Or are you going to be building production capacity so that when the -- the DCP plant comes online in the back end of the year, you guys can flow those volumes pretty quickly -- just conceptually. I know you don't -- can't predict line pressure, but trying to think if you're just trying to hold volumes flat until it comes on, or if you're proactively kind of building that?

John, this is Lance. Yes, so for 2018, no, we're building production volumes in the Wattenberg Field with our 20% to 30% growth as compared to 2017. So there's solid growth with that. We just have been thoughtful in how we think about the amount of capacity there and stuff that is in the system and all. But we're also building some DUCs in 2018 that will carry into 2019 as well and that's one of the key things that also projects out that very strong 30% to 40% production growth in 2019.

Okay. That's helpful. And then just 1 clarification on my end. I didn't see the exit rate guidance kind of reiterated or in the release. Is that being withdrawn or just wasn't included in the update?

I think -- John, I don't know if I have that number off the top of my head. I think it's between 90 and 100 now, and part of that is the extra carryovers and reduction, I think, of 6 turn-in-lines this year and a slight increase in the curtailment factors that we put on the older Wattenberg production.

Okay. So is it adjusted or that's the same as kind of what it has been?

Our expectations are down from where it was. I don't have the exact number.

Yes, I think it's down [indiscernible] at this point. That's accurate.

(Operator Instructions) Our next question comes from the line of Jeff Robertson of our Barclays.

Just to follow up on the prior question about Wattenberg volumes. Is it safe to assume that production will stay relatively flat until plant 10 comes on late next year and then build again in 2019 when plant 11 comes on?

Yes, Jeff, so we see -- we project that in 2018, Wattenberg will definitely be growing production volumes. It is just that it will grow even more in 2019.

And so are there any compression projects that will help alleviate any of the line pressures beyond what's currently planned?

The midstream provider has done a lot of work not only modeling for gas plant expansion, but also for compression facilities within the field to continue to improve that. So yes, there's a lot of work that they have done and are going into establishing compression to be able to really help with those volumes in the specific areas that our acreage is positioned. So plant 10 is not only just a plant, but it is a lot of compression work there too that we think will be very helpful.

And the associated pipe that goes with that, I think the other part of that is -- we don't -- you can't keep adding to the compression into the processing without more pipe, and they're putting big pipe in the ground at the same time.

Jeff, this is Bart. One other thing. Our secondary midstream company, Aka, also has a series of expansions that they're working on related to moving more volumes. And so we've got upside on the growth on their system also. And those projects are this year and carry into next year.

Okay. And if I can, a question on the Delaware Basin with I think 2 to 3 rigs in the plan. I think you all said earlier, you need about 2 rigs to manage your leasehold HBP obligations. Can you just talk about how you think it -- laying out the development plan through 2018 to not only manage HBP but also to test spacing intervals and also to test even spacing vertically in your acreage?

Yes. I'll start, and then Scott can jump in here. So the 3-rig program that we currently have, we believe not only will we HBP the positions that we have, but we'll also be able to test the downspacing as well. We brought in the fourth rig earlier this year in the Delaware so that we can kind of get out ahead of some of the HBP work that we had to do. And the benefit of that is that means that for HBP into 2018, we're estimating sort of a 2 to maybe 3-rig program to HBP, and then that extra time for that third rig will be spent working on the downspacings that we have in the Eastern area as well as drilling additional wells in the Eastern and wells also in the Central area. So there's a lot of work that's gone into this, a lot of the -- the teams have done a great job putting forward their drilling schedules and plans. But we think it's going to be a very solid program for the company in 2018 that tests all of those types of things for the company.

A couple of other comments, just on where we are at now, and a little bit shorter-term look. We are converting over as time passes, from individual wells to multi-well pads. And we have -- the 3 rigs we have running right now are on 2 -- one is on a 2-well pad, and the other 2 are on 3-well pads, so we are getting some of the benefit of some of the efficiencies. And then later in the year we have a larger well pad, so something in the order of -- I think it's going to be about 9 wells. We're still working on that final plan, but about 9 wells that we'll be drilling in the Eastern acreage. And we'll be testing the various -- down -- the spacing between wells and other factors that we're taking into consideration. So starting to get some benefits of some time to actually move away from just single-well pads.

At this time, I'd like to turn the call back over to Mr. Brookman for any closing remarks. Sir?

Yes. Thank you, operator, and thank you, everyone, for joining the call. A good 1 hour and 15 minutes into it, so we just appreciate the patience and time and listening to us.

Thank you. Ladies and gentlemen that does conclude your program. Thank you for your participation and have a wonderful day. You may disconnect your lines at this time.