Welcome to the Range Resources’ Fourth Quarter and Full Year 2013 Earnings Conference Call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speakers’ remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good morning and welcome. Range reported outstanding results for the fourth quarter and calendar year 2013 with record reserves, record production and continuing decrease in unit cost. Both earnings and cash flow per share results were greater than the First Call consensus. The order of our speakers on the call today are Jeff Ventura, President and Chief Executive Officer; Ray Walker, Executive Vice President and Chief Operating Officer; and Roger Manny, Executive Vice President and Chief Financial Officer. In addition, we have Chad Stephens, our Senior Vice President in-charge of Marketing will be available to answer questions after our prepared remarks. Range did file our 10-K with the SEC today. It should be available on the home page of our website or you can access it using the SEC’s EDGAR system. In addition, we have posted on our website supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call today. Now, let me turn the call over to Jeff.

Thank you, Rodney. I will begin by looking back on what we accomplished in 2013 and then I will look ahead to what we expect for 2014. Last year, we grew production 25% with capital budget of $1.3 billion. Cash flow increased 25% year-over-year and cash flow per share debt-adjusted also grew 26% year-over-year. Our proved reserves grew 26%, 8.2 Tcfe, which equates to replacing 612% of our production. This was done at an all-in cost of find and develop at $0.61 per mcfe. Reserves per share debt-adjusted increased 25%, while production per share debt-adjusted grew 26%. As a result of our development activity, we have moved 6.4 Tcfe of unproved resource potential to proved reserves over the past four years. Because of this excellent performance, our total DD&A rate has declined from $2.33 per mcfe in 2009 to $1.44 in 2013. And in the fourth quarter of 2013 was a $1.36. Looking at the same time period, our operating expense per mcfe declined from $0.83 to $0.36 and in the fourth quarter of 2013 was $0.36. The bottom line is that Range is continuing to improve its capital and operating efficiency and the results are flowing through to the bottom line. Net income for 2013 was $116 million, up from $13 million in 2012. Late last year, the Mariner West project became fully operational and the ATEX project started line fill on December. Also in December, we reached two new milestones of our gross Marcellus production reached 1 Bcfe per day and our corporate net production reached 1Bcfe per day. In summary, 2013 was an excellent year in both operational performance and financial performance. Looking to 2014, I believe there will be three key items that will distinguish performance between companies in our industry. The first is, owning a…

Thanks, Jeff. 2013 was a great year. We saw improvements in well performance, capital efficiency, infrastructure and cost control across all divisions and we expect to see similar improvements in 2014 and beyond, all while working safely. Like Jeff said, we have some really great metrics and reaped some important milestones in 2013, but there’s just a couple more achievements that I’d really like to point out. Even with selling our New Mexico assets early in the year and in spite of the delays in the Mariner West pipeline startup, our teams achieved the high end of our production guidance at 25% year-over-year. At the same time, we also saw our direct operating expense decline by 12% for the year. I want to take this opportunity to offer congratulations to all our employees for a job well done in 2013. The innovation and focus on per share growth coupled with core values of cost control while working safely and maintaining sound environmental protections, all are translating to the bottom line. As Jeff described in his remarks, one of the key items that will distinguish companies with an asset base like Range is execution. Execution is one of our strong points and getting better at what we do year after year is simply what we do here at Range. Let me give you just a few examples based on our last four years. In 2009 we averaged 57 million cubic feet equivalent per day from the Marcellus and in 2013 we averaged 790 million per day. That’s 1161% growth over four years. Our direct operating expense per Mcfe corporately has dropped from $0.75 to $0.36 or a drop of 52% from the fourth quarter of 2010. Three examples from southwestern Pennsylvania for the last four years. Today we drill 93% faster…

Thank you Ray. Top line revenue from natural gas, oil and NGL sales for the fourth quarter, including cash-settled derivatives was $446 million, 7% higher than last year and 20% higher production volume. Cash margin for the quarter at $2.68 per Mcfe decrease slightly from the fourth quarter of last year due to much higher NGL realization and fourth quarter of last year, and lower realized prices for both gas and NGLs this year. Cash flow for the fourth quarter was $252 million, 2% higher than 2012, driven by higher production and continued expense control. Cash flow for fully diluted share was $1.56 slightly above last years fourth quarter of the year. And fourth quarter EBITDAX totaled $295 million, 2% higher than last year. Cash flow for all of 2013 totaled $943 million, a year-over-year increase of 25%, cash flow for fully diluted share for the year was $5.84, 24% increase from last year. EBITDAX for the whole year was $1.1 billion, 22% higher than 2012 and the first year our EBITDAX has broken through $1 billion mark. GAAP net income for the fourth quarter was $28 million while earnings calculated using analysts methodology, which excludes asset sales, derivative mark-to-market entries, and various non-recurring items was $68 million or $0.42 per fully diluted share. As Rodney mentioned both cash flow and per share earnings per share for the quarter exceeded consensus estimates. GAAP net income for all of 2013 totaled $116 million a nine fold increase from the 2012 net income figure of $13 million, all of our non-GAAP measures are fully reconciled to GAAP on the various supplemental tables posted to the Investor Relations section of our website. As evident in our 2013 financial performance whether one year’s GAAP or non-GAAP measures as income and cash flow improvements in…

Operator, let’s open it up for Q&A.

Thank you, Mr. Ventura. (Operator Instructions) Thank you. Our first question comes from the line of Gil Yang with DISCERN. Please proceed with your question. Gil K. Yang – DISCERN Investment Analytics, Inc.: Hi, good morning. Thanks for all the details in the call. Jeff, growth clearly on track, cash flow is growing. Could you talk about what your expectations are for CapEx versus cash flow trends over the next several years?

Yes, I mean we really feel comfortable with that 20% to 25% line of sight growth for many years. We have a big inventory. It’s largely de-risked. You can look on the slides that talks about the percent of the wells were drilled upside in many different ways, either through incremental recovery, other horizons things like that. We feel comfortable we can grow 20% to 25% for many years. We talked about in the early years like we are now, we’re getting the 20% to 25% growth with the cash flow outspend depending on where commodity prices are of between $250 million and $350 million. If you project forward a couple of years depending on where prices are we’ll be getting 20% to 25% growth within cash flow. So, I think we’re well-positioned, continue to grow consistently, and one of the highest rate of return, lowest-cost plays out there with a really strong team that has a great track record of delivering quarter-in, quarter out, year-in and year-out. Gil K. Yang – DISCERN Investment Analytics, Inc.: Great. If you just look at the strip, when would you get to that cash flow CapEx breakeven?

It’s hard to say. It might be in a couple of years or something like that. It depends where prices are ultimately be. I really think if you look forward, we’re in a great position of where the strip is, but I think the good news, I think there’s a lot upside in terms of gas. There’s different studies out there about this company – quote a few of them and I’m not picking any one company, but Goldman Sachs is saying 20 Bcf of reserve growth by 2018. Citi has 20 Bcf by 2020. There’s other people out there. So, I think natural gas will be great in this current pricing environment where the strip is, but I think there’s actually good upside to that because natural gas really is a superior fuel. A lot of things are happening, a lot of people are spending money on everything from converting more gas for power generation, LNG for export, gas for transportation, gas for manufacturing, gas for petrochemical business. So, a lot of upside out there. Gil K. Yang – DISCERN Investment Analytics, Inc.: Okay, great. And then, a follow-up in that context. With that 20% to 25% growth rate, you mentioned you could drill your Northeast gas at the right time. So, within the context of the pricing expectations in a 20%, 25% growth, what is the right time for that gas drilling to accelerate?

Well, we’re drilling some of it right now. Ray mentioned some outstanding wells. One of them with 18 Bcf well from a reasonable length laterals 6,000 plus feet a little bit. So, I think we have good returns on that drilling now and the good news is we have a great inventory of dry projects, wet projects and super-rich projects. And we sort of have a portfolio within a portfolio and we can allocate capital where we think we can get the best returns as we go forward. Gil K. Yang – DISCERN Investment Analytics, Inc.: Do you need a specific price though to start accelerating versus what the liquids are doing right now?

Well, I think it comes back to 20% to 25% growth since – we think it’s strong, particularly for a company our size. Every three to four years we’ll be doubling 20% to 25%. So if we can double in three to four years and then double again for a company our size with the returns we have we think that’s great. We are currently drilling some dry gas wells now both in the northeast and in the southwest. It will just become part of our portfolio. Gil K. Yang – DISCERN Investment Analytics, Inc.: Okay. Great. Thanks a lot.

Thank you.

Our next question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question. Neal D. Dingmann – SunTrust Robinson Humphrey: Good morning, gentlemen. Jeff, you’ve obviously put on a lot of solid contracts with Mariner West and some with ATEX and some of these others, just tried coming on. Are there a number of additional ones that you’re considering at this time or what’s your thoughts as far as putting more of those going forward?

. : So we’re in a great position. We don’t have to do anything to take our production to greater than 3 Bcf per day net and beyond. Our gas will be on spec, we’d great contract, great prices. To the extent there’s things that makes sense, clearly we’ll continue to look at those things. Neal D. Dingmann – SunTrust Robinson Humphrey: Okay. And then, you detailed, great detail about the longer laterals and how you come up with higher EURs. Just wondering on your thoughts, I mean I know there is some peers out there that are doing somewhere around your southwest PA, some of these monster laterals closer to 9,000 or even further. Your thoughts about going out, stepping out and try some of those. Are you going to still consider more around that 5,200 foot average?

Well, you’ve kind of hit on it there in your last comment. I mean, the 5,200 foot is an average and so all those numbers that we’re quoting to you and that we show you in the investor presentation is an average of literally 100 plus or minus wells that come online. So we have drilled some longer laterals and we do plan to reach out drilling longer laterals if it’s appropriate. But again we’re really focused on optimizing the recovery of hydrocarbon in place and a lot of that we focus on as EUR per 1,000 foot. Are we targeting the most optimum place in the zone, are we pumping the right size frac job, the right spacing between the per clusters. So we will continue to do like we’ve done for the last several years and we’ll update these curves as we go along. I think you’ll see us continue to get longer and longer, but we don’t wanted to get so long that we really cause our optimal recoveries of hydrocarbon in place to suffer. So we’re going to really proceed along that line, just specifically data base, not outrun our technical understanding of the play. And I think right now in southwest PA for sure, our recoveries per 1,000 foot lateral class leading. We are proud of what the team has done there, Marcellus is a great rock, it’s just getting better and better all of the improvements that we are making, the adjustments that we make year-over-year are getting as higher recoveries, and I expect those to continue to go up with sometime. I still think we are in the early innings of the ball game and being able to optimize that, and I think that’s completely different than we’ve seen in a lot of other shale plays, and [indiscernible] have some of the other ones that have a lot more history. We’ve seen like we got through the bargain pretty quick in a lot of those, and it was just simply stack in laterals closer together. I think we got a lot of efficiencies and improvements to be going forward, and I think that a lot of that has to do with the fact that we are in a very core of the sweet spot in Southwest PA. And then of course, when you stack through upper development in Utica, up and top and below that, we got even more efficiencies that we can get over the years to come.

Now I think having a large foot print in the core of the best play out there with really strong technical team I totally agree with Ray that we ought to be able to continue to improve with time. Neal D. Dingmann – SunTrust Robinson Humphrey: Hey Ray, just as one follow-on to that if I could, just you mentioned about the stack pay and obvious to gas in place math really show that you have a lot of Utica potential, just the sort of cautious approach by maybe not drilling the first there until spring. Is that more a result of just how good your current Marcellus results there or why not obviously just ramp that up quicker on the Utica side if certainly if those gas in place not so as good as they are showing?

Well, we HBP everything as when we drill Marcellus, so it’s been a really a matter of focus on the Marcellus. We are making really good at project economics there. We are seeing improvements year-over-year. We’ve known that Utica is there for sometime, I think there has been wells drilled closer to as we got lot more 3D together, and over the years, it sort of always been there, people tend to forget, we actually drilled the very first horizontal Utica well as we drilled back in 2009. So, we’ve been working on it longer than anybody. It’s just that we’ve been focused on the Marcellus, and I think with the data we have today, I think the timing is right, I think the team has put together some really good technical work. We are really excited about this project, I don’t know if you could tell that or not, when we are [indiscernible], but it’s going to be, I think a great well and we have taken our time, we got prepared for it. We actually believe we can bring this well online pretty quickly after we test it and that’s critically important. We don’t like to have wells sitting around waiting on the infrastructures, so I think that we are really excited about it, and we think it has the potential to be hugely economic, and a great play that we can really ramp in and develop in as the years go forward. But again it’s going to be HBP and as it fits into our plan, I think we are just kind of see us do more and more evidence as the years go forward. Neal D. Dingmann – SunTrust Robinson Humphrey: All great points. Thanks Ray.

Thank you.

Our next question comes from the line of Holly Stewart with Howard Weil. Please proceed with your question. Holly Stewart – Howard Weil: Good morning gentleman.

Good morning.

Hoping to dig a little bit more into the NGL marking side, given your expectations for increased volumes through this three-pronged NGL marking strategies have begun operations. So, can we maybe use January and February as an example of how the realizations are changing, and then maybe a little color on your outlets and how you use them thus far?

Holly thanks, this is Chad, I will try to give a little bit color on that, so in January beginning of January this year, we were flowing 15,000 barrels a day of ethane on MarkWest and approximately 10,000 Mariner West and that’s gross. And about 10,000 barrels a day gross on ATEX. The MarkWest pricing is tied more to Appalachia index price and ATEX is more of a true Mont Belvieu price less the transportation cost. So, if Mont Belvieu prices in January, they had a little jump up or increase in price. So, they were around $0.39 or $0.40. We see that going forward into later end of the year and in 2015 coming back down to a more historical average. Price were around $0.30 a gallon. That’s the Mont Belvieu index price before index, before transportation deduct. But really what you need to look at is going into 2015, once all three projects are in service we’re delivering 15,000 barrels to MarkWest, NOVA, 10,000 barrels a day to ATEX to Mont Belvieu and then 10,000 barrels a day on Mariner East, which has a more European a Napa-based index price. All three of those gives you that 25% uplift and we get a deeper cut. The more ethane we take out of the gas we get a deeper cut of propane, which again gives us a little bit more uplift on our overall NGL realization. So, you really need to look at it that way. Current prices January and February for ethane are up, because gas prices have moved up and ethane will follow that full price of gas, but going forward you need to look at really the 2015 portfolio of all three projects and service.

Perfect. That's helpful. And then, maybe on the basis. Looks like $0.22 during the quarter, but then Appalachian prices have moved up in the first quarter. So, can you just give us a sense of how this is evolving maybe in the first quarter compared to 4Q and then your execution throughout the year?

Yes, and what I really like to do is address. I know there’s a lot of people on the call that probably have – want to know what our thoughts are and want to just get some color on basis differential. So, I’ll kind of try to address that more generally. As Jeff mentioned in his prepared remarks, the basis differentials don't impact all producers equally. Especially that's true in the Appalachian basis, Appalachian basis, notably very depending on which pipes you’re delivering into or which markets or producers you have access to. So, if you look at our supplemental tables it shows corporate gas prices, third quarter 2013 differentials of 17 units and fourth quarter of 2013 was minus $0.22 per Mcf, but if you drill down a little bit and to give a little color on that, if you look at a subset of that corporate differential and just look at our Marcellus differentials, it improves quite a bit. For example, in third quarter 2013 our Marcellus gas price differentials to NYMEX was minus $0.06 and in fourth quarter 2013 it was minus $0.11. So, that should give a little bit of context going forward of what we’re doing with our Marcellus gas, and how to use firm transportation arrangements out of the basins are really helping us. Midwest, the Ohio Valley where there is lots of – we have great relationships with power and utility users, so that’s a key area for us and as well as the Mid-Atlantic area and this percentage could increase in future years with a lot of flexibility we have on our upfront transport. So, and also Ray mentioned we worked hard to add 25 new customers and create strong relationships with these power and industrial users outside the Appalachia basin. And we’ve been successful in doing that. There is no question that likely there will be challenges due to the volatility in the market between now and probably late 2016 with demand, we see demand increasing, but we’ll continue to use this strategy that we’d use in the past to diversify our pricing and expand our capacity in markets and number of customers using our portfolio firm transportation and these relationships that we have. So, really back to your question, what do we think basis is going forward? We understand the importance of that, Range doesn’t typically give guidance on any specific commodity pricing particularly basis. It’s really because of the high volatility and you have seen that of late. In addition, the current dynamics and going forward the volatility in the gas markets is constantly changing, so it’s difficult to give any specific guidance on particular basis of pricing. But what I can tell you and the shareholders is that we are diversifying our risk, our team has done a great job and are continuing to do a great job out there and we are well prepared from a gas marketing standpoint. Thanks.

Perfect, thanks gentlemen.

Thank you.

Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question. Ronald E. Mills – Johnson Rice & Co. LLC: Good morning guys. A couple of real quick questions. Should we view as you move to both longer laterals and drilling more wells off of exiting pads including currently producing pads? Is 2014 more of a transition year in terms of the cycle times pushing some of the growth more to the second, third and fourth quarters, so later in the year, but then in 2015 and beyond, is it something that we can start looking at as more moving into acceleration mode, is that a fair way to look at your points?

Well Ron this is Ray, the – I mean part of that I could say is every year we’ve consistently drilled a little bit longer laterals and we’ve done more and more things like going back to existing pads and testing 500 foot space laterals and RCS completions and so, every year I think we’ve made steady improvements. I think that recent couple of years certainly we’ve seen more of those, have larger impacts, and I think that will continue at least for a few more years I think. As far as acceleration we are going to grow 20% and 25% per year for as far as we can see out there and that essentially seems pretty aggressive to me and that’s doubling, for three years, so there is an operation that grows year-over-year a couple of years out is huge. So that’s certainly accelerating from where we are at today, if you want to look at it that way. So I think that’s going to happen now as far as production seeming to always be back-end loaded. There is a simple fact in Appalachia that we can’t mess with Mother Nature, if we could figure out how to warm her up, in January and February we wouldn’t have these six week periods that we have consistently every year, where it’s just simply hard to frac period one is negative degree, known as negative 15, negative 20 degrees, even 10 pound salt water freezes solid, so you just can’t complete wells during that time. There are control lines on compressors that will freeze up, there are things like that that will always happen when it gets that cold. As much planning as we do and my hats off to our operations teams. They have absolutely done better every year that…

Well the 14 wells is an aggregate number that is across all five pads of 3,4,5 wells pad kind of thing. The Utica is – we are very excited about it. We just have – we just have the one well this year, of course we want to drill it. We want to test it, put it production, analyze it, optimize our plans from that point. And so, it’s going to take us a while to see that. The Upper Devonian, we got figured it out. We drilled enough wells, every time we drill in Marcellus well, we go through it. So, we’ve got hundreds and hundreds of wells worth of information about it. There are now enough Upper Devonian test all around our acreage not even including ours that certainly have delineated and really de-risk that. To us it’s more simply a fact of focus on the Marcellus. And let’s continue to optimize that and I do believe at some point we will start putting Upper Devonian wells on the same pad as we get into that. Once, if you want to refer to it as a manufacturing mode, when we more or less drill all the wells on a pad whether that is 10, 20, 30 wells whatever that is. Eventually going forward, I think you’ll see that more and more starting to occur over the next several years. Ronald E. Mills – Johnson Rice & Co. LLC: Great, thank you for the information.

Thank you, Ron.

Our next question comes from the line of Jack Aydin with Keybanc. Please proceed with your question. Jack N. Aydin – KeyBanc Capital Markets, Inc.: Hey, guys.

Hello, Jack. Jack N. Aydin – KeyBanc Capital Markets, Inc.: Good morning. Could you – I know you’ve been talking about uplift. If you have all the ethane projects on a play [ph] and you’re talking about 25% uplift in revenue. Could you put a circle around what could mean that to the cash flow potential? I’m sure you modeled it.

Well, I mean I’ll turn it over to Roger and Chad in a minute. This is Jeff. I think one things is, when those things online, again to Jack’s point, extracting the ethane, once all three projects are up, there’s a 25% uplift relative to leaving it in the gas stream. So for the analysts and investors that run NAV models or whatever, clearly you’re going to add significant NAV when you model that in for a particular year. One of the other thing I’ll say too, I think we did a great job in 2013. We said we grow 20%, 25% and we did almost every metric you look at including cash flow or cash flow per share debt-adjusted reserves production, all drill in that range. In fact we hit the high end of the range. So I’ll turn it over to Roger or Chad for any additional color you want to add.

Jack, I think when you look at our cash flow growth, it really has twinned our production reserve growth fairly well and this has been a pretty good year last year in terms of comparison. While NGL prices were down fairly significantly, gas prices and oil were pretty – pretty much offset each other. So you saw really 25% cash flow growth in 2013 with relatively flat to down prices. So I think as you start pulling ethane and particularly when, as Chad mentioned, the 2015 enhancements come into play on Mariner East, I think you’ll continue to see cash flow grow in somewhat per well fashion with our production and reserves.

If you look out there far enough and depending on what prices do, it could even grow in excess of that if you go out a few years, which is pretty exciting. Jack N. Aydin – KeyBanc Capital Markets, Inc.: Thanks. Second question for you is basically on your budget. You allocated about $210 million for leasehold and renewals. Could you break it down or to – second, instead of drilling to hold leases on production, now you are renewing it and paying the money? Is that what you are doing? Could you explain it a little bit?

Yes, Jack, it’s a good question. The majority of that is driven of course by the Marcellus. We have 1 million net acres plus or minus there and a lot of that is still in progress of HBP. So it’s just what I would call normal blocking and tackling. It's filling in holes. It's bolting on things to units. It's renewals. It's all of those things that you just mentioned. So we’ll see that taper off. In the future, there's no question about that. We’re getting closer and closer. Our at-risk acreage is becoming a very, very low number. We show that in our investor presentation. And so, we’re doing a much – we’ve made great strides, I would put it that way, in holding as many as four units worth of acreage from one surface location and it gives us not only a lot of operational and capital efficiencies, but it's very efficient at HBP and land. So we’re feeling really good about that. So I think we have a very large acreage position and just normal blocking and tackling, it's going to be that way, but the good news is, there's at least one good leading indicator that we’re seeing in the 10-K. We look at expiration expense. You’re seeing that crest over and come down. So I think that’s our excellent leading indicator, and that shows us that and we are about to get to that point where it comes over, Southwest PA has a lot of small tracks and it just simply going to take us sometime to fill in all of the little puzzle pieces but we do – we’re feeling really good about that. Jack N. Aydin – KeyBanc Capital Markets, Inc.: Thank you, very much.

Thank you.

We are nearing the end of today’s conference. We will go to Phillips Johnston of Capital One for our final question. Phillips Johnston – Capital One Securities, Inc.: Hey, guys thanks. Just on the first Utica Point Pleasant well. I’m wondering if you can say what the ASE might be, and what sort of cost for signs that might include, and given the depth and the pressure what sort of average well cost would you expect in the full development pad drilling mode. And just as a follow-up to the earlier question that Ray answered, if you like what you see there, how many wells, do you think you could feasibly drill looking at in the next year?

Well, the first set of questions on all the detail is no, no, no, and no. The first well, we can’t really talk about the first well. We build a lot of insurance in there. We do a lot of things. From a science standpoint, it is our very first well, the way we tend to look at things like that is on a project basis, is just like any exploration project. Let’s go drill the first well, let’s look at it. The question is in a development mode if it all test out, will it make sense. And all our numbers, what I can’t say is, it looks really, really good, with the high pressure, high gas, it’s in a very workable depth. We got a large position, we know we are in the core from a lot of – we have actual Trenton/Black River test with well logs, lot of modern scientific catalogs right in the area. We have infracture on the surface where we can put some of these well on line early on, so it’s a pretty exciting projects. It’s something again, we’ve been working on since literally back in 2008 and 2009. So I think this first well with lot it’s a little early to say would we drill another one in 2015 or 2016, when would it be. But if we did a good test by the end of the year and things look good, I could definitely see us drilling the second or maybe third well in 2015, but certainly in 2016. From that point forward I think it’s just a matter of when it make sense to ramp that up and it gives us some other great option. Again, we control our own destiny, we don’t have a lot of JV partners. We got great marketing and commercial logistics for the area, got a lot of takeaway capacity and we think it’s got a huge potential for us going forward…

And the wells drill – will be drill of in existing Marcellus?

Yes, I add and there is room for additional wells, so it could really be great upside for us.

I was going to say, plus it’s really easy to build volumes quickly with dry gas, so with big wells like that it just gives us a lot of good options in the future. Phillips Johnston – Capital One Securities, Inc.: And just as a follow-up to Ron’s question earlier, are there any Upper Devonian wells that are planned in this year’s capital budget?

No, we currently don’t have any plans right now in the schedules. Phillips Johnston – Capital One Securities, Inc.: Okay. Thanks guys.

Thank you.

Thank you. This concludes today’s question-and-answer session. I would like to turn the call back over to Mr. Ventura for closing comments.

Range had a great year in 2013 and we expect another great year in 2014, given our approximately 1 million acre position in Pennsylvania focused in the Southwest portion of the state whether there is great stack pay potential and because we have a great portfolio of dry, wet and super-rich wells, we believe we can continue to grow at 20% to 25% for many years. Thanks for participating on the call. I know there were several other people queued up that we can get to for time, if you would please follow up with our IR team. Thank you.

Thank you for your participation in today’s conference. You may disconnect at this time.