Louis Baltimore - Director of Investor Relations Mark Erickson - Chairman and Chief Executive Officer Rusty Kelley - Chief Financial Officer Matt Owens - President Eric Jacobsen - Senior Vice President of Operations.

Dan McSpirit - BMO Capital Markets John Nelson - Goldman Sachs Neal Dingman - SunTrust Robinson Humphrey David Deckelbaum - KeyBanc Capital Markets Michael Hall - Heikkinen Energy Advisors Gail Nicholson - KLR Group Brad Heffern - RBC Capital Markets David Tameron - Wells Fargo Securities Jeanine Wai - Citigroup.

Good morning. My name is Sandra, and I will be your conference facilitator today. I would like to welcome everyone to the Extraction Oil & Gas second quarter 2017 financial and operating results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer period.

[Operator Instructions] Please be advised that the remarks today, including answers to your questions, include statements that the Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act.

These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated.

Those risks include, among others, matters that the Company described in its financial and operating results news release issued yesterday and then it's filling with the Securities and Exchange Commission. Extraction disclaims any obligation to update these forward-looking statements.

While the Company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance. The Company's drilling schedules, capital plans and other factors may cause its results to differ materially.

I would now like to turn the call over to Louis Baltimore, Extraction's Director of Investor Relations..

Thank you and good morning to everyone. We are glad you can join us today for our second quarter earnings call. With us today on the call we have Mark Erickson, our Chairman and CEO; Matt Owens, the Company's President; Rusty Kelley, our CFO; Tom Brock, our Chief Accounting Officer; and Eric Jacobsen, our SVP of Operations.

I'd like to remind you that today's call, in addition to the aforementioned forward-looking statements, also includes a discussion of certain non-GAAP financial measures.

Please be sure to read our full disclosure on forward-looking statements and GAAP reconciliations in our earnings release and in our filing on Form 10-Q which we provided yesterday evening after the close of trading. I'll now turn the call over to Mark Erickson, our CEO, to go through some of the highlights from this quarter..

Thanks, Louis. I would like to thank everyone for joining us today. Extraction continues firmly on its path to achieving its previously disclosed growth targets. While remaining on track with its drilling and completion capital budget.

As we look at our second quarter results, our crude oil sales volumes exceeded the high-end of our guidance by almost 1,100 barrels per day or almost 5%, and our total equivalent volumes came in above the midpoint of our guidance range. Our crude oil volumes grew over 70% sequentially and made up 52% of our total equivalent volumes for the quarter.

This oil cut is up substantially over our first quarters 40% oil cut. Our equivalent volumes grew 32% compared to the first quarter driven almost entirely by crude oil as our natural gas volumes were flat. While those second quarter production numbers were strong, we believe our third quarter production growth to be even better.

We expect our total equivalent volumes to be between 59,000 and 62,000 barrels of oil equivalent per day, which represents about 37% sequential growth at the midpoint. We find this especially impressive considering that we are growing from such a high base.

Our second quarter volumes were the highest in Extraction's history on both a total equivalent and crude oil basis. We expect our third quarter crude production to be between 32,000 and 33,000 barrels of oil per day which is about 39% sequential growth.

As a result of our wells continuing to exceed our crude oil production expectations, we are raising our full-year 2017 crude oil production guidance to 24,000 to 27,000 barrels of oil per day from 23,000 to 25,000. We now have over 60 Niobrara wells on line using our enhanced completions. And we are very pleased with these results so far.

As these wells are approaching the 50% enhanced type curve after more than 120 days of production. Matt will talk about those in greater detail later on the call. Now let's talk a little bit about our new acquisition area in the core of the DJ Basin. I'd like to give a little color on our progress.

To-date we have acquired over 30,000 net acres for about $255 million over several transactions, which includes $160 million previously announced and paid in 2016. Our first operated well here has been online for more than 180 days. And it's producing over our 50% enhanced type curve. While we are still not ready to disclose its exact location.

It's in a low GOR area. It's in a more rural location resulting in relatively lower regulatory risk. It's been well delineated by offset well results in addition to our own and we expect this acreage to be in the top 20% of our inventory.

We expect to tell you more about the area sometime towards the end of this year, once we have successfully solidified our acreage position. This acreage we've already purchased brings our total in the core of the DJ Basin to over 130,000 net acres. With that, I'm going to turn it over to Rusty to go through our financial highlights.

Additionally, Matt will be covering our operating results including the very encouraging results we're seen from our enhanced completions..

Thanks Mark. I'd like to quickly touch on some financial highlights from the reporting period. I want to once again take the chance to reiterate the strength of our balance sheet and our attractive liquidity position.

We exited the second quarter with $89 million in cash and a fully undrawn borrowing base of $475 million, resulting in over $540 million of available liquidity after giving effect to letters of credit. Additionally to further bolster our liquidity position, we executed on a $400 million high yield offering that closed on August 1.

We exited the second quarter with a net debt to EBITDAX ratio of 2.0 times on a six-month annualized basis. The reason we look at six-month trailing EBITDAX is the fact that we've been growing so significantly, it takes a better account of our current run rate. I wanted to address our decision to issue the $400 million of senior notes last month.

We did this to decrease our reliance on a revolving credit facility in light of the current volatile and uncertain commodity price environment.

Instead of relying on a revolver for funding, which subjects to semi-annual redeterminations that could potentially swing negatively in a poor commodity price environment, we decided to preemptively take term debt instead.

On hedging for the second half of 2017, we have about 85% of our forecasted oil production and 80% of our forecasted natural gas production hedged based on the midpoint of our guidance.

We continue to layer in hedges for 2018 program as well having added an additional 6.9 million barrels of oil since the end of the first quarter, which provides us with a visible cash flow stream to execute on our current development plan while minimizing the need to lean on our balance sheet.

We remain right on track with our internal drilling and completion budget as well. I point you to Page 9 on our Investor Presentation that illustrates the front-end loaded nature of our D&C CapEx on a net basis for 2017. We continue to operate three drilling rigs and three frac crews on a full time basis for all of 2017.

But given our working interest in the Windsor program, which was focused - which was our focus during the first half of the year, our CapEx on a net basis was weighted heavily toward the first part of this year.

While we plan to maintain similar levels of gross activity during the second half of 2017, due to the lower working interest nature of our second half program, this results in lower CapEx on a net basis for the back half of 2017 and such as mentioned, we remain right on track with our annual development CapEx budget.

Now turning to our second quarter financial results, adjusted EBITDAX Unhedged was $74.7 million, a 91% increase compared to the second quarter of 2016 and an increase of 45% compared with the first quarter of this year. Our EBITDAX growth profile looks strong given a robust hedge positions in our continuing production growth.

Our LOE for the quarter came in about 600,000 were about 4% above the high end of our guidance range. As discussed in our earnings release, this overage was due to the acceleration of our safety testing and inspections of the flowlines and process lines per the Notice to Operators issued by the Governor of Colorado in May.

It's important to note that this testing process is something we perform annually as part of our ongoing safety protocols and as such we do not expect any impact to annual budget. It's just a function of shifting this timing into the second quarter.

If you turn to Page 7 in our investor presentation, you find a helpful illustration of the shape of our per unit LOE and G&A numbers for the year.

Remember, as we turn in line the wells associated with our large ongoing completion program and continue to grow our volumes in the back half of 2017, we expect to see that per unit LOE significantly decline bringing the full-year average to in line with our guidance range. In addition, we expect to see a similar trend on the cash G&A side.

So with that, I'll turn it over to our President Matt Owens to cover our operational highlights..

Thanks Rusty. Let's jump right into the encouraging results we are seeing from our enhanced completions. We now have over 60 Niobrara wells online stimulated with enhanced completions and we really like what we are seeing thus far.

If you turn to Page 14 in our investor presentation, you'll see the chart showing over 120 days of production data versus our 20% and 50% enhanced type curves and that our average production is approaching the 50% uplift curve. While it's too early to quantify the improved EUR of these wells, the production history is beginning to speak for itself.

So far these wells have settled in nicely and as we turn on more wells, we continue to see similar results, which really confirms our decision to move to this completion design. On the operations front, we had another successful quarter.

During the second quarter, we reached total depth on 41 gross, 25 net wells with an average lateral length of 10,100 feet and completed 51 gross, 46 net wells with an average lateral length of 7,300 feet. We also turned to sales 67 gross, 62 net wells with an average lateral length of 7,100 feet.

Of these 67 wells, 33 were turned on during the back half of the quarter and given the cleanup time these wells contributed little to second quarter production volumes that have already begun to contribute nicely to our third quarter production. Our operational efficiencies continue to improve.

During the second quarter alone, we pumped 2,474 total frac stages while placing over 815 million pounds of proppant. We have already set some pretty impressive records, but we are really focused on bringing our averages closer towards those records.

During the second quarter, we reduced our average spud to TD time for a 2.5 mile well to under five days. This represents a 20% improvement over the first quarter averages. Overall, our development program remains on schedule to deliver on our third quarter and full-year 2017 guidance within budget.

Now let's turn our focus to the Broomfield development program, which has been going well and remains on track with our expectations to have permits for full development in hand sometime around the end of 2017. In addition, we also expect to spud our initial wells before year end.

These initial wells should be on production in early 2018 and will demonstrate the productivity of this area as well as help determine the most efficient sizing of our midstream facilities for future full development. I would like to thank everyone for your time on the call today.

I would also like to once again thank our equity and debt holders for their continued support of Extraction efforts to build a premier DJ Basin Company. This concludes management's prepared remarks. Operator, I would now like to open up the call to the Q&A session..

[Operator Instructions] Our first question comes from the line of Dan McSpirit with BMO Capital Markets. Your line is now open..

Thank you folks, good morning.

Following up on the enhanced completions, what happens to the decline rates for both the oil and gas streams upon reaching the bubble point assuming it hasn't been reached already that is - is there any difference anticipated in the decline rate expected between the standard and enhanced completions? Just asking you in an effort to get a better sense of any changes to the capital intensity of the business?.

Yes. We expect the - once bubble point is reached that the decline of the oil will be flatter afterwards. That's one of the main reasons that we switched to this design was to have that flatter decline profile after bubble points reached in for the following years..

Okay. Got it. And on the acquisition area you state that it's in a low GOR area.

How does it compare to the say that GOR in the area of the Windsor wells?.

It's very similar to the GOR in the Windsor area. If you look at the two charts that we supplied, they're both in that two to four range and I would say that those are very similar to one another in terms of GOR..

Okay. And then lastly here what are the infrastructure needs for that 30,000 net acres acquired in the new acquisition area..

They'll have to be some build out if we're going to get - once we move into full development, but there's enough adequate infrastructure space right now for us to continue drilling our initial wells down there and once we see what the GOR trends are cross our position will be able to build out the right size midstream for when we move in full time..

Got it. Thank you. Have a great day..

Thank you..

Thanks, Dan..

Thank you. And our next question comes from the line of John Nelson with Goldman Sachs. Your line is now open..

Good morning and thank you for taking my questions. Rusty, I appreciate the color on the rationale for the debt issuance, I guess just to clarify it's still a kind of immediately obvious to us why you would take out the term paper unless you planned to have a big 2018 outspend.

So I guess is there something I'm missing there? Can you speak to how you're thinking about 2018 in relation to cash flow spending in cash flow?.

Yes, so we haven't given 2018 guidance yet with regard to CapEx expenditures and we're obviously just watching - we're watching the markets very closely to the commodity prices things like that.

However, what we've talked about before is we expect that given the - kind of given the current environment and given our pace current pace of development we should be approaching cash flow neutrality under this current kind of our current pace of development around mid-year.

For us that would have involved pulling on the revolver between now and then and but for us we just wanted to make sure we could clearly point to the financing sources between now and cash flow neutrality in that some we just basically kind of the derisk the balance sheet to do between now and then..

So the $400 million would have protected you in barricades between kind of now and mid 2018, is that the way to think about it?.

That's the right way. We look at this is using term debt in lieu of revolver, not incremental debt..

And to the extent that we don't see that kind of barricades play out you would just keep the cash on the balance sheet..

Correct..

Okay. That's very helpful. And then for my second question, one of your competitors spoke yesterday, I kind of line pressure on the DCP system.

I know you all have some diversification, but can you help us maybe with some color on either the split between the systems or the volume growth that you all - our based casing on DCP system in your 2018 production guidance?.

Sure. We've been very proactive in working with DCP to build out to our Windsor area where most of our new production is and connecting that into the Grand Parkway.

So we haven't seen very many pressure issues or significant increases in line pressure where we're operating and as far as 2018 goes a lot of the drilling we're doing right now and a lot of the wells are going to be completing in the - towards the end of this year the beginning of next year are actually in our southern acreage and they'll be going into the western gas system.

So that is the unique thing about our position. We're split between the two and we're actively trying to manage where we can drill and have the lease impact from line pressure until the next plant comes up with the DCP..

Matt, is there another kind of a ballpark for 2017 activity was 70% kind of Northern Greeley Windsor, 30% Southern and kind of it flips in 2018 or any kind of way that to think about how that switches?.

I'd say that ratio is probably pretty close for the wells that we've turned online so far of this year. It will definitely give more weighted towards Western Gas with the wells that we're doing right now and tend to complete in Q4 and Q1..

Okay..

It does - when you look at higher line pressures that that everyone is talking about, we just don't view those as being a material problem with respect to our Company. Given the fact that we don't have very many vertical wells and that most of our pads or new horizontal production that can tolerate the higher line pressures.

I'd also like to point out that when you look at our enhanced completion results, those are all against those higher line pressures, which pretty much points out that these horizontal pads particularly with enhanced completions are able to very well address that issue..

Great. And just I guess last one to kind of make sure I'm clear on it. The highest line pressure you probably expect kind of for 3Q, you probably witnessing now.

So you're fairly comfortable with where you set the guidance for 3Q?.

Yes, we have forecast any curtailments that we might see from line pressures that's in our guidance numbers. And right now you're right is probably the highest point that ECP will be for a while because it's the hottest time of the year..

Great, that's really helpful. I'll let somebody else hope in. Thanks..

Thank you..

Thank you. And our next question comes from the line of Neal Dingman with SunTrust Robinson Humphrey. Your line is now open..

Good morning, guys. Just - same that I was just building on maybe what John was just asked. I want to make sure, I'm clear with this. You would mention I think you remark was laying out kind of the plan I know you don't have 2018 out there yet.

But I know you talked about in a press release sort of the first in the new acquisition area being online 180 days.

Have you all said just on a - sort of a more generalized basis? How much of the activity by late this year and next year be in the new era year verses you kind of just on this last question broke it up kind of in different regions? Does that include the acquisition area as well?.

There will be some activity in the acquisition area towards the end of this year and we don't plan on drilling full density down there yet until we finish building out upsize midstream that that's going to be required. But we will have more well results towards the end of this year and beginning of next year..

Okay. And then Matt what is - make sure I have the cadence right for I think I cited in your release or maybe I talked last year you about this, just on the completion schedule that you're anticipating for sort of third quarter versus fourth quarter - versus second quarter and we're not go with that.

Just kind of want to make sure I'm unclear on sort of the timing on that to see if it's going to be more of a kind of a back half third quarter timing like it was in the second quarter?.

So you referring to turn on lines for wells or just amount of completion activity in general?.

The turn on line, just to help us obviously to know that kind of idea with the - and you have guided on the production, but I'm just kind of curious on how that plays out timing wise?.

I think it will be similar to the second quarter, activity wise, we're still running the same amount of practice. We have been for in this quarter as we were last quarter. But we will have some fairly significant size pads that are coming on line in the second half of this quarter..

Okay and then just last, I know rest of you guys have mentioned this just as you keep ramping up, you kind of have a regular sort of hedge process, I mean do you want to kind of continue to be at a certain level or I mean obviously up buyback to close to $50 again the date on the NYMEX, just how you guys think about that on your program?.

Yes, nothing has changed with regard to our strategy there. We've traditionally - once we start spending capital for pads, particularly given the IRRs at these levels. We lean in pretty heavily to hedge between typically 50% to 70% payout of these wells. We've been a little bit more aggressive than that as you see in our - just given the volatility.

So we feel very comfortable, but have continued to do that, which is why in our updated hedge schedule, you have seen us start to layer on things that are - we're starting to spend capital for now through kind of the first half of 2019..

Great details, guys. Thanks a lot. Have a good day..

Thank you..

Thanks..

Thank you. And our next question comes from the line of David Deckelbaum with KeyBanc Capital Markets. Your line is now open..

Good morning, Mark, Rusty and Matt. Thanks for taking my questions.

Just curious I think when you guys came public, you highlighted the ability I think to increase your working interest on targeted pads through swaps et cetera and we saw that high working interest in the first half of the year by quench them perhaps a bit in the second half of the year, can you talk about those opportunities and should we be expecting a higher working interest, then sort of the 70% or so over all for your current location count as we get into 2018?.

Swaps are something that we're always negotiating with partners and non-operators. But it's a case-by-case basis through the non-operator is, some of them have CapEx budget left for non-op and they want the production associated with it. So it really a pad-by-pad basis, but we will increase it where we can.

But right now, we're at the interest that we forecasted so far..

Got it. With this recent success on the acquisition area, you said you have a few test towards the end of the year.

Is that mutually exclusive from plants export in Northern extension area? Northern extension as a bit more, I guess to offset pier activity and some test of enhanced completions in lower GOR, how are you thinking about the extension area now - for the Northern extension area now and how active you want to be up there?.

Right now our plan is still the same for the extension area this year. We plan to drill two wells sometime towards the end of this year and get them completed as quickly as possible on online.

And you're right there has been some other activity up there from some other operators and the results we've seen thus far have been pretty encouraging for what we plan to do on our completions very near there..

Got it. If I could just ask one more maybe a little bit more philosophically. Mark and Rusty and everyone, as you set the budget for next year, you've talked about growing 75% which is still a fairly [indiscernible] great coming off the highs of 2017. You talked about being more free cash neutral in the second half of 2018.

With the industry now sort of indicating that that once more capital restraint or more cash flow neutrality out of operators, how do you think about budgeting now? Is it still driven by rate of return and pulling NAV forward? So we'd be thinking more about balancing CapEx and cash flow for planning around 2018?.

We've always looked to be balancing our D&C budget near cash flow sometime in the back half of 2018. That plan is still intact under the current commodity price environment. Remember our business plan with the high quality of our wells has always performed well at $45 and up.

When I kind of look just kind of philosophically when I look forward, I just kind of give you some guide posts. We've always maintained tremendous flexibility in our business plan. We don't have any rigs or frac fleets or materials or anything under long-term contracts.

So that allows us - we can either look to decrease activity, we've got great service company relationships where we can increase activity. In a kind of a current commodity price environment, I think it's kind of business as usual. And what I mean by that is with the current CapEx spend, what we've had in 2017, we repeated that in 2018.

We should be able to achieve the type of production curve that we've indicated. However, if we get a sustained commodity price pullback, let's say anything in the low-40s or lower. We have great ability to flex our activity level, but regardless we're still going to have strong growth in 2018.

And likewise is true in a rising commodity price environment. We've got a great ability to accelerate. We've built out a very strong inventory of permits this year in multiple areas that could address any type of pipelines concerns or that.

So I think we just find ourselves in a great ability to address the 2018 commodity price environment, but right now it's business as usual..

Thanks for the color Mark and thanks for the answers guys..

Thank you..

Thank you. And our next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Your line is now open..

Good morning, guys. I just want to maybe circle on the enhanced completions a little bit more. And just in the context of kind of what you've shown on Slide 14, clearly the oil is outperforming, it's a good thing.

I'm just curious still on BOEs, how should we think about how the total stream is producing relative to expectations? I mean obviously the GOR is lower, but that's partly a function of higher oil.

What's kind of the current read on the overall stream relative to type curve and expectation?.

I think that's a fairly accurate statement. You can see on that plot that we are below what are our type curve is on GOR to start off, but we're going to be approaching that. You can see it approaching it after 120 days and it will continue that way.

But right now we do look like we're under on gas in the early time, but most importantly for us we're ahead on oil..

Okay.

So overall, BOEs are - I mean is oil sufficiently high enough that it's offsetting the lower gas, I guess on a total basis?.

Absolutely if you look at the last quarter over 70% of our revenues were you know contributed by oil which made up about 52% of our stream. So from that standpoint oil is a great thing and by far that's what we drive the value.

So the longer these things stay lower the happier - lower GOR the happier we are, one of the things if you notice with our rays in our oil guidance. We feel good that we've seen shallower oil declines and as a result we raised our oil guidance.

But what we haven't seen is the corresponding increase in GOR which is why we did not raise our BOE forecast until we see where that shakes out..

Okay. Understood. Thanks for the color. And then I guess in the context of that 2017 guide if we kind of take the 3Q whole guide and the annual whole guide and kind of back into the implied 4Q 2017 pretty much flat quarter-on-quarter limited growth. I'm just curious how you guys are treating the - I guess the guidance in the context of these enhanced.

Completions that have been outperforming closer to 50% curve versus I think 20% have been how you had previously guided.

I guess what's driving that that flattish quarter-on-quarter trajectory how you treat in the enhanced completions in that and is it really just well timing or what?.

It's tough right now. The wells are outperforming on oil so much that it's really it's tough to put together what we - how we think the wells are going to produce. We haven't changed off of our 20% type curve yet.

We're very bullish on what we're seen I think I would point out two is when we go into 2018 and we go through Q3, Q4 the higher sustained rates that we're seeing just makes our job easier going forward and we'll see how that plays out, but right now it's looking good..

Okay. That's helpful.

And then I guess last and I just in the 2018 plan you mentioned kind of similar levels of [indiscernible] could probably support the sort of production growth targets you put out there? Is there any reason to think kind of a portion of midstream and other related spending? Would change materially in 2018 verses 2017 or is that a reasonable level as well..

No I would look at again I'm not offering guys for 2018, but we've always planned on midstream to do that through partnership with third parties. Similar to what we did on the Platte River gathering system which is now I think gathering about close to 40,000 barrels of oil a day off of our wells.

When we look at midstream in other areas we would see similar type arrangements and there has been new private equity backed midstream companies that have entered the basin. As well as our long-term existing relationships with the existing midstream companies out here.

And we're just we're going to leverage our size and our growth to get the best deals that we can on that..

Okay. Fair enough. Appreciate it. Thanks for color guys..

Thank you..

Thank you. And our next question comes from the line of Gail Nicholson with KLR Group. Your line is now open..

Good morning.

You're testing the enhanced completions again on Codell work formation and I was wondering if you utilize any of the newer enhanced completion on the Codell and if you commentary different conclusion with the utilization of those enhanced completions and the uplift of the Codell versus the cost versus your previous commentary made on your 4Q 2016 earnings call..

We have been experimenting with larger completions in some of the Codell's. We've been really trying to strategically locate those. So we have a good control on the tests that we're doing. A lot of those wells are newer wells. They haven't been on line for too long.

So we probably like to wait another quarter or so before we can actually quantify the results on them. But we have done a few tests in the Wattenberg area and like we mentioned, we're going to be doing a much larger completion on the Codell well we drill on the extension area later this year..

Okay, great.

And then just looking at the leasing in the new area of 30,000, do you feel like that's ample acreage on blocking standpoint or is there an internal goal that you're trying to get you from an acreage standpoint in that new lease area?.

We don't really have a kind of total amount of acres we would like to have in that area, frankly I would take all the acres. We can't give the results that we've gotten there already. I mean this is top 20 percentile stuff. We are obviously - we're picking it up at very reasonable costs.

The reason we're not talking about it yet is we are still continuing to have success and we really look forward to providing you with more color on that next quarter. We are getting down to kind of the blocking and tackling phase. There are some big deals that we're working on.

That it will be looking at closing during the next quarter and it will have a good story for you at the end of next quarter..

Okay, great. Thank you..

Thanks..

Thank you. [Operator Instructions] And our next question comes from the line of Brad Heffern with RBC Capital Markets. Your line is now open..

Hi, everyone. Just following up on the earlier question about the schedule being so back half weighted in the second quarter.

Is there any sort of like current production rate or maybe a July production rate that you could give?.

The only color that we gave was - when we gave our early on the - early release or preliminary release on our Q2. In very, very early July, I think it was like the first or second week in July, we were at 55,000 barrels a day, but BOE a day.

There is one thing I would like to point out is, you've picked up on a pretty good fact from our news releases that we had 33 wells that we completed late or back half of Q2 and they set up Q3 really nicely because those wells were just - a lot of those wells are two mile long laterals that were just cleaning up and should contribute very meaningful to Q3 results.

So I just think Q3 set up very nicely with the back end loaded of the tills and we're just - our whole operations is running probably maybe 30 days ahead of schedule and it's pretty much on track and we've got - we're going to be able to really told the line on not be in behind schedule, but the end of the year..

Okay, thanks for that color.

And then thinking further down the road, are you guys planning any tests of the Niobrara, Codell benches at all, Sussex, Greenhorn so on, maybe in 2018?.

We don't currently have any of those plan right now..

Okay, thanks..

Thank you..

Thank you. And we have a follow-up question from the line of John Nelson with Goldman Sachs. Your line is now open..

Hi, guys. Thanks for hope back in for one more.

Congrats on the first acquisition area well that looks sort of really strong and do you look forward seeing that acreage you get closer to year-end I guess my question is, I thought your comment on the location sitting in the top 20% of your inventory, really says a lot and something get a better color on maybe what the magnitude of those locations are? So is there any help you could have or you have a location number associated with 30,000 net acres or number of perspective zones under the acreage? Any help there would be a great..

Yes, we haven't really said anything yet on the number of locations that we're going to be adding. But that's something that we will definitely be able to give more color on with our Q3 call, especially once we get to the point of releasing the acreage and showing everybody where it is.

But we think the spacing for the Niobrara will be similar to what it is up in Wattenberg..

When we look at this area and we have characterized it as being low GOR world, low regulatory risk et cetera. But I think also when you look at it, when we talk about being in the top 20%, we're talking about reservoir quality in well performance and we also have a similar costs structure with these wells.

So we're very pleased that this is very much in line with what we're doing in our best areas..

I didn't know that testing is earlier, but there are a number of perspective benches kind of in the nail that you all are looking for?.

It's very similar to Wattenberg..

We've never looked at the area as you know even - when we look at core DJ, we look at three benches in the Niobrara, but you kind of exploit them like one bench. We have been very cautious about saying that you've got three benches and three equivalent acres.

Yes, we stagger from the A, B's and C's and that improved recoveries between the benches, but we treated as one producing horizon..

Okay. All right. I'll leave it there and look forward to that in the back half of the year. Thanks again..

Thank you..

Thank you. And our next question comes from the line of David Tameron with Wells Fargo. Your line is now open..

Good morning. Congrats on in the acreage. Just clarification on your cash flow neutrality in 2018, Rusty, I guess you said that as well, but what price that - just trying to put our model price….

When we say that that would be in kind of a $50 kind of current strip price..

Okay. That's helpful. And then let me just - I'm trying to chase some stuff on the new acreage just like everybody else. If I think about - you said it's a Niobrara test, not a Codell test.

Does that accurate or should we view those as kind of one zone?.

Yes, we said it was Niobrara on the slide..

The initial test was Niobrara..

Okay.

You said it's in DJ, let me just ask the question, is in the state of Colorado?.

We haven't said anything about the area. We're going to wait until the Q3 call for that..

All right. Okay. Thanks. Appreciate it..

Thank you. And we do have a follow-up question from the line of Dan McSpirit with BMO Capital Markets. Your line is now open..

Hello again. And pardon me if this was already addressed.

Can you speak to the documentary at year end, maybe what was anticipated at the beginning of the year and what you now estimate to be the number at the end of this year?.

We expect it to be similar. We haven't changed our guidance on that..

Very good. Thanks again..

Thanks..

Thank you. And we do have a question from the line of Jeanine Wai with Citigroup. Your line is now open..

Hi. Good morning, everyone..

Good morning..

Sticking to the new acquisition area, do you think you can talk about whether there is potential to include a meaningful amount of activity from this area in your 2019 plan? I know a good portion of 2018 is already lock and loaded with 130 wells that should be hired with this at the end of this year, but as you're saying that you expect these locations to be in the top 20% of your inventory and usual results look very well.

What's the possibility of you kind of bringing more and more activity in 2018 versus 2019?.

We've been permitting very aggressively in the area. So we're going to be in a really good shape, but I would say that our development plans are such that - they're pretty well fixed like you said with the documentary that we're going to enter 2018.

We plan to drill some additional wells late in this year and during next year, but the focus of our activity currently is in areas that we want to get to and get drilled up sooner rather than later..

Okay, great. Thank you for taking my question..

Thanks..

Thank you. And ladies and gentlemen, this does conclude today's Q&A session. I would like to turn the call to Mr. Mark Erickson for any closing remarks..

Thank you very much for your time this morning and all your good questions. Look forward to provide you a very meaningful update at the end of Q3. Thanks for your time..

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