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Rice Energy Inc. (NYSE:RICE)

Q2 2014 Results Earnings Conference Call

August 11, 2014 10:00 AM ET

Executives

Julie Danvers - Director of Investor Relations

Daniel Rice IV - Chief Executive Officer

Grayson Lisenby - Chief Financial Officer

Rob Wingo - VP of Midstream and Marketing

Analysts

Holly Steward - Howard Weil

Cameron Horwitz - U.S. Capital Advisors

Leo Mariani - RBC

Ipsit Mohanty - GMP Securities

Neal Dingman - SunTrust

Tim Rezvan - Sterne Agee

Charles Meade - Johnson Rice

Gordon Douthat - Wells Fargo

Jeffrey Connolly - Mizuho Securities

Ben Wyatt - Stephens

Operator

Welcome and thank you for standing by. And good morning and welcome to Rice Energy’s Second Quarter 2014 Earnings Conference Call. At this time, all participants are in a listen-only mode. There will be a question-and-answer session following the prepared remarks. (Operator Instructions) This call is being recorded.

I'll now turn the meeting over to Julie Danvers, Director of Investor Relations to cover a few housekeeping items. Please go ahead, Julie.

Julie Danvers

Good morning, ladies and gentlemen. Thank you for joining Rice Energy’s second quarter conference call. Before we start, I'd like to remind you that our remarks including the answers to your questions contain forward-looking statements and we refer you to our earnings release for a detailed discussion of these forward-looking statements and the associated risks.

In addition, during this call we make reference to certain non-GAAP financial measures reconciliations to applicable GAAP measures can be found in our earnings release. As you've seen this morning, we filed our 10-K and our amended our S-1Q. This morning and post then updated investor presentation on our website, we'll be participating in the Barclays Energy Conference in September and we look forward to seeing you in New York.

I'll now turn the call over to Daniel Rice IV, Chief Executive Officer of Rice Energy.

Daniel Rice IV

Thanks Julie and thanks everybody for joining us today. Joining me from our side for our prepared remarks is Grayson Lisenby, our Chief Financial Officer and available at the end of this call to answer any questions you may have are Toby Rice, our President and COO; Derek Rice, our Vice President of Exploration; Rob Wingo, our Vice President of Midstream and Marketing and Jamie Rogers, our Vice President and Chief Accounting and Administrative Officer.

We will be referencing the investor presentation we posted this morning to our website, so I would encourage each of you all to have that open if possible. We are pleased to share with you today results for our first six months as a public company and share what gets us excited and drive this everyday. The biggest drive of our engagement and excitement is to creation of long-term value for our shareholders which at the end of the day is our number one goal.

We'll begin by covering safety and we'll be the first technology safety doesn't keep the lights on, but it's the foundation of Rice Energy's operational excellence. For the second quarter of 2014 and dating back to the formation of this company, we continued our streak zero recordable incidents and lost time incidents for all Rice employees. Our competitive spirit drives us to be the best in each capacity including safety and we're intent of become the safest operator in North America. And with technology as our tool, we’re demonstrating this can be accomplished without comprising our operating efficiency.

One of the most important factors creating this long term value for our shareholders is creating visibility and we do that by forecasting the capital landscape, people, asset, liquidity et cetera and in most instances decisions need to be made today in order to protect or grow our long-term value potential.

We have a lot of asset derived value that we’re trying to protect and at the same time we have a lot of value opportunities to create. These assets include our industry leading acreage position in the dry gas course of the Marcellus and Utica which now stands at over 125,000 net acres. And from this acreage position, we believe we are developing our assets in an inappropriate pace which allows us to conduct sufficient science to ensure we’re doing things the best way for long-term value creation.

As you’ve seen from this morning’s announcement, our first Utica well, the Bigfoot 9H is shaping up to be one of the best in Utica and gives us fantastic confidence and visibility towards value potential of our Utica position. Once considered the liability for producers, our firm transportation is clearly becoming an asset and differentiator for our company. We’ve accumulated a little over Bcf a day of firm capacity with over 70% delivered the markets outside of Appalachia including over 300 million a day of Gulf Coast FT starting in the fourth quarter of this year. And our midstream assets are becoming very complementary to our acreage development and it’s a beautiful thing with success and value creation from one business unit can do the same to another business unit. And that's the symbiotic relationship we have between our upstream and midstream groups.

It’s probably worth mentioning that by controlling some of the most prospective shale in North America, in order to extract the highest value and cash flow, having the right team is critical. And protecting value and creating value requires hard work and people. Internally, we have a pretty detailed plan of how we’re going to get to a Bcf a day of net production and the people we need to get there as cost effectively as possible. And the most cost effective way from our perspective is to bring those resources in-house and get them doing things the Rice way.

When we went public, we had approximately 145 employees and the goal was to add 70 to 80 people in specific functions in the 12 months to 18 months following IPO. It’s a pretty competitive market for talented people and that’s particularly true here in Appalachia. And our mentality has always been that when you find the right person, it's better to hire them before you absolutely need them. And we’ve been fortunate to finding out 75 really talented people since IPO and we’re now at 220 full time employees today.

And as all you know, we look at things in really two modes, the first being reserve recovery optimization mode and the second being development cost reduction mode. In the Marcellus, we are pretty close to maximizing our recoveries, we think. And we're now turning our attention to part two, the cost reduction mode. And we think the Utica will be 12 months behind the Marcellus on the reserve optimization mode. So by the middle of next year, both the Marcellus and Utica teams will be maximizing the recoveries and will be in cost reduction mode to really choose our return on investment.

So, to reduce our costs, we’re looking at ways that we can do the current process faster and/or do it differently. And to do that, we're adding people in those roles that we’re confident will drive our cost down over time.

So, yes, it’s a near-term increase to our G&A, but I think if you look at the capacities in which we’re adding people, a lot of these folks are working to reduce our operational cost and keep our production running at greater than 99% up time, just like we averaged for the first six months of this year.

And it's probably worth mentioning that of the 75 new hires since IPO, 25 were placed in our midstream group. And if we had decided to sell our midstream assets, we likely wouldn't have made those hires. But as you all saw from our announcement this morning, we’re going to continue to manage and build up this midstream for a very long time.

So, we've been quietly staffing up on the midstream front to stay ahead of this continued buildout that we’ll control and obviously a decent portion of our run rate G&A is attributable to our midstream team. So when we look at couple of years out where we think production will be relative to our upstream G&A, our production is expected to grow at a much faster rate than our G&A and we’re pretty confident we will be able to drive G&A below $0.35 per Mcf by the end of 2015 and we think because of our flat organizational structure and technology’s role specifically in enabling us to automate a lot of time consuming processes, we have a goal of driving G&A below $0.25 per Mcf by 2018.

One area where I think our team has been able to add a lot of value is on land. Given how competitive it is for core acreage these days I think we’ve done an outstanding job adding to our positions in both the quarters of the Marcellus and Utica shales and we’ve already achieved our 2014 goal of adding 30,000 to 40,000 net acres and more than halfway to our two year goal of adding 60,000 acres since IPO.

In the second quarter we cleared title and closed on nearly 14,000 net acres, in addition we closed our previously announced Greene County acquisition which adds 22,000 net acres to our leasehold position. So to quickly recap this fantastic asset that we just acquired, the 22,000 net leasehold acres is 100% operated and includes a 152 rift, 190 unrift Marcellus locations with an average 7,000 foot lateral per location. It also comes with 7 PDP wells that are producing around 20 million a day net and 5 PD&P Marcellus wells. In order to preserve the drilling locations offset to lease 5 PD&P wells we’re going to keep these five wells behind until we can drill and complete the remaining offset wells and then turn in new and old wells into sales simultaneously. It sounds kind of funky but believe me that the Marcellus is pretty sensitive to pressure integrity. And this acreage is on trend to some of our best Rice operated Marcellus wells that were drilled less than a few miles away. So from a geological and operational perspective, we have a pretty handle on the value potential that the area is developed the right way which we have quantified on page 10 of our most recent presentation on our website. So excluding approximately $75 million for approved developed wells for a $250 million net acquisition cost, we have added approximately 2 Tcf of net potential reserves and $1 billion of value potential in the Marcellus.

We are expecting development cost to be in the $0.60 to $0.80 per Mcf range so all in S&D for this deal should under $1. Now the Marcellus was the primary focus of the acquisition in the basis of our purchased price economics, but there is more. Across our 22,000 acres that we acquired we have the Utica rights on approximately 14,000 acres which translates into approximately 140 net unrisk Utica locations.

Now what we originally hypothesized for planting our flag in Belmont County and have recently validated with the Big Foot well is that the porosity in the Point Pleasant is the primary driver of production in the Utica shale. And in our latest Investor presentation which we posted into our website this morning, we have a really nice West to East cross section on slide 11 depicting the porosity in the Point Pleasant section of the Utica shale. The porosity we are seeing in Belmont remains pretty constant heading into Central Greene County, Pennsylvania and the biggest difference between these two areas is it gets considerably deeper as we move east. So we are expecting the Utica to be at approximately 12,000 feet deep in Western Greene County but what we know about the production potential in Belmont County from our Bigfoot 9H, there is a lot of recoverable gas in the Southern part of the Utica play.

So we like the Utica potential over here and we are going to drill our first Utica Pennsylvania well in the first half of 2015 on this recently acquired Western Greene acreage. Now it’s probably too early to put on the well cost to a reserve figure in this area, but we will share more info at the appropriate time.

In addition to the Marcellus and Utica rights, we also acquired the rights to the Geneseo /Upper Devonian on approximately 18,500 acres which translates into approximately 135 net on ridge Geneseo locations. As you all know, we have three producing Geneseo wells in Washington County that have been online for several years now. And these are recovering about 1 to 1.5 Bcf per thousand foot of lateral. And the nice thing is that Geneseo of flash Upper Devonian formation looks better geologically speaking here in Western Greene than it does in Central Washington County.

So we recognize that we haven’t really profiled our company's they could have having step to potential, but this Western Greene acquisition in particularly yields approximately 54,000 net acres worth of drilling locations across three formations that we've been developing with really good success. So we're pretty excited about this acquisition in incorporating this acreage into our 2015 drilling program.

So to summarize lands pro forma for the recently closed Western Greene County acquisition, but ignoring this text play concept, we've added 37,000 net acres through 630 and total leasehold is are approximately 127,000 net acres which is an up 40% increase since IPO. We have continued to add core echogenic key focus areas of Washington and Greene Counties in Pennsylvania and Belmont County in Ohio. And we expect to exit the year around 140,000 net acres.

So let's turn our attention to operations and we'll start in the Marcellus where we're continuing to execute a coverage plan. During the second quarter, we brought online 10 Marcellus wells with an average lateral length of approximately 8,400 feet. As previously mentioned on our first quarter call in May, at the end of April, we turned outlined a four well pad and a two well pad with average lateral lengths of 9,100 feet and 6,000 feet respectively. In May, we turned online a four well pad with an average lateral of 9,000 feet. And these 10 wells produced a combined 132 million a day gross for the month of June on our restricted choke program.

For the second quarter, our net production Pennsylvania averaged 240 million a day and we averaged almost 280 million a day for the month of June, which is just about the middle of our updated full year guidance range. But as discussed last quarter, we're now experiencing the downtime associated with long-haul mining operations occurring beneath our Greene County sales meter. So, we currently have 50 million a day gross, 41 million net that was shut in at the end of July and we expect this to last for an additional six to 12 weeks from today. So, as a result of this anticipated maintenance we expect our third quarter production to be 5% to 10% higher than second quarter's 241 million a day net production.

So, year-to-date we have turned online 14 Marcellus wells with an average lateral of 7,950 feet and in the second half of 2014 we expect to turn online 22 net Marcellus wells with an average lateral of approximately 7,000 feet and four Utica wells with an average lateral of 7,900 feet and 18 of these 26 wells are expected to be turned into sales in the fourth quarter and therefore we're expecting a fairly significant production ramp in the fourth quarter.

In our presentation posted to website this morning we tightened our annual guidance range to 260 million to 290 million a day with the benefit of greater visibility of the remaining two quarters for the year in relating completions of pipeline connection timing.

I think what's important to note is the downward revision in the range isn't related to well performance but it's just related to timing of a couple pads in the completions phase that were previously budgeted to come online in November December that are now scheduled to come online 30 days later.

And what we’re talking about seven and nine well pads, a 30 day delay in turning online a 100 million a day pad can have a pretty meaningful impact on calendar year average. But in connection with these adjustments our drilling completion and budget was decreased $570 million for the year.

So, we have really good hand on the production profile for each of these wells but just the slight changes in timing of when they come online and the spending of the completion capital. So, right now we have 51 Marcellus wells and three Upper Devonian wells producing into sales and that equates approximately 340,000 horizontal feet.

So these 54 wells are producing approximately $350 million a day growth before the temporary long well curtailment happens and we'll get back to that well in a few weeks excluding any new wells. And I think what gets us excited is we have 51 Marcellus wells in progress today with approximately 360,000 horizontal feet and 22 of these 51 wells will be turned to sales in the back half of 2014 and each are in the completion phase, so either being fracked, plus drilled out or finalizing time to our midstream system. And then most of the remaining 29 wells in progress are in various stages of drilling or waiting on completion and will be turned into sales in 2015.

So, we are planning for two horizontal rigs and two tophole rigs in Pennsylvania in 2015 and all four rigs are locked up under term contracts. So, as we look out into 2015, majority of 2015 production growth is in progress today and so early when I talked about the step up and headcount today to support future production a lot of these people are supporting these ongoing operations for wells that will only begin producing in 2015 and in most cases will produce most meaningfully in 2016.

So, keeping with Pennsylvania, on the midstream side of things, we're about halfway to constructing our 30 inch header system from Washington County to Texas Eastern pipeline in Greene County.

We hold 270,000 dekatherms a day firm capacity on Texas Eastern with delivery to the Gulf Coast that’s scheduled to begin November 1, 2014 and that date has always been our time bogie for completion and commissioning of this pipeline. And right now we are tracking to mid-October in service date, so we're a little bit ahead of schedule.

So, this pipeline will relieve any potential capacity constraints resulting from the new production we are planning to bring online in the fourth quarter and it will deliver a substantial portion of our production to Gulf Coast markets where we're getting a $1 to $1.25 higher price than if we just sold it into the spot market on TETCO-M2 or Dominion South Point here in Appalachia.

As we may have seen from this morning's announcement, we intend to form an MLP of our midstream assets initially, we will include just our Pennsylvania assets which includes our gathering of water sourcing and distribution assets. Including in the anticipated IPO will be the 3 Bcf a day gathering system and 5 million gallon a day water transportation assets. We would expect to complete our IPO in the first half of 2015. And we should mention the SEC imposes restrictions on communications when a securities offering is in process. And therefore we’re limited in the information we can share with you all this time and we will be unable to answer questions about future plans and expectations for the MLP on this call. As we move through the offering process towards an IPO, we will continue to be able to provide information limited to what is included in the registration statement with the SEC.

Turning our attention to the Utica, as we announced in early June, we successfully completed our first Utica well the Bigfoot 9H that tested at a stabilized rate of 42 million a day at 5,850 psi with 1,085 to 1,090 Btu per Scf.

So we turned the well into sales on June 23rd, and it’s been on line for roughly 50 days now on our restricted choke program and around 14 million per day which equates to around 2 million per 1,000 foot a lateral. The reservoir pressures are looking much better than we anticipated which allows us to produce at a higher flow rate. We have a slide in our most recent presentation that visually explains what I am going to walk you through and it may be really helpful for you to turn to page 16 of this presentation and we can walk through this together.

So, on this Bigfoot 9H, we’re watching two things very closely, we’re watching rate and we’re watching pressure. And under our restricted choke program, we know that production will be flat for a period of time and in our economic and budget cases, we had modeled flat production for approximately six months compared to the four to five months of empirical flat production that we’ve seen in the Marcellus but we thought these six months will be justified by the deeper depths and higher resulting pressures in the Utica.

So, on our restricted choke program with the stable flow rate, you’ll actually experience a linear decline in flowing casing pressures or wellhead pressure as it’s named on the slide. And this is what we have seen in our typical Marcellus well. And as long as your wellhead pressure is greater than your line pressure, the flow rate will remain flat. But as your wellhead pressure approaches line rate, your flow rate will begin to drop. And a line pressure in this area is approximately 700 pounds more or less. And so we thought this would be a six-month decline from initial wellhead pressures to this line pressure. And with a simple linear equation, we can determine with a pretty high degree of certainly how many days the well can produce on a restricted choke program before it hits line pressure and begins its normal exponential decline.

So what’s better about this Bigfoot 9H is really two things. First, we are starting with a much higher than expected flowing casing pressures of approximately 6,000 psi compared to 4,000 psi in the Marcellus; and second and more importantly, our wellhead pressure decline is only 12.5 psi per day for the first 50 days compared to the 25 psi to 30 psi decline that we had anticipated and are seeing in the Marcellus. So what this means is that instead of this well starting to decline six months from IP, it’s looking like it may not begin its decline until 12 months from IP.

Now something funky may happen in the reservoir that could throw this off to its linear decline and on slide 16, we have tried to outline that if the daily pressure declines double from here, than the well would decline after eight months. But we think it’s unlikely and we haven’t seen it before in the Marcellus. So we think it’s more realistic that this well produces 14 million a day for 12 to 14 months at its current pressure decline before it hits line pressure and begins its normal production decline.

So there is a couple of things worth mentioning here. First, we are not revising up EURs just yet because we don’t know what the flow rate decline will look like once it hits line rate and although there are Utica wells that have been online for a while and the declines haven’t been that severe but for conservative purposes, we are staying put with our EUR of 2.25 Bcf per 1,000 foot lateral for this dry gas area. So, we will continue monitoring this well closely and we'll adjust our type curves, once we have a couple of more wells on line. Second, regardless of what the ultimate EUR is, we could be recovering nearly 6 Bcf in the first 14 months. So, in development mode, we could see these wells paying out in under a year and before these wells even begin their exponential decline, which is absolutely fantastic for the balance sheet and recycling this cash flow.

Third, there is not a real incentive to radically change our well design, so we’re going to be keeping the drilling completion design pretty constant for the remainder of our 2014 Utica wells, but we’ll be spending a lot more time figuring out the optimal well spacing. And that leads really into this fourth point, which is just given this well’s location in Belmont County, which is in the hard of our Utica position, we believe this well is very indicative of the reservoir quality across the rest of our Belmont County acreage position. And to remind everyone, we have 50,000 net acres in central Belmont County.

And this ultimately leads to this last point, which is the estimated porosity and permeability in the formation, we maybe look to produce our net resource potential with fewer wells. So better single-well economics and lower full field development costs. The Blue Thunder wells, which we’re currently completing 500 foot spacing, should results in some overlap of recoverable reserves. But this means the portion of the production is in acceleration of production through two wells instead of one, so it becomes a time value and PV-10 decision. So that's the beauty of our science program and why we're doing 500 foot test this early in the game. We're going to figure out the spacing because we now understand there is a lot of gas down there and the key will be determining the proper spacing to optimize the NAV of this entire field.

So as I just mentioned, we're in the process of completing our Blue Thunder wells which are two 9,000 foot laterals spaced 500 feet apart. As of this morning, we have another day or two of the frac and we should have the plugs drilled out and have these wells into sales in September. We’re not conducting anymore fluid tests this year because when you're flaring north of 40 million a day, it can become a safety hazard and it’s not worth the risk to us plus at the end of the day production and pressure data is what we are really interested in and we want to get these wells into sales to start watching this data and we look forward to updating you Blue Thunder data on our third quarter call.

So in Belmont County we're currently running one horizontal rig and two top-hole rigs and we expect delivery of our second horizontal rig in the fourth quarter of this year. We're currently drilling the second of two planned laterals on the Gold Digger pad and right next to it we are on the Son of a Digger pad drilling the top hole sections of three planned laterals. These wells have lateral rigs of 9,000 feet and both of these pads will be completed simultaneously and we expect to bring them online in first quarter of 2015.

You'll notice we received the benefit of oil and NGL production for the first time this quarter due to non-operating interest in a couple of Gulfport Blue Thunder, Son of a Digger and Gold Digger are all connected to our gathering system which is which is currently tied into Dominion East Ohio.

We're beginning the construction of our 1.5 Bcf a day header system that will connect our Belmont County acreage with Interconnect on Texas Eastern pipeline and Rockies Express pipeline on which we hold combined FT capacity of 445,000 dekatherms a day by June 2015 and over 525,000 dekatherms a day by November of 2015.

We anticipate in service of the system by summer of 2015, so just in time to begin moving our Utica gas to premium markets on Gulf Coast, Mish-Con and Mid Continent. We're also building other 5 million gallon per day water system from Ohio River to service our completion needs in Belmont County which we expect to be fully operational next year.

Also in Ohio we've entered into a letter of intent of with Gulfport Energy to provide midstream services for a predominately dry gas area covering approximately 60% of Gulf Coast acreage within our joint venture AMI. This agreement provides the greater operational efficiencies by using a single gathering system, it helps to ensure deliver ability of our gas and were honored that Gulfport would entrust us with a responsibility because we understand just how crucial it is to have pipelines connected to the pads before the wells are ready to flow.

So, lastly, I want to give a huge thanks to all of our technical teams who strive daily to deliver these exceptional operational results with safety as our top priority.

Next Grey will summarize our financial results for the quarter.

Grayson Lisenby

Thanks Danny. During the second quarter of 2014, our net production averaged 241 million per day, which was a 15% increase from the first quarter of 2014 and an 84% of our pro forma second quarter 2013 production.

Our production mix for the second quarter was on 100% natural gas. We generated approximately $50.4 million of EBITDAX and adjusted net income of $4 million or $0.03 per diluted share.

Our averaged realized price before the impact of hedges was $4.12 per Mcf. This includes our average basis differential for the quarter of negative $0.74, based on average NYMEX Henry Hub price of $4.58 per MMBtu.

We received a Btu uplift of approximately 5% to account for the heat content of gas which was around $0.19 and we also included $0.09 of other revenue in our realized price, which was some unused firm transportation capacity that we will able to sell to third parties. Including the effect of our hedges, our average realized price was $3.58 per Mcf for the quarter.

On the cost side, lease operating expense has continue to turn balance our team has focused on scale and efficiencies and have moved down to $0.30 per Mcf. Gathering and transportation expense was $0.42 per Mcf, production taxes and impact fees were $0.04 per Mcf.

Our cash production cost, which includes the three costs mentioned above LOEs, gathering and transportation and production taxes and impact fees were $0.76 per Mcf. G&A was $14.8 million for the quarter.

Let me expand a bit on what we’re seeing from a pricing perspective and I note that we’ve added quite a bit of detail in our earnings release regarding what it looks like for the rest of the year and for 2015 as well.

In the second quarter about two thirds of our volumes were sold into TETCO-M2 and Dominion South Point which created on an average a negative of a $1.10. The remaining one-third of our second quarter volumes were sold into TECO which was only a negative $0.07 during the quarter. We expect our average Q2 differential of negative $0.74 to widen to negative $0.85 to $0.90 during the third quarter due to seasonal weaker demand in a capacity constrained market.

However, as we’ve laid out in our news release our based exposure mix will shift significantly beginning in November 2014 we’ll have 278,000 decatherms per day from transportation on TETCO Team South and additional 50 million per day on Columbia’s west side expansion that will access the Gulf Coast markets and mitigate our exposure to volative Appalachian pricing. As a result, we would expect to see differentials to narrow in the fourth quarter than the average of negative $0.55 to $0.60 for the full year at an estimated average of $0.55 in the full year of 2014.

Looking ahead to 2015, we currently had a firm transportation and firm sales portfolio of approximately 810,000 dth/d with approximately two thirds of our volumes being transported to markets outside of the more volatile M2 and Dominion South basis in Appalachia. Our firm transportation and firm sales agreements increased to 920,000 dth/d in 2016. Additionally, we recently acquired a 100 million per day ET River with delivery to Dawn in Ontario, Canada with an expected in service state of July 2017.

In summary the long-term value implications of near-term Appalachian by basis pricing effect each company differently. And the current Appalachian differentials, should they persist for the next several years will have a much smaller impact on companies who are proactive in that to secure transportation to premium markets outside of basin. And we firmly believe that we are in the camps that we have mitigated the basis and both the takeaway risk as well to our growth plans with the 100% of our expected 2015 production covered by firm transportation and firm sales with nearly two-thirds of our expected production being sold outside the more volatile Appalachian basis pricing.

Quickly glancing our balance sheet liquidity. We exited the second quarter with $901 million of total debt and 471 million of cash on hand. Our cash on hand combined with 313 million of availability under our revolving credit facility provided a liquidity position of 785 million at the end of the second quarter and 515 million including our Chesapeake acquisition which closed on August 1st.

We continue to maintain the active hedging program to protect our cash flows used to support our capital investment. We are well positioned to the second half of 2014 with 224 million per day head weighted average $4.06/MMBtu representing 68% of our remaining estimated production based on the midpoint of guidance.

In addition we have layered 2015 hedges and currently have 231 million per day hedged at a weighted average floor of $4.04 for calendar 2015. I will wrap up my comments by mentioning again our pro-forma updated guidance and just affirm what Dan mentioned earlier in his comments. Our production range has narrowed slightly as we had a couple of pads shift from December to January but our wells continue to perform inline or above our expectations.

Our upwardly revised cash G&A for the Europe 60 million to 65 million and the reflection of our goal to stay ahead of our expected production growth and over our staffing and resource prospective for next few years, and we believe we have the assets team in place to be 1 Bcf per day of non-production over the next few years. On the LOE side, we have revised on our LOE '13 has done a great job focusing on increased fuel efficiency.

Thanks very much and right now I'll turn the call back over to the operator to compile Q&A.

Question-and-Answer Session

Operator

Thank you. We'll now begin the question-and-answer session. (Operator Instructions). And our first question comes from Ms. Holly Steward of Howard Weil. Your line is open.

Holly Steward - Howard Weil

Good morning, gentlemen, Julie. First question and I appreciate you can talk much about MLP at this point. But can you just maybe give us some clarity on, I understand the Pennsylvania gathering water will be in MLP. The Belmont system that remains, you have a current system employees now and then 1.5 Bcf a day of gathering expected could you kind walk us through how those two I guess bridged together and then the AMI with Gulfport it looks like in your slide your some office and dedicated acreage to EPT in range. So just maybe help us understand the remaining assets that will be at the sea core?

Rob Wingo

Sure, this is Rob Wingo. Pennsylvania and Ohio operated completely independent systems, they're not connected in any way. Pennsylvania is mostly built out except for the connections to Pepco which will have done by the end of this year. The Ohio System, a portion of that has built but most of that is under construction and will be fully in service by middle of next year. We currently anticipate the gas and the water to be in the initial assets of the MLP and the Ohio dropdown will also include the gas and the water.

For the dedicated acreage, the EQT, Antero and Range dedications were included as part of the M3 acquisition and the Gulfport agreement is still under negotiation that we have signed in Hawaii but we have not executed definitive dots on that yet.

Holly Steward - Howard Weil

Okay, that's helpful. And then maybe just kind of thought process around big projects moving forward on the midstream title those be done at, initially at least I guess at the seacor levels MLP?

Daniel Rice IV

Yes. This is Dan. We don't necessarily have anything big on our radar just yet.

Holly Steward - Howard Weil

Okay. And then I guess final one from me. Dan you guys pointed out the 15,000 of Utica acreage in Greene County, maybe thoughts around initial testing, how will that change compared to either I guess the Utica and Ohio and just from drilling and completion standpoint?

Daniel Rice IV

Yes. I mean we're going through our engineering analysis right now. I mean it's going to be 4,000 5,000 feet deeper. And so things are certainly going to have to change from our current well design in the Utica for a much deeper test. That's where we're at today or we're still in the first inning of understanding exactly what the properties look like for well design so we'll provide more information hopefully on the next call.

Holly Steward - Howard Weil

Okay, great. Thanks guys.

Daniel Rice IV

Thanks Holly.

Operator

Our next question comes from Cameron Horwitz of U.S. Capital Advisors. Your line is open.

Cameron Horwitz - U.S. Capital Advisors

Hey guys, good morning.

Daniel Rice IV

Hey Cam.

Cameron Horwitz - U.S. Capital Advisors

With the performance of the Bigfoot well, obviously above your expectations, tracking it looks like maybe 15% or 20% above or you had modeled and that well just being a shorter lateral versus the program average, all the good things, I guess can you just talk about how that's feeding into and potentially altering your strategy on the midstream and takeaway side?

Daniel Rice IV

This is Dan. I mean, I don't think it necessarily changes it, I mean going in we have an expectation that the Utica was going to be really good and when we start to design the system, we learned the hard way, super, super early on in the company that, if you under size your pipe it's a whole lot more expensive to go back in and little bit or expanded. So when we designed the system, I mean if you the entire system we have will have 3.5, 4.5 Bcf a day of capacity between Pennsylvania and Ohio.

So, we're making sure that we're over sizing the system in the event that this stuff is a lot better than we expected it to be. And so long story short, we have oversized the pipe in Belmont County to accommodate our production.

Cameron Horwitz - U.S. Capital Advisors

Okay. And how more it is down the FTE side, I mean this is a performance there give you a little bit more comfort or even perhaps change the price threshold that you are willing to take out at PR?

Daniel Rice IV

No, not yet. I mean, I think we really need to see what the decline looks like after 12 or 14 months of flat production. Before we're going to be super comfortable making another 15 year to 20 year commitment on the FTPs.

Cameron Horwitz - U.S. Capital Advisors

Okay. I guess just sticking to that, my last question just in terms of the 16 time frame, is there anything out there in the market that you guys are looking at that that could potentially help you keep that percent of non-Appalachian exposure up or is everything pretty much spoken for at this point?

Daniel Rice IV

Yes. I mean any new project and you can see this in our signing up of down that starts from 2017, most new projects are going to be 2017, 2018 which is why Rob and our team were so aggressive in the past six months acquiring every bit of [FT] we could to start before that. So, we still feel like we’re in good shape. We’re 100% covered for ‘15 and 75% covered for ‘16 which is kind of our company policy. And you’ll always be able to flow some interpretively, we just don’t want to have too much exposed, and 75% is our goal. So we’re pretty well set for ‘16 and really just evaluating 17 projects and beyond.

Cameron Horwitz - U.S. Capital Advisors

Okay. And lastly from me, just on the cost efficiency side. Can you just talk about, obviously you’re making great strides in Marcellus on a per foot basis, can you talk about that in the Utica and kind of where you are now and I know early but potentially where you think that could move over time?

Daniel Rice IV

Yes. I mean as I’ve -- I think as we covered in the earnings release, we now have our two fit for purpose tophole rigs in the Utica. So these things are beefed up with the hook load to be able to set the 95 base casing, the intermediate casing, rate above the Utica. So that’s really helped us a lot. I mean I think at the end of the day what are you going to have is you’re going to have Utica vertical section costs that are going to be more expenses than the Marcellus. But what we’ve seen on the last couple laterals that we’ve drilled is we can get the horizontal sections drilled as cheaply as we can in the Marcellus. So it’s going to -- they’re obviously going to be a little bit more expensive in the Marcellus but we’re going to up the curve pretty darn fast we think.

Cameron Horwitz - U.S. Capital Advisors

Okay. And so I guess ultimately, can that do you think from a cost per foot basis that can be say 1,200, 1,300, 1,400, is that kind of the range?

Daniel Rice IV

Yes, I think that’s a really good range for us to be in, especially for averaging 8,000, 9,000 foot laterals over in the Utica.

Cameron Horwitz - U.S. Capital Advisors

Okay, great. Thanks a lot guys, I appreciate it.

Daniel Rice

Thanks [Kim].

Operator

And our next question comes from Leo Mariani of RBC. Your line is open.

Leo Mariani - RBC

Hey guys. Can you talk a little bit about acreage adds? I know you plan on continuing to add acreage between now and the rest of the year. Where you see most of that available; is it largely in Pennsylvania? Maybe you can just kind of talk about what’s there versus what you see in Ohio and then just curious if you guys are going to pick up anything in West Virginia?

Daniel Rice IV

Yes. I mean I think the split on the way we see for the rest of the year is about 70% in Pennsylvania, so Washington and Green counties, and the other 30% in Belmont. I mean it’s tied in all three areas. I mean they are not easy areas to lease and we have pretty good visibility on picking up the remaining 14,000 acres. But we haven’t really turned our attention outside of these three counties until we’ve fully exhausted those opportunities. So, we are not looking at West Virginia just yet.

Leo Mariani - RBC

Okay that’s helpful. And I guess with respect to the current midstream, trying to get a sense how much of the current throughput is third party versus Rice, and then maybe kind of any thoughts on how that could change as we get into next year?

Daniel Rice IV

Yes. That’s a really good question.

Unidentified Company Representative

We think by the end of the year, we’ll have about 20% that will be third party volumes through our gathering systems.

Leo Mariani - RBC

Okay. And I guess how is that going to flow through the financials? I guess this quarter I was a little surprised to not see any breakout for midstream, how does that kind of flow through?

Daniel Rice IV

Yes. That’s something we’ll look at probably more for next year. I mean we’ve said publicly that our third-party EBITDA for this year excluding Gulfport's around $7 million, so it's pretty small. And definitely we’ll look out breaking on 2015, maybe later in this year, but probably more like a 2015 event.

Leo Mariani - RBC

Okay. And I guess just in terms of the Bigfoot well, I guess early days on the performance, but I know you guys are not revising EUR at this point, but it diffidently sounds like it’s likely to go up here. And I guess is it safe on our end to kind of maybe think that it's probably pretty good chance to stuff at least 10%; can we get any kind of range on what that might do?

Daniel Rice IV

Yes. I mean I think we’d caution against revising up the EURs. But I think we're fine changing what the type curve profile looks like because at the end of the day Leo, I mean that's ultimately what drives IRR and drives value as the shape of the type curve and not necessarily what it produces over 50 years.

And so I think the biggest driver is the first 12 months to 18 months of production. So, if you get that right, you're going to get everything elsewhere in terms of the economics. And so I think, the reason why we're only showing 12 months to 18 months on slide 16 is because that’s what’s going to drive 60% to 70% of the economic. So, I think if we put this type of type curve to your model, you're going to be about half way there and what it could ultimately be at the end of the day, if that makes sense.

Leo Mariani - RBC

Okay. That’s helpful. Thanks guys.

Daniel Rice IV

Thanks Leo.

Operator

And our next question comes from Ipsit Mohanty of GMP Securities. Your line is open.

Ipsit Mohanty - GMP Securities

Hi, good morning guys. When would you think the Blue Thunder pad, the wells would be ready to give out some meaningful results in terms of interference or lack of each other?

Daniel Rice IV

Yes. I mean I think three months. I mean the nice thing is, is we’re going to be monitoring the pressures, right? And so pressures will obviously a leading indicator. So I think with 30 to 50 days of production in pressure history, we’ll be able to draw some pretty decent conclusions from those wells. So, we’ll certainly keep you guys posted on that on our November third quarter call.

Ipsit Mohanty - GMP Securities

Got you. Thank you. And then just speaking on to one of the questions asked before about base’s exposure, I see a slight shift from your prior presentations, a slight shift away from the Gulf Coast market in '15 but a more notable shift to the Appalachian market in ‘15; is that a -- if you could talk about what drives that? I mean is that also an indication of how you look at improving differentials in ‘16 and beyond?

Daniel Rice IV

Yes. That's a good question. I think the change that you’re talking about, this is obviously driven by what our total expected production is which we haven’t released but generally speaking, it's little bit higher than it was before. So, any incremental production will stay in Appalachia. So that's the reason for just the slight shift. It’s that we moved around FT project. Does that make sense?

Ipsit Mohanty - GMP Securities

Sure. And then if you could talk about like the broader sentimental where do you think differentials are headed going into ‘16 and beyond?

Daniel Rice IV

Yes. So, generally speaking, we look at the trips and don’t try and outsmart them, and they’re around a buck. If you look at 2015, they’re around a $1.10 for a Dominion South and they're trending down in out years as more projects come on line. But we think assuming $1 for ‘15 and around ‘16 is a reasonable assumption, especially given that about what the marginal cost of transportation is going to be on these more expensive FT projects. So, kind of beyond ‘15 and ‘16 your guess is probably as good as ours. And we underwrite our economics based on what the current markets look like.

Ipsit Mohanty - GMP Securities

Okay, it's good to know. And then on slide five of your presentation you talked about the Western Greene the historical gathering fee that is there IRR versus yours. Are we is that going to end anytime soon the word that the gathering fee, are there any contracts in place that are going to end and you’d probably get better IRRs, when you start drilling that?

Daniel Rice IV

Yes, so, no that acreage was dedicated to access midstreams. So there will always be a gathering fee. We have represented based on the historical rate, I think we're still discussing with them about what our agreement will look like. So we cannot comment on that at this time, but that’s based on the historical gathering agreement and it will always be dedicated. So those numbers could move around slightly based on where we settle on our agreement with them, but there will definitely always be a gathering fee given as dedicated to them.

Ipsit Mohanty - GMP Securities

And will there be an improvement in any gathering fee or something probably early days that you can share?

Daniel Rice IV

Yes, we can't comment, because it's still in discussion.

Ipsit Mohanty - GMP Securities

No worries. Thank you guys.

Daniel Rice IV

But we'll update you as soon as there is something to update on.

Ipsit Mohanty - GMP Securities

Appreciate it. Thanks.

Operator

And our next question comes from Neal Dingmann of SunTrust. Your line is open.

Neal Dingman - SunTrust

Hey, good morning guys. Let's say what's the plans I guess if the down spacing successful here in Utica. Your thoughts as far as how you would sort of proceed versus I guess maybe part of that, I guess discussion would be how much the acreage is HPV held that production there as well. So, maybe if you could tell me just how you guys look at that based on the results of this Blue Thunder?

Daniel Rice IV

Yes, I mean just taking a step back and looking at just the acreage in the expiration schedule. I mean were one of the benefits of being late to the game is yes, when expiration schedule that doesn't start to expire until after most of your peers. So when we start losing the stuff in 2012 and so we are going to reach primary term expiration until November of 2017 and then with five year extensions you’re looking at November of 2022.

So, time in just shortage of time is not driving our near-term operating decisions. So it’s really a non-factor in terms of the well spacing. But yes, I mean it’s a 500 foot test looks really good and just bring that value forward, certainly we’ll continue to evaluate over the course of this year and next year before really planting a flag and this is what our spacing program is going to look like for all of our pads.

Neal Dingman - SunTrust

Okay. And then obviously the Bigfoot looks like the pressure you walked through that slide was a little bit the results so far in the (inaudible) and you were expecting you thoughts as far as once you have that full inventory or the full midstream build out would you guys open those up a little bit more and let those flow a little bit harder and you’re just -- and your thoughts as far as I guess two things around that, you anticipate now maybe the higher pressure in most of your Utica acreage? And then if so, could you open these wells up a little bit more and once the mid the infrastructure let these flow a little bit harder?

Daniel Rice IV

Yes. So I’ll take this in a couple parts, the first one is yes, I mean we’re expecting the rest of acreage to look almost identical to what we’ve seen in the Bigfoot in terms of just the pressures. In terms of flowing these wells at a higher rate it’s not dictated by the midstream or downstream constraints, it’s just dictated by what we’re seeing for bottom hole pressures and the flowing casing prices on what the production looks like. So, we started with the 2 million a day and it’s looking fantastic. Can we open it up to 2 in the quarter, 2.5 maybe but it’s so early with just as far as well that we’re going to keep this well and have this is our test well and the next well will might change something and then we’ll be able to compare and contrast. But this well we’re going to keep it at 2 million a day and we’re just going to watch to see what it does over the next hopefully 12 months. So we’re pretty excited about everything and we’re excited for the next couple of wells so we can continue to evaluate some additional data.

Neal Dingman - SunTrust

Okay. And then just lastly Dan wondering when you look at I think I was looking at that slide 34 that shows the number of locations, you certainly have still quite a few more in the Marcellus and Utica, so just first few Utica wells demonstrate the returns possible are there thoughts of change in the drilling plans and drilling additional Utica wells versus Marcellus originally or would you just even continue still with the same Marcellus maybe just bump up the Utica?

Daniel Rice IV

Yes I mean I think we are super happy with the statuesque that we have going into ‘15 which is going to be two horizontal rigs running in the Marcellus and two horizontal rigs running in the Utica. I mean I think just given where capacity constraints are downstream constraints on FT it’s really important for us to have a pretty balanced approach between the two areas. I think in terms of just where IRR solo venture shake out Marcellus IRR sort of a little bit higher than where our base case Utica IRRs are for the dry gas area. And so I mean I think we are going to see the dry gas IRRs for the Utica come up pretty considerably and compete with the Marcellus but we are really not planning to make any changes this early on with drilling allocation between the two areas.

Neal Dingman - SunTrust

Okay. And the last one if I could for you or Grey just wondering I know you said down the line you consider adding more FT when the time is right your thoughts as far as what that would cost you today versus I know you guys have had the four sites to add a lot of, that have a lot of FT coming on just trying to get a sense if you would add that now how much is FT would cost versus if you would have to put new FT on today versus what you all already put going to have come on?

Daniel Rice IV

Yes good question, it cost over $1 which is why I don’t think you will see us committing to large expensive projects anywhere in the near-term we’re covered for starting in November very well covered for rest of 2014, 2015 and 2016. So we feel like we put ourselves in this position to where we don't have to be signing up for expensive projects, but we don't like either the term or the markets to deliver to them.

Neal Dingman - SunTrust

Perfect. Thanks Grey, thanks Dan again.

Daniel Rice IV

Thanks Neal.

Operator

Our next question comes from Tim Rezvan of Sterne Agee. Your line is open.

Tim Rezvan - Sterne Agee

Hi good morning folks. I wanted to drill down a bit on your comments on the Pennsylvania Utica, it sounds like your thought process has evolved a bit in recent months, we know obviously the formation’s depth it creates some pessimism on kind of how much gas will be in place. What have you seen or heard in the last few months to get you confident to talk to the market about this?

Daniel Rice IV

Yes. There is kind of two things, I mean one was we needed to drill and complete our first Utica well. So we did that in Ohio and it's looking fantastic and those properties continue over to Pennsylvania and the second one was we acquired a 22,000 acres position rate on the West Virginia border that's probably that most highly prospective in Southwestern Pennsylvania for the Utica. So that's going to work, that's the best area that is going to work and so that's ultimately where we're going to drill our first Utica well over there Tim. I mean we haven't come on said, we have Utica potential across all of this acreage and that’s the cross our 75,000 acres in Pennsylvania, we're really just talking about these 14,000 acres in the Southwestern corner right on the West Virginia border. So we're talking a pretty methodical approach we're going to test this stuff and then we'll start evaluating the stuff further East in the Alpha shale and then ultimately up in Washington.

Tim Rezvan - Sterne Agee

Okay, thanks for that color. And then on just quickly on your rig activity now you have horizontal I guess you're moving to two horizontal and two spotter rig program in both parts to the pay. How do you think about, how many wells that can give you in a year if you look out to '15 or in hypothetical development mode scenario?

Daniel Rice IV

Right now in the Marcellus each horizontal rig so we have paired the top hole rig with the horizontal rig. So just thinking about in terms of the horizontal rigs, each horizontal rig can drill around 25 wells per year. And then the Utica, I mean the key thing with that whole top hole program that we've been doing is making sure that we can ahead in top holes because as I said earlier in of the other comments, we can get these lateral sections done just as quickly as we can in Pennsylvania. And so, assuming that we can get the productivity on the top hole side in the Utica to where the Marcellus is, you're going to see us being able to drill 20 to 25 lateral sections with each horizontal rig in the Utica just like we are in the Marcellus. So, we're getting there, just governor of Ohio lateral sections is going to be how quick we can get top hole sections drilled.

Tim Rezvan - Sterne Agee

Okay. Thank you.

Daniel Rice IV

Yes.

Operator

And our next question comes from Charles Meade of Johnson Rice Your line is open.

Charles Meade - Johnson Rice

Good morning to everybody. I'd like to ask question about your 2014 guidance and kind of what’s picture of paints for Q4 going into 2015. If I heard you right Dan you said Q3 is going to be about 5% to 10% higher than Q2 and a big piece of that is because you have shut in that 40 million a day in Green for the long move. So if we paid Q3 around 260 million a day then the math I am doing shows that the range for Q4 implied by 262, 295 is like 330 million a day on the low end 335 up to something north of 450 particularly to high end of guidance.

So, I can see how the low end you guys get the -- you get the increment the effects for the quarter will be around $30 million a day for getting their shut in volumes back. So I could see the how you get to low end of 330 to 340. But what would have to fall in place, what kind of connections and what kind of schedules would you have to hit to be towards the high end of that range?

Grayson Lisenby

Yes. It's a good question. There are two main things. One there is some variability of when the undermining comes back on based on the level of subsidence, though it can be anywhere from one to three months, I think Danny mentioned and one month obviously helps the full year versus three months.

And then the second thing is when you are turning on that many wells in the quarter, I think we're having 17 net wells come online in the fourth quarter. There is a pretty big difference from where those come in the quarter, every two or three weeks makes the difference. And so that variability is what's driving that range now.

When we step back as a team, if we understand the three has numbers that they are trying to model, we step back as a team we feel very highly confidence those numbers are going to be somewhere more towards the higher end of the range you described them in lower end at December 31st. And so it's really just a matter of where it comes on weighted, whether it’s weighted towards October, November, December and we're obviously working our hardest to make sure it's towards the end. But there are just some variable pieces in there, we don't -- it's indicative of where it will be at December 31st, so which is why it gets us pretty excited to talk about our Q1, ‘15 call because that's we feel pretty confident about that number.

Charles Meade - Johnson Rice

Well, so that's why I was going to go next Grayson. So thanks for the lead. Because one of the things if I'm interpreting correctly is you talked about earlier pushing out two to three 7 and 9 well pads into 2015. So part of the variance in Q4, isn't those coming back into Q4, those are still going to be set for big bump in ‘15?

Grayson Lisenby

Correct. That variance does not augment those going back online in Q4.

Charles Meade - Johnson Rice

Go it, got it. And so you’re talking the exit rates and I don’t -- I apologize if I’m pushing too far on this, but an exit rate is somewhere north of 400. And so that would kind of set you guys up for a pretty high mark going into ‘15; is that the right way to think about it?

Daniel Rice IV

Yes. You’re thinking about it the right way.

Charles Meade - Johnson Rice

Okay. Got it. And then going back to the question about the acquisition in Greene County and in the Pennsylvania Utica, do you guys have or did you guys maybe acquire from Chesapeake or any other people, do you have vertical course or logs down through that Point Pleasant member in Greene?

Daniel Rice IV

Yes. We have -- I mean we have logs throughout even going into Central Greene County that are publicly available. So no there is any necessarily through this acreage, but we have subset actually delineate that goes up further east.

Charles Meade - Johnson Rice

Got, got. That’s all then. Thanks a lot.

Daniel Rice IV

Okay. Thanks a lot Charles.

Operator

Our next question comes from Gordon Douthat of Wells Fargo. Your line is open.

Gordon Douthat - Wells Fargo

Good morning, everybody. So, question from me is on in the Marcellus, so there is just a progression of the 90 day rates as you drill longer lateral in the progression there. You kind of hit at this in your prepared remarks Dan, but just wondering have you reached an upper limit there as you drill these longer laterals; and then what benefit do you continue seeing going forward on the cost side of the equation?

Daniel Rice IV

Yes. I mean I think on the cost side -- and you guys can see it in the table that we put in the earnings release for the second quarter. The laterals are getting longer; our costs per foot are getting lower. So, in the cost side that was ultimately as part of the goal why we elected to drill longer laterals, is because we can continue to drive our cost down which is especially important in development mode. I think one of the things that we are seeing is as you are drilling longer laterals, it’s really hard at least on the mechanical side to maintain the same one point, 2 million per thousand foot lateral, just given the share of volume when you have 9,000 foot laterals trying to produce 18 million a day each into a system and you have 3 to 5 of them on pads coming on line at once that it’s just mechanically a whole lot easier to manage those things if you producing them at 1.5 to 1.7 per million foot of lateral.

That’s not really indicative of the reservoir quality, it’s really just indicative of being able to have just to manage flow program on the surface through the equipment that we have. Does that kind of answer your question, Gordon?

Gordon Douthat - Wells Fargo

Yes. And then do you see continued improvement just for costs or where do you see those lateral links trending ultimately?

Daniel Rice IV

Yes, I mean on the lateral links, we turn on I think it was 10,500 foot lateral in Green County in the second quarter and that was looking on a normalized basis, looking just as good as the shorter ones. I think on the cost side, I think the biggest driver of cost reductions going forward is once we have that water system in service and there we’re getting very, very inexpensive water to all of our locations, especially in Washington County, so that’s going to be a big piece of that should help us reduce our well cost by another $200,000 to $500,000 for each of those laterals going forward. That will be a step change once that system is in service in early ‘15.

Gordon Douthat - Wells Fargo

Okay. And then last question from me. In Washington, what’s the depth of the Utica in Washington and do you feel like that acreage is prospective?

Daniel Rice IV

It is 12,500 feet deep. And I mean the Utica is there to be determined on whether it ultimately looks like -- I mean it’s nice that some of our peers around us are going to be drilling other wells that are going to delineate this position well before we get our first Utica well tested. So we are really just going to piggyback on ultimately what they're doing before we really make a decision on what to do with Washington.

Gordon Douthat - Wells Fargo

Okay. Thanks very much.

Daniel Rice IV

Yes.

Operator

Our next question comes from Jeffrey Connolly of Mizuho Securities. Your line is open.

Jeffrey Connolly - Mizuho Securities

Thanks. In the past guys you've talked about the amount of sand per stage is really a differentiator for Rice or you guys trying to anything new on the completions and do you think there is still some more room for improvement on that?

Daniel Rice IV

No, I mean, I think we're pretty happy with the designs that we've been using for the last couple of year, but we're really not looking to shake things up on the completion design or even on the drilling design it’s just going to be a really slow evolution of just minor, minor tweaks here in there from pad-to-pad and that's about it.

Jeffrey Connolly - Mizuho Securities

Alright, great, thanks guys. Most of mine have been answered already.

Operator

And our next question comes from Ben Wyatt of Stephens. Your line is open.

Ben Wyatt - Stephens

Hi, good morning guys. Quick one on the Utica, just curious if any seismic has ever been shot over Utica acreage or if you pursue yourself doing that or you are just happy with kind of the data you've already collected in the area?

Daniel Rice IV

Yes, we 2D seismic across the area it's just flat as a pancake and there is really no reason to do a 3D seismic shoot to really refine the depths and all that stuff. So it makes the drilling on the lateral section a whole lot easier because when it is that flat you don’t have to do as much geo steering.

Ben Wyatt - Stephens

Got you, very good. And then just for clarification, did you guys say that 7 million is a EBITDA generated from third-parties for all of '14 is what you're thinking?

Daniel Rice IV

Roughly, that's associated with M3 acquisition and obviously we're still negotiating with go forward so we can't comment on that.

Ben Wyatt - Stephens

Yes, got you. And remind me again what invested capital has been on the midstream side so far?

Daniel Rice IV

Around $500 million through by end of this year.

Ben Wyatt - Stephens

Got you. Very good. Well, appreciate you guys. Thanks.

Daniel Rice IV

Thank you.

Operator

And at this time I'd like to turn the meeting back over to Daniel Rice for closing remarks.

Daniel Rice IV

Thank you all very much for joining us today. We're super excited about the prospects of this business and we look forward to updating you guys on our third quarter call sometime in early November. Have a great day.

Operator

This concludes today's program. You may disconnect at this time.

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Source: Rice Energy's (RICE) CEO on Q2 2014 Results - Earnings Call Transcript

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