Antero Resources Corp (AR) 2017 Q2 法說會逐字稿

Good day, and welcome to the Antero Resources Second Quarter 2017 Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded. At this time, I would 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 reviewed during today's call.

Before we start our comments, I'd 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 continued 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 midyear 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 a discussion of AR's continued productivity gains from advanced completions. As you can see on Slide #2, titled Higher Intensity Completions Driving Outperformance, we have 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 a 9,000 foot lateral, corresponding to various levels of proppant intensity.

While we are 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.

Towards the end of 2016 and through the first half of this year, we've continued testing higher proppant loads, which we put in 2 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 on 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 us 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 #2. Importantly, we're able to arrive -- to raise the guidance -- the production guidance while maintaining the same drilling and completion capital budget of $1.3 billion.

Directing you to Slide #3, titled Outstanding Marcellus Well Results 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 9 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 and 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 5 Utica completions averaged over 11,200 feet of lateral.

We completed 2 wells on the Cofor pad in the Marcellus that averaged 13,700 feet laterals. And we set a record for our longest lateral drilled at 17,400 feet to the Utica. These 2 Cofer pad wells averaged 30 -- 34 Bcf equivalent each, assuming ethane rejection. The ability to outperform our production forecasts and drive down F&D costs 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 #4, titled, Marcellus EUR Reserve Upgrades. Yesterday, we announced midyear reserves for AR. One of the key highlights from our midyear 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 3-mile buffer area outlined in the orange color to the east.

The other key item that I'd 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 gray, and currently are still booked at 1.7 Bcf per 1,000 type curve for reserve purposes.

As we expand the use of advanced completions, we would anticipate upgrades on a significant number of these 2,400 additional locations.

To further touch on our midyear reserves and the impact we are seeing from the advanced completions, I'll turn you to Slide #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 volumetric and strip PV-10 value basis. The top 2 charts show that we've been able to grow our 3P reserves by approximately 31% from 2014 to midyear 2017, and the after hedge pretax PV-10 value of those 3P reserves by over 73% over the same time period, assuming strip pricing. Another important takeaway 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 an ability to deliver consistent value to shareholders for many years ahead.

With that, I'll turn it over to Glen for his comments.

Thank you, Paul. In my comments today, I'll highlight our second quarter financial results, discuss our capital efficiency gains and touch on AR's continued consolidation success in Appalachia. Let's first discuss some of the key highlights from the quarter.

Production averaged a record 2.2 Bcfe per day for the quarter, including a record 103,000 barrels a day of liquids. 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 remain the largest NGL producer in Appalachia.

Moving on to financial highlights for the quarter, we generated $321 million in consolidated EBITDAX, a 3% increase from the prior year quarter, resulting in an EBITDAX margin of $1.60 per Mcfe. We realized $3.15 per Mcf before hedges on our gas production during the quarter, which was a 63% increase compared to the prior year quarter.

We realized a 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 unhedged oil price of $43.24 per barrel, which was only a $5 differential to NYMEX-WTI for the quarter. The improvement in the realized oil price differential was driven by new contracts we entered that commenced on April 1 of this year. We realized an unhedged C3+ 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 further -- to provide further color on the capital efficiency gains, I'll point you to Slide #6 titled Capital Efficiency Drives High Growth Within Cash Flow. Before I get into the takeaways from the slide, I'll 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 forecasts.

With that being said, the key takeaway from the slide is that we expect to be able to grow at 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 outspend 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 drilling 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 consolidator within Appalachia, given our industry-leading hedge growth and firm transportation portfolio.

Looking at Slide #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 2017, we acquired about 10,300 net Marcellus acres, primarily in early June -- excuse me, 2017 we acquired about 10,300 net Marcellus acres, primarily in Doddridge & Wetzel counties in 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 be about $4,000 per undeveloped acres so an attractive price for us on an undeveloped acreage basis. This was represented by many of the consolidation transactions we completed over the last couple of years, core infill or bolt-on acreage is 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 pickup force on the acreage front.

What did this continued consolidation activity do for us from a core drilling inventory standpoint. For that, I'll refer you to Slide #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 as 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 chart is pro forma for all mergers and acquisitions, both closed and announced to date. So despite some large deals announced within the base in this year, Antero still has a sizable lead in core undrilled location inventory within Appalachia. And we'll look to opportunistically add to this position over time.

Before I wrap up, I want to touch on the sum of the parts topic that has been notable for certain of our peers, lately.

At a recent conference, we rolled out our Slide #9, titled Significant Value Proposition. The idea behind this slide was to provide investors with enough color around the true value of various pieces of the Antero story. One reason for the sum of the parts discounts that we've seen in Appalachia with tax burden of a sale of midstream securities, so we are showing an after-tax value for Antero's 58% ownership of AM after applying AR's $1.5 billion of NOLs.

While we're illustrating the breakdown of the Antero, sum of the parts on this slide, we do see a lot of value in the integrated story, particularly as we continue to target attractive annual production growth from 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 a $2 billion hedge book mark-to-market value, you'll arrive at an implied AR standalone value of about $5.9 billion. With an estimated PDP, PDA value of $4.8 billion, and that's in the gray bar there, which includes conducting 100% of gathering, compression fees paid to Antero Midstream. You'll arrive at an implied undeveloped acreage value of only $1.1 billion, within our core undeveloped acres 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 acre trading value to the recently announced Appalachian corporate transaction, which most analysts pegged it about $10,000 to 15,000 per undeveloped acre.

Slide #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 sponsor's upstream development.

The integration of the midstream business enables us to better control our development program and provide significant visibility into product flows and pricing in Appalachia. This is very important when you can control the largest core acreage position in Appalachia and are 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 in the bullets, 3x 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 #11, entitled De-risked Development Plan Drives Long-term Visibility. Over the past 8 years, we have built the most integrated natural gas and NGL story in the U.S. We run the business with a long-term mentality of ensuring we can continuously develop our 53 Tcfe of 3P reserves for many decades ahead, which we believe will generate the most attractive value creation to our shareholders, including management's substantial ownership.

With that, I'll turn the call over to the operator for questions.

(Operator Instructions) The first question is from Neal Dingmann from SunTrust.

Could you just talk a little bit about just M&A, in general. Obviously, there's been a few deals here and there you guys included. Are you seeing -- continue to see a bunch of deals offered then what do you see with potentially disposing some of your assets as well?

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 that go by, and there's -- so there's continued consolidation. In terms of divestment, you may remember that earlier this year, we sold some nonstrategic acreage in Pennsylvania. So we continue to look at our portfolio and let go 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.

Again, just talk about you're -- it looks like Slide 2 -- looks like you're seeing some diminishing returns. It looks like -- as you increased -- can you just talk about your thoughts around that?

Sorry, Neal, could you repeat that question?

Yes. Just on Slide -- this is Ray on for Neal. Just on Slide 2, it looks like you're seeing some diminishing returns as you go from 1,875 to 2,500, could you just talk about your thoughts around the same load?

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 the blue, I think, as to whether or not it returns to the 2.0 Bcf type curve or you end up at above 2 Bcf. But at some points, you will see diminishing returns. I'm not sure we've found that point yet, we're still searching, depends on the area, too.

The next question is from Holly Stewart from Scotia Howard Weil.

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 that the last few quarters, maybe we were -- I don't know, parity with Belvieu. I mean, it looks like now, maybe we've moved back to a discount, so just kind of curious as to what you're seeing in the marketplace.

Yes, Holly, that's a seasonal phenomenon, generally. You track Belvieu pretty tightly in the winter months, and then it winds out in the summer, generally speaking. And hopefully, that gets bridged, that once we have inning 2 in place. But I think, we have some hedges in place that's detracted from the bottom line value of NGLs this quarter that were a bit negative. But we're still around 50% of WTI in the second quarter. So that sort of the soft period, and we'd expect that to improve as you go into the fall -- late fall and winter time.

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

Well, certainly, you've seen, Holly, and the 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 from shippers that had excess capacity started bidding up on the distressed gas that was in Dominion South and Tetco M2 pools, and so base is narrowed. Once the delays became evident in Rover then 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 from me. Just 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. We -- those Utica wells and pads are being drilled now. And so we're timing the completion to dovetail with Rover phase I, 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 I 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 II -- it's probably a month or 2 behind that. So we're thinking October, November for Phase II to come to Sherwood. And certainly, we'll have plenty of production that will be moving through Phase II Rover when it arrives in the third and fourth quarters.

The next question is from David Tameron from Wells Fargo.

Just -- 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 a Wall Street dummy down version, but what -- why not take that approach and then dial it back, or do not think the rock can put away that much sand? Or how -- can you just talk about that?

Yes. We -- 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's 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 6 wells to the north one way, and 6 wells to the south the other way. So just a little bit of a deliberate approach in not 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, in order -- and the purpose there is to keep the fracs close to the wellbore 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. Let me go back to valuation. I think about slide 9 that you talked about, Glen. And whoever, Paul or Glen whoever want to take this. But as we said on our table not only you laid it out a lot better on the Slide 9. But when you just think about 16.5 Ts and enterprise value of $11 billion or $12 billion. No matter how you look at this, it seems like there's 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 desired to do something to unlock that value? I know -- well, I'll just leave at that. Let you response to that. And I know you're already taking the approach of, a, we'll create the company and create the value in that, it'll 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 decipher unless you really dig in. And one is just that after-tax value of the midstream business. I think some -- may be would not have recognized that we do have $1.5 billion of NOLs, one could apply against any selldown 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, and it worked due to 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's hidden value that the people can't do the math on. So we're just trying to help with that. I think right now, there's something that we discussed at the board level on a quarterly basis. And we'll continue to analyze this -- no real initiatives at this point other than to point this out to the investment community.

The next question is from Subhasish Chandra from Guggenheim.

I'm thinking out loud a little bit here, but this ties in David's question. So the upstream companies with niche amenities have often complained about some of our discounts. It hasn't worked. I don't think pointing it out has helped others either. But one of the things that seems to have worked at least in the EQT/Rice deal is somewhat of a return of capital strategy. So as you know, today's point as you -- and you -- I think you've answered it. It's something you're well aware of and you've discuss at the board level. But when do you go to Plan B? If just the information does not close the sum of parts?

Yes, there's no time line on that. I don't think we're going to hold out that we'll have a plan by the end of 2018 or anything like that. But it's something that we continue to study and are very aware of. I mean, we're shareholders, as well, in a pretty big way. And it's something that we would like to see more value there in the share price. So can't really give you a time line, Subhasish, but it's something that we do think about and spend time on for sure.

Yes. And so what you think of range sort of hinted at it to go down the Cabot path. What you think of return of capital -- pre-capital or dividend, that all.

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

Got it. Okay. My next question is, say, in the PV-10, how much of the increase -- because it was quite strong relative to at least our expectations in the value of the reserves. Was there a lower operating cost structure?

We certainly had some lower well cost built in. So that's come down over time. I think there's a slide on the website, a slide that shows you quarter-by-quarter but we saw another notch down, particularly in the 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 added quite a bit of PV-10 by adding those acquisitions here in the first 6 months of the year. But also, we're just continually adding acreage on the ground and back to the core -- number of core locations slide, I think it was Slide #8. We do a very meticulous bottoms up analysis on core locations. And it's tied to our 3P locations, that's why we disclosed 3P reserves. It's very much bottoms up, laying out lateral links and well density on our acreage position. And we do the same analysis for all the peers. Where some companies, some peers, just simply do a top-down analysis on these locations, and that's what drives analysis around NAV, it's on the Street. If you just use a top line acreage number divide that well density, that gets you to a number of locations. But that's not the same as you're looking at it 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, I mean, at least 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 nice uptick in that 400 locations you see here on the slide in the first half of the year. And so that's part of the driver behind the PV-10 pickup.

And just final one from me. Is the Rover included the Rover FD and so on included in the reserve report?

Yes, I mean, we factor in all of our firm transport in that in terms of pricing and cost.

Yes. And net- backs -- and the ultimate sales price for each Mcf to go into the volumetrically proportional ultimate sales price. So yes, a Rover net-back would be included in that reserve report, and it would be -- I don't know the day-to-day, say, Rover comes on, but it's probably October Phase I and December Phase II, I'm sure they're conservative on that.

The last question is from James Sullivan from Alembic Global Advisors.

Maybe you could talk about it as it pertains to the PV-10, but also maybe in the medium-term about how ethane pricing worked into your assumptions? And maybe just first on the PV-10, and then what you guys are seeing in terms of the near-term market there? If you could just update us on that -- on how you're feeling about that from the marketing side?

Yes, I can tackle the first part of that and maybe Paul for the second on that marketing kind of going forward. But we assume that we extract as much ethane as we need to both meet pipelines spec, but also to meet various contracts that we have in place. One being the Borealis contract, for instance that sprays into place once ME2 is online or is up and running. So the -- those kind of things were baked in. And we don't assume 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 3/4 of the ethane at least is being left in the stream. And the economic 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 [indiscernible] -- so we'll expect to recover more and certainly, as we get towards Cal 20 and Cal 21, or some really big volumes for sales, which (inaudible) on their cracker and others. As that comes closer and closer, there'll be better and better economics for recovering ethane, ultimately.

Okay. Great. And can you just remind us what the pricing mechanism there? Or how exactly on the Borealis contract and what you put over on MET what you guys are expecting to get for that portion of your ethane stream?

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

But it's price -- a premium to gas value at the end of the day, mostly its cost side.

Okay. So you guys are thinking about it as an increment off of what you're -- 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. And just 2 other ones that are also kind of ethane-related. But on your Slide 3, where you show your 17 program pads you kind of estimated you'll [work] for 1,000 feet, are those with or without ethane recovery? I know you're obviously doing some partial ethane recovery, so I just want to know what the actual are? If you could just show in the C3+ processed going on?

I believe these are all just wellhead.

Yes, they're with ATEX.

So that's not assuming -- it's not putting 6x multiple on ethane extracted, it's just simply wellhead production.

So that's actually wellhead without any processing?

Correct.

Okay. All right, that's good. And then, you guys have typically shown those pre- and post-processing numbers in your type curves and you guys gave a kind of wellhead number with your increase here from 172 in the central part of (inaudible) in Tyler. But if you were to just take a stab at, we're like at for 1,250 Btu per cubic foot or would be standard like a wet gas window type curve that's now being upgraded for 172 would have post-processing per foot type curve number would be roughly, including and excluding ethane?

Yes, that's a good question. People are always confused about that wellhead versus process. And if you look at the bottom of Page 3, you can see by well pad 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 average -- all these pads that we've completed this year and they've been online for 60, 90 days-plus, so much -- quite a bit longer, some are up to 6 months, I think, average about 2.5 Bcfe per 1,000. And that's all for that roughly 2 Bcf type curve at the wellhead.

So that's a pretty good rule of thumb, that 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.

Those on Page 3 would probably have -- take all the averages just under 1,250 Btu, maybe 1,240 Btu, or 1,230 Btu, close enough.

So when that bottom's trip on 3 that is with ethane left in the stream?

That's correct. If you've extracted ethane and multiply it by 6 because you really have -- you're getting good market value for ethane above gas value. The net would jump at 2.5 number up into the below 3 region or 3 to 3.2, probably something like that with Tcfe production.

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

Thank you for joining us for today's conference call. If you have any further questions, please feel free to contact us. Thanks again.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.