Welcome to the Range Resources' Fourth Quarter and Year End 2014 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 turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, Adam. Good morning and welcome. Range reported results for the 2014 with record production and reserves and a continuing decrease in unit costs which will set us up -- our operation for 2015. The order of our speakers on the call today are Jeff Ventura, President and CEO; Ray Walker, Executive Vice President and Chief Operating Officer; Roger Manny, Executive Vice President and Chief Financial Officer. Range did file our 10-K yesterday with the SEC yesterday. It should be available on our website under the Investor tab, 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 reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call today. Now let me turn it over to Jeff.

Thank you, Rodney. In 2014 Range achieved some key milestones that I believe position the company well for the future. Range recorded record level of production, reserves, revenue, net income, cash flow and cash flow per share in 2014. Thanks to continued cost structure improvements and steady production growth despite declining realized prices our cash flow and cash flow per share have increased. 2015 is setting up to be a challenging year. Fortunately, we did several things in 2014 that will help us in 2015. With the redemption of our fixed rate 8% bond with the proceeds from an equity offering coupled with the cash proceeds we received from our Conger for Nora swap we ended 2014 with less debt than 2013. Debt per Mcfe of proved reserves was $0.30 at year end 2014 compared to the prior year at $0.038. Last fall we restructured and extended our senior bank facility for five years to 2019 and increased our borrowing base from $2 billion to $3 billion. We have no bonds maturing until 2020. We have continued with our capital and operating efficiencies. In 2014 we improved our operating efficiency by decreasing our unit cost $0.35 or 10% versus the prior year and expect continued improvement this year. Our capital efficiency improved as we continue to drill longer laterals, and more frac stages per lateral and utilized improved targeting of the lateral. We believe this trend will also continue in to 2015. We currently have hedged approximately 65% of our projected 2015 natural gas production with a $4 floor and approximately 77% of our projected oil production with a $90 and $0.57 floor. On the natural gas liquid side Mariner East project is still projected to be on time with the start up in the third quarter of this year.…

Thanks Jeff. While we are focused on the headwinds that we faced in 2015 when we pause to look back at 2014, 2014 was a record year across many aspects of our operations. We set records in production, reserves, cash flow and earnings along with significant improvement in cost structure and capital efficiency. We continue to see great results in well performance in both Southwest and Northeast Pennsylvania and like Jeff said we completed our first Washington County Utica Well. While it’s only a single well based on the early results and all the previous data we have approximately 400,000 net acres in what we believe to be the core of the dry Utica and gives Range another significant growth opportunity to add to our core positions in the Marcellus and Upper Devonian and Southwest Pennsylvania. In 2014 we also put together both [indiscernible] as the Nora field in Virginia, giving us control of operations and the early results were outstanding. We have the ability to significantly grow that asset in one of the best gas markets on the East Coast in the future and in the Midcontinent area we saw continued confirmation of the geologic modeling in the Chat play along the Nemaha Ridge leading to some of the best well performance to-date in that play. I am also really proud of all of our employees for working all of 2014 without a loss time incident; safety, environmental protections and regulatory compliance are a core philosophy at Range and I want to personally congratulate everyone across the company for a job well done in 2014. We had a great year adding reserves at record low drill bit, F&D cost while decreasing the pud percentage and the startup of Mariner East early propane was another significant step in our liquids…

Thanks, Ray. The fourth quarter closed down an excellent financial year for Range. Revenue, cash flow and cash flow per share were all sequentially higher than the third quarter of this year and also significantly higher than the fourth quarter of last year, while total unit costs were lower. For all of 2014 we set record highs for revenue, EBITDAX, cash flow and cash flow per share. And while we understand that everyone is keenly focus on current commodity prices and 2015 budgets we should not overlook these record 2014 results as they properly position Range for a more challenging 2015. So starting with the income statement; the fourth quarter was much like prior quarters, where we offset lower oil, gas and NGL prices with higher production volumes and lower costs. Our net realized price per Mcfe was 17% lower than the fourth quarter of last year but production was 26% higher and unit costs were 11% lower and that drove our strong quarterly performance. Reported net income was $284 million for the quarter benefiting from a $341 million pretax mark-to-market gains on our hedge book. Fourth quarter earnings calculated using analyst methodology which eliminate these non-cash mark-to-market entries was $65 million or $0.39 per fully diluted share. Cash flow for the fourth quarter was $273 million, 8% higher than last year and cash flow per fully diluted share was $1.64. EBITDAX for the fourth quarter came in at $310 million, 5% higher than last year. Cash flow and cash flow per share for the full year of 2014 was just over $1 billion or $6.33 a share. EBITDAX for the full year was $1.2 billion and 2014 was the first year that cash flow topped the $1 billion mark. As Rodney mentioned earlier please reference the various reconciliation tables…

Operator, let's open it up for Q&A.

Thank you, Mr. Ventura. The question-and-answer session will be conducted electronic. [Operator Instructions]. Our first question comes from Ron Mills of Johnson Rice. Please go ahead with your question.

Hey, Ray you talked about slides eight and nine and it shows that the cost improvement particularly adjusted for lateral length, it was a big decrease as expected, a much bigger decrease is expected in ‘15 versus ‘14. Can you talk about how much of that is related to the lower overall service cost environment versus ongoing efficiencies. I am just looking at the last bar and the well cost per lateral length and the pace of the decline is much greater in ‘15.

Yeah, good morning Ron. Good question. The difference, when you look at those charts on page -- slides number eight and nine, what you've seen from 2011 to 2014 has pretty much been a factor of well design improvements, longer laterals, operational efficiencies and the capital efficiency that we have seen during that timeframe. From 2011 seen through 2014 we really have never seen service and supply chain cost reductions. So the difference in the slope of that line, if you want to look at it that way, going from ‘14 to ‘15 is the service or the supply chain side of the pricing reductions that we're seeing. We're seeing discounts across all of the sectors, across all -- from drilling rigs all the way through every piece of it and I think the jury is still out on how much more of that we'll see during the year. But I think it will depend on activity across the industry but certainly with all of the capital reductions that we've seen across all the different plays we're taking advantage of those every opportunity we get. But that's the big difference, so that what I quoted in my remarks, the 37% reduction that we're seeing from 2014 for the planned average in 2015 is really a combination of well design improvements, operational efficiencies, like we've seen in the past and we'll continue with of all those innovations and then the other is -- the thing this year is really the difference in well cost from the supply chain side of things.

Okay, great. And then later in the presentation you show each of the areas and you have the 2014 actual production versus the unrestricted type curves. Can you just give us a little bit color on what the restrictions are and is it just the build out of gathering and right-sizing the gathering for the long term as opposed to flowing unrestricted? And I assume your guidance is based off of how you are actually flowing them I suppose to the unrestricted type curves?

Right, right. Another great question. We have done a couple in our presentation this time. One is in 2014 we were showing you an unrestricted, unconstrained how you want to say a type curve that was based on the wells that we plan to drill that year. Going forward we are giving our predicted forecast for the wells based on all the other system that we have out there, the timing and so forth and we are basing on the mix on the wells that we are actually going to put to sales. So it will actually help the investors more correctly model our production forecast going forward and that is the big difference in the curves.

Yeah, and Ron this is Alan Farquharson. With that I think we have covered a couple of things that and really talked about we are trying to make the forecast easier for people to model one. Two, I think at the end of the day what it looks -- what you are seeing is well EURs on a per normalized basis are exactly the same as what they were before. Overall, we are going to have higher EURs because that will be driven by longer laterals and we are also realizing the benefit of lower well cost. With that this is the constrained situation if you want to call or restricted is really the result of success of the drilling programs that we have had over the last several years. It’s, traditionally you design systems to maximize the overall value of the whole product as opposed to individual well economics. So with that we have kind of modeled everything from that standpoint. That’s not to say we are not going -- we are going to stop to not plan improvements. We still think that they are going to able to realize some improvements going forward in terms of looping lines, additional compression. We have a plant coming on scheduled to come on in 2016. We are also looking at improving the pipeline hydraulics that are out there. So we think with that there are also going to some improvements that hopefully we will be able to see over coming in 2015, 2016 and beyond but with that we believe this is great model to be able to get to the 20% growth that we have.

Great. And then the optimized versus original curves on slide 35, is it fair to assume that the plan is to really do the 700 foot spacing going forward or are you still in early days?

What you will also see Ron in our presentation, the slide before that, on slide 34 is an update of the 500 foot space test that we had talked about several quarters ago, probably over a year ago and we are updating that. We now have basically five years of production almost and our original projections of about 80% of the thousand foot examples is still holding very true. What slide 35 -- what the example I called out in my remarks does is show you not only a version of that, but it also shows you the improvement in well designs and operational efficiencies and just better targeting, you know all of those impacts basically showing the two new wells on a normalized per foot of lateral basis produce 53% more production you know over a year’s timeframe, then the original wells which were only two years par. So I think going forward we have a mix of both of those cases. Now whether the spacing is 500 foot or 700 foot or 900 feet or what the ultimate space is going to be I think when you look at our core position at Southwest Pennsylvania it is very large and is very diverse. We go from super-rich all the way to dry and I think as we develop overtime you are going to see some areas in the liquid, I would think we are probably going to get wells closer together there and maybe not as close in the dry are but I don’t think at this point in time we could say it is going to be only 500 because I don’t think that’s going to be the case. But it’s certainly going to be a lot more well in-fill well drilling and when we go back on those existing pads, what’s -- it is really important to point the improvement in well performance that we are seeing but you can’t also -- you can’t forget the decrease in well cost. When you are looking at $850,000 less per well those economics are going to be outstanding going forward as we go back and redevelop those areas to fill in the gathering system as we get more room. Gathering costs will come down in those areas, those -- there’s going to be some real upside for us going forward.

Great. Thank you.

Just to summarize that a little bit, that slide 34 all those wells were drilled at the same time. So you had a pilot of 500 foot wells versus opposed to a thousand all drilled with old technology of five years ago and in-fill looks very attractive. However when the wells were wider spaced divisionally and then we’ve gone back years later and in-filled rather than that in-fill well getting 80% of the original well it’s actually better because the longer laterals, RCS, all the better landing, all the things that Ray said. So the in-fill wells rather than being a fraction of the original well are actually better.

Thanks again.

Thank you. Our next question comes from Doug Leggate of Bank of America. Please go ahead with your question.

Hi, this is John Attis [ph] speaking for Doug Leggate. We just had a couple of questions; apologize if they had already been asked. With regards to Mississippi Line is that even considered core anymore and if it’s something that you can potentially consider divesting? And considering and what -- and if so when you look at Nora, I mean is there a possibility of -- what would you need to see in order to pick-up activity? And then my follow-up question is it looks like based on your new program for 2015 budget there is the possibility that you may generate free cash flow. If so where would you allocate the cash? Thank you.

This is Jeff. Let me start and I would imagine you’ll hear from two or three more other than me. Yeah, I think what you’ve seen us do is focus our capital on the Marcellus where we have very strong returns, the ability to dry, wet and super rich. So we get -- and we get strong returns, we get good growth. It’s also an area where there is an infrastructure ability to grow it, there’s contracts in place. We have to hold acreages, a lot of different factors that blend in to that decision to focus in the Marcellus. And I think if you step back and look at it, I would argue there are returns in the Marcellus there as good any play really in the U.S. today. So strong returns and yeah that’s an area we need to drill to continue to hold to acreage which we’ll do. But when you look at Nora it’s a totally different decision. It’s all HPP in fact it’s better than that, in that we own the minerals under the bulk of it. So it has strong returns, strong economics and good gas markets but that’s an area we have the ability to ramp up, when we’re ready to do that, great asset. I think we created a lot of value by putting it together. Again it’s all the strength that Ray said. We put the two pieces together that creates value, we try new technology, there’s some great slides in the book that show what those new wells look like in the appendix. And we still get a premium to NYMEX there and we have the ability to grow and ramp that and probably one of the best if not the best gas market in the U.S. In the mid-continent the decision to slowdown there was given the returns that we have in the other areas, we were putting like I said in my notes approximately the number was, 97% or so plus or minus more capital in Appalachia. So we thought the most efficient thing to do is to really operate those properties out of Fort Worth, there’s significant G&A savings that Roger mentioned, several million dollars a year in savings. We still think the properties have potential, big footprint stack play, a lot of that’s controlled. Let me switch gears a little bit and just talk abstract, in the abstract you talked about -- when you look at asset sales, clearly over the last several years we have sold almost $3 billion worth of properties. So if we ever get to the point where we think those assets are worth more to somebody else than us then clearly we’ve done that multiple times. And to be honest with you, it’s early in the morning and I don’t remember all the other questions. I’ll turn it over to Ray now.

Yeah, John this is Roger, yeah, your free cash flow question, I think your modeling is correct. It’s a very, very modest overspend by projection, the lowest overspend we’ve had that I can remember. And the interesting thing about it is it’s not contingent on some asset sale. So there’s not sale risk in that number. It’s not contingent on some capital market transaction, so there is no market risk in that number. And you’re right more cost savings and/or higher prices could easily flip us to cash flow positive and if we find ourselves in that position we’ve got a lots of places to put the capital and we’ll take that decision at that point in time.

I appreciate it. Thank you.

Thank you.

By the way a little color, we’re sitting here looking at the window in Fort Worth and it’s an intense snowfall. It’s extremely rare for those of you that don’t know Fort Worth, it’s very beautiful. Next question?

Our next question comes from the line of Holly Stewart of Howard Weil. Please go ahead with your question.

Hello?

I'm sorry. Our next question comes from the line of Phillips Johnston with Capital One. Please go ahead with your question.

Hey, guys thanks. In your prepared remarks you've referenced sequential production growth throughout this year and I'm wondering how the quarterly progression of that growth is expected to look like in the second, third and fourth quarter. Is it expected to be fairly smooth at close to a 5% sequential per quarter growth rate or would you expect some lumpiness in the progression?

Yeah, Phillips, it's a great question, and I think it's -- we still feel very comfortable with the 20% growth for the capital that we said. We have given you the first quarter guidance. So by definition it’s kind of backend loaded. I think if you look at the company historically it's looked that way for the last decade. So I would just look at the last few years and model it that way.

Okay, and then as we sort of look into next year it sounds like, Jeff you're pretty confident that you can sort of maintain that 20% growth rate. Obviously drilling efficiencies are a tailwind for your growth rate and you have some mix shift from the mid-cont Appalachia, but can you give us some comfort as to how you can continue to grow at that level despite the fact that your planned well count this year is down more than 25% year-over-year.

Yeah, well I think it's fixed to when you look at the well, the quality of the wells have gotten better year-after-year and we've talked about that a lot. For longer laterals this year we're targeting 6,000 foot on average roughly and I think you'll see the laterals progress with time to longer laterals better technology, better landing, better capital efficiencies. And if the pricing, share pricings holds in there with this and I think we'll be in pretty good shape. So I think the other thing is our probably like other, a lot of other companies for 2015 our production curve will progress throughout the year towards backend loaded. So it gives us a good start on 2016. So I think that coupled with capital efficiencies puts us in a position where gas today, we still feel that targeting 20% growth is very reasonable.

Okay, thanks Jeff.

Thank you.

Thank you. Now our next question comes from the line of Holly Stewart of Howard Weil. Please go ahead with your question.

All right, let's try this again, can you hear me?

Yes.

Okay great. Maybe just switching gears to NGL realization, because you guys talked about in your presentation, how in the second half of the year there will be a higher percentage based off of natural gas and obviously the fourth quarter NGL realizations were a lot better, I think than everything was expecting. So could you just maybe walk us through how to think about that in 2015 and beyond?

Yeah hi, Holly, this is Chad. So there is probably three things that affected or influenced fourth quarter NGL realizations or improvements. One, you got to realize or remember that range has a PLP processing arrangement with Mark West. So as prices come down the fee we're paying Mark West comes down, which improves our realizations. October, November the market saw little bit colder temperatures so demand for propane, heating demand for propane increased. So propane prices improved a little bit. And approximately half our NGL barrel is ethane and 80% of our ethane is currently tied to natural gas index as we sell on our Mariner West project, all of the ethane is sold on a gas equivalent and some of the ethane on ATAX [ph] is sold at a gas equivalent price. So that's why you saw that realizations improve in fourth quarter.

Okay, that helps. And then maybe just kind of a bigger picture question for Jeff. You've laid out in the slide deck, you kind of going from 1.4, I think it is to 2.5 Bcf a day of transportation agreements between 2015 and '18. So maybe strategically can you reconcile that growth in sort of ST capacity to the growth in expected production, should kind of prices remain weak.

Yeah, I think one thing we've had for a number of years now is a long range plan. So we have a very integrated process when we look at that production profile that we expect and well integrated with the Chad and the marketing team in terms of the amount of firm transportation that we need to hit those targets. And it's not just on the gas side but on the liquid side as well. We do have -- so we have good plan, capital efficiencies like we said will continue to improve. I think you'll see us move out to longer laterals, more frac stages, all those types of technologies that help on that side, so our capital efficiency should improve. I think another key thing to think about too is really think natural gas demand is going to improve with time as well. And I mentioned it in my notes early on with the mass retirements on power plants start kicking in, in the spring of this year, increased exports to Mexico and LNG starting up later this year, we think demand will be up 1 to 2 bs this year and then we think for every year thereafter demand increases 3 to 4 bcf per year and there is a slide in our book that points that out, peaking out we think the incremental gas demand could be 20 bcf by 2020. So we think there is going to be a lot of gas demand and gas is going to be a good place to be and we're in the highest quality, in the core of the highest quality best gas play out there with the ability to drill wet, dry and super rich as well as Marcellus, Utica and Upper Devonian.

Thank you, gentlemen.

Thank you.

Thank you. Our next question comes from Brian Singer of Goldman Sachs. Please go ahead with your question.

Thank you. Good morning.

Good morning.

Good morning.

Just one question on how you're thinking about longer term, Marcellus production relative to your takeaway capacity. What scenario do you see relative to the very large takeaway that you have lined up to get gas out of the basin for you to be producing above that number versus below that number and how are you thinking about scenarios in what to do with, in terms of contracting additional takeaway capacity, if your plans are to produce above that in 2018 or what you would do with any excess takeaway capacity if you're producing below that?

I think if you look at us now that we're basically fully covered and well integrated for the plan that we have. And right now there is a benefit to having all that from transportation, there is value to that portfolio and yeah I think we have a very forward thinking team that's been able to line up pieces and let me flip it over to Chad to talk about that a little bit more.

Yes, thanks. So getting to where we are today the firm transport capacity we have through 2018 has been a very thoughtful methodical process getting with our drilling teams and understanding what our volumes are going to be up through 2018 and beyond. And when you look at slide 37 in our presentation we show regionally where that firm transportation is and what we deem is relatively cheap firm transportation costs, that dovetails or fits real well with our projected volumes. Going forward we think that there is release capacity markets we've already been involved in and getting again relatively cheap or inexpensive firm transport to layer in to the areas we want to get our markets too. Obviously slide 37 shows our main objective is to try to get as much of our volume out of Appalachia into other areas Midwest, Gulf Coast and Southeast and in the future we want to try to do that as well. We think that with rig rates coming down, CapEx budgets being cut, volume -- projected volumes will be coming down in those companies that committed to firm transportation volumes will not be using all of that capacity. So we're going to take advantage of that and get into the release capacity markets and when needed speak up for some of that released capacity. We're also in discussions with some of the midstream companies about adding layering in additional strategic firm transportation projects they would fit our volumes and our needs again getting the volumes out of the Appalachia basin to other areas of the country where the basis has not been quite as volatile and we don't think it will be in the future.

Got it. Thanks. And then with regards to the cost reductions that you seem to be showing here at least on per thousand foot of lateral basis in the super rich and southwest wet Marcellus plays. Can you talk to how much of that's lower cost and what the split is in terms of what you would call -- we would call cyclical service cost reduction that maybe in a higher oil and gas environment would go away versus what you would consider secular.

Sure Brian. It’s Ray. In my remarks I tried to do that as best we could. But one of the things I said was that on an apples-to-apples basis if you look at the contracts that we -- I call them arrangements, if you look at the arrangements we have in place today with all our folks on the -- or our partners on the supply chain side of things and you look apples-to-apples compared to December of 2014 through today which is what we have in hand again, our well costs are down 23% to 25%. The operational efficiencies, design improvements renewed technology all those things that we have done over the past four years are going to continue going in ’15. So when you add those together that’s where you achieve that big change that you are seeing from ’14 to ’15 which is a bigger decrease then the slope of that line have been previously adding those two together gets you a 37% decrease on a per foot basis. We haven’t put that in our total well cost basis just because all the lateral lengths are different and it is just too difficult to talk about from that standpoint. But again the service price reductions and supply side of thing reductions, those add up to about 23% to 25% on an apples-to-apples basis compared to December of ’14.

And I think if you look on slide eight and nine there is a lot of detail and you can kind of see like Ray mentioned earlier there wasn’t much of change in service industry cost from 2011 to 2014.

If anything it went up.

Yeah, so those are pure operational efficiencies.

Okay, thank you.

Thank you. Our next question comes from -- GMP Securities. Please go ahead with your question.

Thanks for squeezing me in guys and congrats on a great quarter.

Thank you.

My first question it relates to slide 17, if I look at the IRRs now, I understand the upcoming balance between the super-rich and wet gas window driven by the oil pricing but how does this change the plan longer-term plan for Range going forward with gas competing well with the super-rich and rich window? And then I have a follow-up.

Well, let me start and Alan might have some follow-up. But one of the advantage we have is we do have a big acreage position in Dry, Wet and Super-Rich and again across those three things as well as up and down through the various horizons, Marcellus, Utica and Upper Devonian. So we have some ability to shift capital back and forth to try to drive further capital efficiency and better returns. So that is an advantage of the portfolio and the size of the footprint that we have and we will do that with time. Obviously as prices swing, as oil swing high to low or gas swings high to lower NGLs it is going to affect the economics and we will do our best to capture the most optimum returns that we can. Alan, do you want to add to that?

Yeah, really I think comes down to -- it’s kind of - to add on to what Jeff said we have the opportunity to be able to drill in any one of the three areas, number one. Number two, you saw that in 2014 as well that we had a balanced portfolio. We talked about that early in the year last year and so you saw a mix of wells that are going to be in there. I think it still comes down to well performance is still really strong, recoveries are still on a normalized basis still the same but overall EURs are going up cost are coming down so as we continue to work to that process we are going to continue to put the capital in the area in the areas it is going to give us a best return that we can realize. But I think you see those two things really coming at the end of the day and it just allows us more enhancement to the portfolio.

And that is an advantage of having a really large footprint in the core deploy with high quality mark with a strong team. Through multiple years but you can make those kind of continue to improve.

Okay. And the follow-up is, middle of last year there was plan to get to investment grade by middle of ’16 maybe late ‘16 how has that plan changed with the commodity coming down now?

Yeah, hi, Sameer it’s Roger. Yeah, I don’t believe we have put a date on which we desire to be investment grade and agencies tend to take -- their customer telling them that. So there was never a firm date but you are exactly right we are on a trajectory and still are to become investment grade in the future, with sort of the lowering of the tide effecting oil companies it appears that it’s going to take a little longer than it otherwise would have us to be there. When we look at our core metrics and the fact that were our bond trade. I mean every one of our bonds, even though coupons are like 5%, all of our bonds are trading over 100 cents on the dollar. I mean our spread to treasury on our longest notes are about 298. So our bonds are trading right at the crossover mark. So I think the people that really understand credit liquidity are voting with the market and we know we’re still on that trajectory. But again we’re not going to project when that might occur in the future.

Perfect. Thanks.

Thank you.

Thank you. We are nearing the end of today’s conference. We’ll go to Drew Venker of Morgan Stanley for our final question. Please go ahead with your question.

Good morning, everyone. Was hoping to get a little bit more color on the Utica program. You mentioned building out some infrastructure. Are you expecting to produce that well at a higher rate once the infrastructure’s in place?

Good question. We’re excited about the Utica, the first well, it’s only been on line a few weeks. We purposely designed the production facilities to basically limit that well at 20 million a day, because again we tend to focus at Range on the long-term project economics and not initial production rates or anything like that, because the projects at the end of the day is what’s most important. For the first half of this year that first well is actually producing on an interruptible basis as we have room to kind of [indiscernible]. We are currently building a new pipeline segment that will take it directly to the big pipe essentially, that will be finished sometime this summer and that is also corresponding with about the time we believe -- and all this is plus or minus a month at this point. But that corresponds with about the same time that the second well is ready for initial production. We will design those facilities for that second well to also limit it to about 20 million a day, but we do expect for the last half of the years that both those wells will be able to produce at their full rate which is going to again be limited to 20 million a day each, but we think they’ll come online this summer time and produce the rest of the year on an uninterruptible basis. And the third well we’ll drill later in the year. At this point it’s too early to tell we are kind of in the planning process and permitting process to know if it will actually produce this year or not, but it will be somewhere around the end of the year or beginning of next year when the third well’s ready. Second well, we think we can do at about $13 million, we still got some science in it and again I am fully expect and I think our team is pretty pumped about what we see so far and they think we believe that as we go into that program that we can lower those costs another 15% to 25% and now as we take in well designs and different things that we learn and going through first couple of wells. And I’ll also point out that third well, it will be in that same area, but it will actually be on a different pad, is the current plan.

Okay, understood. So it’s obviously very early. How much production history or well control would you want before moving the Utica into development mode or before your let’s say allocating a significant amount of capital to the play?

Well, we have a lot of information about the Utica. We had, as we talked about in quarters past, a lot of old trend Black River tests and a lot more test wells that were done back in the very early days before the Marcellus even. So we have a lot of log data. Industry has certain drilled a lot of Utica wells all around at this point. There is enough production history now to prove out some other things on pressure and the reservoir parameters that we were looking at. So the Utica is a lot different than the Marcellus, we won’t have to be stepping out and delineating acreage like we did it in the early days of the Marcellus. This is going to be more of a manufacturing tied process. We’ll actually be able to just to put existing pads with existing infrastructure and start layering those wells in overtime. We generally like to see, I mean we’ll update you quarter-b y-quarter as we see the production from these wells, just like we did in old days of the Marcellus and I think once we’ve seen three six to nine months of production on these various wells we will be pretty comfortable with what we have going forward and at that point I think it's going to be a factor of the economics. It's going to be pretty easy to grow with those kind of wells. It's got to be -- the economics are going to be very competitive and I think that we'll have to look at what the market is telling us at that point, ‘16 and beyond as we develop these plans as what we do next. But it's another really strong option for us and that's what we like.

Thanks for the color.

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 remarks.

2014 was a record year for Range. Cash flow was over $1 billion for the first time in the company's history, reserves reached a new record level of 10.3 Tcfe with the Conger-Nora swap we now have operational control over essentially all of our property. We ended the year with lower debt and improved bank facility with plenty of liquidity and no bond maturities until 2020. 2014 was also a challenging and difficult year with falling commodity prices that have continued into 2015 with our current plan to spend approximately $700 million less in 2015 and 2014 and still target 20% growth, we believe that we'll be one of the most capital efficient companies in our industry. These capital efficiency coupled with our large footprint in the core of the Marcellus, Utica and Upper Devonian and the optionality of being able to drill dry wet and super rich acreage have us well positioned for 2015, 2016 and beyond. Thanks for participating on the call. If you have additional questions please follow-up with our IR team.

Ladies and gentlemen, thank you for your participation in today's conference. You may now disconnect your lines at this time.