Mike Kennedy - VP, Finance and IR Paul Rady - Chairman and CEO Glen Warren - President and CFO

Neal Dingmann - SunTrust Robinson Humphrey Joe Allman - JPMorgan Holly Stewart - Howard Weil David Cameron - Wells Fargo Securities David Beard - IBERIA Capital Partners

Thank you for joining us for Antero’s second quarter 2014 investor conference call. We’ll spend a few minutes going through the financial and operational highlights and then we will open it up for Q&A.

I would also like to direct you to the homepage of our Web site at www.anteroresources.com, where we have provided a separate conference call presentation under the quick link section that will be reviewed in today’s call. These materials along with the updated company presentation can be located on the homepage of our Web site.

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 would now turn the call over to Glen.

Thank you, Mike. And thank you everyone for listening to our call today.

In my comment I am going to cover the status of our guidance, provide a review of our price utilizations and touch on reserves a bit. Paul will then review our firm transportation portfolio and the operational results for the quarter.

Our guidance for the year was based on a plan that assumed our development program to run an average of 18 drilling rigs during the year. This plan factored in certain risking on the midstream infrastructure build out necessary to move the production from those rigs.

As we progressed throughout the year the timing of the midstream build out have exceeded our risk and expectations. We’re currently waiting on a fourth processing train at MarkWest Sherwood facility to be completed, which right now is resulting in about 400 million cubic feet a day equivalent of curtailed production.

This 200 million cubic feet today facility, processing facility is expected to be placed into service over the next month. With the completion of this facility and the expected completion of Sherwood V in the fourth quarter of this year substantially all of the midstream infrastructure necessary to move our production for the remainder of 2014 would be complete.

Thus we're now reviewing our plan to determine whether we want to further accelerate the development of our assets as we head into 2015. The production targets of 45% to 50% growth in 2015 and 16 assumes an approximate two rig increase in each of those years, so we may want to get a head start on the program if we can get comfortable with the infrastructure and capital needs there.

Now onto realizations. I will be covering a few slides that are located in conference call presentation as Mike mentioned on the homepage of our Web site.

I’ll start with Page Number 2 that is entitled 2Q 2014 realizations. During the quarter we sold 58% of our gas at favorably priced into indices which we define as TCO, NYMEX at Chicago.

The remaining 42% were sold at the Dominion South and Tetco which has experienced a decline in price during the quarter. This made the sales points resulted in a negative differential for the quarter of $0.18 for the effect of cash settled hedges.

We had natural gas cash settled hedge gains for the quarter of $0.04 so in total we received $4.53 per Mcf or $0.14 less than NYMEX. Our natural gas realized prices continuing the most attractive of our sales peers by a wide margin.

Today this attractive realization has been primarily related to the geographic location of our production. As a reminder we are broad gauging the southern portion of the Marcellus including West Virginia so our local index is TCO which is the highest priced index in the basin currently.

TCO Basin features for the remainder of 2014 and an average negative differential NYMEX, of about $0.12 while the Dominion South is around $1.44. The $0.18 negative differential before hedging was below previously provided guidance as market prices for Dominion South and Tetco deteriorated roughly from our last update.

Based on to-date market prices we have answered full year 2014 guidance to reflected average of negative $0.15 to $0.25 differential for the year. This guidance is based on the assumption of selling approximately 44% of our production Tetco, 13% at NYMEX $1.25 8% at Chicago and 35% at Dominion South.

We do however have significant basis hedges in place to reduce our exposure to Dominion South with 160 million cubic feet a day or approximately 60% of our exposure hedged at $5.16. Based on current future prices we would expect to realize approximately $125 million of cash settle hedge gains from our TCO and Dominion South hedges in the second half of 2014 so overall hedge there.

These basis hedges and our above market and NYMEX hedges combined with selling 65% of asset favorable pricing should result in oil and gas realizations above NYMEX pricing for the entire year. In order to ensure that we maintain attractive price realizations going forward we’ve also secured an industry leading firm transport portfolio.

The first significant component of that portfolio came into effect on June 26th of this year as we gained access to 250 million cubic feet a day of REX through the recently completed REX Seneca lateral. This shifts our current 150 million a day of Utica gas production from Tetco, that’s our net reduction from Tetco M2 pricing to Chicago Index pricing which is approximately $1.50 price improvement.

Over the next couple of years we’ll have several firm transport options available to us including much Midwest and Gulf Coast transport, which based on today’s pricing will improve our differential by approximately $0.15 to $0.25. We have also received the attractive prices for our NGL and condensate barrels.

Our NGL barrel is currently C3 plus or heavier and therefore does not contain any methane. This results in a more valuable barrel evidence by $55 per barrel for this quarter which is approximates 53% of the average second quarter WTI price.

Additionally we received approximately $91.20 per barrel for our condensate barrels. Liquids production represents 14% the second quarter volumes and combines with the attractive prices received for our condensate NGL barrels resulted in liquids contributing 27% for this quarter’s revenue so more than a quarter of our revenue are from liquids now, by far the highest percentage of experience.

We expect liquids contributing in a higher proportion going forward. Flipping to slide 3, titled Biggest Bang for the Buck, the attractive gas and liquids differential that we receive combining with our hedge portfolio resulted in top line all-in realization of $5.35 per Mcfe.

This top line realization is over $0.85 better than our nearest Marcellus peer continues to result Antero leading the Appalachian E&P sector from an EBITDAX margin standpoint. Our EBITDAX margin for the quarter was $3.29 per Mcfe as you can see in that first column and when you factored that we had $0.58 per Mcfe defining development cost or $1.15 development cost and if you look at that we can cover that in back of our August presentation.

You can basically see that our process of generate high rates internally. Before I turn it over to Paul to cover firm transport portfolio and our operations results I’d like to touch on mid-year reserves.

The fourth slide is entitled outstanding reserves growth. That can tell substantial reserve growth in the first half of the year as we detailed in the press release in July.

We were able to grow proved reserves by 19% in the first six months of the year to 9.1 Tcfe and three key reserves by 7% to 37.5 Tcfe. The Marcellus accounts for 26.4 Tcfe of that 37.7 Tcfe.

It’s interesting to note that the Marcellus down 97% proved and probable meaning the Marcellus substantial de-risked across our entire 373,000 net. The Marcellus shale accounted for 94% of proved reserve volumes with the remainder attributed to Utica shale.

PV10 of our proved reserves using mid-year 2014 MCC pricing and including the value of our hedges was $9 billion or increase of 28% from year end. Now the PV10 of our three key reserves using the same methodology was $26.4 million for an increase of 24% from year end 2013.

Two important items notice, that one, in the Marcellus mid-year 2014 reserves only 36% of proved locations and 62% of 3P were booked using SSL type curve of 1.7 Bcf per 1,000. Virtually all of our drilling the first half of the year utilize SSL completions and the results have been consistent with type curve.

So you’d expect those percentages to increase overtime as we drill more SSL well. The second item to note is that, there were no dry gas Utica shale reserves located in West Virginia or Pennsylvania booked in our prove or 3P at mid-year.

We did update our West Virginia and Pennsylvania Utica net resource however two account for the recent activity resulting in an increase of 9.5 Tcf. And I’m talking about the industry activity; we haven’t yet drill the Utica well.

This amount combined with our 3P reserves results in the total company net resource of 47 Tcfe. To summarize the quarter and first half of 2014 from financial perspective we achieved tremendous growth with natural gas industry leading price realizations, pure leading cash margins and returns with strong visibility that these results will continue well into the future.

We also had outstanding reserve growth that was consistent with our expectations. With that I will turn it over Paul for his comments.

Thanks Glen. In my comments today I’m going to address couple of our recent developments.

Glen has already covered our significant profitability and reserve growth. So I’m going to focus on our firm transportation strategy and our operational update.

We have an industry leading portfolio of firm gas and NGL takeaway which is detailed on Slide 5, entitled integrated portfolio of firm gas and NGL takeaway. Antero made significant additions to its transportation portfolio during the second quarter of 2014 resulting in an Appalachian E&P industry leading for 4 Bcf a day of residue gas firm transportation in sales.

This portfolio provides us with the ability to move a substantial portion of our Appalachian basin gas production to more favorably priced indices. The firm transport provides Antero the ability to direct 48% of its production to the Gulf Coast.

20% of its production to Midwest pricing including Chicago and Michigan, Detroit, Midwest and 19% to Appalachia and finally 13% to the Atlantic seaboard. The ability to direct our gas is the Gulf Coast is strategic as we expect the vast majority of growth in gas and NGL demand to occur on the Gulf Coast over the next five years.

From a liquids perspective we’ve entered into a agreements with the proposed regional ethane crackers both in West Virginia and Pennsylvania for a total of 55,000 barrels a day of ethane. We also have 20,000 barrels a day of ethane takeaway capacity on Atex which brings out total ethane capacity both in local demand and regional transport to 75,000 barrels a day.

Now during the quarter we signed up our first international customer for ethane sales at price that's expected to be a premium to gas Btu value and this will continue to be a focus for us going forward. We have also contracted for a 52,000 barrels a day of NGL firm transport Sunoco's Mariner East 2 project and have agreed to sale 200 million cubic feet a day of gas to Cheniere in the Gulf Coast for LNG export.

Turning to the final slide titled connectivity to keep pipelines enhance as take away we started a new phase of our takeaway strategy during the second quarter as we were able to secure capacity on two key regional pipelines that connect our acreage to existing firm transportation. The first regional pipeline, the energy transfer Rover pipeline, connects our Marcellus and Utica production to the ANR pipeline at Defiance, Ohio.

We have 800 million cubic feet a day of firm transport on the 2.2 Bcf a day pipeline, which links up with our already existing 600 million a day of firm transport on ANR that will transport us and transport our gas to the Gulf Coast. In addition, our midstream subsidiary Antero midstream has an option to acquire up to a 20% interest in the project.

The second regional pipeline is a new gathering pipeline in West Virginia that will go South from Marcellus acreage and connect to our existing firm transport of Tennessee Gulf Coast pipeline. We have 1.1 Bcf a day of capacity of this gathering pipeline that links up with our already existing 790 million cubic feet a day a firm transport on Tennessee that will transport our gas to the Gulf Coast.

The access amount of transport on this new gathering pipeline above and beyond the Tennessee firm will be directed East to gain access to the Atlantic seaboard opening up a new market for our gas. Similar to the Rover pipeline our midstream subsidiary has an option to acquire a 15% interest project.

We now have sufficient firm transportation capacity to accommodate our accelerated development program for the foreseeable future which enables us to achieve our targeted production growth rates, while also securing access to the most favorable pricing regions. We also believe our forward thinking philosophy resulting us capturing the most cost efficient transport by capitalizing on the limited number a backhaul and reversal projects as they became available, these were the first thing that we did to backhauls and reversals.

This strategy limited our need for more costly new build transport. As you’re probably aware the Marcellus shale recently exceeded 15 Bcf a day of production representing approximately 40% of the overall U.S.

share production. We anticipated this explosive regional growth a couple of years ago we know it is critical to build and structure, a firm transportation portfolio that would diversify our exposure to Appalachian basin pricing.

By 2016 we will have the ability to send it approximately 50% of our gas production to the Gulf Coast, 20% to Midwest markets and the remaining 30% to Appalachia or eastern directed market. Now let me move on to the operational update.

The company’s net daily production for the second quarter of 2014 averaged 891 million cubic feet equivalent a day including over 20,200 barrels of liquids over 14% of total volumes. Second quarter 2014 production represents an annual organic production growth rate of 94% and liquids production for the second quarter of 2014 represents an annual organic production growth rate of 387%.

With strong results in our Marcellus and Utica rich gas areas that I will highlight later in my comments. The company averaged over 1 Bcf equivalent today of net production during July which was ahead of expectations and does represent a company record.

During the first half of the year we ran 20 rigs in the Appalachian basin along with an average of frac spreads. In the Marcellus we continue to be the most active operator with 15 rigs at the seven frac who’s currently working including two fully dedicated spreads.

Antero has transitioned to shorter stage like completions on virtually all of our Marcellus wells we have completed and placed online 70 Marcellus wells 2014 and continue to expect a range of 20% to 30% improvement in our AURs with the average well costs increasing only by 10% to 15%. Additionally 47 of the 70 completed wells have been online for more than 30 days and have average 30 day rate of 12.9 million cubic feet equivalent a day in ethane rejection.

The average lateral link for the 47 wells was approximately 8100 and 50 feet. We continue to complete some of the longest laterals in the Marcellus shale having recently drilled our Weigle well, the Weigle 1H with the lateral link of approximately 10,700 feet and 70 frac stages.

We also recently placed online our four well Bee Lewis pad in our highly rich gas regime and this pad, the four wells had a peak 5 day sales rate of 79 million cubic feet equivalent a day so almost 20 million a day per well and the 79 cubic feet equivalent was 1265 Btu gas in ethane rejection. The strong initial rates are indicative of the successful recent transition of our development program into the more liquids rich areas of our Marcellus and also represent and are utilizing these SSL completions.

As we have shifted our activity at the Marcellus to the liquids rich areas, it's essential that we have adequate processing capacity. We recently authorized Sherwood train number 7 which will bring our total processing capacity in 2016 by the time these are built to 1.35 Bcf a day.

Now shifting to the Utica, we’re in 5 rigs in the Utica along with an average of 1 frac spread and we drilled and completed 23 wells in the first half of 2014. Up those 23 wells 15 have had at least 30 days of production history with an average 30 day rate of 14.8 million cubic feet equivalent a day in ethane rejection and that was 47% liquids.

The average lateral link for the 15 wells was approximately 7300 feet. Similar to the Marcellus, Antero has drilled many of the longest laterals so far in the Utica shale.

We recently completed the Myron 1H with the lateral link of approximately 11,700 feet and 51 frac stages. The Myron 1H had a 30 day rate of 26 million cubic feet equivalent per day including 1400 barrels of condensate and already has accumulative condensate production totaled of more than 100,000 barrels.

We also recently placed online the three well Carpenter pad in the Utica and this is in the highly rich gas regime. Has an average Btu of 1225 and this three well pad had an average initial five day rate of 65 million cubic feet equivalent a day in ethane rejection.

These wells represent our firs highly rich gas wells placed on sales in 2014 and we plan to complete 14 additional wells located in the highly rich and the rich gas regimes throughout the remainder of the year. From a processing perspective we process our gas at the Seneca facility in the Utica and have 450 million cubic feet a day of firm processing capacity that increases to 850 million cubic feet a day of firm processing capacity by 2016.

Regarding CapEx for the quarter we invested $605 million on development, $195 million on infrastructure projects including fresh water distribution services and $180 million on acreage which added 23,000 core Marcellus and Utica liquids rich acres during the quarter. The capital expenditures for acreage induced the recently announced leasehold acquisition under and around Piedmont Lake in Belmont and Harrison Country in Ohio.

And our acreage acquisitions were primarily located in the cohort of the highly rich gas and highly rich gas condensate areas. Regarding land and additions, our strategy is to leverage our strategic advantage of being the most active and sizable operator in the areas by consolidating and blocking up our areas of operation.

The 35,000 net acreages that we added in the core of the liquids rich Marcellus and Utica shale plays during the first half of 2014 for approximately $239 million added approximately 151 new drilling locations and increased the working interest percentage in the plan lateral length associated with many existing locations. The acreage added during this first half of 2014 resulted in the addition of two Tcf equivalent of 3-P reserves with an associated PV-10 value of $1.5 billion assuming midyear 2014 SEC prices.

In summary, we remain the most active operator in Appalachia and have what we believe is the most fully integrated business model in the region which is necessary for this level of activity form our significant grassroots leasing efforts to our accelerated development plant, our midstream focus industry leading firm transportation portfolio, and significant hedge position. We believe are fully integrated model provide significant value creation with clear visibility to high production and reserve growth and peer leading per unit margin for many years to come.

We will continue focus our efforts in the liquid rich portions of our plays as we generate attractive rates of return even at low natural gas prices. We have one of the largest, if not the largest, liquid exposure due to our acreage being located in the core of the liquids core in both the Marcellus and the Utica shale.

Our execution of our plan has been exemplary and we expect that to continue going forward. With that operator, we are now ready to take questions.

Hey, guys, good update. This is actually Will for Neal.

Quick question on the -- overall when we look at pricing in the basin what are you all's thoughts overall activity? Over the next call it a year to 18 months, obviously you're running more rigs right now than you had originally planned, but with pricing exposure in the basin, how do you think about that?

Hey, guys, good update. This is actually Will for Neal.

Quick question on the -- overall when we look at pricing in the basin what are you all's thoughts overall activity? Over the next call it a year to 18 months, obviously you're running more rigs right now than you had originally planned, but with pricing exposure in the basin, how do you think about that?

So is your question, are we concerned about the pricing in the basin and would that slow us down, is that what you’re asking?

Exactly, yes. How would that change your thoughts and where you would focus activity across your acreage?

Exactly, yes. How would that change your thoughts and where you would focus activity across your acreage?

Now, I mean we’re still seeing outstanding rates of return. Every rig running in the Marcellus is drilling processable gas 1150 and above and the same for the Utica, so we have 20 rigs drilling processable gas along with condensate many areas.

So if you look at the rates return slides in our August presentation on the Web site, there is a sensitivity analysis in there where you can -- if you want to $0.50 off the share price or whatever you can see that, you can see that there is still quite outstanding rates returned. So that’s not falling us down plus some of our comments we made as we go forward in the second half of the year about two-thirds of our gas will be priced favorable indices and so that includes Chicago of course but also TCO is also about $0.12 off of NYMEX for the rest of the year, so none of that indicates us that we should slow down or be concerned about our rates of return.

Okay, great. And then also when you -- in your West Virginia dry gas for Utica area, what are you all's thoughts, I know you have a well coming up soon, what are your thoughts on activity there potentially for next year?

Okay, great. And then also when you -- in your West Virginia dry gas for Utica area, what are you all's thoughts, I know you have a well coming up soon, what are your thoughts on activity there potentially for next year?

Well, we still want to just drill our initial test and test it we’re surrounded by other industry tests well that are both down dip and up tip of our locations, so fully expect it to be good it’s just a question of at what rate. We’re still working on infrastructure takeaway to the best markets for the Utica dry gas test so as to whether we’ll get into a full scale Utica dry gas development program that’s probably further on down the road I think it’s to drill our test first and so that’s where our focus is, so most of our all of our Utica activity, as Glen was saying, will be over in the rich, highly rich, high rich condensate areas of the Utica fairway.

I noticed in your latest slide presentation, the August corporate presentation that the Utica shale type curve slide went away, so what's the plan with that going forward? And could you talk about what the data looks -- what the performance looks like recently?

I noticed in your latest slide presentation, the August corporate presentation that the Utica shale type curve slide went away, so what's the plan with that going forward? And could you talk about what the data looks -- what the performance looks like recently?

No changes to the type curve, Joe. As we mentioned in some of the commentary, we’re seeing results that are consistent with the type curve and I think we’ve covered that in the reserve press released that, if you want to go back and look at, we kind of highlight by area what we’re seeing and what we booked at midyear.

So no changes there and we don’t plan the really kind of chase the type curve around quarter-to-quarter, if you will, we’re very satisfied with the results, we’re seeing outstanding wells.

Got you and could also talk about your choke management program in the Utica shale especially in the gassier areas?

Got you and could also talk about your choke management program in the Utica shale especially in the gassier areas?

We continue to do choke management in the Utica. We like other operators are seeing favorable results.

We see more liquids. By the time you get to a certain point on gas production by doing choke management, we see a higher proportion of liquids on the choked wells.

So, we are still doing pilots on any pad we might have too choked and too un-chocked, but it looks favorable.

Let me switch to the midstream side, what's the latest on the private letter ruling and should that continue to get delayed? What's your thought about potentially moving forward without the water infrastructure assets?

Let me switch to the midstream side, what's the latest on the private letter ruling and should that continue to get delayed? What's your thought about potentially moving forward without the water infrastructure assets?

Yes, Holly, that’s a good question. We don’t have a lot of clarity.

I think there has been some press on this over the summer where I believe the IRS has completed their process and now they’re waiting on treasury to sort of sign off on the policy but that doesn’t really tell us when the PLR is going to be issued, so we probably don’t know much more than you do on that even though we have been in contact with all of them. The parties there but to take the water out, we think it’s such an integral component to it and there is certainly nothing that we have heard from either IRS or treasury to think that water would be excluded from future PLR.

So IRS has issued about a dozen PRLs in the past for water to MLPs, so this will be quite a change in approach if they said that freshwater distribution which is very integral to our fraction stimulations is excluded. As you probably know sand has been included and that’s also big part of that fracing and there is bit PRL issued for that.

So we don’t have any real concerns, no reason to be concerned that would be excluded. So we’re trying to be patient with this and wait see how it plays out over the next couple of months.

That’s all we can say about at this point.

Okay, great, that's helpful. And then noticing that you've outlined these two big projects one on the gathering side and then one on the interstate pipeline side in which you've got the potential for an equity partnership.

Can you maybe walk us through how those options came about and then the timing for those decisions that you have to make?

Okay, great, that's helpful. And then noticing that you've outlined these two big projects one on the gathering side and then one on the interstate pipeline side in which you've got the potential for an equity partnership.

Can you maybe walk us through how those options came about and then the timing for those decisions that you have to make?

Yes, Holly, as we build our midstream business and forecast how our MLP looks going forward, it made a lot of sense to us to make sure we had those options and we’re anchor shippers in both of those projects so that opportunity came to us. This is one of those things I think is being a big player and the most active driller in Appalachia, these kind of opportunities can come to you and so we have enjoyed that put those in place.

The option period varies but we have got some time, we consider it’s not something we have to do right away and obviously there are big capital commitments particularly for the Rover pipeline. So let’s see how that plays out.

They just completed their open season and we’ll wait to in the final project looks like and decide whether or not we want to participate in that. But we think those are great add-ons to our MLP business, give us long-term regional pipeline capacity participation.

So we think that’s kind of a nice add-on to our current just water and compression and gathering business. So that’s kind of the way we view that and the processing is something we think about too maybe we participate in that eventually as well in the midstream business for the MLP.

Hi. A couple of questions on reserves, your mid-year reserve bookings, I know you guys talk about that at one point, I think you referenced 1.9 Bcf for 1,000 foot of lateral, were you allowed to book -- whether the engineers allow you to book at that rate, and then if so, I’ll start there and go from there.

Hi. A couple of questions on reserves, your mid-year reserve bookings, I know you guys talk about that at one point, I think you referenced 1.9 Bcf for 1,000 foot of lateral, were you allowed to book -- whether the engineers allow you to book at that rate, and then if so, I’ll start there and go from there.

David I think the 1.9 Bcfe versus 1.7 is the well ahead booking, 1.7 Bcf per 1,000.

Okay.

Okay.

What they want to say they tied together. And yes, definitely the engineering guidelines allow for that booking.

Okay. Yes, I didn’t know how far be enough data in there far enough long in the process to give you 100% credit for that.

Okay. Yes, I didn’t know how far be enough data in there far enough long in the process to give you 100% credit for that.

That’s, we make percentage earlier but at which 35% of our proved or booked with SSL so hence that 1.7 Bcf well ahead but it’s only 60% something about two-thirds of our 3P is booked with SSL. So that implication there is the remainder is booked at the old type curve which was 1.5 Bcf.

So there is upside there overtime as we continue to roll out the SSL.

Okay, that’s helpful. And then on CapEx, I know in the press release you referenced the 20 rigs and you referenced that in your prepared remarks versus you expected a slowdown, now you’re not going to see that slowdown I mean is the right way for us to think about it two additional rigs for half of the year versus your original budget or can you give us any framework around that?

Okay, that’s helpful. And then on CapEx, I know in the press release you referenced the 20 rigs and you referenced that in your prepared remarks versus you expected a slowdown, now you’re not going to see that slowdown I mean is the right way for us to think about it two additional rigs for half of the year versus your original budget or can you give us any framework around that?

I think that’s probably the starting part we haven’t decided yet we’re still working on that detail we’ll cover all that in due time here in the quarter we will roll that out as to what the final budget is for the year and the guidance on production that goes with that both for this year and rolling into next.

Okay and last question, are you guys, is there anything new as far as on the completion if anything you’re trying different out in the Utica, Marcellus other than choke management or pad drilling, is anything new and different that you care to share with us?

Okay and last question, are you guys, is there anything new as far as on the completion if anything you’re trying different out in the Utica, Marcellus other than choke management or pad drilling, is anything new and different that you care to share with us?

I think you’ve touched on the main ones David there is SSLs there is chock management there is density. So at this point within our reach gas area the Utica were developed 500 foot inner lateral distance and so far so good so I would say as we’ve made the point we’re long time share players so we have our techniques to prevent or limit frac hits offset wells we have guidelines there to limit and bring back wells as they get hit by a frac pretty quickly.

So that’s pretty standard at this point I’d say one thing that we will test in our deep Utica will be ceramic proppant probably cargo ceramic high strength, high pressure ceramic proppant on the deep high pressure Utica and which part of the recipe of the frac stages we put in there we were gotten that so it won’t all be ceramic proppant but we’ll definitely put it to a good test.

Okay. I appreciate it.

Thanks guys.

Okay. I appreciate it.

Thanks guys.

Thanks David.

Sorry, just one more. You’ve obviously done a great job on the marketing side with both natural gas end markets and then the NGL take away, but is there anything that you feel right now that you’re kind of still missing in the portfolio as you kind of look out over the next few years?

Sorry, just one more. You’ve obviously done a great job on the marketing side with both natural gas end markets and then the NGL take away, but is there anything that you feel right now that you’re kind of still missing in the portfolio as you kind of look out over the next few years?

No, although there, Holly there will be more pieces to add as time goes on the opportunities are there whether it’s a long haul residue gas transport, developing export markets international for both residue gas and for liquids, there is a piece out there at some point will there be a NGL Y-grade pipeline to the Gulf, time will tell where we’re quite happy with our export capacity out of Marcus Hook and the net backs there relative to Bellevue or the Gulf Coast but that’s one element that I think as a regional group of producers, the Appalachian group will they look to support a y-grade project that will transport y-grade liquids all the way to Gulf to get fractionated and going to the petro chems there, that element has not been answered yet.

And that’s right not just a Kinder project?

And that’s right not just a Kinder project?

There is several out there Kinder is certainly an important open, I think Energy Transfer has one as well.

Okay. Thanks for the help.

Okay. Thanks for the help.

Thank you.

I just want to talk a little bit about the excess capacity that you have on your system, I noticed you sold some, but you're also paying for capacity. Could you talk just about your strategy of how you're dealing with excess capacity and leasing it out and how we should think of that financially going forward?

I just want to talk a little bit about the excess capacity that you have on your system, I noticed you sold some, but you're also paying for capacity. Could you talk just about your strategy of how you're dealing with excess capacity and leasing it out and how we should think of that financially going forward?

Sure. For starters David we are -- as we stated in our press release we aren’t buying access firm capacity to speculate within the market world it’s just that the capacity comes on in steps whereas the production grows in more of a ramp and so from time to time we’ll have access capacity.

And so what we’re looking for of course is the others that don’t have firm that want to go better market we’ll buy that gas and transport it and we’ll get an uptick and we will reward the producer where we buy the gas with a little bit of a premium and then hold on to the premium Marcellus as well. So that’s the intent.

And it’s part of that -- part of that in the marketing expense of course is our Atex capacity which as of yes, we haven’t use but we did some opportunity to utilize some of that Atex capacity going forward.

That concludes our presentation today. Thanks for all your interest.

And we’ll be in contact.