Antero Resources Corp (AR) 2013 Q3 法說會逐字稿

Good morning and welcome to the Antero Resources third-quarter 2013 investor conference call.

(Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Vice President Finance. Please go ahead, sir.

Thank you, Sandy. And thanks to everyone for joining us for Antero's third-quarter 2013 investor conference call. We will spend a few minutes going through the financial and operational highlights and then we will open it up for Q&A. But I would also like to direct you to the homepage of our website at www.anteroresources.com where we have updated our Company presentation for our Q3 results.

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 Glenn.

Thanks, Mike, and thank you, everyone, for joining us today. While we have been doing high-yield conference calls for about four years on a quarterly basis off the radar screen, this is really our first call as a public Company so we appreciate you joining us and we are very excited to report our results for the third quarter.

Third quarter 2013 production of 566 million cubic feet per day equivalent increased 128% year over year and 25% quarter over quarter sequentially. The production included approximately 7,900 barrels of liquids, which was also a significant increase as we did not produce any liquids in last year's third quarter. We did not have processing last years third quarter and it was up 89% sequentially. These impressive results were derived from our transition into the Marcellus [to hard] BTU drilling and first production from our liquids-rich Utica area as well, which kicked off in August of this year. Paul will go into more detail of these in a few moments.

We sold our natural gas during the quarter at a $0.22 per Mcf premium to NYMEX. We are fortunate to be in the southern [quarter] of the Marcellus, which allows us to sell the majority of our gas at a TETCO index price. TETCO traded at a $0.07 discount to NYMEX for the quarter but our gas sold at a premium due to the high BTU content. We are currently in ethane rejection so we get a nice pickup in price from leading ethane in that stream.

We also received attractive prices for our NGL barrel. Our NGL barrel is C3-plus, so propane plus. It does not contain any ethane. This results in a much more valuable barrel evidenced by the $50 per barrel for our NGL product this quarter and that has been average roughly for the past year or so. [We realized] $47 million, or $0.91 per MCF, just under $1 in the quarter, for our hedges -- our natural gas hedges -- also some oil hedges. When you combine our premium value natural gas and liquids production with our significant hedge position, our gas equivalent price was a nice $5.18 per Mcfe for the quarter.

For a cash operating cost perspective, production expenses were $1.40 per Mcfe. This resulted in a net back of $3.78 per Mcfe for the quarter. Our G&A expense for the quarter declined by 46% to $0.28 per Mcfe due to the high production growth. When you factor in that our [finding] and development costs are approximately $1, you can see why we have [pure] leading recycle ratios.

EBITDA for the quarter was $183 million, which is 159% higher than the prior year's quarter and 38% higher than the second quarter of 2013. Development capital was $436 million for the quarter. In addition, we spent $161 million on infrastructure projects and $72 million on acreage. As a reminder, we did create a mid-stream sub upon the close of the IPO and our midstream assets have been dropped down into that entity as we evaluate the potential for a midstream [LP], possibly in 2014 -- likely in 2014. We outlined our hedge position to release the total of approximately 1.1 Tcfe hedged at attractive prices through 2019. The mark-to-market on the hedge book is currently about $1.1 billion, that was as of November 4. As you will note, a substantial amount of these hedges are at the [embassies] where we sell our product so we have much tied -- much of our hedging -- our financial hedging to our firm transport so the financial tied to the physical as much as possible.

We have also provided guidance for the fourth quarter of 2013. We expect production to increase sequentially by about 20% to 660 million to 690 million cubic feet equivalent per day and that includes between 12,000 and 15,00 barrels a day of liquid. We left a pretty wide range on that guidance because we are waiting on a couple of projects to open up the liquids flow in the Utica so we expect those to be (inaudible) here in the quarter. It is just a matter of what week those get done. So we have left that as quite a wide range of liquids but we are comfortable with that range. This type of growth rate should continue into 2014 and we plan on issuing full 2014 guidance early in the upcoming year.

We also increased our capital budget to account for the decision to complete approximately 75% of our Marcellus wells with shorter stage links, or SSL as we call it, completions during the second half of 2013 for the acceleration of compression activity as well from 2014 back into 2013 for the assumption that we close on additional 10,000 acres or so on the lease acquisition and the leasing front. Our decision on increasing the amount of wells completed with SSL was driven by early results that Paul will cover in his comments. We have increased our estimates on rate of return by anywhere from 15% to 25% depending (inaudible) content of the area.

Let's go to the quarter end. We completed our highly successful IPO, which resulted in proceeds of the Company of $1.6 billion, which we used to repay debt. We also were able to issue a $1 billion senior note offering at 5 3/8% that lowered our weighted average interest cost by almost 200 basis points now down to 5.8% on a fixed rate long-term debt -- lengthened our average maturity as well by about 2 years. When you pro forma both of these transactions on our September 30 balance sheet, it results in net debt of about $1.5 billion approximately -- that's about 2 times this quarters annualized EBITDA. So if you annualized the third quarter EBITDA we are about 2 times net debt to EBITDA. And that is with a completely undrawn $2 billion borrowing base. So we have plenty of liquidity.

To summarize the quarter from a financial perspective, we had tremendous growth, excellent cash margins and returns with strong visibility. These results will continue well into the future. We were also able to secure the capital needed to fund continued momentum. So we're in a great position.

With that, I will turn it over to Paul for some comments.

Thanks, Glenn. During the third quarter we ran 19 rigs in the Appalachian basin and we also ran an average of 4 frac spreads -- so on the fracking side it drilled and completed 44 wells. This firmly places us as the most active operator in the Marcellus as we have the highest growth trajectory with a triple digit continuous annual growth rate for the last four years. We've been [asked if our] strategy is to pursue this rapid pace of development and the answer is pretty simple. If we are generating the types of returns that the Appalachian basin, and of course I'm talking about Marcellus and Utica -- if we are getting the types of returns that this yields then we want to bring that value forward.

Our rates of return in the Marcellus range from about 40% in the rich gas area to 90% in the highly rich condensate area. These rates of return do not factor in the SSL completions and those appear to enhance these returns by approximately 15% to 25%, as Glen mentioned. In the Utica shale we believe our rates of return range from approximately 100% in the rich gas area to over 200% in the highly rich condensate area. Obviously with these types of returns we want it to develop as quickly as possible.

Now of course, in order to take care of our production and do what we have to do to be able to move it, we have to be forward thinking. Versus we have jumped out, we have secured the rigs, we have secured the frac fleets and -- but just as importantly, we want to make sure that we can get our product to market at the economic levels that we planned. We have done that, not only by the hedge book that Glen has mentioned just now, and those hedges were put in place years earlier so people wonder how are we reaping these $5-plus prices, we have been hedging the outer part of the curve for a number of years. So we continue to hedge the curve, as many of you know, is in Contango. And so by hedging the outer part of the curve, which is definitely a part of our strategy, we reap the benefits in future years. And that is what we are reaping today from our past hedges.

Not only down the hedge book that Glen mentioned, but also we have committed to processing to stay out in front compression facilities, even before the first wells are drilled, and then we put a big emphasis on securing takeaway capacity in order to get our products to the market. We, today, have about 1.3 Bcf equivalent per day of firm transport and that will be all effective in our region by the end of 2014. And we continue to build out this firm transport to accommodate the significant growth we see coming in the future. We have been able to be in this forward-thinking mode for a number of years because we recognized early on and located ourselves in the right geology and our parts of both the Marcellus play and in the Utica play and we have built our acreage positions in both plays in the most prolific liquids areas. The Marcellus, our core liquid rich net acres, has increased to 302,000 areas since the last press release and that firmly positions Antero with the second highest exposure to core Marcellus and also to Utica amongst our peers.

In the Marcellus, we continue to be the most active operator with 15 rigs working for us, 2 dedicated frac spreads. We continue to drill the longest laterals in the play. We average 7,100 foot lateral lengths for our 34 wells completed in this last quarter. We are able to drill these long laterals, of course, due to our concentrated acreage position where we have good contiguous leases that we can pulled together into units and drill long laterals. And also a huge benefit for us is the general geology in this portion of West Virginia -- no faulting. And that is what we were looking for when we entered the play. We have yet to drill across a fault and we have drilled more than 250 miles now of lateral feet in our 200-and-some wells of horizontal drilling in the Marcellus. So no faults. And that makes for great economics.

Our type curve in the Marcellus is approximately 1.5 Bcf of wellhead gas per 1,000 feet of lateral and is supported by approximately 217 wells across the entire breadth of our acreage position. I do not think you ever reach perfection in techniques and so we continue to innovate in the area. We have seen nice progress in the play as we have had improved results during this last quarter as we have extended our application of our shorter stage links, or SSL completions. We have now decided to use SSL completions on pretty much all wells going forward as we are seeing early trends. And I will emphasize early of at least 20% to 30% greater productivity over our type curve. We estimate about 20% additional well costs. It's still early days and time will tell, but so far it looks good. We will continue to run 15 rigs into 2014 and we expect the pace of development and growth will continue.

Let me shift to the Utica. We are running 4 rigs in the area with a fifth one to be -- the fifth rig to be added this month. We put online 10 wells during the quarter with terrific results and we have 8 of the 9 producers now in the play. We were able to start flowing the wells in early August but we were limited to 90 million cubic feet equivalent a day as the Seneca plant and processing facility was not operational yet. And so we were flowing these wells north up to the Cadiz plant in Harrison County. And because of infrastructure limitations, we had to flow these wells against 1,100 pound line pressure up to the Cadiz plant. So that definitely pushes back on the wells performance. So it is really a testament to the tremendous pressure and pressure gradient of the Point Pleasant shale -- of course the main play in the Utica play -- that we are able to produce in such an environment.

As we noted in our press release, we have now increased our acreage position to 104,000 net acres in the play and we are talking about in the southern core, which is the most important part of the Utica. Since the last press release we have added one well in the Utica that tested for over 7,000 barrels a day equivalent with 44% liquids, assuming ethane recovery. This was the fourth best IP that we have seen in the play and we look at all reports. And now allows Antero to have 8 out of the 9 top producers in the play. Again our wells are in the 5,000 to 9,000 barrel a day equivalent range and those that are not in the core are more like 1,000 to 2,000 barrel equivalent.

We also have six wells that are currently being completed and are forecasted to come online in December of this year, and in fact, one of those we are just testing and starting to bring online today and also looks encouraging as well. We will be able to accommodate these wells as the Seneca processing facility that just came on with the processing facility that just came online. And we have secured the entire capacity of the do -- we call it Seneca 1 -- with all of the initial 200 million cubic foot a day equivalent that is available to us. The capacity increases throughout the next year with Seneca 2 and 3 and results in total firm processing capacity. So that's firm to us, to Antero, of 350 million cubic feet per day by the second quarter of 2014 and we have an option built in that we can increased to a total of 400 million cubic feet per day by early third quarter of next year. So capacity of 350 million by second quarter and up to 400 million by third quarter of processing firm to Antero.

Additional processing beyond this time frame is in the planning and discussion stages. In addition to the processing capacity, we have contracted with a third party to put in compression and condensate stabilization facilities. This will be the first compression within our field and should allow us to flow unconstrained. This is the back pressure that I was talking about through the field and into the (inaudible). The first facility, which is 120 million a day equivalent compressor station, should be online by the end of November. I mentioned we were adding a fifth rig this month to the play and that is going to further accelerate the development of the Utica. And we will continue this pace into 2014 and that will allow for tremendous growth during the year.

Let me talk about the dry Marcellus -- excuse me, the dry Utica real quickly. We do have an additional 116,000 net acres of deep rights in West Virginia underlying our Marcellus that has good Utica dry gas potential. We have done the mapping and we think it looks quite perspective. There have been some recent encouraging industry wells in this similar dry gas area along the trend. And so we have identified, on our deep rights acreage, 950 potential drilling locations. This, again, is on our acreage in West Virginia and it adds up to about 5 Tcf of net resource -- net resource to Antero. We are going to drill our Utica dry gas well in West Virginia sometime in the first half of 2014. So we will have our own results pretty soon.

So in summary, we are the most active operator in the Marcellus. We will soon likely be the most active operator combined in you Marcellus plus Utica and we have the highest growth rate in the combined plays. We have been forward-thinking in securing the necessary takeaway and infrastructure to allow for accelerated development of this very profitable and prolific asset. We continue to grow our position in both plays. But within the Marcellus, we added some 12,000 acres -- net acres, in the third quarter and we might have -- we are likely to have more than that to close in the fourth quarter. So more than 12,000 acres additional in the fourth quarter. Our assets contained the second largest liquids exposure with our acreage being in the core of the core, which is very important, of course.

And with that, that concludes by remarks and, operator, we are now ready to take questions.

(Operator Instructions)

Neal Dingmann of SunTrust.

Good morning gentlemen. Great color. [Say Paul], I was [wondering] if you -- Glen if you could talk a little bit over in the Utica -- you obviously had some outstanding test rates. Just if you could talk a little about anything you could give us -- I know your wells have not been on a whole long time but just how you see the 30 day and 120 day rates on those wells that have been on for a little while stacking up versus those initial test rates.

Well we would say that the rates look encouraging. That we have developed type curves based -- before we started flowing our wells, based on early test results of our own as well as test rates of other people and what we could download from the state of Ohio. So developed some type curve and I am pleased to say that now that we have got our wells online, they look like they've conformed to the type curves so pretty close to our expectations. And so these are -- as you have seen in our press releases as well as others, these can be hellacious wells but really high flow rates and quite strong pressure. They come in at about the BTU's that we have mapped and so the way we have the gas composition, they perform, of course, going through the plant to give us the liquids compositions that we expect. So far so good.

Okay. And then just on the well cost, I know a couple of your earlier wells -- I know you did some science and some things. So maybe we don't have to talk a little bit around the $12.3 million cost -- your thoughts on that going forward as you do not do as much science and run on a go-forward basis on the Utica wells.

Yes. Well we are always, of course, working to try and optimize early on. You are right. We have done a lot of R&D, I would say. We have done such things as pilot wells where we drill vertical all the way down through the Utica and cut a core. And do lots of testing, capture certain gases in pressure chambers so that we can work out there PVT relationships -- pressure, volume, temperature -- and the phase relationship. So a lot of R&D early on.

We are in an area where one must run two strings of pipe, so two intermediates, because of a certain zone down in the 6,000 to 7,000 foot range. So we have a little bit higher cost in this core part of the Utica than they have up north. Will we be able to get our costs down? Yes. I think so. How much will it be? Well it remains to be seen. Can we take $1 million or $2 million off of it? I think that is a reasonable target but time will tell.

Okay. And then last one, if I could. I know it is still early -- your thoughts on optimal spacing or at least what you think you could maybe take some of these Utica wells down to as well as -- I know you're testing. It sounds like now one significant lateral that I know of -- just wondering your thoughts on different lateral links, what -- if you think you have an idea of what is optimal or you're still testing that. So that and downspacing it.

Yes. As far as lateral lengths, the Utica is even more smooth -- I guess I would say more planer than the Marcellus. Virtually no ripples in it or anything. So in terms of long laterals, we use certain downhole tool where we can make at least 2,000 feet a day in the lateral -- the Baker [auto track]. And so we see that we can go quite long in the Utica. Right now we have only gone in that the mid 5s to mid 8s range of lateral feet but we feel we can go quite a bit longer than that. It will always be a little bit of a limit on fracking the tow and pressures required and so on. But in terms of that aspect of it, of course our economics improve as we go longer -- just spreading that vertical cost over more Bcf's.

So good advances I expect to still be made on longer laterals. We have got a number of longer ones planned. In terms of interlateral distance, I think we are pretty comfortable with 1,000 foot interlateral distance. And as we told the market, we have got one pilot, the Wayne pilot, where we've drilled three wells at 500 foot interlateral distance. It looks good so far but it is still early. So I think we could say we are pretty comfortable with 1,000 foot and we will see about 500 foot. The locations that -- number of locations that we have talked about to the market is about 700 or so laterals that we have planned so far on our acreage. And that is all on 1,000 foot interlateral distance. So far so good. Maybe on tighter but I think we feel pretty good about 1,000 foot.

Perfect. Thank you. Great wells.

David Tameron, Wells Fargo.

Hello. Good morning. Congrats on getting the -- on getting that equity out and getting the IPO done. Can you just talk about -- to hit your 2014 targets, so that's 75%. Can you talk about what you need to see happen as far as the midstream, whether that is processing or pipelines? Or I know it is not a simple answer but -- and what are the three or four big guidepost, I guess, that we should be looking for on this side?

You are talking about just specific infrastructure improvements that --

Yes. I guess what are going to be the biggest hurdles to get the infrastructures in so you guys can execute on your plan in 2014?

Well they are -- it is a handful of smaller projects and different parts of our Marcellus. And so it will be compressor stations here. It will be looping there. It'll be taps in another spot. And so there is not really one big project and so they get completed month-by-month. If they get delayed by weather or something else, then that can slow down our production. So it's -- but we feel pretty good about the major projects that we have -- the firm transportation, the mainlines, and so on. It is really getting locally out of our field that can have some bumps in it. And we follow it, of course, day-to-day and week-to-week. But that is the kind of thing that we are looking at between now and 2014 and going into the first and second quarter is compressor stations, low-pressure, high-pressure, gathering, looping and taps.

Okay. And then just stepping back -- the bigger picture for the industry as a whole, particularly with regard to the Utica. What do you think the biggest hurdle is going to be on the takeaway capacity side, just if we look out 12 months or 18 months?

Well, yes. The hurdles will be a few things. It will be producers like ourselves getting compression and condensate stabilization put in ahead of the wells. It will be more processing. And so as we have described, we have got successive trains coming in at Seneca but there's timelines on that. There are a number of parties that either go into TETCO or some of the more local lines. And so one might be referring to BTU issues -- we things that we and others are okay with right now with BTU going into TETCO. There has been more of a move with REX to bring a dry gas over to Clarington to blend out into TETCO and solve that problem.

So there is infrastructure projects up and down the line, again, from local to long-term but we do not see any barriers. There is discussion of REX right now. It is back hauling but by middle of next year it could be forward hauling to the west. And so producers, ourselves and others, look at moving gas away from the region towards Chicago, the Midwest. So all of those things take a little time but there is no one big barrier that we see coming up through 2014. We think infrastructure will keep pace up and ahead of industry production.

Okay. Thanks. That is helpful color. And then just one final question -- if you could address that the potential for an MLP I know upsized offering and you have the debt deal done -- is that still on the table for 2014? And if so, any color you care to give us on that?

Yes. It is very much so on the table. And those kind of things take a lot of background work. And I'd say that is where we are now just preparing carve-out financials and those kinds of things and talking to various folks about evaluation and process and those kind of things. So I'd say we are still early stage but very much on the table for 2014.

Okay. I will let somebody else jump on. Thanks.

Hsulin Peng, Robert Baird.

Good morning, everyone. I was wondering if you can give us an update on production constraints. I know last quarter you said there was a minimal amount of constraint and it sounds like you are still waiting for some compressor coming on in November. So where are you currently?

Yes. We have certainly seen some of those constraints come off and production grow since the third quarter numbers that you see in the reports there. So we are working through that and we continue to have at least 100 million a day constrained in both areas. But those are quite methodical fixes, I think, as Paul was referring to. It's a compressor station in the Utica that we expect to be online by the end of this month. We'll have compression there for the first time. So we are still seeing some constraints because of that. We have some wells that are waiting on that particular compressor station because they do not have dehy on the pad. So once that compressor station is up and running along with the dehy then we will be able to bring on these 6 wells that we are completing right now in the Utica. So that is one key piece.

And then over in the Marcellus, we have a number of projects underway. Anything from -- anywhere from production to processing, like Paul said. The third processing plant there at Sherwood should come online at least by year-end this year. And we will need that as we are bumping up against the full capacity of $400 million a day that is out there right now. So we continue to bring on wells. I think we are going to be bringing on something like 20 wells between now and year-end between the two plays. So we expect to see quite a bit of growth but you need that infrastructure completed to actually see the incremental production growth.

Right. Sounds good. And then second question, just a follow-up on your downspacing. So given that you have that one the pilot testing in Utica, I was wondering if you are planning to do more pilots in Utica. And also, are you testing downspacing in Marcellus?

We do not have any plans right now, Hsulin, to do more of the 500 foot interlateral on Utica. Again, as I have said, that the wells are so young there and the infrastructure has partially curtailed us in the Utica, i.e. we're are producing against big back pressures. But we'd just like to just see unconstrained production so that we can judge our curves performance and evaluate the pilot project better. So we there is certainly room to do plenty of that and we have [sticks] on the map where we can do it but we have not committed to another pilot yet. We just want to see the results of the first one.

In terms of the Marcellus, much of what we develop is on [660] foot interlateral distance but we have some areas where we tried 1,000 foot or 1,320 just to observe. But we feel very good our 660 interlateral distance and our planning is virtually all 660 and feel good about that. We, of coarse, have 200 wells, some of which go back 4 years, that are on 660 foot interlateral. And they definitely support the type curves as we judge them and as B&M judges them too. So feel good that, that is a very good interlateral distance for us.

Okay. And then my last question, and I will go back in the queue, is on the Short Stage Lengths. Do you think the award performance -- I was wondering how much production history do you think you need to -- before you update your EUR type curves and also research booking later on?

Well the longest well probably -- or the longest duration or production history of SSL wells that we have might be 4 months or so. And I might remind people that we have that certain NGL line break due to a landslide coming out of the plant a couple of months ago. And so with that, that curtailed our production.

We try to preferentially flow all our SSL's as best we could but a little bit choppy. So we would like to see probably another 6 months of -- now that the line has been repaired and that constraint has been removed. I would like to see probably another 6 months but we are looking at it every day and every week and comparing the type curve, comparing the offsets. And so, as I said, we are encouraged but probably 6 months more.

Okay. Thank you for the color.

David Deckelbaum, KeyBanc.

Good morning. Thank you for taking my questions. My questions were related to the ramps of five rigs now in the Utica. As you reconcile that with the amount of processing capacity, yet there is in the play right now with having 350 by next year out of Seneca, is it fair to say that this would be the max run rate until you get significantly more processing capacity perhaps with even beyond the Seneca III expansion into Seneca IV in 2015 -- would 5 rigs -- I guess would there be any reason to accelerate beyond 5 rigs given the amount of infrastructure in place right now?

Well one of the things -- two answers to that, David. One is, we are always looking at our production forecast and stacking processing against it to make sure that we have enough. Obviously we do not want to have production that can't get processed. But what is a more it limiting factor in putting more rigs into the Utica -- just a reminder that we have only been in the Utica for less than 2 years and so our acreage position is pretty young there relative to the Marcellus.

And so we have got groups that are doing lots of planning. But it takes the planning group time to work out where the pads can be, working with landowners, forming units where we pool with the different tracks together to form big unit so we can drill long laterals and then planning out where the gathering is going to be, the compression, the condensate stabilization. So it would just be premature to put more rigs in and try and accelerate more. So that is why we are holding at 5 rigs for the time being and we will just see how things unfold relative to production.

But we do think that we are -- for everything that we foresee through 2014, we are ahead of the game on processing. And again, we do not think we are going to probably to be stopping at Seneca III. There is more trains that are under discussion but we will see where those go. So possibilities for more over time but we are just being prudent, I think, in designing our exploitation program to be realistic relative to all the things we need to do in advance.

Got you. And you -- [switching] over to the leasing side -- you guys picked up the 3,000 additional acres or so this quarter in the Utica core. Was that new acreage or are you guys just filling in the working interest? I know prior to this your working interest was around 70% and you guys seem to be drilling stuff with a much higher working interest. I assume at lease you'd expect that working interest -- at least the lease hold level to increase over time. I just wanted to get a sense if you are just kind of filling in your interest right now or if there is some other pieces that you are picking up along the way?

Well it is a little bit of both but I think you see that natural progression and what we have done for a number of years now in the Marcellus, as we do in the Utica, which is we have quite a land staff that is working on these things. And we will design a unit, get a pad, workout the lateral length and then we may have a relatively low working interest, say 65% or so in that unit as we put it on the map. But then our brokers and our land-man build enough of a position and it is mostly base leasing. Sometimes it might be a trade but it is mostly base leasing to add and move our working interest up.

And so that is a pattern you see both in the Marcellus and the Utica that on day one that they're relatively lower interest but we just keep building. I will say that our expectations for additional acreage in the Utica -- it has gotten very tight. So we will see how much we grow it. We would like to be able to grow it more but it is at a lower pace maybe than the Marcellus is.

And then the last one I had, I know before you had mentioned that basically you were going to use the Shorter Stage Length completions on effectively all of your completions going forward in the Marcellus for this year. And I assume that would be for 2014 as well. But would you still exclude I guess some of the dryer portion of your Marcellus from an SSL completion or are you going to be using SSL's as a blanket for the entire program?

Well it might be -- you know, it's the reality is that in 2014 will be -- most of our rigs will have shifted. And they pretty much already have west of the 1,100 BTU line and maybe they will all be over into 1,150 country by then. So we -- but we would not exclude doing SSL's over on the east side, on the dryer side, but more on a pilot basis. But as I say, our -- the amount of drilling we will do over on the dryer side is definitely lower.

We have, through the last number of months, had SSL's over on the dryer side and they can make an impact as well so we wouldn't rule that out. Just if you have an uptick of X percent, so you get more molecules, those molecules are more valuable over on the west side. So I think it is just a cautious approach to say whatever the bump is going to be, it is a more valuable bump and a higher rate of return bump when you are into more of the liquid side. So that is about the way our thinking goes.

But even on the 1,150 BTU window in the Marcellus we should be thinking entirely SSL for next year?

Probably. Virtually. I do not have those numbers in front of us, but, yes. That is probably the case. But again, it is early. We made decided to shift back. And in some areas we want to do it and in some other areas we try a different technique. So just want to be conservative and say we need to see the production unconstrained for at least 6 months and see how we are doing.

Sure. Thank you guys very much.

John Freeman, Raymond James.

Yes. Thanks. I know that you alluded to -- you going to enjoy your first dry gas West Virginia Utica well first half of 2014 -- do you have any plans to test Upper Devonian next year?

No. We don't. We've drilled our Upper Devonian for a cat test and have done pilots. And although those are reasonably good, they do not compete with the Marcellus. They are just not as strong. So they are scheduled for further out on the tail of our Marcellus plans. So if we have several thousand locations to drill at Marcellus, that is probably what the focus will be and the Upper Devonian's will come beyond that probably.

Okay. And then you cited the average completed well cost in the Utica at $12.3 million. Can you give me a sense of kind of how much that could drop once these wells have access to the freshwater distribution system and you start to more aggressively move to pad drilling either over the next 2 years kind of where that number can go?

Well I have given a broad range -- or we have -- of maybe we could drop $1 million or $2 million off of that $12 million-plus cost. You are right. The water system -- a good rule of thumb for us is it saves about $600,000 on a well that has a 7,000 foot lateral. If you go longer, then it saves more. If you do tighter stage lengths then a tighter stage lengths use more water. So proportionately, you could save more than that $600,00.

But I think that we can put our finger on that element but talked about certain things like two strings of intermediate casing that are just a safe way to go. A safer way to go to drill, to run a couple of strings which requires a bigger hole and bigger pipes. So we do not want to over-promise that we can shave many, many, millions off. We will just make stepwise improvements and see where we go there.

Great. That is all I had. Thanks, guys.

David Beard, Iberia.

Hello. Good morning, gentlemen.

Good morning, David.

Would you mind talking as specific as you can a little about your completion thoughts and designs in the Utica just relative to resting period and choke and how you open that up? Just to give us a sense of how you are thinking about developing your wells.

Well we -- the Utica -- and it is really the Point Pleasant is a little bit thicker than the Marcellus -- the pay zones and a little higher pressure. Our amount of water and sand per foot of completion is more in the Utica than it is in the Marcellus. But I think the way we are looking at things -- Glen, go ahead.

We are trying lots of different things. And I think suffice it to say, it is going to take some time for all that to play out -- to come up with a formulaic approach. And we really see differences in the rock too and the performance as well as you move across the BTU regimes. So I think it is hard to give a hard and fast answer on that one.

Okay. Fair enough. Thanks for your time and congratulations on a good quarter out of the box.

Thank you.

Adam Michael, Miller Tabak.

Hello. Good morning, guys. I was wondering if you could maybe comment a little bit on the Shorter Stage Lateral Length SSL's and how those might relate to the Utica. And maybe if you could compare what you are doing in the Marcellus versus what you are currently doing in the Utica on stage length?

Yes. Our standard had been in the Marcellus 350 foot stage lengths and we have gone down to 200. And then in R&D mode we have even gone down to 150. But feel pretty good about that shortening from 350 to 200 as maybe approaching optimized. And because, as I was mentioning, it is thicker in the Utica in the Point Pleasant, it takes more both water and sand. So we have more to frac, we were already at Shorter Stage Lengths -- just our -- what we designed was more like 225 in the Utica and now we are experimenting with as short as 175. So we are working those back and forth just to get better results.

Okay guys. Thank you.

Our last question comes from Mark Lear, Credit Suisse.

Hello. Good morning guys.

Good morning, Mark.

Just overall, there's some concern out there regarding Northeast Basis given all the growth you guys and your peers are delivering. I know not a big ding to what are already pretty big economics for you guys. I just wanted your thoughts on how you think your position regarding those risks.

Well as we have said, we feel pretty good that our acreage is at the southern part of the Marcellus core. And so we have a little less infrastructure that is required to escape the logjam, which is really in Southwestern Pennsylvania. So we can tie into TETCO to move away into the south and west towards the gulf and some of the other pipes too. So I think we have a little bit of an advantage there that we now are Columbia's biggest customer -- biggest firm shipper -- so a lot of gas firm and then we sell to a lot of firm shippers that are on those pipes at either a NYMEX or a TETCO basis.

And so if you look at the futures curve for Basis differentials, and we have that on our website in our presentation, TETCO has had the mildest discount, I would say, to NYMEX over time. It is in the negative $0.05 roughly to negative $0.35 range. Whereas the others, whether it's TETCO or certainly the Northeast, [Mighty] Hub, those have widened by quite a bit more. So I guess I would say, because of where we are, we are located in a spot that has its advantages. But we work hard to stay ahead of Basis blowout. So we hedge a lot of Basis. We have a lot of financial hedges that, of course, have Basis rolled in, so they are TETCO hedges. And then we have a lot of discussions, conversations underway with a lot of the long haul pipe builders to support new projects to move away even more.

I think we are in pretty good shape with the amount of FT that we have to get away and move to places like the gulf. So we have FT that goes to Henry, Louisiana, where we can hedge NYMEX. We have firm to Chicago where we can hedge a healthier basis, a Chicago Basis. But that is where our effort is going to be. And so we have been out ahead of it. We intend to stay out ahead of it to just mitigate Basis risk by selling locally.

Thanks. And then I just had one quick follow-up, do you guys anticipate producing any ethane in 2014? And I guess would that be additive to your 2014 growth targets if so?

We do not anticipate. We -- of course we, as others, look at futures curve as well as lots of research reports on demand for ethane. We have our list of crackers and so on as well as others. We do not necessarily see the ethane prices changing through 2014. And so, again, it is too more economic to leave the ethane in the stream. We do not believe we are going to have a gas quality issue that puts us into the category of must recover. But that is how we see it going forward -- probably won't be recovering ethane.

Thanks for the color.

We do see a whole lot of optionality on that. And if you think a few years further out, we do see some potential to extract ethane and sell it for a nice up tick over gas value.

Thank you.

Thank you. This concludes our question and answer session. I would like to turn the conference back over to Mr. Kennedy for any closing remarks. Please go ahead, sir.

Sure. This concludes our Q3 conference call. If you have any further questions, please feel free to contact us. Thanks again.

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