Antero Resources Corp (AR) 2014 Q1 法說會逐字稿

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

(Operator Instructions)

Please note this event is being recorded.

I would now like to turn the conference over to Mr. Michael Kennedy, VP of Finance and Head of Investor Relations. Please go ahead.

Thank you for joining us for Antero's first-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 home page of our website at www.anteroresources.com, where we have updated our Company presentation for our first-quarter 2014 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 Glen.

Thank you, Mike.

Good morning. Thank you for -- everyone, for listening today. We appreciate your participation. First-quarter 2014 production of 786 million cubic feet equivalent per day increased 105%, so it doubled year-over-year. That was up 16% sequentially, quarter-over-quarter.

The production included approximately 16,300 barrels a day of liquids, or 12% of our total production. That is a significant increase of 583% from the prior year quarter, so almost six-fold from the prior year quarter and up almost 50% sequentially. Of note our oil production was over 3000 barrels a day, or 18% of the liquids production, primarily from the Utica. The midpoint of our guidance for 2014 calls for an average of 25,000 barrels a day of liquids production, which equates to 16% of the total production. So this growth should continue throughout the year since we are at 12% in the first quarter.

We sold our natural gas during the quarter at $0.11 per mcf premium to NYMEX. This compares to our guidance of $0.0 to $0.10 premium. We would like to during the quarter to continue to sell the majority of our gas at Appalachian indices, as they exhibited favorable prices due to the cold winter weather. As a reminder, we are located in the southern portion of the Marcellus, so our local index is TCO. We sold approximately 45% of our gas at TCO, which traded at one penny discount to NYMEX for the quarter, but our gas sold at a $0.38 premium due to the high BTU content. We are currently rejecting ethane, as we get a nice pickup from leaving the ethane in the gas stream and get paid on a BTU value there.

The remainder of our natural gas was sold at various other index pricing points at a $0.43 per mcf differential to NYMEX, but at a net $0.11 negative differential to NYMEX after that BTU upgrade. So blended, you get to that $0.11 premium to NYMEX.

We also received attractive prices for our NGL barrel. Our NGL barrel is currently C3-plus, so propane-plus -- does not contain any ethane. This results in a much more valuable barrel as evidenced by our receiving about $62 per barrel for our product this quarter, which approximates 62% of the average first quarter WTI price. The combination of this attractive price received and the significant liquids production resulted in liquids contributing 24% of this quarter's revenues, which is by far the highest amount we have experienced at Antero.

On the hedging front, despite a significant run up in natural gas, we only had a $1 million realized loss for the quarter. This is due to significant portion of our hedge book being basis hedges at $5 plus levels. These basis hedges continue through 2016.

The premium natural gas prices received, significant growth in liquids, and the C3-plus NGL realizations of over 60% of NYMEX, all resulted in all-in gas equivalent realized price of $5.79 per MCFE. This price realization is among the best in class for the natural gas industry.

From a cash operating perspective production expenses were $1.67 per MCFE. As a reminder, our production expenses included lease operating, gathering, compression, processing, transportation, and production tax, so it's an all-in number. The increase in cash operating costs was driven by our firm transport costs associated with the ATEX pipeline, which went into service this year, adding about $0.16 per MCFE for the quarter. This amount should trend down throughout the year as our firm transport costs are spread over increased production.

Our G&A expense for the quarter was an attractive $0.31 per MCFE, representing a 16% decrease year over year. From an EBITDA margin standpoint, we also believe we are at the top of the natural gas industry. We realized revenue on a gas equivalent basis of $5.85 per MCFE after hedges, and had operating costs, including all cash production expense and G&A, of $1.98 per MCFE, so just under $2.00 of cash expenses.

That resulted in an EBITDA margin of $3.87 per MCFE, so almost $4.00 per MCFE EBITDA margin. When you factor in that we had approximately $1.00 per MCFE of development costs -- we tend to gravitate around that $1.00 per MCFE on the development side -- you can easily see that our projects are generating high rates of return. EBITDA for the quarter was $274 million, which was 130% higher than the prior-year quarter and 27% higher than the fourth quarter of 2013. This quarter was an outstanding financial performance that tracked 105% year over year, and 16% sequential production growth, a dramatic increase in liquids production.

The organic growth realizations and EBITDA margins that I just outlined firmly positioned Antero as the highest-growth and highest-margin large cap E&P company in the Appalachian basin. Please refer to page 9 in our updated May investor presentation on our website for further details on that.

Regarding CapEx for the quarter, we invested $496 million on development, $168 million on infrastructure projects, including freshwater distribution services; and $60 million on acreage adding, about 12,000 core Marcellus and Utica liquids-rich acres during the quarter. In addition to the land we added in Q1, Antero recently released approximately 6,400 net acres on the Piedmont Lake block, primarily in Belmont County, Ohio, in the Utica shale for about $95 million. The acreage provides Antero with 29 gross liquids-rich 3P locations, assuming an average lateral length of 8,600 feet -- so very long laterals laid out there, assuming 1,000-foot interlateral distance.

Now, if we ultimately move to tighter density, the number of locations will increase. This transaction increases Antero leasehold to 115,000 net acres of the core of Utica shale play. Given that this one-off transaction is additive to our normal course leasing operations, we raised the 2014 land budget by $100 million to a total of $300 million, and thus have updated our capital budget guidance by $100 million for 2014, up to $2.85 billion.

From a capital structure perspective, we recently executed a revised credit facility and completed a senior note issuance. We just closed on our $3.5 billion amended and restated credit facility that extends the maturity of the credit facility by three years, out to 2019. In addition as a result of the significant growth in value of the Company's proved developed reserve base since the previous borrowing base redeterminaton, the borrowing base was increased by 50% to $3 billion, and we also increased lender commitments under the facility by $500 million to $2 billion, while adding five new banks to our bank group. And there is a new slide in the appendix that lays out the term structure of our debt, which is quite attractive with an average all-in interest rate on our debt of under 5%.

We issued $600 million senior notes due 2022 with a coupon rate of 5 1/8% that priced at par. This represents Antero's lowest bond rate to date. These notes are trading now below a 5% yield. The proceeds of this issuance are being used to call our 7 1/4% 2019 bonds, and to term out a portion of our credit facility. Our weighted average interest cost, as I mentioned, is below 5%; and our average maturity is over seven years now. Based on the first quarter's annualized EBITDA we are 2.3 times on a debt-to-EBITDA basis compared with 2.5 times a year in 2013. We project this improvement to continue throughout the year.

As of March 31, 2014, pro forma for the borrowing base and lender's commitments increased under the credit facility and the senior notes offering, Antero had $13 million in cash, $431 million drawn under the credit facility, and $73 million in letters of credit outstanding, resulting in $1.5 billion of available liquidity and over $2.5 billion of unused borrowing base capacity that we could access with lender approval.

To summarize the quarter from a financial perspective, we had tremendous growth with natural gas industry-leading realizations, gas margins and returns, with strong visibility that these results will continue well into the future.

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 growth and profitability, so I am going to focus on our firm transport strategy and our operational update. Our guidance for 2014 represents a 75% to 85% organic production growth rate, and we recently announced that we are targeting an annual production growth rate of 45% to 50% for each of the next two years. So that is 2015 and 2016.

In order to achieve that type of explosive growth, we believe we need certainty that we will be able to get our product to market, and that we need optionality on where we can market our gas. We also believe that, in order to capture the most cost-efficient transport, we have to be forward thinking, and so we want to secure both the back haul and the pipeline reversal opportunities when they are available, in order to limit the amount of newbuild transport that we need.

These beliefs have resulted in us accumulating an industry-leading firm transportation portfolio that grows to approximately 2.6 BCF a day in 2016. Firm transport provides Antero the ability to direct almost half, 49% of its production, to the Gulf coast, 28% to Appalachia, and 23% to Midwest pricing, which includes Chicago, Michigan, Detroit, Wisconsin, the Midwest.

The ability to direct our gas to the Gulf Coast is strategic, as we expect the vast majority of growth in gas demand and NGL demand will occur on the Gulf Coast over the next five years. Obviously the firm transport has a cost, but we believe that we are capturing the most cost-efficient transport. Antero was one of the first to recognize the need for firm transport, so we initially focused on back haul agreements, those being the least expensive; and certain firm sales, as they are typically the lowest cost.

We recently expanded our efforts to participate in certain projects that involve the reversal of pipelines, and we've been quite successful in adding these projects to our portfolio. These reversals have a greater cost in the back hauls, but are still quite attractive and cost much less than newbuild projects. Our firm costs per MMBTU, including both demand and commodity charges for the next three years, are $0.31 an mcf; $0.32 an mcf; and $0.42 an mcf for the years 2014, 2015, and 2016, respectively.

The firm transportation portfolio, based on current futures pricing and differentials, would result in an approximate $0.15 per MMBTU-basis differential improvement in our 2016 realized prices compared to 2014 realized prices; thus more than offsetting the $0.11 per MMBTU increase in costs over the same time period. Importantly, this firm transportation portfolio significantly increases our exposure to favorable Gulf Coast and Midwest markets, thereby reducing our overall basis risk. It also provides us with certainty of the ability to produce, which is critical.

Now on to first quarter operational updates. During the first quarter we ran 20 rigs in the Appalachian basin, along with an average of five frac spreads. And we drilled and completed 36 wells. In the Marcellus we continue to be the most active operator with 15 rigs working for us, as well as 7 frac crews working for us including two fully dedicated spreads. We have a significant backlog with 76 wells in various stages of drilling and completing. We expect to maintain our current frac fleet until the backlog returns to more normal levels, which we anticipate to happen by midyear this year.

Antero, as we have told the investment community, has transitioned to shorter stage length completions on virtually all of our Marcellus wells. We have completed and placed online now 38 Marcellus wells using SSL or shorter stage length completion, that have 30 days of production history; and the rate improvement over our non-SSL type curve has been 30%. Of those 38 wells, 15 have been online for at least 180 days, and that improvement continues to hold as they are up 25% over the non-SSL type curve.

We are currently expecting a range of 20% to 30% improvement in EURs, and the average well cost for these wells have been approximately 10% to 15% higher than the old design. One recent SSL well, the Antero Heflin 2H in our highly rich liquids and gas area in the Marcellus, had a 30-day production rate of 21 million cubic feet equivalent a day, with approximately 20% liquids, well above our current SSL type curve -- just to give you an example some of the success we are having.

As we've shifted our activity in the Marcellus to the liquids-rich areas, we need to make sure that we have adequate processing capacity. We recently authorized Sherwood V and Sherwood VI, which will bring our total processing capacity by early 2015 to 1,150 million, that is 1.15 BCF a day. And we will continue to add capacity in 2015. So six trains, times 200 million per day, less 50 million a day equates to that 1,150 million cubic feet a day.

Now shifting to the Utica. During the first quarter, we ran five rigs in the Utica, along with an average of one frac spread, and we drilled and completed 12 wells. We currently have 20 wells in various stages of drilling and completing. We averaged 79 million cubic feet equivalent of production in the first quarter, and so far in the second quarter we have seen production grow by about 50% to 120 million cubic feet equivalent a day. Year-to-date we have completed and placed on line 15 wells in the Utica that have at least 30 days of production history.

We've added a new slide in our slide deck, page 26, that I will refer you to, to our presentation, which breaks out our wells by regime. I will note two items from the slide, with the first being that one well just recently put on line and not included in our April operation update which we put out a couple weeks ago -- this well is called the Antero Myron 1H, and it had our second-best 30-day rate at approximately 26 million cubic feet equivalent a day with a 50% liquids contribution while in ethane rejection mode.

This well was drilled with a lateral length of 11,690 feet, so that is our longest so far -- 11,690 -- and we think it may be the longest lateral drilled in all of Appalachia to date. In addition, you will note that the majority of our activity has been concentrated in the condensate region of our acreage. This was result of the infrastructure been in place in that area first, with established drilling units.

Over the past six months we've been able to establish more drilling units in our rich gas areas slightly to the east, and have recently added 120 million a day of compression there. So you will see more results from these areas, the slightly drier areas than the condensate area, early this summer. And I am talking about the rich gas areas. These rich gas areas of our acreage represent what we think is some of the very best acreage in the entire play.

The prolific nature of our acreage is illustrated by the Ohio DNR -- Department of Natural Resources -- report on well results that just came out that summarizes through the fourth quarter of 2013. During the fourth quarter of 2013, Antero -- or a summary at the end of the quarter -- Antero had 5 of the top 10 gas-producing wells in the Utica play, including the most prolific well. It is important to note these five wells represent the only five wells we've drilled in the rich gas areas so far.

The most prolific well during the quarter, the Antero Gary number 1H, produced approximately 1.3 BCF of wellhead gas over 67 days, or an average of roughly 20 million cubic feet a day of wellhead gas. This production level was nearly double the next closest well and was the only rich well that Antero brought online during the fourth quarter. Additionally, the Gary well has produced approximately 2.8 BCF equivalent in just over six months.

As I mentioned earlier, we will be completing numerous pads in this rich gas area over the next couple of months. We will be able to accommodate this gas, as we recently added 120 million a day of additional fully dedicated compression in this area, giving us a total of 240 million a day of current compression capacity. A third party is building a third 120 million a day compressor station, and that's scheduled to be in service at midyear. In addition, Antero Midstream is building its first two 120 million a day compressor stations, and we expect those to be completed in the second half of 2014.

Let me talk about processing in the Utica for a moment. From a processing perspective, we process all of our gas at the Seneca facility, which is located in the heart of our acreage in the southern Utica. Currently we have 250 million a day of processing capacity, and that increases to 450 million cubic feet a day by midyear this year. We have been pleased with the operations at the facility and currently have excess capacity that we should grow into over the course of the year.

There has been also been some recent encouraging industry wells in the dry Utica gas area. We performed a thorough engineering and cataloging of our acreage position and of the dry gas area under our acreage position in both West Virginia and Pennsylvania during this last quarter. We originally identified some 950 potential drilling locations on our deep Utica acreage under the Marcellus acreage, and that tallied approximately 5 TCF.

But that has been revised upward based on new results, and so we've increased our cataloging to 1080 potential drilling locations, and based on performance of some of the nearby wells, we now tally up 7 to 11 TCF of net resource. We plan to drill a Utica dry gas well in the northwest corner of our Marcellus acreage in Tyler County, West Virginia, in the second half of this year.

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. From our significant grassroots leasing efforts, our accelerated development plan, midstream focus, our firm transportation portfolio, and our significant hedge position, we believe that our fully integrated model, when we put all of the pieces together, provides significant value creation with clear visibility to high production and cash flow growth for many years to come.

We will continue to focus our efforts in the liquids portion of these plays as we have one of the largest, if not the largest liquids exposure, due to our acreage being located in the core of the core in both the Marcellus and the Utica shales.

We are excited for the remainder of 2014; and with that, Operator, we are now ready to take questions.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning, solid quarter. A question now that you've got on -- you had mentioned about the compressors. I think Paul or Glen was talking about that. Just wondering the typical line pressure now how you're flowing these wells, and I guess another way to ask that is how much you're deciding to choke back these wells going forward now that you have ample pressure?

Yes we -- the operating pressures on the interstates is in the 1100- 1400-pound range, PSI. So now with compression as you say we are able to bring the wells on and be able to be into the line, so were not bucking that big line pressure anymore. But as to choking back, we are doing choke maintenance or pressure maintenance in a number of pilots in the Western area in our condensate region just to see with the behavior is. As everybody knows, we are in retrograde condensate country on the west edge of our acreage.

So that is the only choking back we are doing -- is -- just to see what the behavior of the wells will be in various pressure modes. But in the rich gas area we are not choking back the wells. We are able to flow those into compression and into the line. And no problem getting into the line with the compression bucking mainline pressure.

Okay. On slide 28 you showed your huge midstream footprint. I am just wondering based on this, we don't have ample infrastructure in the Utica even if you added another rig or so, in light of obviously the Gulfport issue today with midstream. Sure seems like you've got more than ample. I'm just wondering if you could give some color on your Utica midstream?

Yes we feel that we've got most of the elements in place that we could add another rig. We have got excess capacity in processing as the compressor stations cone on and condensates stabilization. We can handle more production. We flow our NGLs to the north to Harrison County, where they are fractionated at Hopedale, and there is plenty of room at Hopedale in the fracs that are there. We think that at the moment we could accelerate a little bit.

Good, and then lastly, just besides Piedmont how aggressive are you all adding Utica acreage, including both Ohio and West Virginia?

Well -- we have a large land team, and they are working every day. But it is very tight. It's not easy to pry loose acreage. A lot of it has been leased. So we continue to add acreage overall as a Company. We are adding it on the order of 4000 or 5000 acres a month. But it is tough sledding right in the very heart of the Utica fairway.

Thanks, guys. Excellent quarter. Looking forward to all the production coming.

Thank you, Neal.

David Tameron, Wells Fargo.

Hello, good morning. If we think about Harrison or just as the play moves east, how far east do you think you can push this in Harrison County?

And of course -- there is two Harrison counties. Are you talking about Harrison County, Ohio or West Virginia?

West Virginia.

It is possible. There are geologic indicators that would say that the Point Pleasant goes that far east. Certainly it's going to be down dip. Will be tighter? There's just not enough well control to know, but in terms of depositional faces indications are that Point Pleasant will be over there in Harrison County.

But we will start naturally the lowest risk and for us start under our Marcellus acreage is to start in the Northwest corner. But it is possible it will work in Harrison County, too.

Okay. Can you just talk about -- you've obviously been out front of the midstream, I guess it is called infrastructure. You guys a been out front and have locked in. I know you've done the same maybe a little more aggressive than some of your counterparts in some of the gas hedging.

Can you talk about how you think about locking that in today, which some people might say is a little bit more expensive than perhaps given the optionality later as infrastructure is built out? I know some operators have taken a different tack in the plan maybe because they do not have the infrastructure locked in today? Can you just talk about how you think about that, as far as when you plan the business strategically?

Yes, I think you know to take a big picture view, of course everyone knows that the center of the natural gas business, the source of natural gas is shifting to Appalachia, both the Marcellus and the Utica. Huge resources; and so that is where the very lowest cost and the biggest resources are going to be. So, I think one wants to take advantage as we said in our remarks on back haul and reversals in the first place, and then talk about new builds after that. What we have learned over this last winter, as production has grown is that if you do not have firm capacity, you're going to be curtailed.

And so you can look at it in a couple ways. You can say well, maybe if you don't commit to these projects but others do and get them off the ground, then you'll be able to flow interruptably. And that is the risk that you take if you don't have your own firm, is that you'll be able to -- that the pipes will not be full. The game has changed, I think the pipeline builders, the pipeline operators certainly are not willing to go at risk to build speculative pipe.

They are going to want to have them fully subscribed or as close to it as possible in order to build the new builds. So they are getting a lot of full subscriptions. Now if you did not think the gas supply list was there, then the bet you could make would be well, they will get fully subscribed but gas prices will go down, not as much gas will be developed, there will be room in the pipe for my gas to flow interruptably on a spec basis. The way we see the Appalachian basin is there is such a huge volume that is readily available to be developed at reasonable gas prices that the pipes are going to fill up.

So -- we are on the side of we feel good about the cost that we are taking firm transportation and feel good about our economics, our cost structure. And it's the safest thing to do to make sure that we can move our gas to markets and then focus very much on which markets we're going to both on the gas side and the NGL side to maximize the price. So we look at it; we are very confident in our resource and feel we have the gas there and gas to last for decades.

And so we more than perhaps the smaller players that have lesser balance sheets and lower resource, we are willing to step in and take that capacity and tie it end to end to LNG markets to liquid markets and to end-users.

Okay, and then just one final question. I'll ask this knowing -- I'm not meaning to put you on the spot I just want to see if you have any comment. Gulfport -- your shares have come back a little bit, but you were getting beat up this morning, and we got a number of calls asking is this Company specific?

Is this more the call in the Utica, or how should we think about this? We've indicate we thought it more company specific? Any comment on Gulfport's release? And I will leave it out there and see if you have any comment on that.

Well, I think we certainly think Gulfport is a good company. The things we can comment on is there enough processing capacity or fractionation capacity? We feel good about the fracs. We have our firm processing capacity ourselves and feel good about those volumes for us going forward. Just not familiar enough with Gulfport's committed capacity to comment on that.

So, I think maybe they have gotten hurt in the market for some temporary curtailment there. On the other aspect, the communication between wells or what we'd call the frac hits, we feel pretty good about what we are doing. Just a reminder to the market, we have been shale players and pioneers for the last dozen years now, and have had a lot of opportunity along the way. We've drilled and completed more than 500 horizontal wells. So, we've learned a lot going back to our Barnett days, our Woodford days and so on.

And so we routinely have frac hits, that is communication between wells certainly in our Marcellus, where we've drilled and completed over 200 Wells. As a reminder, we are developing Marcellus on 660 foot inter-lateral distance, and we see plenty of frac hits. We have certain rules of thumb. Of course, we have been very studious and -- first of all in microseismic, we use chem -- chemical and radioactive tracers to track interference between wells, and, of course, production history, and we map out any communication between wells. We know which way the fractures are going and so on.

And so, we have rules of thumb that we won't offset a well if it has made a certain amount of production. We will leave an open slot, or if it's made a certain amount, we will move to 1000 foot inter-lateral distance. But in virtually all of our cases whenever we have a frac hit there may be a delay, as the well, I guess you could say, resuscitates itself. It comes back as pressure builds up.

The well has come back to their original type curves. You lose a little bit of PV because the wells go down for a little bit, but longer-term the performance is just fine on frac hits. So, we don't have the density in the Utica yet to be able to say, but we would expect that the performance would be about the same as we honor our rules of thumb and everything that we have learned that frac hits will be okay, and the wells will be able to recover.

So, that I think that is the perspective we can land on on horizontal wells in the region. Whether you really suffer on overall performance, or whether it is temporary thing, we think it is more temporary.

Okay, thanks for all of the color and the time. I appreciate it.

Subash Chandra, Jefferies.

Hi, Paul. Did you share a Q2 Marcellus number? I might have missed it.

No, we did not. We just gave an indication of quarter-to-date Utica production just to show the confidence that we have in our execution there, and we are averaging about 120 million a day equivalent net for the second quarter to date. That's the only comment we had on the second quarter there, Subash.

Got you, thanks. Back to David's point of view same caveat here, I'm sorry same disclaimer here. Don't want to put you on the spot for another company. But the other thing they did talk about that your commentary on frac interference is very helpful.

I was hoping maybe can add a bit more context to liquids fallouts and in the wet gas area in particular. And if you think this compression that you sort of line up ahead of time if that is sort of prevents all this from happening for you?

Subash, no, I do not think the progression will prevent the liquids fallouts from happening. So it's -- you know -- when you look at retrograde condensate reservoirs really across the world, including the Eagle Ford and plenty of fields that have been developed over the last many years. There is the fundamental pressures and the behavior once you get into liquids rich. And the key points are the initial reservoir pressure and then the dewpoint. So there is that differential between initial pressure and dewpoint.

And the greater the differential is the more you can -- the more you can produce the reservoir before you begin to get into that -- those dewpoint considerations. When you're on the liquids rich side the dewpoint is higher and the overall reservoir pressure is lower, so that differential is lower. As you get onto the east side of the play, the dewpoint is much lower, because there's not that much liquids, and the reservoir pressure is higher. So delta P, as we call it is a key, and there is just really not that much getting around the dewpoint.

But with choke maintenance, pressure maintenance you can keep the bottom hole pressure, the flowing pressure higher and not have the liquids dropout back into the formation. We do think that the west side is going to have some of that liquids fallout. And so what choke maintenance and pressure maintenance will do to enhance productivity, I do not think anyone quite knows yet.

But time will tell on that. But I don't think just adding compression is going to be a solution for it. We have adjusted for that phenomenon in our type curve, so contained in our book on page 27 on the website. Those are our recently adjusted type curves, and we put that information out in our operating update in April.

Right, got it. So just to understand that line of concern, you're obviously referring, I think, to the condensate. Within the wet gas area, I think answering a prior question, you were talking about being comfortable flowing these wells on fairly open chokes. So trying to understand how the behavior changes in the wet gas window? Or how you, yes. If that made sense? ( Laughter )

Yes, so in the wet gas window you have higher reservoir pressure and you have a much lower dewpoint and it's just because it is drier, number one. But the phase interreaction between condensate and rich gas, you just get a much lower dewpoint in the rich gas or wet gas area. So you have a much larger delta P. And furthermore, when you start approaching the dewpoint or you get below the dewpoint, there are far fewer of the large molecules, the condensate, just because it isn't as rich gas to fallout within the formation.

So you do not hit nearly the blockage. So we don't think pressure maintenance is a big issue in the rich gas portion of the trend, but it is on the condensate side. So -- so --

Got it. Okay.

Does that the answer your question, Subash?

Yes, yes, absolutely. One quick one for me, the split quarter fracs, what is your sort of current -- I think you are using a mix of things and if that frac design or completion design was evolving?

Yes. Fracking, of course, has been around 30 years. Well actually around quite a bit more than that, since the late 1940s. But in our careers it's a been around 30-plus years. I don't think you ever reach perfection in your frac design, but there is major evolutions.

So 1980s and 1990s was much more of a gel frac era, and now it has gone to slick water. We continually adjust, but we have our favorites formulas or recipes that we do both in the Utica and the Marcellus.

In general, we are much more slick water, but we tail in with gel. So, as we get into higher and higher sand concentrations within a stage, then we start putting in guar gel. And the reason for that is we do have limits on what we like to pump in terms of volume. And so we use gel in the tail end in order to move the sand up into the fractures and away from the formation. Gel just has greater viscosity and carrying capacity. We're early slick water, late gel in each frac, I guess would be the summary.

Got it. Thanks a lot.

Thank you, Subash.

Holly Stewart, Howard Weil.

Question: you mentioned your move into the highly rich/condensate and then the highly rich gas area of the Utica, compared to your activity in the condensate area. So can you talk about your rig allocation for the remainder of the year, and then maybe into 2015 for those three areas?

Right now we are running five rigs in the Utica, five big rigs. As we said earlier, we started a little bit more on the condensate side. That was some of our earliest acreage was a little more mature, meaning it was blocked up, and we could permit there and put the pads together and drill there. So our drilling started out a little bit earlier there, and we started building infrastructure there.

Now as our planners on geology and engineering and land put it together, we have more and more pads that are just slightly east in the rich gas area. So today we're -- we are running one of those five rigs in the condensate area and four of those rigs in the rich gas area. And that is the proportion that we will stay at through this year. As we add more rigs, it will still be on the order of 20% in the condensate and 80% in the rich gas.

Very helpful thank you. Given your activity in the Utica, how are you thinking about takeaway in the play as just the Utica evolves in general?

Well, we think similar to our comments just overall for Appalachia that the Utica is going to be quite prolific both dry and rich. And there is going to be when wells can make 20 million or 30 million a day, and each company has lots of locations, the volume can build pretty quickly. And it is an area that does not have that many longhaul pipes. Some are crisscross it, but quite a few more are being proposed.

So producers like ourselves and others are just looking at all of the different projects, whether it is reversal such as we have done with [racks]. First is was back haul, then reversal and now possible new builds. And so -- we do think the Utica both rich and dry as it goes down dip into eastern Ohio and Western Pennsylvania and West Virginia is going to be very prolific. So we have the same view that it is going to be underpiped and it is important to make sure that you have firm takeaway.

I appreciate the color, thanks, guys.

Adam Michael, Miller Tabak.

Good morning guys. I noticed on this slide 28 that you have a new bullet point. In Q1 you generated EBITDA of about $25 million from the gathering systems and the water infrastructure in place. I am wondering how much of that, was that 100% Antero, or are you taking any third party into the system?

That is virtually all Antero. We are starting to see some water revenues from moving waters to some third parties, but it's close to 100% Antero.

Okay. As the dry gas window continues to emerge in West Virginia, how much overlap is the Marcellus infrastructure -- how much overlap is there with Marcellus infrastructure and the Utica dry gas kind of emerging window in northwest West Virginia?

There will definitely in the sense -- there will be overlap. The corridors will be -- probably the same. But remember the western side of the Marcellus is rich -- very rich gas. And so that's the gathering of the main lines through there will be rich gas gathering to get to processing plants, whereas the Utica will be dry. And so one is not going to mix those two gas streams into the same gathering infrastructure.

But beyond that there will be bullet lines that will be residue gas and coming out of plants. And dry gas lines, and so those can be used for the same gas more or less. But wet and dry gathering will not mix, but, as I say can put two pipes in about the same ditch or the same right of away. There will be overlaps that way, not only midstream but just surface access between roads and pads and water systems. And containment frac sourcing ponds and so on; that will work for both places.

Okay. That is helpful. Thank you, guys.

Thank you.

Jeoffrey Lambujon, Tudor Pickering and Holt

Real quick on the density in the Utica. You mentioned 660 foot spacing in the Marcellus. Could you remind me what your current down spacing assumption is across your Utica?

All of our numbers that we site for a number of locations and, cataloging the resources all on 1000 foot inter-lateral distance. We are piloting right now both on 750 foot and 500 foot inter-lateral distance. But all the numbers that we talk about our 1000 foot. And so we are doing these pilots. It will probably take a year or more just as we build up our type curves and be able to compare and contrast. It will take at least a year to figure out what the right density is. But in that range.

Okay and on your type curves, are there any updates to your thoughts there? It sounds like it's early, but are you seeing any benefits from the pressure maintenance you are conducting in the condensate window?

Too soon to tell. Just -- only have been doing it for -- 60 days or less. So, too soon to tell.

Okay just one last one for me, I know this has been hit on a lot. On the midstream I know you have been ahead of constraints. It sounds like you feel comfortable with the capacity you've locked in so far. Could you talk a bit more about how you see that ramping over time as you accelerate in the play?

Well on the Antero midstream infrastructure, yes, we try to stay ahead of the production and the drilling. I think we are doing that. We don't see a lot of constraints today really. We have maybe two wells waiting on pipe in the Marcellus. So it is pretty free-flowing, good line pressures and such.

On the takeaway, on the gas side you've seen us ramp up to now 2.6 BCF a day, and we continue to look at all of the projects. And there's a real advantage there to being the early mover. You end up with the -- we think the lowest-cost takeaway. We think we've done a good job with that. There is a slide in the presentation on that. And now we have started to focus on the liquids side a bit, as you've seen with supporting Mariner East II which is still in open season. But we were confident that project will go forward, as well as we will be looking at Y-grade pipeline projects, too, to Belleview, so that is kind of the next area of focus.

Thank you.

Thanks very much.

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

Thanks, everyone, for joining us today. If you have any follow-up questions, please feel free to contact us. Thanks again.

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