Antero Resources Corp (AR) 2014 Q2 法說會逐字稿

Good day and welcome to the Antero Resources second-quarter earnings 2014 conference call and webcast.

(Operator Instructions)

Please note this event is being recorded.

I would now like to turn the conference call over to Mr. Michael Kennedy, Vice President of Finance. Mr. Kennedy, the floor is yours, sir.

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'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 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 website.

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 judgements 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 Glen.

Thanks, Mike, and thank you, everyone, for listening to our call today. In my comments, I'm going to cover the status of our guidance, provide a review of our price realizations 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 will run an average of 18 drilling rigs during the year. This plan factored in certain risks (inaudible) on the midstream infrastructure build out necessary to move the production from those rigs.

As we progress throughout the year, the timing of the midstream build out has exceeded our risk expectations. We're currently waiting on the fourth processing train at MarkWest Sherwood facility to be completed, which right now is resulting in about 100 million cubic feet a day equivalent of [curtailed] production.

This 200 million cubic feet a day 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 will 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 in 2015. The production to targets of 45% to 50% growth in 2015 and 2016 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 website. I'll start with page number 2 that is titled 2Q 2014 Realizations.

During the quarter, we sold 58% of our gas at favorably priced indices which we define as TCO NYMEX at Chicago. The remaining 42% were sold at Dominion South and Tetco which have experienced a decline in price during the quarter. This makes the sales points result 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 continue the most attractive of our sales peers by a wide margin. To date this attractive realization has been primarily related to the geographic location of our production.

As a reminder, (inaudible) in the southern portion of our Marcellus including West Virginia. So our local index is TCO, which is the highest price index in the basin currently.

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

Based on today's market prices, we revised our full-year 2014 guidance to reflect an 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 at TCO, 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 for approximately 60% of our exposure hedged at $5.16. Based on current futures prices, we would expect to realize approximately $125 million in cash settled hedge gains from our TCO and Dominion South hedges in the second half of 2014, so we're well hedged there.

These basis hedges and our above market and NYMEX hedges combine with selling 65% of our gas at favorable pricing should result in all-in gas realizations above NYMEX pricing for the remainder of the year -- but for the entire year, excuse me.

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 26 of this year as we gained access to 250 million cubic feet a day of REX capacity through the recently completed REX Seneca lateral. This shifts our current 150 million a day of Utica gas production from Tetco, that's our nat production, from Tetco M2 pricing to Chicago Index pricing which is approximate $1.50 price improvement.

Over the next couple of years, we'll have several firm transport options available to us including much more Midwest and Gulf Port -- Gulf Coast transport. Which based on today's futures pricing would improve our differentials by approximately $0.15 to $0.25.

We've also received attractive prices for our NGL and condensate barrels. Our NGL barrel is currently C3-plus or propane and heavier, and therefore does not contain any ethane.

This results in a more valuable barrel evidence by us receiving $55 per barrel for our product this quarter, which approximates 53% of the average second quarter WTI price. Additionally we received approximately $91.20 per barrel for hedges for our condensate barrel this quarter.

Liquids production represented 14% of second quarter volumes and combined with the attractive prices received for our condensate NGL barrels resulted in liquids contributing 27% to this quarter revenue, so more than a quarter of our revenues are from liquids now. By far the highest percentage we've experienced. We expect liquids to contribute an even higher proportion going forward.

Flipping to slide 3, titled Biggest Bang for the Buck, the attractive gas in liquids differentials that we received combined with our [SNIP] and hedge portfolio resulted in the 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 in 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 throughout. And when you factor that we had $0.58 per Mcfe of finding and development costs, or $1.15 of development cost depending on how you want to look at that, and we cover that in the back of our August presentation. You can basically see that our properties are generating high rates of return.

Before I turn you over to Paul to cover the firm transport portfolio and our operational results, I'd like to touch on our mid-year reserves. The fourth slide is entitled Outstanding Reserve Growth.

That details the substantial reserve growth during the first half of the year. This was 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 3-P reserves by 7% to 37.5 Tcfe.

The Marcellus accounts for 26.4 Tcfe of that 37.7 Tcfe to 3-P. It's interesting to note that the Marcellus is now 97% proved and probable, meaning the Marcellus is substantially derisked across our entire 373,000 net acre block.

The Marcellus shale accounted for 94% of our crude reserve volumes with the remainder attributed to the Utica shale. The PV-10 of our proved reserves using mid year 2014 to MCC pricing and including the value of our hedges was $9 billion, or increase of 28% from the year end. Now the PV-10 of our 3-P reserves using the same methodology was $26.4 million for an increase of 24% from year end 2013.

Two important items to note is that one, in the Marcellus mid-year 2014 reserves only 36% are proved locations and 62% of 3-P were booked using SSL type curve or 1.7 Bcf per 1,000. Virtually all of our drilling during this first half of year utilize SSL completions and the results have been consistent with the type curve. So you'd expect those percentages to increase over time as we drill more SSL wells.

The second item to note is that there were no dry gas Utica shale reserves located in West Virginia or Pennsylvania booked in our proved or 3-P at midyear. We did update our West Virginia and Pennsylvania Utica net resource however to account for the recent activity resulting in an increase of 9.5 Tcf, and I'm talking about industry activity, we haven't yet drilled a Utica well. This amount combined with our 3-P reserves results in a total Company net resource of 47 Tcfe.

To summarize the quarter and first half of 2014 from a 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 to Paul for his comments.

Thanks, Glen. In my comments today I'm going to address a 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 4 Bcf a day of residue gas firm transportation and sales. This portfolio provides us with the ability to move a substantial portion of our Appalachian base and 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 Michcon, Detroit, Midwest and 19% to Appalachian and finally 13% to the Atlantic seaboard. The ability to direct our gas to 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 prospective, we've entered into 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 our 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 pricing 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 52,000 barrels a day of NGL firm transport on Sunoco's Mariner East 2 project and have agreed to sell 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 Key Pipelines Enhances Takeaway. 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 our Marcellus acreage and connect to our existing firm transport on the Tennessee Gulf Coast pipeline. We have 1.1 Bcf a day of capacity on this gathering pipeline that links up with our already existing 790 million cubic feet a day of firm transport on Tennessee that will transport our gas to the Gulf Coast.

The excess 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 in this project. We now have sufficient firm transportation capacity to accommodate our accelerated development program for the foreseeable future which will enable 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 results in us capturing the most cost efficient transport by capitalizing on the limited number of back haul and reversal projects as they became available. These were the first things that we did, the back hauls 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 US shale production. We anticipated this explosive regional growth a couple of years ago so we know is critical to build and structure a from transportation portfolio that would diversify our exposure to Appalachian Basin pricing. By 2016, we will have the ability to send approximately 50% of our gas production to the Gulf Coast, 20% to mid US markets and the remaining 30% to Appalachian or eastern directed markets.

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, or 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 of day 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 eight frac spreads. In the Marcellus, we continue to be the most active operator with 15 rigs and 7 frac crews currently working including 2 fully dedicated spreads.

Antero has transitioned to shorter stage length completions of virtually all of our Marcellus wells. We have completed and placed on line 70 Marcellus wells in 2014 and continue to expect a range of 20% to 30% improvement in our EURs with the average well cost increasing only by 10% to 15%.

Additionally 47 of the 70 completed wells have been online for more than 30 days and had an average 30-day rate of 12.9 million cubic feet equivalent a day in ethane rejection. The average lateral length for the 47 wells was approximately 8,150 feet. We continue to complete some of the longest laterals in the Marcellus shale having recently drilled our Weigle well, the Weigle 1H with a lateral length of approximately 10,700 feet and 70 frac stages.

We also recently placed on line our four-well Bee Lewis pad in our highly rich gas regime and this pad, the four wells had a peek five day sales rate of 79 million cubic feet equivalent a day, so almost 20 million a day per well. And this 79 million cubic feet equivalent was 1265 Btu gas ain ethane rejection. These 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 represents our utilizing these SSL completions.

As we have shifted our activity in 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 ran five rigs in the Utica along with an average of one frac spread and we drilled and completed 23 wells in the first half of 2014. Of 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 length for the 15 wells was approximately 7,300 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 a lateral length 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 1,400 barrels of condensate and already has accumulative condensate production total of more than 100,000 barrels.

We also recently placed on line 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 first 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 all 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 acres during the quarter. The capital expenditures for acreage included the recently announced leasehold acquisition under and around Piedmont Lake in Belmont and Harrison Counties in Ohio. And our acreage acquisition were primarily located in the core of the highly rich-gas and highly-rich gas condensate areas.

Regarding land additions, our strategy is to leverage our strategic advantage of being the most active and sizable operator in the area by consolidating and blocking up our areas of operations. The 35,000 net acres 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 play on lateral length associated with many existing locations. The acreage added during this first half of 2014 resulted in the addition of 2 Tcf equivalent of 3-P reserves with an associated PV-10 value of $1.5 billion assuming mid year 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. From our significant grassroots leasing efforts to our accelerated development plan, our midstream focus, industry-leading firm transportation portfolio and significant hedge position, we believe our fully integrated model provides 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 to focus our efforts in the liquids-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, liquids exposure due to our acreage being located in the core of the liquids core in both the Marcellus and Utica shales. Our execution of our plan has been exemplary and we expect that to continue going forward.

With that, Operator, we're now ready to take questions.

(Operator Instructions)

Neal Dingmann, SunTrust.

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 wouldn't 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?

No, we're still seeing outstanding rates of return, every rig running in the Marcellus is drilling processable gas 1,150 BTU and above. And the same for the Utica, so we have 20 rigs drilling processable gas along with condensate in many area. So if you look at the rates of returns slides in our August presentation on the website, there's a sensitivity analysis in there where you can if you want to take $0.50 off of the strip price or whatever, you can do that. But you can see that there's still quite outstanding rates of return. So that's not slowing us down, plus some our comments we made as we go forward in the second half of the year, about two-thirds of our gas will be priced at favorable indices. And so that includes Chicago, of course, but also TCO is only about $0.12 off of NYMEX for the rest of the year. So none of that indicates to 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?

Well we still want to drill our initial test and test it. We are surrounded by other industry test wells that are both down dip and up dip of our locations. So fully expect it to be good it's a question of at what rate. We're still working on infrastructure takeaway to the best markets for Utica dry gas tests. 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, highly-rich condensate areas of the Utica Fairway.

Okay. All right, thank you.

Joe Allman, JPMorgan.

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?

Yes, no changes to the type curve, Joe, as we mentioned some of the commentary we're seeing results that are consistent with the type curve. And I think we recovered that in the reserve press release, if you want to go back and look at that, we highlight by area what we're seeing and what we booked at midyear. So no changes there and we don't plan to really chase the type curve around quarter to quarter, if you will, we're very satisfied with results and seeing outstanding wells.

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 choked management we see a higher proportion of liquids on the choked wells. So we're still doing pilots and -- on any pad we might have two choked and two unchoked, but it looks favorable.

All right, very helpful, guys. Thank you

Holly Stewart, Howard Weil.

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's 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 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 the parties there.

But to take the water out, we think it's such an integral component to it and there's certainly nothing that we have heard from either IRS or Treasury to think that water would be excluded from future PLR. So the IRS has issued about a dozen PLRs in the past for water to MLPs. So this would be quite a change in approach if they said that fresh water distribution, which is very integral to our fracture stimulations, is excluded. And as you probably know sand has been included, and that's also a big part of fracking and there have been PLRs issued for that. So we don't have any real concerns, no reason to be concerned that, that would be excluded. So we're trying to be patient with this and wait and see how it plays out over the next couple of months. But that's about 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?

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 have those options. And we're anchor shippers in both of those projects, so that opportunity came to us. So 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've enjoyed that and put those in place.

And the option period varies but we've got some time to 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 completed their open season and we'll wait to see what 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 giving us long-term regional pipeline capacity participation. So we think that's a nice add on to our current water and compression and gathering business. So that's 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.

Great, thanks for the color.

David Cameron, Wells Fargo.

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 -- will the engineers allow you to book at that rate, and then if so -- I'll start there and go from there.

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

Okay.

They're one in the same, they tie together.

And yes, definitely the engineering guidelines allow for that booking.

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

And that's -- we mentioned the percentages earlier, but I believe it's 35% of our proved are booked with SSL, so hence that 1.7 Bcf wellhead. But it's only 60% something of our -- about two-thirds of 3P is booked with SSL. So that's the implication there is the remainder is booked at the old type curve which was 1.5 Bcf, so there's an 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. 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 point, we haven't decided yet we're still working on that detail and we'll cover all that in due time here in the quarter we'll 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, any -- 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?

Well I think you've touched on the main ones, David, there's SSLs, there's choke management, there's density. So at this point on the -- within our rich-gas area, the Utica, we're developing on 500 foot inter-lateral distance and so far so good. So that's I'd say as we've made the point, we're longtime shale players and so we have our techniques to prevent or limit frac hits of offset wells. We have guidelines there to limit and bring back wells if 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 CARBO ceramic, high-strength, high-pressure ceramic proppant on the deep high-pressured Utica. And as to which part of the recipe of the frac stages we put in there, we work on 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.

(Operator Instructions)

Holly Stewart, Howard Weil.

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 still missing in the portfolio as you look out over the next few years?

No, although there -- Holly there will be more pieces to add as time goes on. But the opportunities are there, whether it's long haul residue gas transport, developing export markets internationally 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. 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 the Gulf to get fractionated and going to the petrochems there, that element has not been answered yet.

And that's right not just a Kinder project?

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

Okay, thanks for the help.

David Beard, IBERIA.

I wanted 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 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 excess firm capacity to speculate with in the marketing 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 excess capacity. And so, what we're looking for, of course, is that others that don't have firm that want to go to better markets will 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 the premium and then hold onto the premium ourselves as well, so that's the intent.

And then part of that in the marketing expense of course is our ATEX capacity which as of yet we haven't used, but we do see some opportunity to utilize some of that ATEX capacity here going forward.

Great, appreciate the time, thank you.

At this time, we'll go ahead and conclude our question-and-answer session. I will now like to turn the conference back over to Management for any closing remarks.

That concludes our presentation today, thanks for all of your interest and we'll be in contact.

And we thank you, Sir, and to the rest of Management team for your time today. The conference call has now concluded, we thank you all again for attending today's presentation. At this time you may disconnect your lines. Thank you, take care everyone.