Antero Resources Corporation (AR) Q2 2017 Earnings Report, Transcript and Summary

Good day, and welcome to the Antero Resources Second Quarter 2017 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. At this time, I would now like to turn the conference over to Mr. Michael Kennedy. Please go ahead.

Thank you for joining us for Antero's second quarter 2017 investor conference call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com where we have provided a separate earnings call presentation that will be viewed during today's call. Before we start our comments, I would like to first remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Joining me on the call today are Paul Rady, Chairman and CEO; and Glen Warren, President and CFO. I will now turn the call over to Paul.

Thank you, Mike. And thank you to everyone for listening to the call today. In my comments I'm going to focus on the productivity gains we continue to achieve through our advanced completions, and discuss how these productivity gains have led to an increase in our 2017 production guidance and in our mid-year reserves. Glen will then highlight our second quarter financial results discuss our capital efficiency gains and touch on AR's continued consolidation success in Appalachia. Let's begin with discussion of AR's continued productivity gains from advanced completions. As you can see on Slide number 2, titled higher intensity completions driving out performance, we've illustrated the impact to production performance from various proppant intensity levels. The black dotted line represents our legacy 1.7 Bcf per 1,000 cumulative type curve, which is the type curve that we have historically used for both internal forecasting and reserve bookings. The black dash line represents an improved 2.0 Bcf per 1,000 type curve based on results from our advanced completions dating back to early 2016. And finally the various colored lines represent the average cumulative wellhead production per well, normalized to 9,000 foot lateral corresponding to various levels of proppant intensity. While we're still in the early innings of analyzing the EUR impact from these advanced completions, we do have over a year of production history for wells that were completed with 1,500 pounds of proppant which is shown in green. This data set easily supports the 2.0 Bcf per 1,000 type curve outlined on this slide. Toward the end of 2016 and through the first half of this year, we've continued testing higher proppant loads which we put in two buckets, the 1,875 pound bucket and the 2,500 pound bucket per foot shown as red and blue lines respectively. As illustrated on the slide these completions using higher proppant loads have yield production that is significantly outperforming the 2.0 per 1,000 wellhead type curve, with 2,500 pounds per foot completions outperforming the type curve by an average of 20% through the first 150 days of production. This outperformance which we will dive into more on the next few slides has enabled to increase our 2017 net production guidance by 3% from a range of 2.16 to 2.25 Bcfe per day to a range of 2.25 to 2.3 Bcfe per day as depicted in the insert on Slide number 2. Importantly, we're able to raise the production guidance while maintaining the same drilling and completion capital budget of $1.3 billion. Directing you to Slide number 3, titled outstanding Marcellus well reserves in 2017. I'd like to provide some more color around the encouraging results I just mentioned by highlighting some notable Marcellus pads. The chart on the top of the slide compares the actual daily production as compared to the originally forecast production for nine Marcellus pads completed thus far in 2017, that have at least 60 days of production history. On average, the production from Antero's 2017 Marcellus well completions is trending 25% ahead of forecast which is primarily attributable to the increase in proppant intensities that I just discussed. In addition to the enhanced productivity from these pads, the other key takeaway from this slide is the continued downward trend in finding in development costs. As portrayed in the chart on the bottom of the slide, the average F&D for all pads in 2017 is $0.45 per Mcfe. Additionally, we continue to be a leader in drilling longer laterals. During the second quarter, the 29 Marcellus completions averaged almost 9,400 feet of lateral and the five Utica completions averaged over 11,200 feet of lateral. We completed two wells on the Kofer [ph] pad in the Marcellus that averaged 13,700 feet laterals and we set a record for our longest lateral drilled at 17,400 to the Utica. These two Kofer [ph] pad wells averaged 34 Bcf equivalent each assuming ethane rejection. The ability to outperform our production forecast and drive down F&D cost, is a testament to the efficiencies we've been able to achieve through drilling these longer laterals and improving drilling and completion times as well as the impact of advanced completions. Turning your attention to Slide number 4 titled Marcellus EUR reserve upgrades. Yesterday, we announced mid-year reserves for AR. One of the key highlights from our mid-year reserve evaluation was the upgrade of about 600 proved undeveloped and probable drilling locations from a 1.7 Bcf per 1,000 EUR type curve to an approximate 2.0 Bcf per 1,000 EUR type curve. The 199 upgraded PUD locations are highlighted in red within the purple statistically proven area that we use for reserve bookings. The 398 upgraded probable locations are highlighted in blue and primarily located within that same purple statistically proven area as well as in the three mile buffer area outlined in the orange color to the east. The other key item that I would like to point out on this slide is the red star symbol, which highlights third-party industry pads where advanced completions were utilized and average EURs were at least 2.0 Bcf per 1,000. Antero has over 2,400 proved and probable drilling locations that are outside of the purple and orange upgrade outlines that are shaded black and grey and currently are still booked at 1.7 Bcf per 1,000 type curve for reserve purposes. As we expand the use of advance completions, we would anticipate upgrades on a significant number of these 2,400 additional locations. To further touch on our mid-year reserves and the impact we're seeing from the advanced completions. I'll turn you to Slide number 5, titled reserves summary. Since the severe downturn that began in late 2014, we've been able to consistently grow our reserves both on a volume metric and strip PV-10 value basis. The top two charts show that we've been able to grow our 3P reserves by approximately 31% from 2014 to mid-year 2017 and the after hedge pre-tax PV-10 value of those 3P reserves by over 73% over the same time period assuming strip pricing. Another important take away from this slide, is the fact that 96% of Antero's 3P reserves are actually comprised of 2P reserves, that would be proved and probable. This further demonstrates AR's low-risk highly repeatable drilling inventory and ability to deliver consistent value to shareholders from many years ahead. With that, I'll turn it over to Glen for his comments.

Thank you, Paul. In my comment today, I'll highlight our second quarter financial results. Discuss our capital efficiency gains and touch on AR's continued consolidation success on Appalachia. Let's first discuss some of the key highlights from the quarter. Production average a record 2.2 Bcfe per day for the quarter including a record 103,000 barrels a day of liquids. The liquids production during the quarter consisted of 6,700 barrels a day of oil and over 96,000 barrels a day of NGLs representing a 37% increase in the prior year quarter and a 4% increase sequentially, as we've remained the largest NGL producer in Appalachia. Moving onto financial highlights from the quarter, we generated $321 million in consolidated EBITDAX, a 3% increase from the prior year quarter resulting in an EBITDAX margin of $1.16 per Mcfe. We realized $3.15 per Mcf before hedges on our gas production during the quarter, which was 63% increase compared to the prior year quarter. We realized natural gas hedge gain of $55 million during the quarter or $0.38 per Mcf bringing our after tax or after hedge realized price to $3.53 per Mcf, a $0.35 premium to the average NYMEX Henry Hub price for the quarter. Quarter-after-quarter Antero continues to lead the industry in realized gas pricing before and after hedges. As it relates to liquids, we realized an unhedge oil price of $43.24 per barrel which was only $5 differential to NYMEX WTI for the quarter. The improvement in the realized oil price differential was driven by new contracts weighing into the, to commence on April 1 of this year. we realized an unhedge C3 plus NGL price of $24.14 per barrel during the quarter which represents, a 41% increase from the prior year quarter and 50% of NYMEX WTI. To provide further color, on the capital efficiency gains. I'll point you to Slide number 6 titled capital efficiency dry high growth within cash flow. Before I get into the takeaways from this slide. I will remind everyone that the standalone AR cash flow projections outlined here are all based on Wall Street research estimates as of July 31, 2017 and should not be relied upon as management forecast. With that being said, the key takeaway from the slide is that we expect to be able to grow an attractive 20% to 22% annual production growth rate while essentially spending within upstream cash flow through 2019. Circled in red you can see that the total outspent for 2018 and 2019 is just over $100 million each year only about 5% to 10% of upstream EBITDAX. Again this speaks to the major strides we've made on the operational front over the last couple of years, with our advanced completions and continued operational efficiencies that include drawing longer laterals and reductions in drilling and completion cycle times. Moving onto consolidation activity, which has received a lot more attention lately. We wanted to touch on Antero's continued success. Since the commodity downturn in late 2014, Antero has been a leading consolidated within Appalachia, given our industry leading hedge growth and firm transportation portfolio. Looking at Slide number 7, titled a leading consolidator in Appalachia. You can see that we've added over 111,000 net acres to our core Marcellus and Utica position since the beginning of 2016 including over 20,000 net acres thus far in 2017. In early June 2017, we acquired about 10,300 net Marcellus acres primarily in Doddridge and Wetzel Counties, West Virginia for $130 million. The acquisition included 17 million cubic feet a day equivalent of net production, 15 drilled but uncompleted wells with an average lateral length of 8,200 feet and one drilling pad. And that works out to about 4,000 per undeveloped acres on attractive price force on an undeveloped acreage basis. This was representative many of the consolidation transactions we've completed over the last couple of years. Core infill or bolt-on acreage that's primarily undedicated from a midstream perspective. This particular transaction added 89 undeveloped 3P locations and enhanced 74 existing 3P locations, by incremental working interest and or increased lateral length. The lateral length of the new or identified 3P locations averages 8,700 feet. So another nice pick up for some of the acreage front. What does this continued consolidation activity do for us from a core drilling inventory standpoint? For that I'll refer you to Slide number 8, titled largest core drilling inventory in Appalachia to make a couple of points. First, Antero continues to maintain the largest core drilling inventory in Appalachia with approximately 3,900 undrilled locations, that's up almost 400 locations from year-end 2016. Roughly 72% of these locations are liquids rich and is outlined in the pie chart on the slide. Antero holds about 41% of the undrilled core liquids rich locations in Appalachia. This significant liquids rich inventory has and will continue to enable us to achieve tremendous growth in our liquids production, with significant exposure to liquids pricing upside. It is important to point out, that this is chart is pro forma for all mergers and acquisitions both closed and announced to-date. So despite some large deals announced we did basing this year. Antero still has a sizable leading core undrilled location inventory within Appalachia. And we'll look to opportunistically add to this position overtime. Before I wrap up, I wanted to touch on some of the parse topics that has been notable for certain of our peers lately. At a recent conference we rolled out, our Slide number 9 titled significant value proposition. The idea behind this slide was to provide investors with enough color around the true value of great pieces of Antero story. One reason for some of parts discounts that we see in Appalachia the tax burden of it, sale of midstream security. So we're showing an after-tax value for Antero's 58% ownership at AM, after applying AR's $1.5 billion of NOLs. While we are illustrating the breakdown of the Antero, some of the parts on the slide, we do see a lot of value and integrated story, particularly as we continue to target attractive annual production growth of 20% to 22% through the end of the decade. That being said, you can see in the waterfall that when you consider the after tax AM value of $2.9 billion along with $2 billion hedge booked mark-to-market value. You arrive at implied AR standalone value of about $5.9 billion. With an estimated PDP, PBA value of $4.8 billion and that's in the grey bar there, which includes deducting 100% of gather and compression fees paid to Antero Midstream. You've arrived at implied undeveloped acreage value of $1.1 billion. Looking at our core undeveloped acreage of 492,000 net acres. This implies that AR is currently trading at only $2,300 per core undeveloped acre, a very attractive value proposition. It's instructive to compare that $2,300 per acreage trading value to recently announced Appalachia corporate transaction which most analyst pegged at about $10,000 to $15,000 per undeveloped acre. Slide number 10 titled midstream drives value for AR. Demonstrates why we believe that there should be a premium for the integration that Antero has built, where the Midstream simply serves its sponsor upstream development. Integration of the Midstream business enables us to better control our development program and provide significant visibility and to product flows and pricing Appalachia. This is very important when you can control the largest core acreage position in Appalachia and targeting 20% to 22% annual growth through the end of the decade. Midstream has also been a very attractive investment for AM as you can see the in the bullets, three times capital invested pre-IPO and we've seen 18% total annual return on AM, since its IPO. In closing, I'll point you to Slide number 11. Entitled de-risked development plans drives long-term visibility. Over the past eight years, we've built the most integrated natural gas and NGL story in the US. We run the business with a long-term mentality of ensuring we can continuously develop our 53 Tcfe 3P reserves for many decades ahead, which we believe will generate the most attractive value creation to our shareholders including management and substantial owners too. With that, I'll turn the call over to the operator for questions.

[Operator Instructions] the first question is from Neal Dingmann from SunTrust. Please go ahead.

Can you just talk a little bit about just M&A in general obviously, there is been a few deals here and there? You guys included are you seeing - continuing to see bunch of deals offered and then, what do you say with potentially disposing some of your assets as well. Thank you.

Yes, there are smaller deals out there, A&D, M&A type deals of course the big one that was announced, we all know is EQT-Rice but, there are others go by and there's - so there's continued consolidation, in terms of divestment, you may remember that earlier this year we sold some non-strategic acreage in Pennsylvania, so we continue to look at our portfolio and let go of some of the things that aren't strategic to us. But everything we have now in our core area, we consider strategic. So we certainly participate where sellers pass by their properties and we pick and choose which ones we're interested in, so pretty active market. And continued consolidation is the theme in Appalachia.

And can you just talk about you. It looks like Slide 2; looks like you're seeing some diminishing returns. It looks like as you increase - can you just talk about your thoughts around there?

Sorry, Neal. Can you repeat that question?

This is Ray on for Neal. Just on Slide 2, it looks like you're seeing some diminishing returns as you deal from basing 75 [ph] to 2,500. Could you just talk about your thoughts around the same load [ph]?

Yes, I'm not sure I'll read it that way exactly, I mean that's pretty phenomenal outperformance but it's still too early to tell on the red and blue. I think as to whether or not it returns to 2 Bcf type curve or you end up at above 2 Bcf. But at some point you'll see diminishing returns I'm not sure we've found that point yet, we're still searching. Depends on the area too.

Okay, thanks.

The next question is from Holly Stewart from Scotia Howard Weil. Please go ahead.

Maybe can we just talk broadly on NGL realizations? I know you guys take some of yours in kind, maybe just talk about kind of what you're seeing in the market right now. It seems at the last two quarters maybe we were parity with Bellevue and it looks like now maybe move back to discounts, so just kind of curious as to what you're seeing in the marketplace.

Yes, Holly that's a seasonal phenomenon generally. You track Bellevue pretty tightly in the winter months and then it winds out in the summer generally speaking. And hopefully that bridge to that ones we have ME2 in place, but I think we have some hedges in place that's attractive from the bottom line value of NGL's this quarter that we've been negative, but we're still around 50% of WTI in the second quarter, so that's sort of the soft period and we expect that to improve as you go into the late fall and once you're done.

Okay, that's great. And then maybe just on the marketing effort to know we were a bit narrower in the last few quarters and that's tougher to remarket your excess capacity. Are you seeing anything that's changed so far here in the third quarter given that basis is wind out?

Well certainly you've seen Holly and market has seen that, all eyes are looking towards Rover and so when Rover looked like it was going to happen in the second quarter, then firm shippers that had excess capacity started bidding up on the distress gas that was on Dominion South and Tetco, M2 pools and so basis narrowed. Once the delays became evident in Rover than the basis widened again. So we're certainly seeing that dynamic going on production in Appalachia continues to grow, so including with ourselves. So we do see that the near-term projects will fill up relatively soon and but the dynamic there is just with Dom South and Tetco M2 relative to Rover and REX right now.

Okay and then maybe, final one for me. Since you hit on Rover, the delays. I know you guys have kind of shifted some activity back to the Utica in preparation for that project coming online has this delay impacted any thoughts on kind of the development schedule?

Not really, those Utica wells and pads are being drilled down, so we're timing the completion to dovetail with Rover Phase 1 as it arrives at Seneca, our latest estimate and obviously we're in contact with both energy transfer on the Rover project as well as with regulatory people on the other side and do see that the project is moving forward. We expect Rover Phase 1 to get to Seneca in September, October and so we'll time the completion of our pads there in the Utica to that. And then we would expect Rover Phase 2, it's probably a month or two behind that. So we're thinking October, November for Phase 2 to come to sure would, that certainly will have plenty of production that will be moving through Phase 2 Rover, when it arrives in the third and fourth quarters.

Okay, great. Thanks guys.

The next question is David Tameron from Wells Fargo. Please go ahead.

Can I just talk about philosophically the higher sand proppant, the higher loadings? Why not just - all the operators are doing this, but as rather than going 1,500 to 1,800 to 2,000, 2,500? Have you guys put on any big - why not just jump like a 3,500 number and try some of those wells. I know that's a little bit of Wall Street dummy down version but why not take that approach and then dial it back or do you think the rock can put away that much sand? Can you just talk about that?

I do think that the rock can take that much proppant and we've just been a little more conservative wanting to make sure that what we're doing, I think we're inching up from the low side versus jumping out there. So and being a little bit conservative, we try not to change too many variables too quickly, especially when there is a lag time of at least 90 days before we have a bead on, what the well is doing relative to type curve. So we've just - when we do these pilots, we do them say a pad at a time. Let's say it's a 12-well pad, we'll do six wells to the North, one way and six wells to the south the other way. So just a little bit of delivered approach in changing too many variables at once. But there is nothing to say that the rock can't take more proppant. We're also working with our cluster spacing and just tightening that up, and the purpose there is to keep the fracs close to the well bore and just have higher recovery factors close to the wellbore. So continue to adjust the parameters. We're still in the relatively early innings on what the optimum frac is, I don't think we've arrived at that yet. But making good progress and seeing really encouraging results up through 2,500.

Okay, thanks for that. Let me go back to valuation. I think in the Slide 9 that you talked about Glen and whoever Paul or Glen, whoever wants to take this. But - you as we said on [indiscernible] not only you laid it out a lot better on that Slide 9, when you just think about 16.5T then enterprise value $11 billion or $12 billion, no matter how you look at it, it seems like there is value embedded within the shares and we can talk about why the stock has worked or hasn't worked. But can you - how should we think about your ability to or your desire to do something to unlock that value. I know - well I'll just leave at that. Let you respond to that. I know you've already taken the approach of - will create the company, create the value. It will eventually be recognized, but how should we think about your desire to maybe accelerate that process?

Well I think, this is part of it highlighting the various pieces. Some of these parts are difficult to decide for, unless you really dig in. and one is just that after tax value of the Midstream business. I think some maybe would not have recognized that we do have $1.5 billion of NOLs, once could apply against any sell down of that. I'm not implying that we would sell down any, I'm just taking it to the extreme, what's it worth? If you sold the whole block. And then the hedge value and you do the math. It worked through the core acres and this is kind of one way to look at it, so I think we agree. There is a lot of value there and part of the process is perhaps just highlighting the various parts for investors. It's not particularly hidden, it's not something where there is hidden value that people can't do the math on. So we're just trying to help with that. I think right now to something that we discuss at the board level in a quarterly basis. We'll continue analyze this, no real initiatives at this point, other than to point this out to the investment community.

Okay, thanks.

The next question is from Subash Chandra from Guggenheim. Please go ahead.

Yes, I was thinking out loud a little bit here, but this ties in David's question. Upstream companies with Midstream entities have often complained about summer part discounts. It hasn't worked, I don't think pointing it out has helped others either, but one of things that seems to have worked at least in the EQT-Rice deal is somewhat of return of capital strategy. So to Dave's point of view and I think you answered it, it's something you're well aware of and you discuss it with board level. When do you go to plan B? If just the information does not close the summer parts.

There is no timeline on that. I don't think we're going to pulled out, that we'll have a plan by the end of 2018 or anything like that. But it's something that we continue to selling - we're aware of, I mean we're shareholders as well in a pretty big way. And it's something we would like to see more value, they're in the share price. So can't really give you a timeline, Subash, but it's something we do think about and spend time on, for sure.

And so what do you think of range sort of hinted at it to go down the caveat path? What do you think of return of capital? Pre-tax dividend.

Yes, I think that's within the horizon that look at, certainly over the next few years. We do expect to fairly free cash flow neutral here over the next couple of years. So we're getting to that point as well and it's something that certainly will be considered at the board level.

Got it, okay. My next question is that, in the PV-10 how much of the increase because it was quite strong relative to at least not expectations in the value of the reserves, was a lower operating cost structure?

We certainly had some lower well cost built-in, so that's come down over time. And I guess slide on web slide that shows you quarter-by-quarter but we saw another notch down particularly in Utica on the well cost in the second quarter. Operating cost, no real change there. The 600 wells that were upgraded type curve that drives partly the acquisitions drive it. We had a quite a bit of PV-10 by adding those acquisitions here in the first six months of the year. But also we're just continually adding acreage on the ground and back to the core number of location, slide I think it was Slide number 8. We do a very meticulous bottoms up analysis on core locations and it's tied to our 3P locations, that's far we can disclose, 3P reserves. It's very much bottoms up, laying out, lateral links and weld into the on our acreage position. And we do the same analysis for all of the peers. Yes, where some companies, some peers just simply do a top down analysis on these locations and that's what drives analysis around NAVs on the street. If you just use a top line acreage number to buy the well density that gets you to number of locations, but that's not the same as really looking at on the ground because a lot of acreage is scattered and we don't really count that. So we're kind of 85% efficient in our location counts in both our reserves and on this slide. Meaning we leave 15% of the acreage out that's scattered. And we do the same for other operators, so it's truly developable acreage. But we saw a nice uptick on that. 400 locations just see here on the slide, in the first half of the year. So that's part of the driver behind PV-10 pickup.

Right. And just final one from me. Is the Rover included, the Rover FT and so on included in the Reserve Report?

Yes, I mean we back channel from transport in that - in terms of pricing and cost.

Yes and net backs, the ultimate sales price for each Mcf is going to be volume metrically proportional ultimate sales price, so yes. A Rover netback would be included in that Reserve Report and it would be - I don't know the date - say Rover comes on, but it's probably October Phase 1 and December Phase 2, I'm sure they're conservative on that.

Great. Thank you.

The last question is from James Sullivan from Alembic Global Advisors. Please go ahead.

Maybe you could talk about it as it pertains to the PV-10, but also maybe in the medium term about how I think pricing worked into your assumptions, maybe just first on the PV-10. And then what you guys are seeing in terms of the near term market there. Could you just update us on that? On how you're feeling about that little market inside?

Yes, I can tackle the first part of that. Maybe Paul, the second on the market kind of going forward. But we assume that we extract as much ethane as we need to both meet pipelines spec, but to also to meet various contracts that we have in place. One being the Borealis contract for instance, it springs into places once ME2 is online or is running. So those kinds things are baked in and we know to sink any more than that, so we're not recovering all of the ethane by any means, in the reserve report. So it's very much tied to what we're doing on the ground.

Yes, that's right. And in terms of economics right now, as Glen mentioned, we're recovering just enough ethane to stay within spec for the pipelines and so, three quarters of the ethane at least is being left in the stream and the economics dictates that, that one gets paid more on BTU basis for the ethane. Right now, leaving it in the stream. The forward curve would say that we will be recovering, next year ethane is up in the 26, 27 range and it goes up further from there. So that will get into recovery mode net of [indiscernible], so we'll expect to recover more and certainly as we get towards Cal 20 and Cal 21, we're - really big volumes for sales which Shell on their cracker and others, as that comes closer and closer, there will be better and better economics for recovering ethane ultimately.

Okay, great. And can you just remind what the pricing mechanism is or how exactly on the Borealis contract and what you put over on ME2, what you guys are expecting to get for that portion of your ethane stream?

We can't get into that exact particulars of the contract, but suffice it to say that it's based on gas value and recovery of costs and net of transportation. So we feel it's a reasonable contract and we have others that are in a similar range.

But it's priced, premium to gas value [indiscernible].

So you guys thinking about it as an incremental of what you've been realizing in the middle part of this year?

Yes that's right, the premium to gas value, net of cost.

Great. Thank you and just two other ones that are also kind of ethane related. But on your Slide 3, where you show your 2017 proppant adds, you kind of estimated URs [ph] per 1,000 feet, are those with or without ethane recovery? I know you obviously doing some partial ethane recovery. So I just [indiscernible] actual or if you're just trying to C3 plus processed volume.

I believe these are all just wellhead.

Yes, they're without ethane [indiscernible]. It's not putting six times multiple one extracted, it's basically wellhead production.

So that's actually wellhead without any processing.

Correct.

Okay, all right. That's good. And then, you guys have typically shown both pre and post processing numbers in your type curves and you guys gave a kind of wellhead number, with your increase here from 1.7 to 2 in the central part of Doddridge and Tyler. But if you were to just take a stab at - for 1,250 BTU per cubic foot or standard kind of wet gas type curve that's now been upgraded for 1.7 to 2, with a post-processing per foot. Type curve number would be roughly including and excluding ethane.

Yes, that's a good question. People always get confused about that wellhead versus processed. If you look at the bottom of Page 3, you can see by well pads what the average processed BCFE per 1,000. So whenever we put E on the end of BCF that denotes that it's been processed. So you can see that these averages all these pads that we've completed this year and they've been online for 60, 90 days plus some much, quite a bit longer, some up to six months. They average about 2.5 BCFE per 1,000 and that's off of that roughly 2 BCF type curve at the wellhead.

So that's a pretty good rule of thumb, a 2.0 BCF converts to a 2.5. It will depend a little bit on BTU, but add a 0.5 factor to convert to equivalent and that is with ethane, left in the stream.

That was on Page 6.

They'll probably have it just under 12.50 BTU, maybe 12.40 BTU, 12.30.

Got it. So NAVs bottoms trip on three that is I think left in the stream.

That's correct. If you extract ethane and you multiply it by six because you really had, yes you're getting good market value for ethane above gas value, then that would jump that 2.5 number up into the 3, 3.2 probably something like that, BCFE per day.

Got it, perfect. That's exactly what I was looking for. Thank you guys.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Kennedy for any closing remarks.