PDC Energy Inc (PDCE) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy Third Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to turn the conference over to Mr. Mike Edwards, Senior Director, Investor Relations. Sir, you may begin.

Thank you. Good morning, everyone, and welcome. On the call today 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.

Yesterday afternoon we issued our press release and posted a slide presentation that accompanies our remarks today. We also filed our 10-Q. The press release and presentation are available on the Investor Relations page of our website, pdce.com.

I'd also 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 numbers today, so I'd also like to call your attention to the appendix slides of that presentation where you'll find a 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 hello, everyone. Thank you for joining us on our call today.

Another great quarter with production growth of 42% when compared to the third quarter of 2016. First, I would like to personally thank our operating teams for all their efforts as the company has grown our production base from approximately 50,000 barrels of oil equivalent per day just 2 years ago, now approaching 100,000 barrels of oil equivalent per day, a terrific job. Again, thank you.

Some key themes for today. First, a great story emerging in our Central and Eastern acreage in the Delaware Basin. Well performance and an emerging resource potential in the Wolfcamp A and B that significantly exceeds our expectations from the original acquisition model. While we are clearly disappointed with the 2 unsuccessful wells in our Western acreage and the resulting impairment, we couldn't foresee allocating any significant capital to the Western acreage based on the results from these 2 wells and the terrific performance we are seeing in the Central and Eastern portions of the basin.

Second theme -- our Wattenberg. Predictable, high-return, low-risk projects that right now are the foundation of the company's operational performance and production base. And from a business development standpoint we are repositioning the Wattenberg with our anticipated 2 acreage swaps and acquisition, all expected to close in the fourth quarter. Over the next several years you will see enhanced focus on more capital- and operating-efficient 2-mile laterals in our now consolidated Kersey, Plains and Prairie areas within the field. And Lance will discuss this more in a moment.

Next theme -- the company's financial strengths. Strong cash flow from operations at $151 million, a record for the company, improved leverage ratio to 1.8 and expanded borrowing base from $950 million to $1.1 billion, giving us the financial flexibility to execute on our capital programs.

And last, we are pleased we reached agreement with state and federal regulators which settled the lawsuit filed, against PDC in late June, related to tank emissions in our Wattenberg operations. I can assure you we remain steadfast in our commitment to safety of our employees and to protecting the communities and the environments where we operate.

Now let me hit on some of the highlights for the third quarter. Again, production of 8.5 million barrels of oil equivalent, an average of 92,500 Boe per day, again, a 42% enhancement from the same quarter last year.

In the quarter we spud 52 wells and turned-in-line 43. From a financial perspective, lifting cost for the quarter came in at $2.98 per Boe, in line with our guidance. And we are at $2.81 per Boe through 9 months, also in line with our expectations.

We ended the quarter with approximately $136 million cash on hand, giving us approximately $840 million liquidity quarter-end. And again, we lowered our leverage ratio to 1.8. Our capital investment for the quarter was approximately $205 million, in line with our expectations and, as I noted earlier, adjusted cash flow from operations of $151 million.

To sum things up, let me give a quick snapshot of where we are headed in 2018, as we begin the final stages of our budgeting process. Expect a 3-rig Delaware, 3-rig Wattenberg pace; production growth anticipated somewhere between 20% and 30%, depending on our final capital allocation; a strengthening balance sheet as we go through the year; and an ongoing focus on improved capital efficiencies.

As we enter 2018, we are excited to see the next steps in the technical evolution in the Delaware Basin as we pursue this tremendous resource potential, while we look to the Wattenberg to continue delivering some of the lowest-risk, highest-return drilling in the country.

With that, I will turn this call over to Scott Reasoner for a much more detailed update on our operations.

Thanks, Bart, and good morning.

From an operational standpoint, things went very smoothly in the third quarter. Starting in the Wattenberg, we had 46 spuds and 39 turn-in-lines, resulting in production of approximately 77,600 barrels of oil equivalent per day. Wattenberg daily production grew by about 2% from the second quarter. This is the type of modest growth profile we alluded to last quarter and through turn-in-line and field management is pretty close to what we'd expect for the next several quarters prior to DCP's Plant 10 startup, which is projected to expand our midstream capacity by about 200 million cubic feet a day to a combined capacity of over 1 Bcf per day.

In the Delaware we had 6 spuds and 4 turn-in-lines, including some impressive well results that we'll cover in more detail in a minute. Production in the Delaware increased 28% sequentially from the second quarter to nearly 13,000 barrels of oil equivalent per day. We continue to see great results from the Wattenberg team, and our Delaware team is quickly coming together and starting to shine.

Moving to Slide 7, you can see a little more detail on the spuds and turn-in-lines for each basin. Important to note, over 60% of both our spuds and turn-in lines were mid- or extended-reach laterals.

In terms of our capital outlay for each basin, the third quarter was really pretty similar to the second quarter. We dropped our fourth rig in the Wattenberg in October and continue running 3 rigs in the Delaware. While we had originally planned to release the frac crew in the Wattenberg in mid-November, this crew will go complete some of the DUC wells associated with our pending acquisition. As a reminder, we have a cooperative arrangement to manage the completion operations of these wells.

With under 2 months left in the year and a good line of sight on our expected activity, we fully plan to meet our full year capital guidance.

On Slide 8 we give a little more detail on our quarterly production and LOE profiles. Oil production increased 47% compared to the third quarter of last year and, as was the case last quarter, outpaced total production growth of 42%. In terms of total production, our commodity mix falls right in line with our expectations, including 40% oil.

Shifting to LOE, you can see that for the first 9 months we are at $2.81 per Boe, right in the middle of our full year guidance.

Shifting gears, I'd like to spend a few minutes going through some of the exciting work going on in our Delaware Basin asset. Slide 9 gives a glimpse at the steady ramp in production and some of the early improvements we're achieving as we continue to gain operational momentum in the basin. You can see that from time to time -- that from the time we closed the acquisition in December of 2016, we've more than doubled our daily production. We've already begun testing modifications to our completion design that I'll highlight in a moment, and we believe our infrastructure investments and choke management are beginning to pay off.

Our team has great job adapting to a pretty complex drill schedule that has gone from 2 rigs to 4, back to 3 in a matter of months. In terms of drilling days, we're still early in the game and have room for improvement, but the trend is beginning to move in the right direction. This is due to a couple of things. First, we've right-sized our rigs throughout the year to be more fit for purpose and are happy with the improvements that our team has made. Second, our crews have been together for a while now and are really starting to find a rhythm. And, last, as we continue to drill more wells in the basin, especially wells in closer proximity to each other, it leads to better geologic understanding and smoother operations overall. As we move forward on our Eastern and Central areas, we're focused on continuously improving our efficiencies.

In terms of individual well results, Slide 10 starts with an update of our Eastern-area Wolfcamp A wells. On the left side of the slide, we show our average performance compared to the 1 million barrel of oil equivalent EUR type curve for the area. As you can see, our average well, which is shown by the dotted line, is significantly outperforming our type curve on a normalized basis. To quantify this, early data indicates that the average performance is falling right between 50% and 100% uplift to the curve.

Moving to the right-hand side of the slide, we've updated each individual well and highlighted the Lost Saddle well. This is our first well with an enhanced perf cluster completion design that is an effort to more effectively target reserves with almost no increase in cost. You can see, with an average 30-day IP of over 360 barrels of oil equivalent per 1,000 feet, it's one of the strongest wells to date and is performing extremely swell through 150 days or so.

We're becoming more and more confident in all of our Eastern acreage. The graph on the top right now includes wells that are north of our consolidated Block 4 acreage for the first time.

On Slide 11 we give our first look at the Wolfcamp B in the Eastern area. As a reminder, our acquisition type curve is 25% less than the Wolfcamp A, at 750,000 barrels of oil equivalent for a 5,000-foot lateral. At our Analyst Day back in April we showed the type curve as well as the Triangle Wolfcamp B well, which continues to outperform the type curve through 400 days plus.

We've now turned-in-line 2 extended-reach lateral Wolfcamp B wells this year, the Hermit, which is currently flowing about 1,500 barrels of oil equivalent per day and, more recently, the Elkhead, which is flowing at about 2,300 barrels of oil equivalent per day, and hasn't yet reached peak production.

On the right-hand side of the slide, we've highlighted the daily performance of the Elkhead Wolfcamp B 2-mile well compared to the Kenosha Wolfcamp A 2-mile well, which we highlighted last quarter. As you can see, similar to the Kenosha, the Elkhead shows a very strong, flat production profile through the first 70 days or so.

Moving over to the Central area on Slide 12, we've updated each of the production curves that were shown last quarter. As you can see, the 2 Greenwich wells are still exceeding the type curve, for about 6 months.

But what really grabbed our attention was the performance of the Liam well, shown in green. As a reminder, at the time of the second quarter call, the Liam was coming back online after being temporarily shut in due to offset operator activity. You can see the inflection point at about 150 days, and now through 250 days it has caught up to the type curve on a cumulative basis. We are obviously lacking the data points that the Central area has at this point, but know that we have 4 additional Central area wells planned to turn-in-line in late first quarter or early second quarter 2018, and we plan to be active in this area for the foreseeable future.

In closing, Slide 13 gives a summary of some of the key [points] for the quarter. From a high level, the quarter ran very smoothly in both basins. Wattenberg continues to methodically grow production, while the Delaware is really beginning to gain momentum. We're looking forward to more of the same in the fourth quarter, and as we enter 2018 expect to be clicking on all cylinders.

With that, I'll turn the call over to David for a review of the financials for the quarter.

Thanks, Scott.

Slide 15 summarizes our GAAP metrics for the 3 and 9 months ended September 30 of 2017 and 2016. This was a noisy quarter on the surface, yet I encourage folks to reflect on the quality of the underlying operational results and do not overlook what was really a smooth and impressive quarter.

Bart and Scott have already provided good detail in terms of production for the quarter, which is shown on the graph to the bottom right. These impressive results, coupled with an increase in our realized price per Boe, has led us to an increase of nearly 65% in our crude oil, natural gas and NGL sales compared to the third quarter of 2016. For the 9 months, our total sales are nearly double that of last year.

Our net loss for the quarter requires a bit of discussion, so let me provide more detail on the impairments that occurred in the third quarter. As we highlighted on our last call, we were disappointed with the results of our 2 Western area wells. These wells have now been expensed as exploratory dry holes, at just over $41 million, which includes drilling and completion costs, allocated lease costs and infrastructure associated with these wells.

These results, together with increases in our drilling and completion costs and a decrease in the commodity price outlook since we announced the acquisition more than a year ago, prompted us to take a closer look at where we are likely to deploy capital in the next 12 to 24 months. Following that review, we concluded that an impairment of all but about 2,500 acres in the Western Culberson block was appropriate. This impairment of unproved properties was just over $250 million associated with the Culberson acreage block in our Western Delaware area.

To understand the number reported for this impairment, it's helpful to remember that the book basis we recorded for the allocated purchase price value included not only the announcement date purchase consideration of approximately $1.5 billion, but it also included the effect of the increase in PDC's share price between the PSA execution and closing of the transaction, as well as the significant noncash impact from recording the required deferred tax liability. This additional noncash deferred tax liability and associated increase in our allocated asset value was created at the time of the acquisition to account for the book basis being higher than the tax basis of the properties inside the Arris entity that was acquired. The significant deferred tax item and the associated impact to the allocated asset values were disclosed in our initial purchase price estimate of approximately $2 billion from our 10-K filed last February.

Realistically, we see the Western area as challenged in terms of competing for capital moving forward and believe it's more appropriate that our team's time and energy be focused on the development of the other areas.

Lastly, we've also impaired $75 million of goodwill that was created at the time of the acquisition, taking our remaining goodwill balance to 0. This impairment has an impact on our effective tax rate for the quarter, as there is no income tax benefit associated with this specific charge. And it therefore results in a lower than normal effective tax rate. This has no cash tax effect and it's simply a financial reporting item to be aware.

While we certainly appreciate that the market has had limited expectations attributed to the Western acreage and we all would have liked to see a different result in this area, I believe it's important to focus on the successes and outperformance of the wells that Scott has highlighted in the Eastern and Central areas.

Moving over to Slide 16, we show a summary of our production costs for the quarter, both in terms of absolute dollars and on a per-Boe basis. When we discuss production costs, we're referring to LOE, production taxes and TG&P.

Scott already covered the LOE, but I'd like to reiterate that we're very pleased with where we sit through 9 months. As you can see in the table, our LOE per Boe has increased only 3% as compared to the comparable 9 months in 2016, inclusive of the integration of our Delaware assets.

One minor housekeeping item in relation to our TG&P that was also mentioned in our press release -- we recently entered into midstream contracts in Delaware that require the classification of the fees to be recorded as TG&P expense, whereas these elements were previously embedded in our revenue deducts. There's no margin impact. Rather, it's really just a shift of dollars form one accounting classification standpoint to the other because of the contract structure and it's worth mentioning from a modeling standpoint. Details of our realized prices are provided in our Form 10-Q in the MD&A section if you'd like to look at that more closely.

Moving to Slide 17 and our non-GAAP metrics, we highlight our adjusted EBITDAX and adjusted cash flow from operations here. As Mike mentioned, please note that reconciliations for non-GAAP metrics can be found in the appendix to this slide deck. Our adjusted EBITDAX for the quarter was $167 million, an increase of 26% compared to the third quarter last year.

Also, to remind folks, our second quarter adjusted EBITDAX included proceeds from the sale of our MK promissory note of approximately $40 million. The reason for mentioning this is that if we concentrate on the presentation of the ongoing core business, it reflects an increase in our adjusted EBITDAX on a sequential quarter-over-quarter basis.

In terms of adjusted cash flow from operations, it was $151 million for the quarter and $408 million for the 9 months, representing increases of 23% and 25%, respectively. These increases were largely driven by production volumes and the resulting increases in crude oil, natural gas and NGL sales from the operational successes that have been highlighted earlier.

Shifting gears, Slide 18 shows the current state of our balance sheet and hedge portfolio. Liquidity at the end of the quarter was over $800 million and consisted of an undrawn revolver and more than $100 million of cash on hand. Our leverage ratio as defined by our revolving credit facility improved to 1.8x.

Another item worth calling out is the result of our semiannual borrowing base redetermination. In early October we finalized the approval of the increase of our borrowing base to $1.1 billion, from $950 million last spring. While we've elected to maintain our commitment level of $700 million, the increase in the borrowing base is a reflective measure of the strength of our drilling program and the value that's being created.

In terms of hedges, we continue to methodically layer in additional crude oil and natural gas volumes, and have improved our average hedge price modestly. As you can see, we've begun hedging small portions of our 2019 forecast production, with nearly 2.5 million barrels layered in right around $50 a barrel.

To close out my prepared comments, on Slide 19 we've got a quick summary of our current full year 2017 guidance, with just 2 months left in the year. We feel comfortable with full year production guidance of approximately 32 million Boe and full year capital investment guidance of approximately $800 million. In terms of operating costs on a Boe basis the only change made has been to the TG&P line item, as discussed a few minutes ago. We expect our full year TG&P to increase about $0.20 per Boe as a result of how we account for the changes in new contracts. But, again, our margins are unaffected.

Additionally, we've seen an increase in our NGL realizations due to increases in NGL component pricing, primarily in propane. Our current range of 32% to 36% of NYMEX is an increase from the previous levels of approximately 30%.

Lastly, a quick note that we are currently in the middle of our 2018 budgeting process. This is typically something that we've been able to complete and deliver before year end. While certainly not the final budget and tentative at this time, I will remind folks that we did provide some high-level color and direction on our plans for 2018 in the quarterly materials from our second quarter call.

With that, Lance is here to give some perspective on the business development initiatives announced over the last couple of months.

Thanks, David.

And on this final slide we want to provide a little more detail around our recently announced strategic acreage trades and bolt-on acquisition in the Wattenberg. As a reminder, these transactions have anticipated closing dates in the fourth quarter and the map you see is a post-closing pro forma acreage amount.

Over the past year our teams have focused almost exclusively on efficiently developing our Kersey area, where we have realized very strong operational and capital efficiencies in this 30,000-acre consolidated position.

At our Analyst Day back in April we provided our XRL type curves in this area of approximately 1.1 million Boe per well. These wells are 30% to 34% crude oil, resulting in approximately 350,000 barrels of oil per well. As a result of the pending transactions, we are pleased to have formed 2 additional consolidated positions in the Plains and Prairie areas.

Our Prairie area, which is also approximately 30,000 net acres, is a result of our 8,300-acre -- net-acre bolt-on acquisition. This anticipated acquisition at the time of the announcement includes over 2,000 Boe per day of production, an additional 240 gross drilling locations, an increase in working interest in approximately 60 existing PDC locations and then, finally, 30 operated drilled-but-uncompleted wells.

As Scott touched on, we have reached a cooperative arrangement with the seller to control the completion operations prior to closing on the operated DUC wells. We expect to turn-in-line approximately 18 of these wells around year-end 2017. One item to note, the capital associated with completing these DUC wells will be treated as an increase to the acquisition purchase price.

Based on industry completed wells between 2014 and 2016, we've established a preliminary estimated XRL type curve of approximately 600,000 barrels of oil equivalent per well in the Prairie area. We anticipate that these wells will have a higher crude mix of approximately 40% to 60%, resulting in approximately 300,000 barrels of oil per well. Again, these are preliminary estimates based largely upon completion designs that we believe have been greatly enhanced in the past few years.

Finally, our Plains area consists of approximately 17,500 net acres and is located in the Inner and Middle Core areas of the field. You can see that our preliminary estimated EUR of our XRL wells in this area is comparable to our Kersey area at over 1 million Boe per well. The crude oil percentage is slightly lower than Kersey, at 24% to 30%, with our oil volume per well still a strong 285,000 barrels.

As you think about our development plans in the field and consider our existing permits and the planned expansions of the midstream gathering system by our third-party providers, we currently model beginning development in the Plains area in 2019 and the Prairie area in 2020.

We are currently in our year-end reserve process and at this time are unable to provide too much detail on the inventory breakdown of these new areas, but plan to do so at the expected closing of these transactions and completion of our year-end reserve work.

To summarize, we are very pleased to have created 3 consolidated core Wattenberg positions that are capable of delivering very strong, repeatable economic returns driven by longer laterals and increased capital efficiencies.

I also want to note that the 3 consolidated positions are located primarily in rural areas and we look forward to continuing to work very closely with the communities where we operate.

I want to thank all our teams for their efforts in these transactions as we continue to work towards our planned closing later this year.

Prior to turning it over to Q&A, I want to shift gears and just give a quick status update on our Utica divestiture process. We had very good interest in the data room and we have received several proposals for the assets. We are currently working through the next phases of the process, but can't comment further on it at this stage.

So with that, I'll turn it over to the operator for Q&A.

Thank you, sir. (Operator Instructions) Our first question comes from Welles Fitzpatrick with SunTrust.

Congrats on a good quarter and the EPA settlement. So the 18 turn-in-lines from the acquisition, obviously those will have a de minimis impact on '17 volumes. But can you talk to -- were those previously factored in to the 20% to 30% growth in '18? Or should we think of those as maybe biasing you all to the better end of that range?

From the perspective of our growth for next year, the 20%, 30%, from that perspective we were thinking about those as including those in as part of that growth. So, Welles, I would look at it from this standpoint, to say that growth is part of the 20% to 30% that we're looking at going forward.

Okay, perfect. And then in the Prairie area, the EUR obviously looks good. But can you talk a little bit -- I know it's early -- but a little bit to well costs? Do you think that's still going to be in the kind of $4.5 million range for an XRL? Or are you probably going to put a little bit more in the completions there that might put cost up a bit?

Welles, this is Scott. And we have a plan at this point to test additional sand loadings, which would drive those costs up somewhat. But I don't expect it to move outside that $4.5 million much. In fact, we could probably hold it to that $4.5 million based on what we're seeing today. And we'll be testing, though, the additional sand loadings at the same time running the sand loadings like we run. So the difference is we run 1,100 pounds per foot at this point and we're looking at 1,500, 1,600 pounds a foot as a test. And something that we've seen from the other operators that they're having success with.

Okay, perfect. And then just one last one if I could. The 5 [clustering] design tests that you guys have turned-in-line in 4Q, are those testing anything except for the Wolfcamp A? I mean, any B tests in there?

We're actually testing both the A and the B in that process.

Okay, that's great.

Our next question comes from Tim Rezvan with Mizuho.

I wanted to touch on the Delaware Basin impairment. I believe in your initial assumptions on locations in the Delaware, that area represented 40 of 710 locations. And the assumptions seemed extremely conservative. I know you're still doing sort of early delineation drilling. When do you think you'll be able to provide investors an updated location estimate, given now you're doing more work on the A and B, just to ease concern on the location depletion from your initial assumptions?

Yes. So, Tim, this is Lance. And so, yes, when we did our initial analysis here on the field we had a total, with just the Kimmeridge acquisition, 710 locations. Then we had a bolt-on that brought us to 785 locations total. The 40 that were in the Western area were 2-milers, where the rest of them were 1-milers. So when we look at the impairment that we've taken, we still have the approximately 2,500 acres that we're still watching and monitoring there. And there's some activity to the north and east of us there that we'll continue to watch with that. As far as how we assess then all of the work that's been going on by our technical teams in both the Eastern and Central areas and the impact on the inventories, that's something that we believe is probably going to sometime early next year we'll have an update to the inventory count and assessment that goes with that. And that's something that we always have to sort of tie it in line with all the year-end reserve work that we're doing as well.

Okay, great. I guess we'll look for that information then. And then, one thing I noticed in your slide deck, you didn't have any mention of the production growth CAGR through 2019. You did give some color on 2018, which is pretty consistent with past commentary. How should we think about your prior kind of guide -- the multiyear growth CAGR through 2019? Is there any reason that you didn't include that now? Or has your thoughts on that sort of changed?

Tim, good question. And so we outlined that outlook in our second quarter call and the ranges that we had for production growth in 2018 was in the 20% to 30% range. And Bart shared that again this morning on the call. And then for 2019 it was in the range of 30% to 40% growth in '19 versus that of '18. And a lot of that is driven by our DUC management that'll be going into 2019 and just working around some of the timing of the plants and stuff that are coming up online here for DCP in their Wattenberg field. So I'd like to for the most part refer you back to the second quarter there on what we provided then.

Okay. So just not seeing that slide in this quarter's deck did not imply any change in that plan. Is that safe to say?

Yes, that's safe to say. And keep in mind we always wait till the end of the year, December, to do our actual budget for the following year. So that's something that we are currently in the process of. And we'll provide more specifics on 2018 in December.

Our next question comes from Paul Grigel with Macquarie.

Could you just talk to well costs, more specifically I guess within the Delaware Basin and as you move on to the longer laterals going forward, what you're seeing there as well as service availability within the play?

This is Scott, Paul. We continue to see the costs I think in the range of what we've seen in the past. We've talked in the range of $8.5 million, $10.5 million, $12.5 million by lateral length, being 1-, 1.5- and 2-mile laterals. And those are really targets for us yet. We're not performing at that level, but when you look at what we're doing, there's still a significant amount of science involved in what we're doing. We're doing pilot holes, logging, logging the horizontal portion of the wells themselves. So those three things all play into that cost, as well as we're still drilling quite a few single-well batteries and that really is an inefficient process we're working through. And we're working out some of the surprises that happen early in a process like this as we go through the drilling process and get pressure that we didn't expect, either less than or more than. So dealing with all of that, we're targeting that range in the future, I guess is the way to look at it. When you talk about service costs overall, we're seeing some stability in that right now. There are still some small pieces that are moving up, but we're actually seeing some more stability than we've seen in the past. And I think it's a -- you know, you look at rig count, it's such that that's an indicator of how much the costs really are going to move. And it's somewhat stabilized, I guess you'd say. And then lastly, in terms of service availability, we're getting what we believe is better and better service. We continue to shift contractors, service providers and really that's part of what gets you to that more optimum and effective approach at executing. So we're making headway there. And then I think consistency is what really gets you that. We've got to work through some of that in order to get to a consistent level of -- and I guess a consistent and efficient level.

Okay. No, that's helpful, Scott. And I guess sticking in the Delaware, could you just talk about the Hermit well and just the curve on that one looks to be catching up here, but a bit of a strange shape. So if you could talk to what's the driver of the performance on that well.

Yes. It's a really interesting well in that it sits on the northwest blanket of field. And it's somewhat isolated, the best we can tell, from the rest of the field -- Block 4 of the field, I should say, that consolidated block we have on the eastern part of the field. It's a very gassy well, surprisingly gassy compared to really the rest of the block. We're seeing it perform with more gas. And therefore it's cleaning up differently. And I guess that's the reason why we see the difference in that well. It isn't something we expect generally. It's across what we believe is a fault there, we see on the seismic as a fault. And it also runs up what's called the [Toya] Arch. And so those things we think contribute to the higher gas-oil ratio in that particular well. But that's a pretty good description, I think, of what we're seeing there.

Okay, sounds great, I guess and then one last one, just on the DJ. You guys had mentioned a couple times on line pressure moving the program around. Do you see any near-term constraints into the '18 program based on line pressure? And could that have any impact on your vertical well production that you have coming from the basin?

Yes, the DCP line pressure is something we spoke to I think very specifically last quarter. We continue to see pretty much what we expected, I think, as we move into the fourth quarter. And that's something that we predicted I think, the idea that this was coming, and it's here. We have -- I don't know that we would say we're expecting anything different that we projected second quarter. It is impacting our vertical wells and some of the older horizontals. And so those 2 things are playing into why our production is not growing as much as we'd like to see. But we look at this in 12 months, roughly, and hopefully less than that if we can continue to encourage DCP to adjust their schedule as much as they can to get that done earlier. But in 12 months we see that plant coming in line and we're going to have some backup production that should start flowing. We look through next year and see, as I described, small incremental increases in Wattenberg through the year is the best way to describe it. And one other thing, just to make sure we're clear. We are 30% associated with AKA as well. So 70%, almost 70%, DCP to 30% AKA is a pretty good estimate. So a different system there an [isolated] system from the DCP system that's actually had a little bit better line pressures than what the DCP pressure has been.

Appreciate the color.

Our next question comes from David Deckelbaum with KeyBanc.

Bart, I guess the recent bolt-on and any commentary there, are you guys still pretty actively looking in the Wattenberg now and to go back to the Wattenberg and bolt-on? I think we understand the benefit of the longer laterals there. Do you still see more opportunity to kind of consolidate there? And should we be thinking about that? As we follow the company, is Wattenberg being higher on the priority list now for future expansion?

Let me start with the last part of that question. I don't think we would put Wattenberg as a priority. I think we've got equal focus in both basins of looking for strategic bolt-on value-add, probably modest-sized deals. And, David, to answer your question, yes, there are some additional opportunities in the Wattenberg and we're starting to see an increased flow of opportunities in the Delaware. We would like those to be close to our acreage bolt-on, give us additional capital efficiencies, similar to the Bayswater acquisition and the 2 swaps that we announced. I think the focus you can really expect is continue to look for small deals, ones that won't strain the balance sheet. We're not seeing a heavy flow of those type of transactions, but there are some of those out there. But I think more importantly would be ongoing pursuit of swaps. And the swaps, when you look at the Kersey area in the Wattenberg, to really dissect that deal and show what value it has driven to the bottom line of the company, is very difficult. But I can tell you when you look at our overall LOE per Boe, our cost efficiency in the basin, our operating efficiency for our operating team and -- this is really important -- those consolidated batteries under our consent decree with the EPA and the efficiency of our teams to be able to monitor the emissions from those areas, all of that becomes much more efficient. So we will continue to pursue those type of swaps. And I think the neat thing right now is our relationships with our peer operators is really strong and conducive to us trying to find constructive ways for PDC and their benefit to strike on those deals.

Appreciate the color there, Bart. If I could just ask another one about Culberson -- the 2 wells from my understanding were drilled by the prior operator (inaudible) before the acquisition. In the impairment process it would have seemed to me that you would have had more time to evaluate the area. And I understand that really as you look at capital allocation you had not intended to put capital there. But I guess if you square that with, one, you hadn't necessarily had an operated well there from soup to nuts. And, two, the acquisition did not close greater than 12 months ago. I guess how do we think about this right now in terms of is this just actively on the docket for sale? Or would you have a desire to have sort of a longer evaluation process? How do you think about recouping some of the losses there?

David, this is David Honeyfield. I'll talk a little bit about what we acquired and the drilling and such, and then maybe turn it over to Bart or Lance on the other part of that question. But just as a refresher, we actually acquired 3 PDP wells in that area, kind of in the northern half of the field. And then we did drill these 2 wells ourselves. And so part of that was really just because we were trying to figure out what was there. So the activity that has taken place during the year and since acquisition is really what drove our need to evaluate this and consider whether or not this was a place where we were going to continue to invest capital over the next 12 to 24 months. As we touched on a little bit, again, just a reminder on the allocated value there, there were 3 elements to it -- one, that original announced acquisition price; two, the change in the share price between signing the PSA and closing; and then that deferred tax item. So I think some of the numbers have kind of surprised folks a little bit. But it's helpful to keep in mind I think some of the stuff Lance was referencing earlier, too. And that is that if you kind of put these things all on a 1-mile lateral equivalent it represented about 10% to 11% of allocated location miles. And that's about the way the dollars shook out on the impairment, too, so even though it was a much bigger chunk of the acreage. But in terms of looking forward, Lance, do you want to touch a little bit on that?

Yes, sure, David. On the 2 wells, we just saw a lot of geologic complexity in those 2 wells and they produced more water than what we had expected. And we weren't, and still aren't, quite able to figure out exactly where it's coming from. But I mean, that said, we continue to flow both wells to determine and obtain more information that we'll use in our updated technical analysis. And so, we had the 3 wells that we inherited that are producers there in the Wolfcamp A, and these 2 new wells that we drilled that don't look like and are not performing like those other 3 wells. So that's what got us to sit back and say, "Okay, what are some of the complexities that are going on here?" And so that's some of the things we're working on right now to try to work out. And then in the meantime, we continue to flow the wells and do various tests and stuff on them and we utilize all that data to kind of really understand best our geologic model and positioning three.

And I think it's important, David, one thing. All 5 wells, the 3 we inherited and the 2 we drilled which we were very disappointed in the 2 we drilled, all of them are nowhere near performing at a level from a GOR standpoint, a pressure standpoint and a resource potential. They are not even close to what we're seeing in the Eastern and Central blocks. So a huge part of this as we went through our assessment, recognizing we had this book value allocated there, we could not see justifying as we try to unbundle this opportunity in Texas, allocating additional dollars out here over the next year or 2. So I just think it was really the right decision as far as where we're going. And I think focus will be in the Central and Eastern and I think the market can expect continued exceptional results in those areas as we go forward.

Yes, I appreciate you keeping that cost pull on this. Thanks, Bart.

Our next question comes from Leo Mariani with National Alliance Securities.

Just a couple follow-ups here on the Permian. Just kind of looking at your projection here, I think your third quarter Delaware production was about 37% oil. The first quarter it was about 45%. I guess you mentioned a couple of the -- the Western poor performers that were gassier. Anything else sort of going on there? Should we expect that gas-oil number to change a little bit going forward? I mean, how should be looking at kind of what roughly the split should be in terms of gas and oil here in the Delaware?

This is Scott, Leo. And I'll hit on this and then Lance may jump in here at the end, too. When you look at the wells that I was speaking to, particularly the Hermit and Lost Saddle, we've got a couple of wells there that are higher GOR than what we had projected initially. And so they're not -- I don't want to say they're bad wells, though. They've made more gas, but they're really strong wells. And I guess when we look at the pressures, the producing capacity, that type of thing, they're really strong wells and we're not disappointed in the economics of those at all. It's much more of a difference in production mix than we had anticipated. And so that's really driving this. A lot of our project rolling forward as we look into next year -- and, again, we haven't finalized our budget, but we definitely see the oil percentage moving up in the Delaware, particularly on the Eastern drilling. So we've drilled a few wells there that are driving the gas to a higher level. But I think overall we're still expecting numbers in that range of -- let's put it in that 50% oil range for now. And it may move around there. As we drill in those more gassy areas or move to the more oily areas, it could move around more than that. We've got a particular well that's sitting there. It's called the Elkhead well and it's a B well where you'd expect it to be more gassy. But it's sitting around 70% oil. And so you've got that variety of things that are happening out there. And so really it depends on where we're drilling and how that drilling program plays out with the least obligation. We have that type of thing as to how that oil mix looks over time.

Okay, that's helpful. And I guess just with respect to some of the wells that you tied in in the Delaware here in the third quarter, I think you kind of gave us some performance kind of from 1 of the wells, but I think you guys had tied in 3 additional wells. Is there any other color you can kind of offer on those three recent tie-in lines at this point in time?

Two of them particularly are very young. I think they're still in the early flowback. It's a (inaudible) wells. And I don't recall the third one, unfortunately. But they all are performing very well. The only wells that we were really disappointed in are those westernmost wells out in Culberson County. The others are falling right in line from a rate of return perspective, reserves perspective, as to where we feel like they should be.

Okay, that's helpful. And I guess just in the Central area, I think you guys commented you've got some wells coming on kind of late first quarter, early second quarter. Just wanted to get kind of a high-level thought here. Are you guys really going to be concentrating most of the activity in the East and it's kind of only that one small grouping of wells in the Central area that we should expect here going forward? Just wanted to get a -- thoughts on kind of breakdown of activity in the Central versus East.

Yes, when we look at that, I think we're going to focus mostly in the Eastern area. But we will be drilling the Central area off and on next year, is probably the best way to describe it until we get to the final budget that we'll roll out. So when we look at that, we'll be testing the A, B, and C zones in the East and the A, B and C -- A, B zones for sure in the Central and it may jump into a C there as well. So there's a lot of options in front of us yet that we're trying to decide on. But the bulk of the wells will be in the Eastern part of the play.

(Operator Instructions) Our next question comes from Brian Corales with Howard Weil.

I mean, I think you made the comment that this kind of bringing on close to 40 Niobrara wells a quarter is going to be kind of the run rate. Would you all be building DUCs in the next few quarters before more infrastructure comes online?

Brian, this is Scott. When we look at rolling into 2018, because we're releasing that frac crew to the Bayswater acquisition -- it's actually still working for us basically. It's an agreement that we have where we get to manage that with them as a, I guess, co-manager, really. We're putting a lot of effort into making sure we get a chance to have say on those completions. But we are building DUCs. And when you look at going into 2018, we have in the middle 80s in terms of DUCs without the Bayswater. And then we have a number of about 18, between 15 and 20, let's say, that will come from the Bayswater. So we'll have something slightly north of 100 DUCs that we roll into 2018 with, when you combine the 2 pieces.

Okay, that's helpful. And then one other one. You mentioned we could see an uplift once the infrastructure comes on in the Wattenberg. Can you maybe quantify that? I just want to quantify deferred production from what you're seeing, say, for third quarter current rate, something from that nature.

Yes, Brian. This is Scott again. And it's one of those things that we pull our hair out over here, trying to figure out how much it's impacting us going into next year and what that uplift will be once that plant gets online. Really the only way we have to look at it is the past. And I don't know that that's really fair at this point, because this as high a line pressure as we've really seen. So as far as that, we are still trying to put those numbers into the budget and try to figure all that out. And I would say the best I can tell you is there's a pretty significant amount of gas and less oil behind that, or with that, that we'll be looking at. It's a question we're still trying to get our arms around in terms of the late part of this year and then exactly when that plant comes online. And we're hopeful that it gets accelerated, but we're still looking at fourth quarter based on the current plans.

That concludes our Q&A session for today. I would now like to turn the call back to the President and CEO, Bart Brookman, for any further remarks.

Thank you, Andrew, and just thank you to everyone for joining the call today and your ongoing support of the company. And we will talk to you in a few months. Thanks.

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may disconnect. Everyone have a great day.