Louis Baltimore - Director, IR Mark Erickson - Co-Founder, Chairman and CEO Russell Kelley - CFO Matthew Owens - Co-Founder, President and Director.

Daniel McSpirit - BMO Capital Markets Welles Fitzpatrick - SunTrust Robinson Humphrey Benjamin Wyatt - Stephens Inc. David Deckelbaum - KeyBanc Capital Markets John Nelson - Goldman Sachs Group Gail Nicholson - KLR Group Holdings Jeffrey Campbell - Tuohy Brothers Investment Research Jeanine Wai - Citigroup Jeffrey Robertson - Barclays PLC.

Good morning. I am Jonathan, and I will be your conference facilitator today. I would like to welcome everyone to the Extraction Oil & Gas Third Quarter 2017 Financial and Operating Results Conference Call. [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 in its filings 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. Please go ahead..

Thank you, and good morning to everyone. We're glad you could join us today for our third 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 over the call to Mark Erickson, our CEO, to go through some of the highlights for this quarter..

Thanks, Louis. I would like to thank everyone for joining our earnings call.

With a strong third quarter coming right on the heels of a great second quarter, Extraction continues firmly on its path to achieving its previously disclosed targets, while maintaining the low cost structure, which we believe puts us in a solid position to generate very strong corporate level returns.

We got approval at Broomfield, and we now have roughly 60,000 net acres in our new acquisition area, which we call the Hawkeye Area, in the southern DJ Basin in Arapahoe and Adams Counties to discuss with you today.

While we expect to provide our formal 2018 guidance sometime in December, I'll tell you that I expect we can meet our guidance, calling for 75% production growth in 2018, based on the midpoint of our original 2017 guidance, with the D&C budget that is actually slightly less than the one we have this year.

The incremental D&C dollars we invest this year will contribute to more production growth in the first half of 2018, allowing us to get to cash flow neutrality sooner in the second half of next year. Now let's talk about a set of big regulatory approvals we had at the end of October in Broomfield and Adams County.

First, the Broomfield City Council approved our operator agreement. Second, the COGCC approved 10 of our spacing unit applications for our Broomfield area development program. We'll spud our first set of wells testing our Broomfield leasehold from our Coyote Trails pad sometime near the end of this year or early 2018.

Those results will demonstrate the quality of this acreage, while providing further clarity on midstream requirements and optimal spacing for the area. We are still on track to be ready for this development drilling by the end of 2018.

We believe this demonstrates, as previously discussed, that the regulatory environment is something we can successfully navigate. This achievement unlocks approximately 12,000 gross acres of some of our highest quality development opportunities, as highlighted in the updated investor presentation on Page 16.

Several pads drilled by offset operators demonstrate results in both the Codell and Niobrara that are significantly outperforming our build type curves. Turning to Page 14 in our investor presentation, we have provided detail on our Hawkeye Area.

We followed a similar strategy from the past of targeting an area with little competition, stacked pay zones that are oil-prone, with few vertical wells. This area has been highly delineated with 30 existing wells, many of which have demonstrated production results on par with the best oil wells in the DJ Basin.

This organically assembled position will yield approximately 1,000 operated high-working interest, long laterals, providing us with years of development. With an all-in cost of approximately $7,500 per acre, we expect this project to generate not just high per well economics, but strong full cycle returns.

We are in the process of completing our second well in the area and are planning to do spacing optimization sometime in 2018. We currently have over 100 permits in hand, with an additional 110 in process.

Further, we are in negotiations with multiple parties for both crude oil and natural gas gathering, and believe we will be able to secure attractive rates similar to our other operations in other parts of the basin. At this point, we have about 160,000 net acres in the core of the DJ Basin, with an additional 155,000 acres in the Northern Extension.

With well over 300,000 acres in the DJ Basin, we have reached a size where we are starting to high grade our portfolio through potential divestiture of nonstrategic assets. With that, I'm going to turn the call over to Rusty to go through financial highlights.

Additionally, Matt will be covering our operating results, including the very encouraging results we continue to see from our enhanced completions..

Thanks, Mark. I want to once again take the chance to reiterate the strength of our balance sheet and our attractive liquidity position. We exited the third quarter with $114 million in cash and a fully undrawn borrowing base of $375 million. Last month, our borrowing base was increased to $525 million.

So pro forma for that increased borrowing base, we have ended the third quarter with approximately $613 million in available liquidity after giving effect to letters of credit.

In addition, we've begun the next redetermination process, which is expected to be completed prior to year-end, which will incorporate wells turned to sales through September 30, 2017. We continue to target a run rate of 1.5x net debt-to-EBITDAX.

As Mark mentioned, we think we have a portfolio that is now ready for high grading, and we expect to generate meaningful proceeds from nonstrategic asset sales in 2018 and beyond. These proceeds, along with continued growth in our EBITDAX that outpaces any incremental borrowings, should provide us with a clear path to get back to that 1.5x range.

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

Thanks, Rusty. I want to quickly touch on the encouraging results we continue to see from our enhanced completions. If you turn to Page 13 in our investor presentation, you'll see that after 210 days of production, these wells are still close to the 50% enhanced type curve, despite the high line pressures we've been experiencing. On to operations.

Efficiencies continued to improve. During the third quarter alone, we pumped 3,053 total frac stages, while placing 965 million pounds of proppant. We continue to focus on bringing our averages closer towards our records.

For example, during the third quarter, we reduced our 2-mile average spud to TD time by over 20% versus the second quarter to just under 3.5 days. Above all else, we are committed to achieving safe and strong operating results throughout our acreage, and we work every day to continually improve in our operational excellence.

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's efforts as we build a premiere 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 from BMO Capital Markets..

I was hoping you could speak further to leverage and liquidity in the context of the cash flow outspend over the immediate term and the amounts needed to permanently finance the acreage acquisitions at Hawkeye..

Sure. This is Rusty. While we haven't disclosed a total amount that we're targeting, we have begun an internal review that we're going through right now, and we're going to be targeting what the kind of the best bang for our buck is.

But what I will tell you is the goal of this is to effectively get our balance sheet back to the long-term goals that we've always been targeting of kind of that 1.5x net debt-to-EBITDA..

Okay.

And I guess maybe more directly asked, is there a need for equity capital?.

Yes. At this point in time, we have no plans to issue any form of equity..

Got it.

As a follow-up to that, if you could just speak to maybe how the depth and pressure differs at Hawkeye compared to, say, the southern area and Greeley, and with it, the D&C costs?.

Dan, this is Matt. In the Hawkeye Area, the depth is roughly the same. It's within a few hundred feet of what we've been drilling up in Windsor or Greeley. The pressures are probably a little bit less downhold in Greeley, but very comparable to what we've had in Windsor.

So the wells that we've drilled so far, the drill times and the completion times have been very similar to what we've seen up in the Wattenberg part of the field. So we don't expect there to be a material change in well price as we move development down to the Hawkeye Area..

[Operator Instructions]. Our next question comes from the line of Welles Fitzpatrick from SunTrust..

Congrats on the 60,000 acres. It's great to see Conoco highlighting that on their Analyst Day this morning as well..

Yes. Thank you..

The GOR shifts in the Conoco wells that you guys outlined on Slide 15, it doesn't look like there's a whole pattern to it.

Is that flaring, and you're capturing it on state data? And so maybe we should look at that as a range but not try and see some sort of geographical delineation in that?.

So clarify that, are you talking about the percent oils changing in geographically?.

Yes. So like the Watkins, it would be a relatively low oil cut in the center and then if you jumped to say -- sorry, one, Watkins would be a relatively low oil cut and then the ones around it would be higher.

And it doesn't seem as though there's kind of a standard dip that's shifting that GOR either up or down, and I was just wondering if that was because some of these wells maybe were flaring, and so the percent oil might not be indicative of the rock and more of sort of above ground limitations..

That's correct. A lot of those early wells, I believe, were flared. And for the first several months that they -- once they went on production. But generally, in this area, the oil volumes for the wells are very similar and the oil APIs are very similar as you move from east to west.

There's not much of a change there, like you would see up in Wattenberg. The GOR does increase slightly as you go from east to west, so further west, the higher the GOR has been. But that does not mean that the oil rates have been lower. The oil rates are still very strong to the west. There's just more gas in the reservoir..

All Right. Okay. Perfect. And then can you talk a little bit about the different zones? Obviously, the 2 BH was a Nio B.

What have you guys seen from Conoco in the A and the C? And can you talk about sort of where the 12 to 16 wells might be landing if that all works out?.

Yes. So what we've been able to tell from the public data on the wells Conoco has drilled, they've mostly targeted the B bench, but they have also drilled the A bench wells and C bench wells. So of all their wells, I'd say probably 80% were in the B bench.

They've tested at least one Nio A and then they've done, I believe 3 Nio Cs with very similar results across all 3 benches. And all 3 benches in this area are well developed. They show very well on the logs on resistivity and porosity, and they've shown very similar results for the wells that Conoco has drilled..

Our next question comes from the line of Ben Wyatt from Stephens..

Just kind of sticking on the new asset there, the Hawkeye Area. It sounds like, Matt, you were just talking about Nio benches working.

Any Codell across this acreage?.

Yes, a good question. So the majority of our position in Hawkeye is going to be Niobrara only. However, the very northwestern piece on the map, particularly the acreage in 1 South, that will have Codell potential. But once you move south of the 1 South Township, the Codell is pretty much fully eroded away.

So everything south of there will be Niobrara A, B and C development..

Very good. And then maybe moving to -- looking at Slide 16 here on the Broomfield type curves you've got out there. Obviously, the offset operator oil barrels are outperforming kind of the standard Nio and Codell type curves.

Just curious if kind of you can give us a sense of maybe what the completion design is like for those well enhanced completions work down as you move into Broomfield. Just really any kind of color on what's making that type curve and maybe how you guys could have something come along a little better..

Yes. So the wells that are public that we have on this slide, what we can tell from the completion data is they've been slip water or a linear gel type wells with anywhere from 750 to about 1,200 pounds per foot of proppant depending on whether it was a Codell or a Niobrara.

As far as enhanced completions go, we really look at enhanced completions based off the oil API being produced, and we think that this area is going to be in that mid to upper 40s, which we think is going to be conducive for enhanced completions because that's how some of our Eastern Windsor acreage has been as far as API gravities go, and we've seen pretty good results up there.

So we have a good base, standard 1,000 pound per foot completion production results from the offset operators. And when we go down there, we'll be testing what enhanced will do in the area..

Our next question comes from the line of David Deckelbaum from KeyBanc..

I'll try to keep it to two, I have a lot, I guess more pressing on the Hawkeye Area, you have a couple of hundred permits in hand. You comment that you believe that it will compete with the upper 20% of your inventory.

How quickly is this folded into your development, and I guess, squaring that with the commentary around being sort of free cash neutral in the back half of '18?.

Yes. So the Hawkeye Area, we do, we have several hundred permits in process, of which over 50% of those are approved. What we're working on right now is completing the second well that we have drilled, which is near the first Bison well that -- where we have drilled.

And we're also in negotiations with several other parties on what the midstream offtake is going to be in this area. So for 2018, we will continue development down here, mostly testing spacing for the -- whatever we're going to end up at the 12 to 16 wells per section in the Niobrara.

But we'll also be really focused on getting the midstream implemented for 2019 full development.

Our 2018 program, remember, is pretty set in stone with the permits that we've gotten, and we plan to spend a lot of time developing our Greeley acreage, which is still the top acreage that we have in the company's portfolio and will really help us hit that cash flow neutrality in the second half..

David, I want to add that -- this is Mark. We're 100% committed to operating inside of cash flow in the back half 2018. And based on where we're at today, that's very, very achievable..

Mark, I wanted to clarify that comment that, that means all-in CapEx, not D&C CapEx?.

That's all-in CapEx..

Okay. Perfect.

And the midstream plans, I guess, on the asset, do you envision this as requiring any of Extraction's capital for a build out?.

No, we don't anticipate that. Actually, it's a very competitive area. There's a new PE firm out that's expanding the system out there. We've got Western Gas Resources, which has one of the most robust systems in the area. We're in deep discussions with both of them on the gas side.

Additionally, on crude oil side, there is multiple parties within the basin that are doing crude gathering. So we anticipate kind of utilizing relationships and joint ventures to move forward with the midstream and don't anticipate really any CapEx spend from our side..

Our next question comes from the line of John Nelson from Goldman Sachs..

Now that we have a kind of the big unveil out on Hawkeye, I was wondering if we can maybe take a step back.

Can you speak to maybe the play concept that kind of led you here that others may have been missing? But to put that in context everything by your legacy position, I know you've talked about having more virgin rock that maybe others weren't willing to drill where you're drilling.

What were others missing kind of in this new area? Is it just the changing completion design that's opening up, or can you just speak to whatever that might be, that would give you the confidence to spend about 15% of the market cap?.

Sure. I'll add some points here and then Matt can jump in if he's got something else to add. But I just really want to stick to we follow a similar strategy as to what we've done in the past.

We really like this area because it had enough vertical wells to give us really solid geological control, but not so many that we would have to worry about the mechanical risks of drilling around verticals or depletion.

The other thing we liked about this area is it's an area that really is from the DJ Basin perspective, it's very oily, which when you look at our revenues, it's like 70-plus-percent of our revenues are derived from oil, even though only roughly 50% of our production is oil-weighted. So we targeted that for superior economics.

We felt it was very good results that Conoco has had. Actually, some of the very best oily wells in the whole basin when you look at even across the whole basin, as was exhibited by our initial well out here.

So I think the reason we are able to get the acreage position we did is there was a very, very significant perception in the basin that this area was 100% controlled by Conoco. And Conoco obviously had -- there were some holes that developed in their acreage.

We discovered that opportunity, and we've spent a couple of years out here kind of really getting a toehold and you know that actually grew into a very significant position for us..

That's really helpful, so I could follow up kind of on one point, you mentioned the vertical well control. If I just look at the Slide 15 in the kind of horizontal success that you've highlighted, it would kind of indicate that you're more on the fringe of where at least the horizontal wells are.

As you look at those vertical wells, do they extend kind of even past your acreage? Or is that you're on the fringe that you think will end being within the fair way of more fair way to characterize the leasehold?.

The vertical wells that are down here were drilled a long time ago and most all of them are plugged and abandoned now, but they were targeting D Sand and J Sand fields. So there are several small D and J fields that might have had a dozen wells or so that are scattered out, and there's actually a lot more of them as you move to the east.

So the vertical well control actually was less as you move to the west, but it was enough to the east where we were able to define the boundary that we think is going to be the limit or the area that we'll be able to get good results from enhanced fracs, and that was where our by area was based on..

Okay. That's all really helpful. For my second question, I think the release commented expectation of the DCP plant to start up around the summer time frame. If you could just kind of highlight us on when you think the timing of that plant expansion is and to what extent you think line pressures may impact you until then..

I think the official timing is still Q3 from DCP, but we've been working on some ways to help them expedite that, and we're hoping that they are able to expedite that into late summer, somewhere around the July-August time frame..

And how do you see line pressures impacting the 2018 program?.

So we've been very proactive as far as the line pressure situation goes. We've seen this coming along ways out, so we started ordering a lot of our compression, a lot of our gas lift about 1 year ago.

And we've had all that delivered, and we've had it installed or finally being installed right now on the pads that we believe will be most affected by line pressure.

Fortunately, for us, we do have a lot of brand-new wells that make up the most of our production, and they are still flowing with very high pressures, and they're able still to get into the lines themselves. But we have identified the oil pads and put well head compression on those to keep the base production going.

We took that into account in our 2017 guidance. We will do the same with our 2018 guidance. But we do expect that there will be a big increase in production for most all the operators once we come to Q3 of 2018..

I would also add that we've been able to change our development program and take into account the DCP line pressures. As part of anticipating it, we've directed a lot of our development. We sit in a pretty unique position and that about 50% of our acreage goes into Western Gas.

And so the first half of the year, we're anticipating most of the wells that we turn on will be going into the Western Gas system..

Our next question comes from the line of Gail Nicholson from KLR..

In Matt's prepared remarks, he mentioned the 20% improvement in drilling times this quarter, which is phenomenal. I was just curious from a standpoint of cycle times, where you guys are today on spud to first production versus where you were one year ago..

We've definitely seen that improved based off the cycle times from drilling and our efficiencies we've been able to add on the completion side. So several of our pads, recently, we've been able to fit two completion crews on, and that's been able to significantly speed that up.

But just for example, we do have 1 22-well pad in Greeley of 2.5 mile laterals that 18 months ago, when we were planning that out would've been probably 18 months of total cycle time to get it online.

And because of our improved cycle times on drilling and our efficiencies on completions, we were able to get that from spud to first production in just under 10 months..

And then just looking at the new Hawkeye Area and regarding the permit, what is the permit time in Hawkeye versus your other acreage in the DJ?.

I'd say it's pretty comparable to our acreage in Weld County that's outside of municipalities, anywhere around that 6-month time frame from really identifying a surface location and then going through the permitting process.

Our other areas in Weld County that are in the municipal areas obviously take a little bit longer since we're very involved with the local governments on where we should cite those pads. But there's not a lot of municipalities down in the area that we're drilling in Hawkeye or at least not a lot of surface development that we have to contend with..

Our next question comes from the line of Jeffrey Campbell from Tuohy Brothers..

Congratulations on the stealthy work to get that Hawkeye position put together.

My first question regards Hawkeye, I was just wondering what HBP requirements you have over the next couple of years? And are your drilling plans in excess of any holding acreage requirements anyway?.

Yes. Most of this acreage obviously is not held by production, but it was all taken over the last 12 months. So our standard lease down there is going to allow for 5 years, so we have ample time to work through everything.

And we're very far ahead in the permitting process, and we don't anticipate HBP being much of an issue, since down here we can HBP about 1,280 acres with every well that we drill..

Okay.

And I'm just curious what if anything is your relationship with Conoco? I mean do you foresee the possibility of doing some swapping with them to drill more logically? Or do you not really even see that as much of a necessity?.

Yes. It's a great question. We have been in contact with Conoco, and we have completed swaps with them so far to date. And I think it's something that will continue to happen just like we do up in Wattenberg with other operators. But everybody typically wants to gross up their own working interest in the units that they're drilling..

Our next question comes from the line of Jeanine Wai from Citi..

The press release mentions that half of the increase in the full year CapEx guidance is related to incremental delineation and half is due to just being ahead of schedule in testing larger fracs.

My question is whether all the incremental delineation and testing, is that all within 4Q? And will that show up as kind of stellar growth in Q1 versus the new exit rate? And then also, can you talk about your thought process on moving forward on those incremental items versus slowing down and staying within the CapEx budget, given that it seems like your development plan over the first several months of next year seems to have been pretty locked down for some time?.

I'll take the first part of that question on the incremental wells that we've done. Over the third quarter especially and in the fourth quarter, we've done several really test wells on seeing what enhanced completions will do in different parts of our acreage before we move in there for full development.

So those are kind of scattered out in different areas where we've gone in and we only want to drill 1 or 2 wells before we move in with a full pad of 16 to 20 wells per section with enhanced completions. We want to at least get some data points in each area before we move forward with the full development there.

And then what was the second part of that question?.

I could take that. With respect to the slowing down in Q4, essentially, what we did in Q3, Jeanine, is we moved because of efficiencies some of our work program from Q4 into Q3. It's not going to result in a big uplift in production.

It's basically moving production from Q1 to the front part of Q1 or towards the end of Q4, which is why we increased our exit rate. But just given the fact that we're a little bit ahead of schedule on that, we have the ability in the back end of Q4 just to slow down a little bit as we get ready for 2018.

But the nice takeaway is that we're going to enter 2018 in very good position to demonstrate very strong results..

Our next question comes from the line -- it's a follow-up from the line of David Deckelbaum from KeyBanc..

The guidance for fourth quarter implies about a 50% crude cut versus 55% in 3Q. It sounds like, geographically, I guess the Greeley area doesn't come online, I guess, the triple creek pad wouldn't be until the first half of '18.

And then, it sounds like, Mark, from your comments around the Western Gas system that most of your activity is going to be in the southern area in the first half of the year in terms of tie-ins.

I guess when you think about guiding to mix, I know that you guys tried to be conservative, but are you guiding to your sort of target type curves and you've just been outperforming them in the last several quarters in terms of oil cut? Because it kind of struck me as if you're keeping up with that completion cadence, I know things kind of slowed down a little bit, but it wouldn't seem to me that your oil mix would change dramatically from 3Q to 4Q..

So David, we have had a little bit of a lag time in bringing on pads. So we're bringing on a whole bunch in the fourth quarter, which will be lower cut -- or higher oil cut on the wells.

But we also are -- we're able to accelerate some of that triple creek pad into the fourth quarter, which, if you remember triple creek is in the Greeley area where it does have very high gas rates, but it also has very high oil rate. So that we'll be producing in the fourth quarter and has an effect -- or an impact on the total oil cut..

Okay. I appreciate that. And then the other one I just had on the Hawkeye Area.

I guess as the way that you guys see it now, of the 60,000 acres, I guess do you break it up in the multiple buckets of what type of play you think of it as -- because I mean the Adams County acreage, if you think of those more of a typical sort of DJ-Wattenberg play versus more of the oil-prone Arapahoe County acreage that offsets Conoco's position.

And I guess can you kind of break down what the number of acres that you kind of have and maybe different buckets?.

As far as the Niobrara formation goes, we're looking at it very similarly across the whole position right now as the oil APIs are very similar. They range from -- anywhere from 40 to 42. So there's not much of a change there.

The one difference -- or the one different bucket, I guess, I could say is when we talked about a few questions ago with there being Codell potential in the very northwestern side. So up on the northwestern side of Hawkeye, we will be drilling Codell wells, and there will be Codells in those development units up there.

But once we move south, into two South and below, that will mostly all just be Niobrara..

Our next question comes from the line of Jeff Robertson from Barclays..

Can you all talk a little bit more about what now has become nonstrategic in the portfolio since the Hawkeye acreage, you say, is -- ranks among the top 20%?.

Yes. I want to make sure that we emphasize, we use the term nonstrategic versus noncore. We're doing a full -- and the reason I differentiate from that it's really we're looking at the Hawkeye Area being very, very attractive, but also, potentially letting some things from a timeframe just be further back in the inventory bucket.

So there's several things that we've actually been approached on that are very attractive acreage that we may see as nonstrategic just because it's going to be further back in the inventory. We are conducting a internal review as we speak and believe we'll be able to give some color at a later time frame.

But right now, we're not ready to kind of disclose exactly where in our portfolio we're going to target that. But I can affirm that we have a very high level of confidence on our ability to execute this plan just given proactive approaches that we had on inbounds..

Rusty, the talk about growing 75% in 2018 at least as a goal, does that include or take into effect any potential asset sales? And I guess, the other part of that question is, are these -- are you talking about acreage, or you talking about current production that gets pushed as a package back to the back of the line, and therefore, becomes something that might be considered to monetize?.

Yes. So what we are targeting the 75% and does anticipate the program, the asset rationalization, so that is net of asset rationalization.

Is that your question?.

Yes..

Yes. And the things that we're carving. Again, I don't want to lock anything in stone right now. But right now, the things in view have a very limited contribution to cash flow..

Our next question is a follow-up from the line of Jeffrey Campbell from Tuohy Brothers..

I wanted to kind of hit the portfolio thing in a different way. Again, you've identified Hawkeye as top quantile. You've also got Broomfield in hand now, which is really great. And I don't think we talked about it this quarter, but I know you've been doing experiments in the extension area.

So I was just wondering can you kind of rank order how your portfolio asset is currently composed is going to attract capital over 2018?.

For 2018?.

In 2018, our development program is, basically, some of it will be in Greeley, some of it will be in kind of our southern area that will go to Western Gas Resources. And then we will have the kind of the spacing tests in Broomfield and in the Hawkeye Area.

And what's really pretty cool about where we're sitting right now, you start looking at the -- we're probably approaching 20 years of inventory. So when you look at line of sight for what are we going to be doing for the next 5 to 10 years, it's all kind of stuff like Greeley, Broomfield, Hawkeye, I mean, Western Wattenberg.

I mean you're just lining up basically a decade of very, very high return stuff. It's really a good position to be in, and that gives me a lot of comfort at night..

Let me ask one last question. On Slide 14, you've got the 50% enhanced curve, which I assume is consistent with where you've shown 50% enhanced relative to your current production and so forth at 20% enhanced. But then you've got this offset average curve that's way up there, and it's composed data from 26 wells.

I was just wondering, can you give us some kind of an idea of what the EUR is that's being projected and then offset average?.

Obviously, the offset average is performing very good and well above the 50% enhanced curve for us. As far as the EUR goes on that well, we haven't disclosed any of that yet, but it's looking very promising just from the cumes to date with most of those wells having 2 to 3 years of production history..

Well then, maybe I'll ask it another way.

The 20% and the 50% enhanced, are those based off of what you would consider to be your historically standard EUR for production wells?.

Yes. It's the exact same 20% and 50% enhanced curves that we've been showing all year..

Our next question is a follow-up from the line of Dan McSpirit from BMO Capital Markets..

You addressed the oil cut change expected in fourth quarter '17.

What about 2018? Can you sketch for us how oil production is expected to grow next year? And maybe what oil cut looks like at the corporate level?.

We think that, in 2018, it will be very similar to what our average oil cut was for this year, as we will be drilling a lot more wells in Greeley, but we are still drilling a lot of our lower GOR type acreage too in the Windsor area and further down south. So we don't expect a material change year-over-year..

Okay.

And oil production growth next year as part of the equivalents?.

I don't think that's something that we've said yet.

We only did the 70% number on the Boes?.

Yes. But just to clarify, it's similar to what Matt was referring to, similar to kind of where we're looking at, kind of fourth quarter, we're anticipating a pretty consistent oil cut through 2018..

We'll update the oil number when we give guidance in December..

Got it. And as a follow-up to that. If I heard you correctly, you opened up with a statement that the company can beat 2018 guidance based on lower D&C capital spending than invested this year.

I guess my question is, how conservative is the guide?.

How conservative is 75% growth?.

Right..

So I would just say that what we tried to say in that statement is that with a capital budget for drilling and completing less than what we did this year, we can hit that number or beat that number..

Thank you. And this does conclude the question-and-answer session of today's program. I'd like to hand the program back to Mark Erickson for any further remarks..

I just like to thank everybody for participating in our call today. I look forward to continuing to come back each quarter with good, strong results and hitting our targets. Thank you..

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day..